In situ thermal processing of an oil shale formation having permeable and impermeable sections

• US 20030131996A1
• Filed: 04/24/2002
• Published: 07/17/2003
• Est. Priority Date: 04/24/2001
• Status: Active Grant

• Current Assignee: Shell Oil Company (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: Vinegar, Harold J., Wellington, Scott Lee, Rouffignac, Eric Pierre de
• Granted Patent: US 6,915,850 B2
• Time in Patent Office: Days
• US Class Current: 166/272.1
• CPC Class Codes: E21B 43/24 using heat, e.g. steam injection
• CPC Class Codes: E21B 43/2401 by means of electricity
• CPC Class Codes: E21B 43/243 Combustion in situ
• CPC Class Codes: E21B 43/247 in association with fracturing processes or crevice forming processes
• CPC Class Codes: E21B 43/30 Specific pattern of wells, e.g. optimising the spacing of wells

Abstract

An oil shale formation may be treated using an in situ thermal process. Heat may be provided to a formation from one or more heat sources in the formation. Hydrocarbons within the formation may be pyrolyzed. Hydrocarbons, H₂, and/or other formation fluids may be produced from the formation. In some embodiments, the formation may include a relatively impermeable portion and/or a relatively permeable portion.

Claims

55. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least the portion to a selected section of the formation substantially by conduction of heat;

pyrolyzing at least some hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

56. The method of claim 55, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

57. The method of claim 55, wherein the one or more heat sources comprise electrical heaters.

58. The method of claim 55, wherein the one or more heat sources comprise surface burners.

59. The method of claim 55, wherein the one or more heat sources comprise flameless distributed combustors.

60. The method of claim 55, wherein the one or more heat sources comprise natural distributed combustors.

61. The method of claim 55, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

62. The method of claim 55, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0 C per day during pyrolysis.

63. The method of claim 55, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

64. The method of claim 55, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

65. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

66. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

67. The method of claim 55, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

68. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

69. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

70. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

71. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

72. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

73. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

74. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

75. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

76. The method of claim 55, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

77. The method of claim 55, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

78. The method of claim 55, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

79. The method of claim 55, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

80. The method of claim 55, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

81. The method of claim 80, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

82. The method of claim 55, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

83. The method of claim 55, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

84. The method of claim 55, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

85. The method of claim 55, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen

86. The method of claim 55, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

87. The method of claim 55, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

88. The method of claim 55, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

89. The method of claim 55, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

90. The method of claim 89, wherein at least about 20 heat sources are disposed in the formation for each production well.

91. The method of claim 55, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

92. The method of claim 55, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

93. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 370°

C. such that production of a substantial amount of hydrocarbons having carbon numbers greater than 25 is inhibited;

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least 2.0 bars; and

producing a mixture from the formation, wherein about 0.1% by weight of the produced mixture to about 15% by weight of the produced mixture are olefins, and wherein an average carbon number of the produced mixture is greater than 1 and less than about 25.

94. The method of claim 93, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

95. The method of claim 93, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

96. The method of claim 93, wherein the one or more heat sources comprise electrical heaters.

97. The method of claim 93, wherein the one or more heat sources comprise surface burners.

98. The method of claim 93, wherein the one or more heat sources comprise flameless distributed combustors.

99. The method of claim 93, wherein the one or more heat sources comprise natural distributed combustors.

100. The method of claim 93, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

101. The method of claim 93, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

102. The method of claim 93, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

103. The method of claim 93, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

104. The method of claim 93, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

105. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

106. The method of claim 93, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

107. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

108. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

109. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

110. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

111. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

112. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

113. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

114. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

115. The method of claim 93, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

116. The method of claim 93, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

117. The method of claim 93, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

118. The method of claim 93, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

119. The method of claim 118, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

120. The method of claim 93, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

121. The method of claim 93, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

122. The method of claim 93, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

123. The method of claim 93, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

124. The method of claim 93, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

125. The method of claim 93, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

126. The method of claim 93, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

127. The method of claim 126, wherein at least about 20 heat sources are disposed in the formation for each production well.

128. The method of claim 93, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

130. The method of claim 93, further comprising separating the produced mixture into a gas stream and a liquid stream.

131. The method of claim 93, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.

132. The method of claim 93, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.

133. The method of claim 93, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.

134. The method of claim 93, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

135. The method of claim 93, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

136. The method of claim 93, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the produced mixture comprise a large non-condensable hydrocarbon gas component and H₂.

137. The method of claim 93, wherein the minimum pyrolysis temperature is about 270°

C.

138. The method of claim 93, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

139. The method of claim 93, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the produced mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.

140. The method of claim 93, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.

1153. The method of claim 122, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

129-1. The method of claim 1122, wherein the first heat source, second heat source and third heat source are positioned substantially at apexes of an equilateral triangle.

141. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute; and

producing a mixture from the formation.

142. The method of claim 141, wherein controlling the pressure comprises controlling the pressure with a valve coupled to at least one of the one or more heat sources.

143. The method of claim 141, wherein controlling the pressure comprises controlling the pressure with a valve coupled to a production well located in the formation.

144. The method of claim 141, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

145. The method of claim 141, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

146. The method of claim 141, wherein the one or more heat sources comprise electrical heaters.

147. The method of claim 141, wherein the one or more heat sources comprise surface burners.

148. The method of claim 141, wherein the one or more heat sources comprise flameless distributed combustors.

149. The method of claim 141, wherein the one or more heat sources comprise natural distributed combustors.

150. The method of claim 141, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

151. The method of claim 141, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

152. The method of claim 141, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

153. The method of claim 141, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

154. The method of claim 141, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

155. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

156. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

157. The method of claim 141, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

158. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

159. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

160. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

161. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

162. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

163. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

164. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

165. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

166. The method of claim 141, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

167. The method of claim 141, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

168. The method of claim 141, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

169. The method of claim 141, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

170. The method of claim 169, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

171. The method of claim 141, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

172. The method of claim 141, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

173. The method of claim 141, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

174. The method of claim 141, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

175. The method of claim 141, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

176. The method of claim 141, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

177. The method of claim 141, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

178. The method of claim 141, wherein producing the mixture from the formation comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

179. The method of claim 178, wherein at least about 20 heat sources are disposed in the formation for each production well.

180. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375°

C.; and

producing a mixture from the formation.

181. The method of claim 180, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

182. The method of claim 180, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

183. The method of claim 180, wherein the one or more heat sources comprise electrical heaters.

184. The method of claim 180, wherein the one or more heat sources comprise surface burners.

185. The method of claim 180, wherein the one or more heat sources comprise flameless distributed combustors.

186. The method of claim 180, wherein the one or more heat sources comprise natural distributed combustors.

187. The method of claim 180, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

188. The method of claim 180, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

189. The method of claim 180, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

190. The method of claim 180, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

191. The method of claim 180, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

192. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

193. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

194. The method of claim 180, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

195. The method of claim 180, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

196. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

197. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

198. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

199. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

200. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

201. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

202. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

203. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

204. The method of claim 180, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

205. The method of claim 180, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

206. The method of claim 180, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

207. The method of claim 180, wherein controlling the heat further comprises controlling the heat such that coke production is inhibited.

208. The method of claim 180, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

209. The method of claim 208, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

210. The method of claim 180, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

211. The method of claim 180, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

212. The method of claim 180, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

213. The method of claim 180, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

214. The method of claim 180, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

215. The method of claim 180, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

216. The method of claim 180, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

217. The method of claim 180, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

218. The method of claim 217, wherein at least about 20 heat sources are disposed in the formation for each production well.

219. The method of claim 180, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

220. The method of claim 180, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

221. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation, wherein at least a portion of the mixture is produced during the pyrolysis and the mixture moves through the formation in a vapor phase; and

maintaining a pressure within at least a majority of the selected section above about 2.0 bars absolute.

222. The method of claim 221, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

223. The method of claim 221, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

224. The method of claim 221, wherein the one or more heat sources comprise electrical heaters.

225. The method of claim 221, wherein the one or more heat sources comprise surface burners.

226. The method of claim 221, wherein the one or more heat sources comprise flameless distributed combustors.

227. The method of claim 221, wherein the one or more heat sources comprise natural distributed combustors.

228. The method of claim 221, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

229. The method of claim 221, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

230. The method of claim 221, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

231. The method of claim 221, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

232. The method of claim 221, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

233. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

234. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

235. The method of claim 221, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

236. The method of claim 221, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

237. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

238. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

239. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

240. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

241. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

242. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

243. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

244. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

245. The method of claim 221, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

246. The method of claim 221, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

247. The method of claim 221, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

248. The method of claim 221, wherein the pressure is measured at a wellhead of a production well.

249. The method of claim 221, wherein the pressure is measured at a location within a wellbore of the production well.

250. The method of claim 221, wherein the pressure is maintained below about 100 bars absolute.

251. The method of claim 221, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

252. The method of claim 251, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

253. The method of claim 221, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

254. The method of claim 221, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

255. The method of claim 221, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

256. The method of claim 221, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

257. The method of claim 221, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

258. The method of claim 221, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

259. The method of claim 221, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

260. The method of claim 221, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

261. The method of claim 260, wherein at least about 20 heat sources are disposed in the formation for each production well.

262. The method of claim 221, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

263. The method of claim 221, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

264. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation above 2.0 bars absolute; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity higher than an API gravity of condensable hydrocarbons in a mixture producible from the formation at the same temperature and at atmospheric pressure.

265. The method of claim 264, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

266. The method of claim 264, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

267. The method of claim 264, wherein the one or more heat sources comprise electrical heaters.

268. The method of claim 264, wherein the one or more heat sources comprise surface burners.

269. The method of claim 264, wherein the one or more heat sources comprise flameless distributed combustors.

270. The method of claim 264, wherein the one or more heat sources comprise natural distributed combustors.

271. The method of claim 264, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

272. The method of claim 264, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

273. The method of claim 264, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

274. The method of claim 264, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

275. The method of claim 264, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

276. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

277. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

278. The method of claim 264, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

279. The method of claim 264, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

280. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

281. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

282. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

283. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

284. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

285. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

286. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

287. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

288. The method of claim 264, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

289. The method of claim 264, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

290. The method of claim 264, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

291. The method of claim 264, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

292. The method of claim 264, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

293. The method of claim 264, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

294. The method of claim 264, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

295. The method of claim 264, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

296. The method of claim 264, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

297. The method of claim 264, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

298. The method of claim 264, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

299. The method of claim 264, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

300. The method of claim 264, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

301. The method of claim 300, wherein at least about 20 heat sources are disposed in the formation for each production well.

302. The method of claim 264, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

303. The method of claim 264, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

304. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and

producing a fluid from the formation, wherein condensable hydrocarbons within the fluid comprise an atomic hydrogen to atomic carbon ratio of greater than about 1.75.

305. The method of claim 304, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

306. The method of claim 304, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

307. The method of claim 304, wherein the one or more heat sources comprise electrical heaters.

308. The method of claim 304, wherein the one or more heat sources comprise surface burners.

309. The method of claim 304, wherein the one or more heat sources comprise flameless distributed combustors.

310. The method of claim 304, wherein the one or more heat sources comprise natural distributed combustors.

311. The method of claim 304, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

312. The method of claim 304, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

313. The method of claim 304, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, PB is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

314. The method of claim 304, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

315. The method of claim 304, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

316. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

317. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

318. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

319. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

320. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

321. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

322. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

323. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

324. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

325. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

326. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

327. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons a re cycloalkanes.

328. The method of claim 304, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

329. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

330. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

331. The method of claim 304, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

332. The method of claim 304, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

333. The method of claim 304, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

334. The method of claim 304, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

335. The method of claim 304, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

336. The method of claim 304, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

337. The method of claim 304, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

338. The method of claim 304, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

339. The method of claim 304, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

340. The method of claim 304, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

341. The method of claim 340, wherein at least about 20 heat sources are disposed in the formation for each production well.

342. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

343. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

344. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and

producing a mixture from the formation, wherein the produced mixture comprises a higher amount of non-condensable components as compared to non-condensable components producible from the formation under the same temperature conditions and at atmospheric pressure.

345. The method of claim 344, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

346. The method of claim 344, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

347. The method of claim 344, wherein the one or more heat sources comprise electrical heaters.

348. The method of claim 344, wherein the one or more heat sources comprise surface burners.

349. The method of claim 344, wherein the one or more heat sources comprise flameless distributed combustors.

350. The method of claim 344, wherein the one or more heat sources comprise natural distributed combustors.

351. The method of claim 344, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

352. The method of claim 344, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

353. The method of claim 344, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

354. The method of claim 344, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

355. The method of claim 344, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

356. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

357. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

358. The method of claim 344, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

359. The method of claim 344, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

360. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

361. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

362. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

363. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

364. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

365. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

366. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

367. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

368. The method of claim 344, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

369. The method of claim 344, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia

370. The method of claim 344, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

371. The method of claim 344, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

372. The method of claim 344, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

373. The method of claim 344, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

374. The method of claim 344, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

375. The method of claim 344, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

376. The method of claim 344, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

377. The method of claim 344, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

378. The method of claim 344, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

379. The method of claim 344, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

380. The method of claim 379, wherein at least about 20 heat sources are disposed in the formation for each production well.

381. The method of claim 344, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

382. The method of claim 344, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

383. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% by weight of hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

384. The method of claim 383, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

385. The method of claim 383, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

386. The method of claim 383, wherein the one or more heat sources comprise electrical heaters.

387. The method of claim 383, wherein the one or more heat sources comprise surface burners.

388. The method of claim 383, wherein the one or more heat sources comprise flameless distributed combustors.

389. The method of claim 383, wherein the one or more heat sources comprise natural distributed combustors.

390. The method of claim 383, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

391. The method of claim 383, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

392. The method of claim 383, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

393. The method of claim 383, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

394. The method of claim 383, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

395. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

396. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

397. The method of claim 383, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

398. The method of claim 383, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

399. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

400. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

401. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

402. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

403. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

404. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

405. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

406. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

407. The method of claim 383, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

408. The method of claim 383, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

409. The method of claim 383, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

410. The method of claim 383, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

411. The method of claim 383, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

412. The method of claim 383, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

413. The method of claim 383, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

414. The method of claim 383, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

415. The method of claim 383, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

416. The method of claim 383, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

417. The method of claim 383, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

418. The method of claim 383, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

419. The method of claim 383, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

420. The method of claim 383, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

421. The method of claim 420, wherein at least about 20 heat sources are disposed in the formation for each production well.

422. The method of claim 383, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

423. The method of claim 383, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

424. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% of hydrocarbons within the selected section of the formation; and

producing a mixture from the formation, wherein the mixture comprises a condensable component having an API gravity of at least about 25°

.

425. The method of claim 424, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation

426. The method of claim 424, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

427. The method of claim 424, wherein the one or more heat sources comprise electrical heaters.

428. The method of claim 424, wherein the one or more heat sources comprise surface burners.

429. The method of claim 424, wherein the one or more heat sources comprise flameless distributed combustors.

430. The method of claim 424, wherein the one or more heat sources comprise natural distributed combustors.

431. The method of claim 424, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

432. The method of claim 424, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

433. The method of claim 424, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, PB is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

434. The method of claim 424, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

435. The method of claim 424, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

436. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

437. The method of claim 424, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

438. The method of claim 424, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

439. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

440. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

441. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

442. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

443. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

444. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

445. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

446. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

447. The method of claim 424, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

448. The method of claim 424, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

449. The method of claim 424, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

450. The method of claim 424, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

451. The method of claim 424, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

452. The method of claim 424, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

453. The method of claim 424, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

454. The method of claim 424, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

455. The method of claim 424, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

456. The method of claim 424, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

457. The method of claim 424, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

458. The method of claim 424, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

459. The method of claim 424, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

460. The method of claim 424, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

461. The method of claim 460, wherein at least about 20 heat sources are disposed in the formation for each production well.

462. The method of claim 424, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

463. The method of claim 424, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

464. A method of treating a layer of an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the layer, wherein the one or more heat sources are positioned proximate an edge of the layer;

allowing the heat to transfer from the one or more heat sources to a selected section of the layer such that superimposed heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

465. The method of claim 464, wherein the one or more heat sources are laterally spaced from a center of the layer.

466. The method of claim 464, wherein the one or more heat sources are positioned in a staggered line.

467. The method of claim 464, wherein the one or more heat sources positioned proximate the edge of the layer can increase an amount of hydrocarbons produced per unit of energy input to the one or more heat sources.

468. The method of claim 464, wherein the one or more heat sources positioned proximate the edge of the layer can increase the volume of formation undergoing pyrolysis per unit of energy input to the one or more heat sources.

469. The method of claim 464, wherein the one or more heat sources comprise electrical heaters.

470. The method of claim 464, wherein the one or more heat sources comprise surface burners.

471. The method of claim 464, wherein the one or more heat sources comprise flameless distributed combustors.

472. The method of claim 464, wherein the one or more heat sources comprise natural distributed combustors.

473. The method of claim 464, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

474. The method of claim 464, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0°

C. per day during pyrolysis.

475. The method of claim 464, wherein providing heat from the one or more heat sources to at least the portion of the layer comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr =h*V*C_v*ρ

B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, PB is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

476. The method of claim 464, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

477. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

478. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

479. The method of claim 464, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

480. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

481. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

482. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

483. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

484. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

485. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

486. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

487. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

488. The method of claim 464, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

489. The method of claim 464, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

490. The method of claim 464, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

491. The method of claim 464, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

492. The method of claim 464, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

493. The method of claim 492, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

494. The method of claim 464, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

495. The method of claim 464, further comprising controlling formation conditions, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

496. The method of claim 464, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

497. The method of claim 464, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

498. The method of claim 464, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

499. The method of claim 464, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

500. The method of claim 464, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

501. The method of claim 464, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

502. The method of claim 501, wherein at least about 20 heat sources are disposed in the formation for each production well.

503. The method of claim 464, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

504. The method of claim 464, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

505. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure; and

producing a mixture from the formation.

506. The method of claim 505, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

507. The method of claim 505, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

508. The method of claim 505, wherein the one or more heat sources comprise electrical heaters.

509. The method of claim 505, wherein the one or more heat sources comprise surface burners.

510. The method of claim 505, wherein the one or more heat sources comprise flameless distributed combustors.

511. The method of claim 505, wherein the one or more heat sources comprise natural distributed combustors.

512. The method of claim 505, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

513. The method of claim 505, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, β

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

514. The method of claim 505, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

515. The method of claim 505, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

516. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

517. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

518. The method of claim 505, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

519. The method of claim 505, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

520. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

521. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

522. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

523. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

524. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

525. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

526. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

527. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

528. The method of claim 505, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

529. The method of claim 505, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

530. The method of claim 505, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

531. The method of claim 505, wherein the controlled pressure is at least about 2.0 bars absolute.

532. The method of claim 505, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

533. The method of claim 505, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

534. The method of claim 505, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

535. The method of claim 505, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

536. The method of claim 505, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

537. The method of claim 505, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

538. The method of claim 505, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

539. The method of claim 505, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

540. The method of claim 505, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

541. The method of claim 505, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

542. The method of claim 541, wherein at least about 20 heat sources are disposed in the formation for each production well.

543. The method of claim 505, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

544. The method of claim 505, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

545. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling API gravity of the produced mixture to be greater than about 25 degrees API by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section;

p=e<sup>[−

44000/T+67]</sup>

where p is measured in psia and T is measured in °

Kelvin.

546. The method of claim 545, wherein the API gravity of the produced mixture is controlled to be greater than about 30 degrees API, and wherein the equation is:

547. The method of claim 545, wherein the API gravity of the produced mixture is controlled to be greater than about 35 degrees API, and wherein the equation is:

548. The method of claim 545, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

549. The method of claim 545, wherein controlling the average temperature comprises maintaining a temperature in the selected section within a pyrolysis temperature range.

550. The method of claim 545, wherein the one or more heat sources comprise electrical heaters.

551. The method of claim 545, wherein the one or more heat sources comprise surface burners.

552. The method of claim 545, wherein the one or more heat sources comprise flameless distributed combustors.

553. The method of claim 545, wherein the one or more heat sources comprise natural distributed combustors.

554. The method of claim 545, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

555. The method of claim 545, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

556. The method of claim 545, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

557. The method of claim 545, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

558. The method of claim 545, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

559. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

560. The method of claim 545, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

561. The method of claim 545, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

562. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

563. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

564. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

565. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

566. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

567. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

568. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

569. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

570. The method of claim 545, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

571. The method of claim 545, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

572. The method of claim 545, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

573. The method of claim 545, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

574. The method of claim 545, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

575. The method of claim 545, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

576. The method of claim 545, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

577. The method of claim 545, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

578. The method of claim 545, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

579. The method of claim 545, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

580. The method of claim 545, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

581. The method of claim 545, wherein the heat is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

582. The method of claim 545, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

583. The method of claim 582, wherein at least about 20 heat sources are disposed in the formation for each production well.

584. The method of claim 545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

585. The method of claim 545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

586. A method of treating an oil shale formation in situ, comprising:

providing heat to at least a portion of an oil shale formation such that a temperature (T) in a substantial part of the heated portion exceeds 270°

C. and hydrocarbons are pyrolyzed within the heated portion of the formation;

controlling a pressure (p) within at least a substantial part of the heated portion of the formation;

wherein p_bar>

e<sup>[(−

A/T)+B−</sup>

26744]

wherein p is the pressure in bars absolute and T is the temperature in degrees K, and A and B are parameters that are larger than 10 and are selected in relation to the characteristics and composition of the oil shale formation and on the required olefin content and carbon number of the pyrolyzed hydrocarbon fluids; and

producing pyrolyzed hydrocarbon fluids from the heated portion of the formation.

587. The method of claim 586, wherein A is greater than 14000 and B is greater than about 25 and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than 25 and comprise less than about 10% by weight of olefins.

588. The method of claim 586, wherein T is less than about 390°

C., p is greater than about 1.4 bars, A is greater than about 44000, and b is greater than about 67, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number less than 25 and comprise less than 10% by weight of olefins.

589. The method of claim 586, wherein T is less than about 390°

C., p is greater than about 2 bars, A is less than about 57000, and b is less than about 83, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than about 21.

590. The method of claim 586, further comprising controlling the heat such that an average heating rate of the heated portion is less than about 3°

C. per day during pyrolysis.

591. The method of claim 586, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

592. The method of claim 586, wherein heat is transferred substantially by conduction from the one or more heat sources to the heated portion of the formation.

593. The method of claim 586, wherein heat is transferred substantially by conduction from the one or more heat sources to the heated portion of the formation such that the thermal conductivity of at least part of the heated portion is substantially uniformly modified to a value greater than about 0.6 W/m °

C. and the permeability of said part increases substantially uniformly to a value greater than 1 Darcy.

594. The method of claim 586, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture flowing through the formation is greater than 0.5 bars.

595. The method of claim 594, further comprising, hydrogenating a portion of the produced pyrolyzed hydrocarbon fluids with at least a portion of the produced hydrogen and heating the fluids with heat from hydrogenation.

596. The method of claim 586, wherein the substantially gaseous pyrolyzed hydrocarbon fluids are produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the hydrocarbon fluids within the wellbore.

597. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling a weight percentage of olefins of the produced mixture to be less than about 20% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section;

p=e<sup>[−

57000/T+83]</sup>

where p is measured in psia and T is measured in °

Kelvin.

598. The method of claim 597, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 10% by weight, and wherein the equation is:

599. The method of claim 597, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 5% by weight, and wherein the equation is:

600. The method of claim 597, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

601. The method of claim 597, wherein the one or more heat sources comprise electrical heaters.

602. The method of claim 597, wherein the one or more heat sources comprise surface burners.

603. The method of claim 597, wherein the one or more heat sources comprise flameless distributed combustors.

604. The method of claim 597, wherein the one or more heat sources comprise natural distributed combustors.

605. The method of claim 597, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

606. The method of claim 605, wherein controlling an average temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

607. The method of claim 597, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3.0°

C. per day during pyrolysis.

608. The method of claim 597, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

609. The method of claim 597, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

610. The method of claim 597, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

611. The method of claim 597, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

612. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

613. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

614. The method of claim 597, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

615. The method of claim 597, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

616. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

617. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

618. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

619. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

620. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

621. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

622. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

623. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

624. The method of claim 597, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

625. The method of claim 597, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

626. The method of claim 597, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

627. The method of claim 597, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

628. The method of claim 597, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

629. The method of claim 597, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

630. The method of claim 597, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

631. The method of claim 597, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

632. The method of claim 597, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

633. The method of claim 597, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

634. The method of claim 597, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

635. The method of claim 597, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

636. The method of claim 597, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

637. The method of claim 636, wherein at least about 20 heat sources are disposed in the formation for each production well.

638. The method of claim 597, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

639. The method of claim 597, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

640. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling hydrocarbons having carbon numbers greater than 25 of the produced mixture to be less than about 25% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section;

p=e<sup>[−

14000/T+25]</sup>

where p is measured in psia and T is measured in Kelvin.

641. The method of claim 640, wherein the hydrocarbons having carbon numbers greater than 25 of the produced mixture is controlled to be less than about 20% by weight, and wherein the equation is:

642. The method of claim 640, wherein the hydrocarbons having carbon numbers greater than 25 of the produced mixture is controlled to be less than about 15% by weight, and wherein the equation is:

643. The method of claim 640, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

644. The method of claim 640, wherein the one or more heat sources comprise electrical heaters.

645. The method of claim 640, wherein the one or more heat sources comprise surface burners.

646. The method of claim 640, wherein the one or more heat sources comprise flameless distributed combustors.

647. The method of claim 640, wherein the one or more heat sources comprise natural distributed combustors.

648. The method of claim 640, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

649. The method of claim 648, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

650. The method of claim 640, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

651. The method of claim 640, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

652. The method of claim 640, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

653. The method of claim 640, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

654. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

655. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

656. The method of claim 640, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

657. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

658. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

659. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

660. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

661. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

662. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

663. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

664. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

665. The method of claim 640, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

666. The method of claim 640, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

667. The method of claim 640, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

668. The method of claim 640, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

669. The method of claim 640, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

670. The method of claim 640, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

671. The method of claim 640, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

672. The method of claim 640, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

673. The method of claim 640, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

674. The method of claim 640, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

675. The method of claim 640, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

676. The method of claim 640, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

677. The method of claim 676, wherein at least about 20 heat sources are disposed in the formation for each production well.

678. The method of claim 640, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

679. The method of claim 640, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

680. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling an atomic hydrogen to carbon ratio of the produced mixture to be greater than about 1.7 by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section;

p=e<sup>[−

38000/T+61]</sup>

where p is measured in psia and T is measured in °

Kelvin.

681. The method of claim 680, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.8, and wherein the equation is:

682. The method of claim 680, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.9, and wherein the equation is:

683. The method of claim 680, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

684. The method of claim 680, wherein the one or more heat sources comprise electrical heaters.

685. The method of claim 680, wherein the one or more heat sources comprise surface burners.

686. The method of claim 680, wherein the one or more heat sources comprise flameless distributed combustors.

687. The method of claim 680, wherein the one or more heat sources comprise natural distributed combustors.

688. The method of claim 680, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

689. The method of claim 688, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

690. The method of claim 680, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

691. The method of claim 680, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

692. The method of claim 680, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

693. The method of claim 680, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

694. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

695. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

696. The method of claim 680, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

697. The method of claim 680, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

698. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

699. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

700. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

701. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

702. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

703. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

704. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

705. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

706. The method of claim 680, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

707. The method of claim 680, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

708. The method of claim 680, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

709. The method of claim 680, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

710. The method of claim 680, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

711. The method of claim 680, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

712. The method of claim 680, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

713. The method of claim 680, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

714. The method of claim 680, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

715. The method of claim 680, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

716. The method of claim 680, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

717. The method of claim 680, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

718. The method of claim 680, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

719. The method of claim 718, wherein at least about 20 heat sources are disposed in the formation for each production well.

720. The method of claim 680, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

721. The method of claim 680, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

722. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure-temperature relationship within at least the selected section of the formation by selected energy input into the one or more heat sources and by pressure release from the selected section through wellbores of the one or more heat sources; and

producing a mixture from the formation.

723. The method of claim 722, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

724. The method of claim 722, wherein the one or more heat sources comprise at least two heat sources.

725. The method of claim 722, wherein the one or more heat sources comprise surface burners.

726. The method of claim 722, wherein the one or more heat sources comprise flameless distributed combustors.

727. The method of claim 722, wherein the one or more heat sources comprise natural distributed combustors.

728. The method of claim 722, further comprising controlling the pressure-temperature relationship by controlling a rate of removal of fluid from the formation.

729. The method of claim 722, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

730. The method of claim 722, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

731. The method of claim 722, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

732. The method of claim 722, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

733. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

734. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

735. The method of claim 722, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

736. The method of claim 722, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

737. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

738. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

739. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

740. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

741. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

742. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

743. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

744. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

745. The method of claim 722, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

746. The method of claim 722, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

747. The method of claim 722, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

748. The method of claim 722, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

749. The method of claim 722, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

750. The method of claim 722, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

751. The method of claim 722, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

752. The method of claim 722, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

753. The method of claim 722, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

754. The method of claim 722, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

755. The method of claim 722, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

756. The method of claim 722, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

757. The method of claim 722, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

758. The method of claim 722, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

759. The method of claim 722, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

760. The method of claim 759, wherein at least about 20 heat sources are disposed in the formation for each production well.

761. The method of claim 722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

762. The method of claim 722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

763. A method of treating an oil shale formation in situ, comprising:

heating a selected volume (V) of the oil shale formation, wherein formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

764. The method of claim 763, wherein heating a selected volume comprises heating with an electrical heater.

765. The method of claim 763, wherein heating a selected volume comprises heating with a surface burner.

766. The method of claim 763, wherein heating a selected volume comprises heating with a flameless distributed combustor.

767. The method of claim 763, wherein heating a selected volume comprises heating with at least one natural distributed combustor.

768. The method of claim 763, further comprising controlling a pressure and a temperature within at least a majority of the selected volume of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

769. The method of claim 763, further comprising controlling the heating such that an average heating rate of the selected volume is less than about 1°

C. per day during pyrolysis.

770. The method of claim 763, wherein a value for C_v is determined as an average heat capacity of two or more samples taken from the oil shale formation.

771. The method of claim 763, wherein heating the selected volume comprises transferring heat substantially by conduction.

772. The method of claim 763, wherein heating the selected volume comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

773. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

774. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

775. The method of claim 763, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

776. The method of claim 763, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

777. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

778. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

779. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

780. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

781. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

782. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

783. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

784. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

785. The method of claim 763, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

786. The method of claim 763, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

787. The method of claim 763, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer

788. The method of claim 763, further comprising controlling a pressure within at least a majority of the selected volume of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

789. The method of claim 763, further comprising controlling formation conditions to produce a mixture from the formation comprising condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

790. The method of claim 763, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

791. The method of claim 763, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

792. The method of claim 763, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

793. The method of claim 763, further comprising:

providing hydrogen (H₂) to the heated volume to hydrogenate hydrocarbons within the volume; and

heating a portion of the volume with heat from hydrogenation.

794. The method of claim 763, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

795. The method of claim 763, further comprising increasing a permeability of a majority of the selected volume to greater than about 100 millidarcy.

796. The method of claim 763, further comprising substantially uniformly increasing a permeability of a majority of the selected volume.

797. The method of claim 763, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

798. The method of claim 763, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

799. The method of claim 798, wherein at least about 20 heat sources are disposed in the formation for each production well.

800. The method of claim 763, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

801. The method of claim 763, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

802. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

controlling heat output from the one or more heat sources such that an average heating rate of the selected section rises by less than about 3°

C. per day when the average temperature of the selected section is at, or above, the temperature that will pyrolyze hydrocarbons within the selected section; and

producing a mixture from the formation.

803. The method of claim 802, wherein controlling heat output comprises:

raising the average temperature within the selected section to a first temperature s that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation;

limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and

increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when production of formation fluid declines below a desired production rate.

804. The method of claim 802, wherein controlling heat output comprises:

raising the average temperature within the selected section to a first temperature that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation;

limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and

increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when quality of formation fluid produced from the formation falls below a desired quality.

805. The method of claim 802, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section.

806. The method of claim 802, wherein the one or more heat sources comprise electrical heaters.

807. The method of claim 802, wherein the one or more heat sources comprise surface burners.

808. The method of claim 802, wherein the one or more heat sources comprise flameless distributed combustors.

809. The method of claim 802, wherein the one or more heat sources comprise natural distributed combustors.

810. The method of claim 802, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

811. The method of claim 802, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1.5°

C. per day during pyrolysis.

812. The method of claim 802, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

813. The method of claim 802, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density.

814. The method of claim 802, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

815. The method of claim 802, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

816. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

817. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

818. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, wherein the condensable hydrocarbons have an olefin content is less than about 2.5% by weight of the condensable hydrocarbons, and wherein the olefin content is greater than about 0.1% by weight of the condensable hydrocarbons.

819. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

820. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.10 and wherein the ratio of ethene to ethane is greater than about 0.001.

821. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.05 and wherein the ratio of ethene to ethane is greater than about 0.001.

822. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

823. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

824. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

825. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

826. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

827. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

828. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

829. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

830. The method of claim 802, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

831. The method of claim 802, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

832. The method of claim 802, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

833. The method of claim 802, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

834. The method of claim 802, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

835. The method of claim 802, wherein a partial pressure of H₂ is measured when the mixture is at a production well.

836. The method of claim 802, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

837. The method of claim 802, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

838. The method of claim 802, further comprising:

providing H₂ to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

839. The method of claim 802, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

840. The method of claim 802, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

841. The method of claim 802, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

842. The method of claim 802, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

843. The method of claim 802, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

844. The method of claim 843, wherein at least about 20 heat sources are disposed in the formation for each production well.

845. The method of claim 802, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

846. The method of claim 802, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

847. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

to heat a selected section of the formation to an average temperature above about 270°

C.;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation;

controlling the heat from the one or more heat sources such that an average heating rate of the selected section is less than about 3°

C. per day during pyrolysis; and

producing a mixture from the formation.

848. The method of claim 847, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

849. The method of claim 847, wherein the one or more heat sources comprise electrical heaters.

850. The method of claim 847, further comprising supplying electricity to the electrical heaters substantially during non-peak hours.

851. The method of claim 847, wherein the one or more heat sources comprise surface burners.

852. The method of claim 847, wherein the one or more heat sources comprise flameless distributed combustors.

853. The method of claim 847, wherein the one or more heat sources comprise natural distributed combustors.

854. The method of claim 847, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

855. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 3°

C./day until production of condensable hydrocarbons substantially ceases.

856. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1.5°

C. per day during pyrolysis.

857. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

858. The method of claim 847, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density.

859. The method of claim 847, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

860. The method of claim 847, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

861. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

862. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

863. The method of claim 847, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

864. The method of claim 847, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

865. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

866. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

867. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

868. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

869. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

870. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

871. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

872. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

873. The method of claim 847, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

874. The method of claim 847, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

875. The method of claim 847, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

876. The method of claim 847, further comprising controlling a pressure within at least -a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

877. The method of claim 847, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

878. The method of claim 877, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

879. The method of claim 847, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

880. The method of claim 847, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

881. The method of claim 847, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

882. The method of claim 847, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

883. The method of claim 847, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

884. The method of claim 847, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

885. The method of claim 847, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

886. The method of claim 847, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

887. The method of claim 886, wherein at least about 20 heat sources are disposed in the formation for each production well.

888. The method of claim 847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

889. The method of claim 847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

890. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation through at least one production well;

monitoring a temperature at or in the production well; and

controlling heat input to raise the monitored temperature at a rate of less than about 3°

C. per day.

891. The method of claim 890, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

892. The method of claim 890, wherein the one or more heat sources comprise electrical heaters.

893. The method of claim 890, wherein the one or more heat sources comprise surface burners.

894. The method of claim 890, wherein the one or more heat sources comprise flameless distributed combustors.

895. The method of claim 890, wherein the one or more heat sources comprise natural distributed combustors.

896. The method of claim 890, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

897. The method of claim 890, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

898. The method of claim 890, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density.

899. The method of claim 890, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

900. The method of claim 890, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

901. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

902. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

903. The method of claim 890, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

904. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

905. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

906. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

907. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

908. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

909. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

910. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

911. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

912. The method of claim 890, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

913. The method of claim 890, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

914. The method of claim 890, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

915. The method of claim 890, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

916. The method of claim 890, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

917. The method of claim 916, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

918. The method of claim 890, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

919. The method of claim 890, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

920. The method of claim 890, further comprising:

providing H₂ to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

921. The method of claim 890, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

922. The method of claim 890, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

923. The method of claim 890, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

924. The method of claim 890, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

925. The method of claim 890, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

926. The method of claim 925, wherein at least about 20 heat sources are disposed in the formation for each production well.

927. The method of claim 890, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

928. The method of claim 890, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

929. A method of treating an oil shale formation in situ, comprising:

heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion, wherein the portion is located substantially adjacent to a wellbore;

flowing an oxidant through a conduit positioned within the wellbore to a heat source zone within the portion, wherein the heat source zone supports an oxidation reaction between hydrocarbons and the oxidant;

reacting a portion of the oxidant with hydrocarbons to generate heat; and

transferring generated heat substantially by conduction to a pyrolysis zone of the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone.

930. The method of claim 929, wherein heating the portion of the formation comprises raising a temperature of the portion above about 400°

C.

931. The method of claim 929, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.

932. The method of claim 929, further comprising removing reaction products from the heat source zone through the wellbore.

933. The method of claim 929, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.

934. The method of claim 929, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.

935. The method of claim 929, further comprising heating the conduit with reaction products being removed through the wellbore.

936. The method of claim 929, wherein the oxidant comprises hydrogen peroxide.

937. The method of claim 929, wherein the oxidant comprises air.

938. The method of claim 929, wherein the oxidant comprises a fluid substantially free of nitrogen.

939. The method of claim 929, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200°

C.

940. The method of claim 929, wherein heating the portion of the formation comprises electrically heating the formation.

941. The method of claim 929, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.

942. The method of claim 929, wherein heating the portion of the formation comprises heating the portion with a flameless distributed combustor.

943. The method of claim 929, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

944. The method of claim 929, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1°

C. per day during pyrolysis.

945. The method of claim 929, wherein heating the portion comprises heating the pyrolysis zone such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m °

C.).

946. The method of claim 929, further comprising controlling a pressure within at least a majority of the pyrolysis zone of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

947. The method of claim 929, further comprising:

providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

948. The method of claim 929, wherein transferring generated heat comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

949. The method of claim 929, wherein transferring generated heat comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

950. The method of claim 929, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

951. The method of claim 929, wherein the wellbore is located along strike to reduce pressure differentials along a heated length of the wellbore.

952. The method of claim 929, wherein the wellbore is located along strike to increase uniformity of heating along a heated length of the wellbore.

953. The method of claim 929, wherein the wellbore is located along strike to increase control of heating along a heated length of the wellbore.

954. A method of treating an oil shale formation in situ, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidant;

flowing the oxidant into a conduit, and wherein the conduit is connected such that the oxidant can flow from the conduit to the hydrocarbons;

allowing the oxidant and the hydrocarbons to react to produce heat in a heat source zone;

allowing heat to transfer from the heat source zone to a pyrolysis zone in the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone; and

removing reaction products such that the reaction products are inhibited from flowing from the heat source zone to the pyrolysis zone.

955. The method of claim 954, wherein heating the portion of the formation comprises raising the temperature of the portion above about 400°

C.

956. The method of claim 954, wherein heating the portion of the formation comprises electrically heating the formation.

957. The method of claim 954, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.

958. The method of claim 954, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.

959. The method of claim 954, wherein the conduit is located within a wellbore, wherein removing reaction products comprises removing reaction products from the heat source zone through the wellbore.

960. The method of claim 954, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.

961. The method of claim 954, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.

962. The method of claim 954, wherein the conduit is located within a wellbore, the method further comprising heating the conduit with reaction products being removed through the wellbore to raise a temperature of the oxidant passing through the conduit.

963. The method of claim 954, wherein the oxidant comprises hydrogen peroxide.

964. The method of claim 954, wherein the oxidant comprises air.

965. The method of claim 954, wherein the oxidant comprises a fluid substantially free of nitrogen.

966. The method of claim 954, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200°

C.

967. The method of claim 954, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone at a temperature that inhibits production of oxides of nitrogen.

968. The method of claim 954, wherein heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion further comprises heating with a flameless distributed combustor.

969. The method of claim 954, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

970. The method of claim 954, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1°

C. per day during pyrolysis.

971. The method of claim 954, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

972. The method of claim 954, wherein allowing heat to transfer comprises heating the pyrolysis zone such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m °

C.).

973. The method of claim 954, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.

974. The method of claim 954, further comprising:

providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

975. The method of claim 954, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

976. The method of claim 954, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

977. The method of claim 954, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

978. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation;

providing the oxidizing fluid to a heat source zone in the formation;

allowing the oxidizing gas to react with at least a portion of the hydrocarbons at the heat source zone to generate heat in the heat source zone; and

transferring the generated heat substantially by conduction from the heat source zone to a pyrolysis zone in the formation.

979. The method of claim 978, further comprising transporting the oxidizing fluid through the heat source zone by diffusion.

980. The method of claim 978, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

981. The method of claim 978, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

982. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

983. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring substantial heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

984. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

985. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

986. The method of claim 978, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

987. The method of claim 978, wherein the heat source zone extends radially from the opening a width of less than approximately 0.15 m.

988. The method of claim 978, wherein heating the portion comprises applying electrical current to an electric heater disposed within the opening.

989. The method of claim 978, wherein the pyrolysis zone is substantially adjacent to the heat source zone.

990. The method of claim 978, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

991. The method of claim 978, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1°

C. per day during pyrolysis.

992. The method of claim 978, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

993. The method of claim 978, wherein allowing heat to transfer comprises heating the portion such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m °

C.).

994. The method of claim 978, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.

995. The method of claim 978, further comprising:

providing hydrogen (H₂) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

996. The method of claim 978, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

997. The method of claim 978, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

998. The method of claim 978, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

999. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

maintaining an average temperature within the selected section above a minimum pyrolysis temperature and below a vaporization temperature of hydrocarbons having carbon numbers greater than 25 to inhibit production of a substantial amount of hydrocarbons having carbon numbers greater than 25 in the mixture.

1000. The method of claim 999, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1001. The method of claim 999, wherein maintaining the average temperature within the selected section comprises maintaining the temperature within a pyrolysis temperature range.

1002. The method of claim 999, wherein the one or more heat sources comprise electrical heaters.

1003. The method of claim 999, wherein the one or more heat sources comprise surface burners.

1004. The method of claim 999, wherein the one or more heat sources comprise flameless distributed combustors.

1005. The method of claim 999, wherein the one or more heat sources comprise natural distributed combustors.

1006. The method of claim 999, wherein the minimum pyrolysis temperature is greater than about 270°

C.

1007. The method of claim 999, wherein the vaporization temperature is less than approximately 450°

C. at atmospheric pressure.

1008. The method of claim 999, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1009. The method of claim 999, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1010. The method of claim 999, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1011. The method of claim 999, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1012. The method of claim 999, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1013. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1014. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1015. The method of claim 999, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1016. The method of claim 999, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to e thane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1017. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1018. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1019. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1020. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1021. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1022. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1023. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1024. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1025. The method of claim 999, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1026. The method of claim 999, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1027. The method of claim 999, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1028. The method of claim 999, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1029. The method of claim 999, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1030. The method of claim 1029, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1031. The method of claim 999, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1032. The method of claim 999, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1033. The method of claim 999, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1034. The method of claim 999, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1035. The method of claim 999, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1036. The method of claim 999, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1037. The method of claim 999, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1038. The method of claim 1037, wherein at least about 20 heat sources are disposed in the formation for each production well.

1039. The method of claim 999, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1040. The method of claim 999, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1041. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than 25; and

producing a mixture from the formation.

1042. The method of claim 1041, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1043. The method of claim 1041, wherein the one or more heat sources comprise electrical heaters.

1044. The method of claim 1041, wherein the one or more heat sources comprise surface burners.

1045. The method of claim 1041, wherein the one or more heat sources comprise flameless distributed combustors.

1046. The method of claim 1041, wherein the one or more heat sources comprise natural distributed combustors.

1047. The method of claim 1041, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1048. The method of claim 1047, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

1049. The method of claim 1041, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1050. The method of claim 1041, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, β

B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1051. The method of claim 1041, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1052. The method of claim 1041, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1053. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1054. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1055. The method of claim 1041, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1056. The method of claim 1041, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1057. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1058. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1059. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1060. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1061. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1062. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1063. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1064. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1065. The method of claim 1041, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1066. The method of claim 1041, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1067. The method of claim 1041, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1068. The method of claim 1041, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1069. The method of claim 1041, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1070. The method of claim 1069, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1071. The method of claim 1041, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1072. The method of claim 1041, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1073. The method of claim 1041, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1074. The method of claim 1041, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1075. The method of claim 1041, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1076. The method of claim 1041, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1077. The method of claim 1041, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1078. The method of claim 1077, wherein at least about 20 heat sources are disposed in the formation for each production well.

1079. The method of claim 1041, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1080. The method of claim 1041, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1081. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1082. The method of claim 1081, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1083. The method of claim 1081, wherein the one or more heat sources comprise electrical heaters.

1084. The method of claim 1081, wherein the one or more heat sources comprise surface burners.

1085. The method of claim 1081, wherein the one or more heat sources comprise flameless distributed combustors.

1086. The method of claim 1081, wherein the one or more heat sources comprise natural distributed combustors.

1087. The method of claim 1081, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1088. The method of claim 1081, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1089. The method of claim 1081, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1090. The method of claim 1081, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1091. The method of claim 1081, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1092. The method of claim 1081, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1093. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1094. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1095. The method of claim 1081, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1096. The method of claim 1081, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1097. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1098. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1099. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1100. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1101. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1102. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1103. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1104. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1105. The method of claim 1081, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1106. The method of claim 1081, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1107. The method of claim 1081, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1108. The method of claim 1081, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1109. The method of claim 1081, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1110. The method of claim 1109, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1111. The method of claim 1081, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1112. The method of claim 1081, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1113. The method of claim 1081, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1114. The method of claim 1081, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1115. The method of claim 1081, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1116. The method of claim 1081, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1117. The method of claim 1081, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1118. The method of claim 1081, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1119. The method of claim 1118, wherein at least about 20 heat sources are disposed in the formation for each production well.

1120. The method of claim 1081, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1121. The method of claim 1081, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1122. A method of treating an oil shale formation in situ, comprising:

heating a section of the formation to a pyrolysis temperature from at least a first heat source, a second heat source and a third heat source, and wherein the first heat source, the second heat source and the third heat source are located along a perimeter of the section;

controlling heat input to the first heat source, the second heat source and the third heat source to limit a heating rate of the section to a rate configured to produce a mixture from the formation with an olefin content of less than about 15% by weight of condensable fluids (on a dry basis) within the produced mixture; and

producing the mixture from the formation through a production well.

1. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375°

C.; and

producing a mixture from the formation.

2. The method of claim 1, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

3. The method of claim 1, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

4. The method of claim 1, wherein the one or more heat sources comprise electrical heaters.

5. The method of claim 1, wherein the one or more heat sources comprise surface burners.

6. The method of claim 1, wherein the one or more heat sources comprise flameless distributed combustors.

7. The method of claim 1, wherein the one or more heat sources comprise natural distributed combustors.

8. The method of claim 1, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

9. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to at least one of the one or more heat sources.

10. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to a production well located in the formation.

11. The method of claim 1, further comprising controlling the heat such that an average beating rate of the selected section is less than about 1°

C. per day during pyrolysis.

12. The method of claim 1, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity(C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

13. The method of claim 1, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

14. The method of claim 1, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

15. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

16. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

17. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

18. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

19. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

20. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

21. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

22. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

23. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

24. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

25. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

26. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

27. The method of claim 1, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, and wherein greater than about 10% by volume of the non-condensable component comprises hydrogen and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

28. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

29. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

30. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

31. The method of claim 1, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H₂ within the mixture greater than about 0.5 bars.

32. The method of claim 31, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

33. The method of claim 1, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

34. The method of claim 1, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

35. The method of claim 1, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

36. The method of claim 1, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

37. The method of claim 1, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

38. The method of claim 1, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

39. The method of claim 1, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

40. The method of claim 1, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

41. The method of claim 40, wherein at least about 20 heat sources are disposed in the formation for each production well.

42. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

43. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

44. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream.

45. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.

46. The method of claim 1, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.

47. The method of claim 1, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.

48. The method of claim 1, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

49. The method of claim 1, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

50. The method of claim 1, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H₂.

51. The method of claim 1, wherein the minimum pyrolysis temperature is about 270°

C.

52. The method of claim 1, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

53. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons.

54. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.

129. The method of claim 93, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1123. The method of claim 1122, wherein superposition of heat form the first heat source, second heat source, and third heat source pyrolyzes a portion of the hydrocarbons within the formation to fluids.

1124. The method of claim 1122, wherein the pyrolysis temperature is between about 270°

C. and about 400°

C.

1125. The method of claim 1122, wherein the first heat source is operated for less than about twenty-four hours a day.

1126. The method of claim 1122, wherein the first heat source comprises an electrical heater.

1127. The method of claim 1122, wherein the first heat source comprises a surface burner.

1128. The method of claim 1122, wherein the first heat source comprises a flameless distributed combustor.

1130. The method of claim 1122, wherein the production well is located substantially at a geometrical center of the first heat source, second heat source, and third heat source.

1131. The method of claim 1122, further comprising a fourth heat source, fifth heat source, and sixth heat source located along the perimeter of the section.

1132. The method of claim 1131, wherein the heat sources are located substantially at apexes of a regular hexagon.

1133. The method of claim 1132, wherein the production well is located substantially at a center of the hexagon.

1134. The method of claim 1122, further comprising controlling a pressure and a temperature within at least a majority of the section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1135. The method of claim 1122, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1136. The method of claim 1122, further comprising controlling the heat such that an average heating rate of the section is less than about 3°

C. per day during pyrolysis.

1137. The method of claim 1122, further comprising controlling the heat such that an average heating rate of the section is less than about 1°

C. per day during pyrolysis.

1138. The method of claim 1122, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1139. The method of claim 1122, wherein heating the section of the formation comprises transferring heat substantially by conduction.

1140. The method of claim 1122, wherein providing heat from the one or more heat sources comprises heating the section such that a thermal conductivity of at least a portion of the section is greater than about 0.5 W/(m °

C.).

1141. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1142. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1143. The method of claim 1122, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1144. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1145. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1146. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1147. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1148. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1149. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1150. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1151. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1152. The method of claim 1122, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1154. The method of claim 1122, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1155. The method of claim 1122, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1156. The method of claim 1122, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1157. The method of claim 1156, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1158. The method of claim 1122, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1159. The method of claim 1122, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1160. The method of claim 1122, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1161. The method of claim 1122, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1162. The method of claim 1122, wherein heating the section comprises increasing a permeability of a majority of the section to greater than about 100 millidarcy.

1163. The method of claim 1122, wherein heating the section comprises substantially uniformly increasing a permeability of a majority of the section.

1164. The method of claim 1122, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1165. The method of claim 1122, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1166. The method of claim 1165, wherein at least about 20 heat sources are disposed in the formation for each production well.

1167. The method of claim 1122, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1168. The method of claim 1122, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1169. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1170. The method of claim 1169, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1171. The method of claim 1169, wherein the one or more heat sources comprise electrical heaters.

1172. The method of claim 1169, wherein the one or more heat sources comprise surface burners.

1173. The method of claim 1169, wherein the one or more heat sources comprise flameless distributed combustors.

1174. The method of claim 1169, wherein the one or more heat sources comprise natural distributed combustors.

1175. The method of claim 1169, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1176. The method of claim 1175, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1177. The method of claim 1169, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1178. The method of claim 1169, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1179. The method of claim 1169, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1180. The method of claim 1169, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1181. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1182. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1183. The method of claim 1169, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1184. The method of claim 1169, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1185. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1186. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1187. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1188. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1189. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1190. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1191. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1192. The method of claim 1169, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1193. The method of claim 1169, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1194. The method of claim 1169, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1195. The method of claim 1169, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1196. The method of claim 1169, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1197. The method of claim 1196, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1198. The method of claim 1169, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1199. The method of claim 1169, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1200. The method of claim 1169, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1201. The method of claim 1169, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1202. The method of claim 1169, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1203. The method of claim 1169, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1204. The method of claim 1169, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1205. The method of claim 1169, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1206. The method of claim 1205, wherein at least about 20 heat sources are disposed in the formation for each production well.

1207. The method of claim 1169, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1208. The method of claim 1169, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1209. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1210. The method of claim 1209, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1211. The method of claim 1209, wherein the one or more heat sources comprise electrical heaters.

1212. The method of claim 1209, wherein the one or more heat sources comprise surface burners.

1213. The method of claim 1209, wherein the one or more heat sources comprise flameless distributed combustors.

1214. The method of claim 1209, wherein the one or more heat sources comprise natural distributed combustors.

1215. The method of claim 1209, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1216. The method of claim 1215, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1217. The method of claim 1209, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1218. The method of claim 1209, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1219. The method of claim 1209, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1220. The method of claim 1209, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1221. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1222. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1223. The method of claim 1209, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1224. The method of claim 1209, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1225. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1226. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1227. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1228. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1229. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1230. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1231. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1232. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1233. The method of claim 1209, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1234. The method of claim 1209, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1235. The method of claim 1209, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1236. The method of claim 1209, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1237. The method of claim 1209, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1238. The method of claim 1237, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1239. The method of claim 1209, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1240. The method of claim 1209, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1241. The method of claim 1209, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1242. The method of claim 1209, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1243. The method of claim 1209, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1244. The method of claim 1209, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1245. The method of claim 1209, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1246. The method of claim 1209, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1247. The method of claim 1246, wherein at least about 20 heat sources are disposed in the formation for each production well.

1248. The method of claim 1209, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1249. The method of claim 1209, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1250. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1251. The method of claim 1250, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1252. The method of claim 1250, wherein the one or more heat sources comprise electrical heaters.

1253. The method of claim 1250, wherein the one or more heat sources comprise surface burners.

1254. The method of claim 1250, wherein the one or more heat sources comprise flameless distributed combustors.

1255. The method of claim 1250, wherein the one or more heat sources comprise natural distributed combustors.

1256. The method of claim 1250, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1257. The method of claim 1256, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1258. The method of claim 1250, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1259. The method of claim 1250, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1260. The method of claim 1250, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1261. The method of claim 1250, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1262. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1263. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1264. The method of claim 1250, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1265. The method of claim 1250, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1266. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1267. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1268. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1269. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1270. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1271. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1272. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1273. The method of claim 1250, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1274. The method of claim 1250, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1275. The method of claim 1250, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1276. The method of claim 1250, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1277. The method of claim 1250, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1278. The method of claim 1277, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

1279. The method of claim 1250, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1280. The method of claim 1250, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1281. The method of claim 1250, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1282. The method of claim 1250, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1283. The method of claim 1250, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1284. The method of claim 1250, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1285. The method of claim 1250, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1286. The method of claim 1250, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1287. The method of claim 1286, wherein at least about 20 heat sources are disposed in the formation for each production well.

1288. The method of claim 1250, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1289. The method of claim 1250, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1290. A method of treating an oil shale formation in situ, comprising:

raising a temperature of a first section of the formation with one or more heat sources to a first pyrolysis temperature;

heating the first section to an upper pyrolysis temperature, wherein heat is supplied to the first section at a rate configured to inhibit olefin production;

producing a first mixture from the formation, wherein the first mixture comprises condensable hydrocarbons and H₂;

creating a second mixture from the first mixture, wherein the second mixture comprises a higher concentration of H₂ than the first mixture;

raising a temperature of a second section of the formation with one or more heat sources to a second pyrolysis temperature;

providing a portion of the second mixture to the second section;

heating the second section to an upper pyrolysis temperature, wherein heat is supplied to the second section at a rate configured to inhibit olefin production; and

producing a third mixture from the second section.

1291. The method of claim 1290, wherein creating the second mixture comprises removing condensable hydrocarbons from the first mixture.

1292. The method of claim 1290, wherein creating the second mixture comprises removing water from the first mixture.

1293. The method of claim 1290, wherein creating the second mixture comprises removing carbon dioxide from the first mixture.

1294. The method of claim 1290, wherein the first pyrolysis temperature is greater than about 270°

C.

1295. The method of claim 1290, wherein the second pyrolysis temperature is greater than about 270°

C.

1296. The method of claim 1290, wherein the upper pyrolysis temperature is about 500°

C.

1297. The method of claim 1290, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the first or second selected section of the formation.

1298. The method of claim 1290, wherein the one or more heat sources comprise electrical heaters.

1299. The method of claim 1290, wherein the one or more heat sources comprise surface burners.

1300. The method of claim 1290, wherein the one or more heat sources comprise flameless distributed combustors.

1301. The method of claim 1290, wherein the one or more heat sources comprise natural distributed combustors.

1302. The method of claim 1290, further comprising controlling a pressure and a temperature within at least a majority of the first section and the second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1303. The method of claim 1290, further comprising controlling the heat to the first and second sections such that an average heating rate of the first and second sections is less than about 1°

C. per day during pyrolysis.

1304. The method of claim 1290, wherein heating the first and the second sections comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1305. The method of claim 1290, wherein heating the first and second sections comprises transferring heat substantially by conduction.

1306. The method of claim 1290, wherein heating the first and second sections comprises heating the first and second sections such that a thermal conductivity of at least a portion of the first and second sections is greater than about 0.5 W/(m °

C.).

1307. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1308. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1309. The method of claim 1290, wherein the first or third mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1310. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1311. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1312. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1313. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1314. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1315. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1316. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1317. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1318. The method of claim 1290, wherein the first or third mixture comprises a non-condensable component, and wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1319. The method of claim 1290, wherein the first or third mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1320. The method of claim 1290, wherein the first or third mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1321. The method of claim 1290, further comprising controlling a pressure within at least a majority of the first or second sections of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1322. The method of claim 1290, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1323. The method of claim 1322, wherein the partial pressure of H₂ within a mixture is measured when the mixture is at a production well.

1324. The method of claim 1290, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1325. The method of claim 1290, further comprising:

providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section; and

heating a portion of the first or second section with heat from hydrogenation.

1326. The method of claim 1290, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1327. The method of claim 1290, further comprising increasing a permeability of a majority of the first or second section to greater than about 100 millidarcy.

1328. The method of claim 1290, further comprising substantially uniformly increasing a permeability of a majority of the first or second section.

1329. The method of claim 1290, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1330. The method of claim 1290, wherein producing the first or third mixture comprises producing the first or third mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1331. The method of claim 1330, wherein at least about 20 heat sources are disposed in the formation for each production well.

1332. The method of claim 1290, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1333. The method of claim 1290, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1334. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

hydrogenating a portion of the produced mixture with H₂ produced from the formation.

1335. The method of claim 1334, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1336. The method of claim 1334, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1337. The method of claim 1334, wherein the one or more heat sources comprise electrical heaters.

1338. The method of claim 1334, wherein the one or more heat sources comprise surface burners.

1339. The method of claim 1334, wherein the one or more heat sources comprise flameless distributed combustors.

1340. The method of claim 1334, wherein the one or more heat sources comprise natural distributed combustors.

1341. The method of claim 1334, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1342. The method of claim 1334, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1343. The method of claim 1334, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1344. The method of claim 1334, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1345. The method of claim 1334, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1346. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1347. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1348. The method of claim 1334, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1349. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1350. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1351. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1352. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1353. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1354. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1355. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1356. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1357. The method of claim 1334, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1358. The method of claim 1334, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1359. The method of claim 1334, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1360. The method of claim 1334, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1361. The method of claim 1334, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1362. The method of claim 1334, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1363. The method of claim 1334, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1364. The method of claim 1334, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1365. The method of claim 1334, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1366. The method of claim 1334, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1367. The method of claim 1334, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1368. The method of claim 1334, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1369. The method of claim 1368, wherein at least about 20 heat sources are disposed in the formation for each production well.

1370. The method of claim 1334, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1371. The method of claim 1334, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1372. A method of treating an oil shale formation in situ, comprising:

heating a first section of the formation;

producing H₂ from the first section of formation;

heating a second section of the formation; and

recirculating a portion of the H₂ from the first section into the second section of the formation to provide a reducing environment within the second section of the formation.

1373. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with an electrical heater.

1374. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a surface burner.

1375. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a flameless distributed combustor.

1376. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a natural distributed combustor.

1377. The method of claim 1372, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1378. The method of claim 1372, further comprising controlling the heat such that an average heating rate of the first or second section is less than about 1°

C. per day during pyrolysis.

1379. The method of claim 1372, wherein heating the first section or heating the second section further comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1380. The method of claim 1372, wherein heating the first section or heating the second section comprises transferring heat substantially by conduction.

1381. The method of claim 1372, wherein heating the first section or heating the second section comprises heating the formation such that a thermal conductivity of at least a portion of the first or second section is greater than about 0.5 W/(m °

C.).

1382. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1383. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1384. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1385. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1386. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1387. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1388. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1389. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1390. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1391. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1392. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1393. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1394. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1395. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1396. The method of claim 1372, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1397. The method of claim 1372, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1398. The method of claim 1397, wherein the partial pressure of H₂ within a mixture is measured when the mixture is at a production well.

1399. The method of claim 1372, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1400. The method of claim 1372, further comprising:

providing hydrogen (H₂) to the second section to hydrogenate hydrocarbons within the section; and

heating a portion of the second section with heat from hydrogenation.

1401. The method of claim 1372, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1402. The method of claim 1372, wherein heating the first section or heating the second section comprises increasing a permeability of a majority of the first or second section, respectively, to greater than about 100 millidarcy.

1403. The method of claim 1372, wherein heating the first section or heating the second section comprises substantially uniformly increasing a permeability of a majority of the first or second section, respectively.

1404. The method of claim 1372, further comprising controlling the heating of the first section or controlling the heat of the second section to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1405. The method of claim 1372, further comprising producing a mixture from the formation in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1406. The method of claim 1405, wherein at least about 20 heat sources are disposed in the formation for each production well.

1407. The method of claim 1372, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1408. The method of claim 1372, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1409. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

controlling formation conditions such that the mixture produced from the formation comprises condensable hydrocarbons including H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1410. The method of claim 1409, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1411. The method of claim 1409, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

1412. The method of claim 1409, wherein the one or more heat sources comprise electrical heaters.

1413. The method of claim 1409, wherein the one or more heat sources comprise surface burners.

1414. The method of claim 1409, wherein the one or more heat sources comprise flameless distributed combustors.

1415. The method of claim 1409, wherein the one or more heat sources comprise natural distributed combustors.

1416. The method of claim 1409, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1417. The method of claim 1409, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1418. The method of claim 1409, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1419. The method of claim 1409, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1420. The method of claim 1409, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1421. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1422. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1423. The method of claim 1409, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1424. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1425. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1426. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1427. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1428. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1429. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1430. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1431. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1432. The method of claim 1409, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1433. The method of claim 1409, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1434. The method of claim 1409, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1435. The method of claim 1409, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1436. The method of claim 1409, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1437. The method of claim 1409, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1438. The method of claim 1409, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1439. The method of claim 1409, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1440. The method of claim 1409, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy

1441. The method of claim 1409, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1442. The method of claim 1409, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1443. The method of claim 1409, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1444. The method of claim 1443, wherein at least about 20 heat sources are disposed in the formation for each production well.

1445. The method of claim 1409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1446. The method of claim 1409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1447. The method of claim 1409, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1448. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure of the selected section above atmospheric pressure to increase a partial pressure of H₂, as compared to the partial pressure of H₂ at atmospheric pressure, in at least a majority of the selected section; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1449. The method of claim 1448, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1450. The method of claim 1448, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1451. The method of claim 1448, wherein the one or more heat sources comprise electrical heaters.

1452. The method of claim 1448, wherein the one or more heat sources comprise surface burners.

1453. The method of claim 1448, wherein the one or more heat sources comprise flameless distributed combustors.

1454. The method of claim 1448, wherein the one or more heat sources comprise natural distributed combustors.

1455. The method of claim 1448, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1456. The method of claim 1448, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1457. The method of claim 1448, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1458. The method of claim 1448, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1459. The method of claim 1448, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1460. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1461. The method of claim 1448, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1462. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1463. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1464. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1465. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1466. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1467. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1468. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1469. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1470. The method of claim 1448, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1471. The method of claim 1448, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1472. The method of claim 1448, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1473. The method of claim 1448, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1474. The method of claim 1448, further comprising increasing the pressure of the selected section, to an upper limit of about 21 bars absolute, to increase an amount of non-condensable hydrocarbons produced from the formation.

1475. The method of claim 1448, further comprising decreasing pressure of the selected section, to a lower limit of about atmospheric pressure, to increase an amount of condensable hydrocarbons produced from the formation.

1476. The method of claim 1448, wherein a partial pressure comprises a partial pressure based on properties measured at a production well.

1477. The method of claim 1448, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1478. The method of claim 1448, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1479. The method of claim 1448, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1480. The method of claim 1448, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1481. The method of claim 1448, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1482. The method of claim 1448, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1483. The method of claim 1448, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1484. The method of claim 1448, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1485. The method of claim 1484, wherein at least about 20 heat sources are disposed in the formation for each production well.

1486. The method of claim 1448, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1487. The method of claim 1448, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1488. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing H₂ to the formation to produce a reducing environment in at least some of the formation;

producing a mixture from the formation.

1489. The method of claim 1488, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1490. The method of claim 1488, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1491. The method of claim 1488, further comprising separating a portion of hydrogen within the mixture and recirculating the portion into the formation.

1492. The method of claim 1488, wherein the one or more heat sources comprise electrical heaters.

1493. The method of claim 1488, wherein the one or more heat sources comprise surface burners.

1494. The method of claim 1488, wherein the one or more heat sources comprise flameless distributed combustors.

1495. The method of claim 1488, wherein the one or more heat sources comprise natural distributed combustors.

1496. The method of claim 1488, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1497. The method of claim 1488, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1498. The method of claim 1488, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1499. The method of claim 1488, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1500. The method of claim 1488, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1501. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1502. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1503. The method of claim 1488, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1504. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1505. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1506. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1507. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1508. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1509. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1510. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1511. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1512. The method of claim 1488, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1513. The method of claim 1488, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1514. The method of claim 1488, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1515. The method of claim 1488, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1516. The method of claim 1488, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1517. The method of claim 1488, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1518. The method of claim 1488, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1519. The method of claim 1488, wherein providing hydrogen (H₂) to the formation further comprises:

hydrogenating hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1520. The method of claim 1488, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1521. The method of claim 1488, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1522. The method of claim 1488, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1523. The method of claim 1488, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1524. The method of claim 1488, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1525. The method of claim 1524, wherein at least about 20 heat sources are disposed in the formation for each production well.

1526. The method of claim 1488, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1527. The method of claim 1488, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1528. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing H₂ to the selected section to hydrogenate hydrocarbons within the selected section and to heat a portion of the section with heat from the hydrogenation; and

controlling heating of the selected section by controlling amounts of H₂ provided to the selected section.

1529. The method of claim 1528, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1530. The method of claim 1528, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1531. The method of claim 1528, wherein the one or more heat sources comprise electrical heaters.

1532. The method of claim 1528, wherein the one or more heat sources comprise surface burners.

1533. The method of claim 1528, wherein the one or more heat sources comprise flameless distributed combustors.

1534. The method of claim 1528, wherein the one or more heat sources comprise natural distributed combustors.

1535. The method of claim 1528, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1536. The method of claim 1528, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1537. The method of claim 1528, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1538. The method of claim 1528, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1539. The method of claim 1528, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1540. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1541. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1542. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1543. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1544. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1545. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1546. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1547. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1548. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1549. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1550. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1551. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1552. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1553. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1554. The method of claim 1528, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1555. The method of claim 1528, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1556. The method of claim 1555, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1557. The method of claim 1528, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1558. The method of claim 1528, further comprising controlling formation conditions by recirculating a portion of hydrogen from a produced mixture into the formation.

1559. The method of claim 1528, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1560. The method of claim 1528, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1561. The method of claim 1528, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1562. The method of claim 1528, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1563. The method of claim 1562, wherein at least about 20 heat sources are disposed in the formation for each production well.

1564. The method of claim 1528, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1565. The method of claim 1528, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1566. An in situ method for producing H₂ from an oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein a H₂ partial pressure within the mixture is greater than about 0.5 bars.

1567. The method of claim 1566, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1568. The method of claim 1566, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1569. The method of claim 1566, wherein the one or more heat sources comprise electrical heaters.

1570. The method of claim 1566, wherein the one or more heat sources comprise surface burners.

1571. The method of claim 1566, wherein the one or more heat sources comprise flameless distributed combustors.

1572. The method of claim 1566, wherein the one or more heat sources comprise natural distributed combustors.

1573. The method of claim 1566, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1574. The method of claim 1566, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1575. The method of claim 1566, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1576. The method of claim 1566, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1577. The method of claim 1566, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1578. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1579. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1580. The method of claim 1566, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1581. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1582. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1583. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1584. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1585. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1586. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1587. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1588. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1589. The method of claim 1566, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1590. The method of claim 1566, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1591. The method of claim 1566, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1592. The method of claim 1566, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1593. The method of claim 1566, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1594. The method of claim 1566, further comprising recirculating a portion of the hydrogen within the mixture into the formation.

1595. The method of claim 1566, further comprising condensing a hydrocarbon component from the produced mixture and hydrogenating the condensed hydrocarbons with a portion of the hydrogen.

1596. The method of claim 1566, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1597. The method of claim 1566, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1598. The method of claim 1566, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1599. The method of claim 1566, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1600. The method of claim 1566, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1601. The method of claim 1600, wherein at least about 20 heat sources are disposed in the formation for each production well.

1602. The method of claim 1566, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1603. The method of claim 1566, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1604. The method of claim 1566, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1605. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic hydrogen weight percentage of at least a portion of hydrocarbons in the selected section, and wherein at least the portion of the hydrocarbons in the selected section comprises an atomic hydrogen weight percentage, when measured on a dry, ash-free basis, of greater than about 4.0%; and

producing a mixture from the formation.

1606. The method of claim 1605, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1607. The method of claim 1605, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1608. The method of claim 1605, wherein the one or more heat sources comprise electrical heaters.

1609. The method of claim 1605, wherein the one or more heat sources comprise surface burners.

1610. The method of claim 1605, wherein the one or more heat sources comprise flameless distributed combustors.

1611. The method of claim 1605, wherein the one or more heat sources comprise natural distributed combustors.

1612. The method of claim 1605, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1613. The method of claim 1605, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1614. The method of claim 1605, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1615. The method of claim 1605, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1616. The method of claim 1605, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1617. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1618. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1619. The method of claim 1605, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1620. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1621. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1622. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1623. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1624. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1625. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1626. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1627. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1628. The method of claim 1605, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1629. The method of claim 1605, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1630. The method of claim 1605, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1631. The method of claim 1605, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1632. The method of claim 1605, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1633. The method of claim 1632, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1634. The method of claim 1605, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1635. The method of claim 1605, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1636. The method of claim 1605, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1637. The method of claim 1605, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1638. The method of claim 1605, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1639. The method of claim 1605, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1640. The method of claim 1605, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1641. The method of claim 1605, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1642. The method of claim 1641, wherein at least about 20 heat sources are disposed in the formation for each production well.

1643. The method of claim 1605, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1644. The method of claim 1605, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1645. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen weight percentage of greater than about 4.0%; and

producing a mixture from the formation.

1646. The method of claim 1645, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1647. The method of claim 1645, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1648. The method of claim 1645, wherein the one or more heat sources comprise electrical heaters.

1649. The method of claim 1645, wherein the one or more heat sources comprise surface burners.

1650. The method of claim 1645, wherein the one or more heat sources comprise flameless distributed combustors.

1651. The method of claim 1645, wherein the one or more heat sources comprise natural distributed combustors.

1652. The method of claim 1645, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1653. The method of claim 1645, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1654. The method of claim 1645, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1655. The method of claim 1645, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1656. The method of claim 1645, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1657. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1658. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1659. The method of claim 1645, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1660. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1661. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1662. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1663. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1664. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1665. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1666. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1667. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1668. The method of claim 1645, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1669. The method of claim 1645, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1670. The method of claim 1645, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1671. The method of claim 1645, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1672. The method of claim 1645, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1673. The method of claim 1672, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1674. The method of claim 1645, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1675. The method of claim 1645, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1676. The method of claim 1645, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1677. The method of claim 1645, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1678. The method of claim 1645, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1679. The method of claim 1645, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1680. The method of claim 1645, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1681. The method of claim 1645, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1682. The method of claim 1681, wherein at least about 20 heat sources are disposed in the formation for each production well.

1683. The method of claim 1645, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1684. The method of claim 1645, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1685. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using vitrinite reflectance of at least some hydrocarbons in the selected section, and wherein at least a portion of the hydrocarbons in the selected section comprises a vitrinite reflectance of greater than about 0.3%;

wherein at least a portion of the hydrocarbons in the selected section comprises a vitrinite reflectance of less than about 4.5%; and

producing a mixture from the formation.

1686. The method of claim 1685, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1687. The method of claim 1685, further comprising maintaining a temperature within the selected section within a pyrolysis temperature.

1688. The method of claim 1685, wherein the vitrinite reflectance of at least the portion of hydrocarbons within the selected section is between about 0.47% and about 1.5% such that a majority of the produced mixture comprises condensable hydrocarbons.

1689. The method of claim 1685, wherein the vitrinite reflectance of at least the portion of hydrocarbons within the selected section is between about 1.4% and about 4.2% such that a majority of the produced mixture comprises non-condensable hydrocarbons.

1690. The method of claim 1685, wherein the one or more heat sources comprise electrical heaters.

1691. The method of claim 1685, wherein the one or more heat sources comprise surface burners.

1692. The method of claim 1685, wherein the one or more heat sources comprise flameless distributed combustors.

1693. The method of claim 1685, wherein the one or more heat sources comprise natural distributed combustors.

1694. The method of claim 1685, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1695. The method of claim 1685, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1696. The method of claim 1685, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1697. The method of claim 1685, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1698. The method of claim 1685, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1699. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1700. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1701. The method of claim 1685, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1702. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1703. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1704. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1705. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1706. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1707. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1708. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1709. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1710. The method of claim 1685, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1711. The method of claim 1685, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1712. The method of claim 1685, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1713. The method of claim 1685, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1714. The method of claim 1685, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1715. The method of claim 1714, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1716. The method of claim 1685, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1717. The method of claim 1685, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1718. The method of claim 1685, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1719. The method of claim 1685, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1720. The method of claim 1685, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1721. The method of claim 1685, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1722. The method of claim 1685, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1723. The method of claim 1685, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1724. The method of claim 1723, wherein at least about 20 heat sources are disposed in the formation for each production well.

1725. The method of claim 1685, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1726. The method of claim 1685, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1727. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using a total organic matter weight percentage of at least a portion of the selected section, and wherein at least the portion of the selected section comprises a total organic matter weight percentage, of at least about 5.0%; and

producing a mixture from the formation.

1728. The method of claim 1727, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1729. The method of claim 1727, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1730. The method of claim 1727, wherein the one or more heat sources comprise electrical heaters.

1731. The method of claim 1727, wherein the one or more heat sources comprise surface burners.

1732. The method of claim 1727, wherein the one or more heat sources comprise flameless distributed combustors.

1733. The method of claim 1727, wherein the one or more heat sources comprise natural distributed combustors.

1734. The method of claim 1727, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1735. The method of claim 1727, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1736. The method of claim 1727, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1737. The method of claim 1727, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1738. The method of claim 1727, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1739. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1740. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1741. The method of claim 1727, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1742. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1743. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1744. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1745. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1746. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1747. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1748. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1749. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1750. The method of claim 1727, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1751. The method of claim 1727, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1752. The method of claim 1727, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1753. The method of claim 1727, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1754. The method of claim 1727, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1755. The method of claim 1754, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1756. The method of claim 1727, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1757. The method of claim 1727, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1758. The method of claim 1727, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1759. The method of claim 1727, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1760. The method of claim 1727, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1761. The method of claim 1727, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1762. The method of claim 1727, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1763. The method of claim 1727, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1764. The method of claim 1763, wherein at least about 20 heat sources are disposed in the formation for each production well.

1765. The method of claim 1727, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1766. The method of claim 1727, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1767. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein at least some hydrocarbons within the selected section have an initial total organic matter weight percentage of at least about 5.0%; and

producing a mixture from the formation.

1768. The method of claim 1767, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1769. The method of claim 1767, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1770. The method of claim 1767, wherein the one or more heat sources comprise electrical heaters.

1771. The method of claim 1767, wherein the one or more heat sources comprise surface burners.

1772. The method of claim 1767, wherein the one or more heat sources comprise flameless distributed combustors.

1773. The method of claim 1767, wherein the one or more heat sources comprise natural distributed combustors.

1774. The method of claim 1767, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1775. The method of claim 1767, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1776. The method of claim 1767, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1777. The method of claim 1767, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1778. The method of claim 1767, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1779. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1780. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1781. The method of claim 1767, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1782. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1783. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1784. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1785. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1786. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1787. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1788. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1789. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1790. The method of claim 1767, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1791. The method of claim 1767, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1792. The method of claim 1767, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1793. The method of claim 1767, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1794. The method of claim 1767, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1795. The method of claim 1794, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1796. The method of claim 1767, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1797. The method of claim 1767, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1798. The method of claim 1767, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1799. The method of claim 1767, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1800. The method of claim 1767, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1801. The method of claim 1767, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1802. The method of claim 1767, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1803. The method of claim 1767, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1804. The method of claim 1803, wherein at least about 20 heat sources are disposed in the formation for each production well.

1805. The method of claim 1767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1806. The method of claim 1767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1807. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic oxygen weight percentage of at least a portion of hydrocarbons in the selected section, and wherein at least a portion of the hydrocarbons in the selected section comprises an atomic oxygen weight percentage of less than about 15% when measured on a dry, ash free basis; and

producing a mixture from the formation.

1808. The method of claim 1807, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1809. The method of claim 1807, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1810. The method of claim 1807, wherein the one or more heat sources comprise electrical heaters.

1811. The method of claim 1807, wherein the one or more heat sources comprise surface burners.

1812. The method of claim 1807, wherein the one or more heat sources comprise flameless distributed combustors.

1813. The method of claim 1807, wherein the one or more heat sources comprise natural distributed combustors.

1814. The method of claim 1807, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1815. The method of claim 1807, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1816. The method of claim 1807, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1817. The method of claim 1807, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1818. The method of claim 1807, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1819. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1820. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1821. The method of claim 1807, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1822. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1823. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1824. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1825. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1826. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1827. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1828. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1829. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1830. The method of claim 1807, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1831. The method of claim 1807, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia

1832. The method of claim 1807, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1833. The method of claim 1807, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1834. The method of claim 1807, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1835. The method of claim 1834, wherein the partial pressure of H₂ Within the mixture is measured when the mixture is at a production well.

1836. The method of claim 1807, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1837. The method of claim 1807, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1838. The method of claim 1807, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1839. The method of claim 1807, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1840. The method of claim 1807, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1841. The method of claim 1807, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

1842. The method of claim 1807, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1843. The method of claim 1807, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1844. The method of claim 1843, wherein at least about 20 heat sources are disposed in the formation for each production well.

1845. The method of claim 1807, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1846. The method of claim 1807, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1847. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbon within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic oxygen weight percentage of less than about 15%; and

producing a mixture from the formation.

1848. The method of claim 1847, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1849. The method of claim 1847, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range

1850. The method of claim 1847, wherein the one or more heat sources comprise electrical heaters.

1851. The method of claim 1847, wherein the one or more heat sources comprise surface burners.

1852. The method of claim 1847, wherein the one or more heat sources comprise flameless distributed combustors.

1853. The method of claim 1847, wherein the one or more heat sources comprise natural distributed combustors.

1854. The method of claim 1847, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1855. The method of claim 1847, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1856. The method of claim 1847, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1857. The method of claim 1847, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1858. The method of claim 1847, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1859. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1860. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1861. The method of claim 1847, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1862. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1863. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1864. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1865. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1866. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1867. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1868. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1869. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1870. The method of claim 1847, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1871. The method of claim 1847, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1872. The method of claim 1847, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1873. The method of claim 1847, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1874. The method of claim 1847, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1875. The method of claim 1874, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1876. The method of claim 1847, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1877. The method of claim 1847, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1878. The method of claim 1847, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1879. The method of claim 1847, further comprising:

producing hydrogen a nd condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1880. The method of claim 1847, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1881. The method of claim 1847, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1882. The method of claim 1847, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1883. The method of claim 1847, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1884. The method of claim 1883, wherein at least about 20 heat sources are disposed in the formation for each production well.

1885. The method of claim 1847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1886. The method of claim 1847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1887. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic hydrogen to carbon ratio of at least a portion of hydrocarbons in the selected section, wherein at least a portion of the hydrocarbons in the selected section comprises an atomic hydrogen to carbon ratio greater than about 0.70, and wherein the atomic hydrogen to carbon ratio is less than about 1.65; and

producing a mixture from the formation.

1888. The method of claim 1887, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1889. The method of claim 1887, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1890. The method of claim 1887, wherein the one or more heat sources comprise electrical heaters.

1891. The method of claim 1887, wherein the one or more heat sources comprise surface burners.

1892. The method of claim 1887, wherein the one or more heat sources comprise flameless distributed combustors.

1893. The method of claim 1887, wherein the one or more heat sources comprise natural distributed combustors.

1894. The method of claim 1887, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1895. The method of claim 1887, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1896. The method of claim 1887, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1897. The method of claim 1887, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1898. The method of claim 1887, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1899. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1900. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1901. The method of claim 1887, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1902. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1903. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1904. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1905. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1906. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1907. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1908. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1909. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1910. The method of claim 1887, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1911. The method of claim 1887, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1912. The method of claim 1887, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1913. The method of claim 1887, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1914. The method of claim 1887, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1915. The method of claim 1914, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1916. The method of claim 1887, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1917. The method of claim 1887, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1918. The method of claim 1887, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1919. The method of claim 1887, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1920. The method of claim 1887, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1921. The method of claim 1887, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1922. The method of claim 1887, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1923. The method of claim 1887, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1924. The method of claim 1923, wherein at least about 20 heat sources are disposed in the formation for each production well.

1925. The method of claim 1887, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1926. The method of claim 1887, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1927. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbons within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen to carbon ratio greater than about 0.70;

wherein the initial atomic hydrogen to carbon ratio is less than about 1.65; and

producing a mixture from the formation.

1928. The method of claim 1927, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1929. The method of claim 1927, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1930. The method of claim 1927, wherein the one or more heat sources comprise electrical heaters.

1931. The method of claim 1927, wherein the one or more heat sources comprise surface burners.

1932. The method of claim 1927, wherein the one or more heat sources comprise Blameless distributed combustors.

1933. The method of claim 1927, wherein the one or more heat sources comprise natural distributed combustors.

1934. The method of claim 1927, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1935. The method of claim 1927, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1936. The method of claim 1927, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1937. The method of claim 1927, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1938. The method of claim 1927, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1939. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1940. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1941. The method of claim 1927, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1942. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1943. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1944. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1945. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1946. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1947. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1948. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1949. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1950. The method of claim 1927, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1951. The method of claim 1927, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1952. The method of claim 1927, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1953. The method of claim 1927, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1954. The method of claim 1927, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1955. The method of claim 1954, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1956. The method of claim 1927, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1957. The method of claim 1927, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1958. The method of claim 1927, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1959. The method of claim 1927, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1960. The method of claim 1927, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1961. The method of claim 1927, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1962. The method of claim 1927, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1963. The method of claim 1927, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1964. The method of claim 1963, wherein at least about 20 heat sources are disposed in the formation for each production well.

1965. The method of claim 1927, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1966. The method of claim 1927, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1967. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic oxygen to carbon ratio of at least a portion of hydrocarbons in the selected section, wherein at least a portion of the hydrocarbons in the selected section comprises an atomic oxygen to carbon ratio greater than about 0.025, and wherein the atomic oxygen to carbon ratio of at least a portion of the hydrocarbons in the selected section is less than about 0.15; and

producing a mixture from the formation.

1968. The method of claim 1967, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1969. The method of claim 1967, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1970. The method of claim 1967, wherein the one or more heat sources comprise electrical heaters.

1971. The method of claim 1967, wherein the one or more heat sources comprise surface burners.

1972. The method of claim 1967, wherein the one or more heat sources comprise flameless distributed combustors.

1973. The method of claim 1967, wherein the one or more heat sources comprise natural distributed combustors.

1974. The method of claim 1967, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1975. The method of claim 1967, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

1976. The method of claim 1967, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

1977. The method of claim 1967, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

1978. The method of claim 1967, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

1979. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

1980. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1981. The method of claim 1967, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1982. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1983. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1984. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1985. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1986. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1987. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1988. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1989. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1990. The method of claim 1967, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1991. The method of claim 1967, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1992. The method of claim 1967, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1993. The method of claim 1967, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1994. The method of claim 1967, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

1995. The method of claim 1994, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

1996. The method of claim 1967, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1997. The method of claim 1967, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1998. The method of claim 1967, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1999. The method of claim 1967, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2000. The method of claim 1967, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2001. The method of claim 1967, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2002. The method of claim 1967, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2003. The method of claim 1967, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2004. The method of claim 2003, wherein at least about 20 heat sources are disposed in the formation for each production well.

2005. The method of claim 1967, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2006. The method of claim 1967, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2007. A method of treating an oil shale formation in situ, comprising providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbons within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic oxygen to carbon ratio greater than about 0.025;

wherein the initial atomic oxygen to carbon ratio is less than about 0.15; and

producing a mixture from the formation.

2008. The method of claim 2007, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2009. The method of claim 2007, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2010. The method of claim 2007, wherein the one or more heat sources comprise electrical heaters.

2011. The method of claim 2007, wherein the one or more heat sources comprise surface burners.

2012. The method of claim 2007, wherein the one or more heat sources comprise flameless distributed combustors.

2013. The method of claim 2007, wherein the one or more heat sources comprise natural distributed combustors.

2014. The method of claim 2007, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2015. The method of claim 2007, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2016. The method of claim 2007, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2017. The method of claim 2007, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2018. The method of claim 2007, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2019. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2020. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2021. The method of claim 2007, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2022. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2023. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2024. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2025. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2026. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2027. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2028. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2029. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2030. The method of claim 2007, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2031. The method of claim 2007, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2032. The method of claim 2007, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2033. The method of claim 2007, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2034. The method of claim 2007, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2035. The method of claim 2034, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2036. The method of claim 2007, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2037. The method of claim 2007, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2038. The method of claim 2007, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2039. The method of claim 2007, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2040. The method of claim 2007, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2041. The method of claim 2007, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2042. The method of claim 2007, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2043. The method of claim 2007, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2044. The method of claim 2043, wherein at least about 20 heat sources are disposed in the formation for each production well.

2045. The method of claim 2007, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2046. The method of claim 2007, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2047. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using a moisture content in the selected section, and wherein at least a portion of the selected section comprises a moisture content of less than about 15% by weight; and

producing a mixture from the formation.

2048. The method of claim 2047, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2049. The method of claim 2047, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2050. The method of claim 2047, wherein the one or more heat sources comprise electrical heaters.

2051. The method of claim 2047, wherein the one or more heat sources comprise surface burners.

2052. The method of claim 2047, wherein the one or more heat sources comprise flameless distributed combustors.

2053. The method of claim 2047, wherein the one or more heat sources comprise natural distributed combustors.

2054. The method of claim 2047, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2055. The method of claim 2047, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2056. The method of claim 2047, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2057. The method of claim 2047, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2058. The method of claim 2047, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2059. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2060. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2061. The method of claim 2047, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2062. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2063. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2064. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2065. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2066. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2067. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2068. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2069. The method of claim 2047, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2070. The method of claim 2047, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2071. The method of claim 2047, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2072. The method of claim 2047, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2073. The method of claim 2047, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2074. The method of claim 2047, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2075. The method of claim 2074, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2076. The method of claim 2047, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2077. The method of claim 2047, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2078. The method of claim 2047, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2079. The method of claim 2047, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2080. The method of claim 2047, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2081. The method of claim 2047, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2082. The method of claim 2047, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2083. The method of claim 2047, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2084. The method of claim 2083, wherein at least about 20 heat sources are disposed in the formation for each production well.

2085. The method of claim 2047, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2086. The method of claim 2047, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2087. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation;

wherein at least a portion of the selected section has an initial moisture content of less than about 15% by weight; and

producing a mixture from the formation.

2088. The method of claim 2087, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2089. The method of claim 2087, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2090. The method of claim 2087, wherein the one or more heat sources comprise electrical heaters.

2091. The method of claim 2087, wherein the one or more heat sources comprise surface burners.

2092. The method of claim 2087, wherein the one or more heat sources comprise flameless distributed combustors.

2093. The method of claim 2087, wherein the one or more heat sources comprise natural distributed combustors.

2094. The method of claim 2087, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2095. The method of claim 2087, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2096. The method of claim 2087, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2097. The method of claim 2087, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2098. The method of claim 2087, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2099. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2100. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2101. The method of claim 2087, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2102. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2103. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2104. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2105. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2106. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2107. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2108. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2109. The method of claim 2087, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2110. The method of claim 2087, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2111. The method of claim 2087, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2112. The method of claim 2087, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2113. The method of claim 2087, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2114. The method of claim 2087, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2115. The method of claim 2114, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2116. The method of claim 2087, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2117. The method of claim 2087, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2118. The method of claim 2087, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2119. The method of claim 2087, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2120. The method of claim 2087, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2121. The method of claim 2087, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2122. The method of claim 2087, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2123. The method of claim 2087, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2125. The method of claim 2087, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2126. The method of claim 2087, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2124. The method of claim 2124, wherein at least about 20 heat sources are disposed in the formation for each production well.

2127. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section is heated in a reducing environment during at least a portion of the time that the selected section is being heated; and

producing a mixture from the formation.

2128. The method of claim 2127, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2129. The method of claim 2127, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2130. The method of claim 2127, wherein the one or more heat sources comprise electrical heaters.

2131. The method of claim 2127, wherein the one or more heat sources comprise surface burners.

2132. The method of claim 2127, wherein the one or more heat sources comprise flameless distributed combustors.

2133. The method of claim 2127, wherein the one or more heat sources comprise natural distributed combustors.

2134. The method of claim 2127, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2135. The method of claim 2127, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2136. The method of claim 2127, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2137. The method of claim 2127, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2138. The method of claim 2127, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2139. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2140. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2141. The method of claim 2127, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2142. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2143. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2144. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2145. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2146. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2147. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2148. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2149. The method of claim 2127, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2150. The method of claim 2127, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2151. The method of claim 2127, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2152. The method of claim 2127, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2153. The method of claim 2127, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2154. The method of claim 2127, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2155. The method of claim 2154, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2156. The method of claim 2127, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2157. The method of claim 2127, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2158. The method of claim 2127, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2159. The method of claim 2127, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2160. The method of claim 2127, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2161. The method of claim 2127, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2162. The method of claim 2127, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2163. The method of claim 2127, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2164. The method of claim 2163, wherein at least about 20 heat sources are disposed in the formation for each production well.

2165. The method of claim 2127, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2166. The method of claim 2127, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2167. A method of treating an oil shale formation in situ, comprising:

heating a first section of the formation to produce a mixture from the formation;

heating a second section of the formation; and

recirculating a portion of the produced mixture from the first section into the second section of the formation to provide a reducing environment within the second section of the formation.

2168. The method of claim 2167, further comprising maintaining a temperature within the first section or the second section within a pyrolysis temperature range.

2169. The method of claim 2167, wherein heating the first or the second section comprises heating with an electrical heater.

2170. The method of claim 2167, wherein heating the first or the second section comprises heating with a surface burner.

2171. The method of claim 2167, wherein heating the first or the second section comprises heating with a flameless distributed combustor.

2172. The method of claim 2167, wherein heating the first or the second section comprises heating with a natural distributed combustor.

2173. The method of claim 2167, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2174. The method of claim 2167, further comprising controlling the heat such that an average heating rate of the fir st or the second section is less than about 1°

C. per day during pyrolysis.

2175. The method of claim 2167, wherein heating the first or the second section comprises:

heating a selected volume (V) of the oil shale formation from one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2176. The method of claim 2167, wherein heating the first or the second section comprises transferring heat substantially by conduction.

2177. The method of claim 2167, wherein heating the first or the second section comprises heating the first or the second section such that a thermal conductivity of at least a portion of the first or the second section is greater than about 0.5 W/(m °

C.).

2178. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2179. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2180. The method of claim 2167, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2181. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2182. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2183. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2184. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2185. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2186. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2187. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2188. The method of claim 2167, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2189. The method of claim 2167, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2190. The method of claim 2167, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2191. The method of claim 2167, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2192. The method of claim 2167, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2193. The method of claim 2167, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2194. The method of claim 2193, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2195. The method of claim 2167, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2196. The method of claim 2167, further comprising:

providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section; and

heating a portion of the first or second section with heat from hydrogenation.

2197. The method of claim 2167, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2198. The method of claim 2167, wherein heating the first or the second section comprises increasing a permeability of a majority of the first or the second section to greater than about 100 millidarcy.

2199. The method of claim 2167, wherein heating the first or the second section comprises substantially uniformly increasing a permeability of a majority of the first or the second section.

2200. The method of claim 2167, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2201. The method of claim 2167, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2202. The method of claim 2201, wherein at least about 20 heat sources are disposed in the formation for each production well.

2203. The method of claim 2167, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2204. The method of claim 2167, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2205. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation; and

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that a permeability of at least a portion of the selected section increases to greater than about 100 millidarcy.

2206. The method of claim 2205, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2207. The method of claim 2205, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2208. The method of claim 2205, wherein the one or more heat sources comprise electrical heaters.

2209. The method of claim 2205, wherein the one or more heat sources comprise surface burners.

2210. The method of claim 2205, wherein the one or more heat sources comprise flameless distributed combustors.

2211. The method of claim 2205, wherein the one or more heat sources comprise natural distributed combustors.

2212. The method of claim 2205, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2213. The method of claim 2205, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2214. The method of claim 2205, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2215. The method of claim 2205, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2216. The method of claim 2205, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2217. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2218. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2219. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2220. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2221. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2222. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2223. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2224. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2225. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2226. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2227. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2228. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2229. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2230. The method of claim 2205, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2231. The method of claim 2205, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2232. The method of claim 2205, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2233. The method of claim 2232, further comprising producing a mixture from the formation, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2234. The method of claim 2205, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2235. The method of claim 2205, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2236. The method of claim 2205, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2237. The method of claim 2205, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2238. The method of claim 2205, further comprising increasing a permeability of a majority of the selected section to greater than about 5 Darcy.

2239. The method of claim 2205, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2240. The method of claim 2205, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2241. The method of claim 2205, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2242. The method of claim 2241, wherein at least about 20 heat sources are disposed in the formation for each production well.

2243. The method of claim 2205, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2244. The method of claim 2205, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2245. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation; and

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that a permeability of a majority of at least a portion of the selected section increases substantially uniformly.

2246. The method of claim 2245, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2247. The method of claim 2245, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2248. The method of claim 2245, wherein the one or more heat sources comprise electrical heaters.

2249. The method of claim 2245, wherein the one or more heat sources comprise surface burners.

2250. The method of claim 2245, wherein the one or more heat sources comprise flameless distributed combustors.

2251. The method of claim 2245, wherein the one or more heat sources comprise natural distributed combustors.

2252. The method of claim 2245, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2253. The method of claim 2245, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2254. The method of claim 2245, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2255. The method of claim 2245, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2256. The method of claim 2245, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2257. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2258. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2259. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2260. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2261. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2262. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2263. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2264. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2265. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2266. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2267. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2268. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2269. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2270. The method of claim 2245, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2271. The method of claim 2245, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2272. The method of claim 2245, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2273. The method of claim 2245, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2274. The method of claim 2245, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2275. The method of claim 2245, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2276. The method of claim 2245, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2277. The method of claim 2245, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2278. The method of claim 2245, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2279. The method of claim 2245, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2280. The method of claim 2245, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2281. The method of claim 2280, wherein at least about 20 heat sources are disposed in the formation for each production well.

2282. The method of claim 2245, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2283. The method of claim 2245, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2284. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation; and

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that a porosity of a majority of at least a portion of the selected section increases substantially uniformly.

2285. The method of claim 2284, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2286. The method of claim 2284, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2287. The method of claim 2284, wherein the one or more heat sources comprise electrical heaters.

2288. The method of claim 2284, wherein the one or more heat sources comprise surface burners.

2289. The method of claim 2284, wherein the one or more heat sources comprise flameless distributed combustors.

2290. The method of claim 2284, wherein the one or more heat sources comprise natural distributed combustors.

2291. The method of claim 2284, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2292. The method of claim 2284, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2293. The method of claim 2284, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2294. The method of claim 2284, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2295. The method of claim 2284, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2296. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2297. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2298. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2299. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2300. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2301. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2302. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2303. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2304. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2305. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2306. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2307. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2308. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2309. The method of claim 2284, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2310. The method of claim 2284, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2311. The method of claim 2284, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2312. The method of claim 2284, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2313. The method of claim 2284, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2314. The method of claim 2284, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2315. The method of claim 2284, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2316. The method of claim 2284, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2317. The method of claim 2284, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2318. The method of claim 2284, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2319. The method of claim 2284, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2320. The method of claim 2284, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2321. The method of claim 2320, wherein at least about 20 heat sources are disposed in the formation for each production well.

2322. The method of claim 2284, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2323. The method of claim 2284, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2324. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling the heat to yield at least about 15% by weight of a total organic carbon content of at least some of the oil shale formation into condensable hydrocarbons.

2325. The method of claim 2324, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2326. The method of claim 2324, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2327. The method of claim 2324, wherein the one or more heat sources comprise electrical heaters.

2328. The method of claim 2324, wherein the one or more heat sources comprise surface burners.

2329. The method of claim 2324, wherein the one or more heat sources comprise flameless distributed combustors.

2330. The method of claim 2324, wherein the one or more heat sources comprise natural distributed combustors.

2331. The method of claim 2324, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2332. The method of claim 2324, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2333. The method of claim 2324, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2334. The method of claim 2324, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2335. The method of claim 2324, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2336. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2337. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2338. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2339. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2340. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2341. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2342. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2343. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2344. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2345. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2346. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2347. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2348. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2349. The method of claim 2324, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2350. The method of claim 2324, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2351. The method of claim 2324, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2352. The method of claim 2324, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2353. The method of claim 2324, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2354. The method of claim 2324, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2355. The method of claim 2324, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2356. The method of claim 2324, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2357. The method of claim 2324, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2358. The method of claim 2324, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2359. The method of claim 2324, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2360. The method of claim 2324, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2361. The method of claim 2360, wherein at least about 20 heat sources are disposed in the formation for each production well.

2362. The method of claim 2324, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2363. The method of claim 2324, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2364. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2365. The method of claim 2364, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2366. The method of claim 2364, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2367. The method of claim 2364, wherein the one or more heat sources comprise electrical heaters.

2368. The method of claim 2364, wherein the one or more heat sources comprise surface burners.

2369. The method of claim 2364, wherein the one or more heat sources comprise flameless distributed combustors.

2370. The method of claim 2364, wherein the one or more heat sources comprise natural distributed combustors.

2371. The method of claim 2364, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2372. The method of claim 2364, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2373. The method of claim 2364, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2374. The method of claim 2364, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2375. The method of claim 2364, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2376. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2377. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2378. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2379. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2380. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2381. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2382. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2383. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2384. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2385. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2386. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2387. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2388. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2389. The method of claim 2364, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2390. The method of claim 2364, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2391. The method of claim 2364, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2392. The method of claim 2364, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2393. The method of claim 2364, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2394. The method of claim 2364, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2395. The method of claim 2364, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2396. The method of claim 2364, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2397. The method of claim 2364, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2398. The method of claim 2364, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2399. The method of claim 2364, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2400. The method of claim 2399, wherein at least about 20 heat sources are disposed in the formation for each production well.

2401. The method of claim 2364, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2402. The method of claim 2364, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2403. A method of treating an oil shale formation in situ, comprising:

heating a first section of the formation to pyrolyze at least some hydrocarbons in the first section and produce a first mixture from the formation;

heating a second section of the formation to pyrolyze at least some hydrocarbons in the second section and produce a second mixture from the formation; and

leaving an unpyrolyzed section between the first section and the second section to inhibit subsidence of the formation.

2404. The method of claim 2403, further comprising maintaining a temperature within the first section or the second section within a pyrolysis temperature range.

2405. The method of claim 2403, wherein heating the first section or heating the second section comprises heating with an electrical heater.

2406. The method of claim 2403, wherein heating the first section or heating the second section comprises heating with a surface burner.

2407. The method of claim 2403, wherein heating the first section or heating the second section comprises heating with a flameless distributed combustor.

2408. The method of claim 2403, wherein heating the first section or heating the second section comprises heating with a natural distributed combustor.

2409. The method of claim 2403, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2410. The method of claim 2403, further comprising controlling the heat such that an average heating rate of the first or second section is less than about 1°

C. per day during pyrolysis.

2411. The method of claim 2403, wherein heating the first section or heating the second section comprises:

heating a selected volume (V) of the oil shale formation from one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2412. The method of claim 2403, wherein heating the first section or heating the second section comprises transferring heat substantially by conduction.

2413. The method of claim 2403, wherein heating the first section or heating the second section comprises heating the formation such that a thermal conductivity of at least a portion of the first or second section, respectively, is greater than about 0.5 W/(m °

C.).

2414. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2415. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2416. The method of claim 2403, wherein the first or second mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2417. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2418. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2419. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2420. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2421. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2422. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2423. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2424. The method of claim 2403, wherein the first or second mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2425. The method of claim 2403, wherein the first or second mixture comprises a non-condensable component, and wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2426. The method of claim 2403, wherein the first or second mixture comprises ammonia, and wherein greater than about 0.05% by weight of the first or second mixture is ammonia.

2427. The method of claim 2403, wherein the first or second mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2428. The method of claim 2403, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2429. The method of claim 2403, further comprising controlling formation conditions to produce the first or second mixture, wherein a partial pressure of H₂ within the first or second mixture is greater than about 0.5 bars.

2430. The method of claim 2403, wherein a partial pressure of H₂ within the first or second mixture is measured when the first or second mixture is at a production well.

2431. The method of claim 2403, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2432. The method of claim 2403, further comprising controlling formation conditions by recirculating a portion of hydrogen from the first or second mixture into the formation.

2433. The method of claim 2403, further comprising:

providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section, respectively; and

heating a portion of the first or second section, respectively, with heat from hydrogenation.

2434. The method of claim 2403, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2435. The method of claim 2403, wherein heating the first section or heating the second section comprises increasing a permeability of a majority of the first or second section, respectively, to greater than about 100 millidarcy.

2436. The method of claim 2403, wherein heating the first section or heating the second section comprises substantially uniformly increasing a permeability of a majority of the first or second section, respectively.

2437. The method of claim 2403, further comprising controlling heating of the first or second section to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay, from the first or second section, respectively.

2438. The method of claim 2403, wherein producing the first or second mixture comprises producing the first or second mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2439. The method of claim 2438, wherein at least about 20 heat sources are disposed in the formation for each production well.

2440. The method of claim 2403, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2441. The method of claim 2403, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2442. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation through one or more production wells, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2443. The method of claim 2442, wherein at least about 20 heat sources are disposed in the formation for each production well.

2444. The method of claim 2442, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2445. The method of claim 2442, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2446. The method of claim 2442, wherein the one or more heat sources comprise electrical heaters.

2447. The method of claim 2442, wherein the one or more heat sources comprise surface burners.

2448. The method of claim 2442, wherein the one or more heat sources comprise flameless distributed combustors.

2449. The method of claim 2442, wherein the one or more heat sources comprise natural distributed combustors.

2450. The method of claim 2442, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2451. The method of claim 2442, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2452. The method of claim 2442, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2453. The method of claim 2442, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2454. The method of claim 2442, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2455. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2456. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2457. The method of claim 2442, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2458. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2459. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2460. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2461. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2462. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2463. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2464. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2465. The method of claim 2442, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2466. The method of claim 2442, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2467. The method of claim 2442, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2468. The method of claim 2442, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2469. The method of claim 2442, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2470. The method of claim 2442, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2471. The method of claim 2470, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2472. The method of claim 2442, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2473. The method of claim 2442, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2474. The method of claim 2442, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2475. The method of claim 2442, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2476. The method of claim 2442, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2477. The method of claim 2442, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2478. The method of claim 2442, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2479. The method of claim 2442, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2480. The method of claim 2442, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2481. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation, wherein the one or more heat sources are disposed within one or more first wells;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation through one or more second wells, wherein one or more of the first or second wells are initially used for a first purpose and are then used for one or more other purposes.

2482. The method of claim 2481, wherein the first purpose comprises removing water from the formation, and wherein the second purpose comprises providing heat to the formation.

2483. The method of claim 2481, wherein the first purpose comprises removing water from the formation, and wherein the second purpose comprises producing the mixture.

2484. The method of claim 2481, wherein the first purpose comprises heating, and wherein the second purpose comprises removing water from the formation.

2485. The method of claim 2481, wherein the first purpose comprises producing the mixture, and wherein the second purpose comprises removing water from the formation.

2486. The method of claim 2481, wherein the one or more heat sources comprise electrical heaters.

2487. The method of claim 2481, wherein the one or more heat sources comprise surface burners.

2488. The method of claim 2481, wherein the one or more heat sources comprise flameless distributed combustors.

2489. The method of claim 2481, wherein the one or more heat sources comprise natural distributed combustors.

2490. The method of claim 2481, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2491. The method of claim 2481, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0°

C. per day during pyrolysis.

2492. The method of claim 2481, wherein providing heat from the one or more heat sources to at least the portion of the formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2493. The method of claim 2481, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2494. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2495. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2496. The method of claim 2481, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2497. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2498. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2499. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2500. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2501. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2502. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2503. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2504. The method of claim 2481, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2505. The method of claim 2481, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2506. The method of claim 2481, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2507. The method of claim 2481, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2508. The method of claim 2481, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2509. The method of claim 2481, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2510. The method of claim 2509, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

2511. The method of claim 2481, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2512. The method of claim 2481, further comprising controlling formation conditions, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

2513. The method of claim 2481, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2514. The method of claim 2481, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2515. The method of claim 2481, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2516. The method of claim 2481, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2517. The method of claim 2481, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2518. The method of claim 2481, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2519. The method of claim 2518, wherein at least about 20 heat sources are disposed in the formation for each production well.

2520. The method of claim 2481, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2521. The method of claim 2481, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2522. A method for forming heater wells in an oil shale formation, comprising:

forming a first wellbore in the formation;

forming a second wellbore in the formation using magnetic tracking such that the second wellbore is arranged substantially parallel to the first wellbore; and

providing at least one heat source within the first wellbore and at least one heat source within the second wellbore such that the heat sources can provide heat to at least a portion of the formation.

2523. The method of claim 2522, wherein superposition of heat from the at least one heat source within the first wellbore and the at least one heat source within the second wellbore pyrolyzes at least some hydrocarbons within a selected section of the formation.

2524. The method of claim 2522, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.

2525. The method of claim 2522, wherein the heat sources comprise electrical heaters.

2526. The method of claim 2522, wherein the heat sources comprise surface burners.

2527. The method of claim 2522, wherein the heat sources comprise flameless distributed combustors.

2528. The method of claim 2522, wherein the heat sources comprise natural distributed combustors.

2529. The method of claim 2522, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2530. The method of claim 2522, further comprising controlling the heat from the heat sources such that heat transferred from the heat sources to at least the portion of the hydrocarbons is less than about 1°

C. per day during pyrolysis.

2531. The method of claim 2522, further comprising:

heating a selected volume (V) of the oil shale formation from the heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2532. The method of claim 2522, further comprising allowing the heat to transfer from the heat sources to at least the portion of the formation substantially by conduction.

2533. The method of claim 2522, further comprising providing heat from the heat sources to at least the portion of the formation such that a thermal conductivity of at least the portion of the formation is greater than about 0.5 W/(m °

C.).

2534. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2535. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2536. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2537. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2538. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2539. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2540. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2541. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2542. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2543. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2544. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2545. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2546. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2547. The method of claim 2522, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2548. The method of claim 2522, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2549. The method of claim 2522, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2550. The method of claim 2522, further comprising producing a mixture from the formation, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2551. The method of claim 2522, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2552. The method of claim 2522, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2553. The method of claim 2522, further comprising:

providing hydrogen (H₂) to the portion to hydrogenate hydrocarbons within the formation; and

heating a portion of the formation with heat from hydrogenation.

2554. The method of claim 2522, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2555. The method of claim 2522, further comprising allowing heat to transfer from the heat sources to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of a selected section of the formation increases to greater than about 100 millidarcy.

2556. The method of claim 2522, further comprising allowing heat to transfer from the heat sources to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of the selected section increases substantially uniformly.

2557. The method of claim 2522, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2558. The method of claim 2522, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2559. The method of claim 2558, wherein at least about 20 heat sources are disposed in the formation for each production well.

2560. The method of claim 2522, further comprising forming a production well in the formation using magnetic tracking such that the production well is substantially parallel to the first wellbore and coupling a wellhead to the third wellbore.

2561. The method of claim 2522, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2562. The method of claim 2522, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2563. A method for installing a heater well into an oil shale formation, comprising:

forming a bore in the ground using a steerable motor and an accelerometer; and

providing a heat source within the bore such that the heat source can transfer heat to at least a portion of the formation.

2564. The method of claim 2563, further comprising installing at least two heater wells, and wherein superposition of heat from at least the two heater wells pyrolyzes at least some hydrocarbons within a selected section of the formation.

2565. The method of claim 2563, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.

2566. The method of claim 2563, wherein the heat source comprises an electrical heater.

2567. The method of claim 2563, wherein the heat source comprises a surface burner.

2568. The method of claim 2563, wherein the heat source comprises a flameless distributed combustor.

2569. The method of claim 2563, wherein the heat source comprises a natural distributed combustor.

2570. The method of claim 2563, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2571. The method of claim 2563, further comprising controlling the heat from the heat source such that heat transferred from the heat source to at least the portion of the formation is less than about 1°

C. per day during pyrolysis.

2572. The method of claim 2563, further comprising:

heating a selected volume (V) of the oil shale formation from the heat source, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2573. The method of claim 2563, further comprising allowing the heat to transfer from the heat source to at least the portion of the formation substantially by conduction.

2574. The method of claim 2563, further comprising providing heat from the heat source to at least the portion of the formation such that a thermal conductivity of at least the portion of the formation is greater than about 0.5 W/(m °

C.).

2575. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2576. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2577. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2578. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2579. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2580. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2581. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2582. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2583. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2584. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2585. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2586. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2587. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2588. The method of claim 2563, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2589. The method of claim 2563, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2590. The method of claim 2563, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2591. The method of claim 2563, wherein a partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2592. The method of claim 2563, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2593. The method of claim 2563, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2594. The method of claim 2563, further comprising:

providing hydrogen (H₂) to the at least the heated portion to hydrogenate hydrocarbons within the formation; and

heating a portion of the formation with heat from hydrogenation.

2595. The method of claim 2563, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2596. The method of claim 2563, further comprising allowing heat to transfer from the heat source to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of a selected section of the formation increases to greater than about 100 millidarcy.

2597. The method of claim 2563, further comprising allowing heat to transfer from the heat source to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of the selected section increases substantially uniformly.

2598. The method of claim 2563, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2599. The method of claim 2563, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2600. The method of claim 2599, wherein at least about 20 heat sources are disposed in the formation for each production well.

2601. The method of claim 2563, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2602. The method of claim 2563, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2603. A method for installing of wells in an oil shale formation, comprising:

forming a wellbore in the formation by geosteered drilling; and

providing a heat source within the wellbore such that the heat source can transfer heat to at least a portion of the formation.

2604. The method of claim 2603, further comprising maintaining a temperature within a selected section within a pyrolysis temperature range.

2605. The method of claim 2603, wherein the heat source comprises an electrical heater.

2606. The method of claim 2603, wherein the heat source comprises a surface burner.

2607. The method of claim 2603, wherein the heat source comprises a flameless distributed combustor.

2608. The method of claim 2603, wherein the heat source comprises a natural distributed combustor.

2609. The method of claim 2603, further comprising controlling a pressure and a temperature within at least a majority of a selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2610. The method of claim 2603, further comprising controlling the heat from the heat source such that heat transferred from the heat source to at least the portion of the formation is less than about 1°

C. per day during pyrolysis.

2611. The method of claim 2603, further comprising:

heating a selected volume (V) of the oil shale formation from the heat source, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2612. The method of claim 2603, further comprising allowing the heat to transfer from the heat source to at least the portion of the formation substantially by conduction.

2613. The method of claim 2603, further comprising providing heat from the heat source to at least the portion of the formation such that a thermal conductivity of at least the portion of the formation is greater than about 0.5 W/(m °

C.).

2614. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2615. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2616. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2617. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2618. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2619. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2620. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2621. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2622. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2623. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2624. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2625. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2626. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2627. The method of claim 2603, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2628. The method of claim 2603, further comprising controlling a pressure within at least a majority of a selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2629. The method of claim 2603, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2630. The method of claim 2629, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2631. The method of claim 2603, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2632. The method of claim 2603, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2633. The method of claim 2603, further comprising:

providing hydrogen (H₂) to at least the heated portion to hydrogenate hydrocarbons within the formation; and

heating a portion of the formation with heat from hydrogenation.

2634. The method of claim 2603, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2635. The method of claim 2603, further comprising allowing heat to transfer from the heat source to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of a selected section of the formation increases to greater than about 100 millidarcy.

2636. The method of claim 2603, further comprising allowing heat to transfer from the heat source to a selected section of the formation to pyrolyze at least some hydrocarbons within the selected section such that a permeability of a majority of the selected section increases substantially uniformly.

2637. The method of claim 2603, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2638. The method of claim 2603, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2639. The method of claim 2638, wherein at least about 20 heat sources are disposed in the formation for each production well.

2640. The method of claim 2603, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2641. The method of claim 2603, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2642. A method of treating an oil shale formation in situ, comprising:

heating a selected section of the formation with a heating element placed within a wellbore, wherein at least one end of the heating element is free to move axially within the wellbore to allow for thermal expansion of the heating element.

2643. The method of claim 2642, further comprising at least two heating elements within at least two wellbores, and wherein superposition of heat from at least the two heating elements pyrolyzes at least some hydrocarbons within a selected section of the formation.

2644. The method of claim 2642, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2645. The method of claim 2642, wherein the heating element comprises a pipe-in-pipe heater.

2646. The method of claim 2642, wherein the heating element comprises a flameless distributed combustor.

2647. The method of claim 2642, wherein the heating element comprises a mineral insulated cable coupled to a support, and wherein the support is free to move within the wellbore.

2648. The method of claim 2642, wherein the heating element comprises a mineral insulated cable suspended from a wellhead.

2649. The method of claim 2642, further comprising controlling a pressure and a temperature within at least a majority of a heated section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2650. The method of claim 2642, further comprising controlling the heat such that an average heating rate of the heated section is less than about 1°

C. per day during pyrolysis.

2651. The method of claim 2642, wherein heating the section of the formation further comprises:

heating a selected volume (V) of the oil shale formation from the heating element, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2652. The method of claim 2642, wherein heating the section of the formation comprises transferring heat substantially by conduction.

2653. The method of claim 2642, further comprising heating the selected section of the formation such that a thermal conductivity of the selected section is greater than about 0.5 W/(m °

C.).

2654. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2655. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2656. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2657. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2658. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2659. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2660. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2661. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2662. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2663. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2664. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2665. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2666. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2667. The method of claim 2642, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2668. The method of claim 2642, further comprising controlling a pressure within the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2669. The method of claim 2642, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2670. The method of claim 2669, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2671. The method of claim 2642, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2672. The method of claim 2642, further comprising producing a mixture from the formation and controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2673. The method of claim 2642, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the heated section; and

heating a portion of the section with heat from hydrogenation.

2674. The method of claim 2642, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2675. The method of claim 2642, wherein heating comprises increasing a permeability of a majority of the heated section to greater than about 100 millidarcy.

2676. The method of claim 2642, wherein heating comprises substantially uniformly increasing a permeability of a majority of the heated section.

2677. The method of claim 2642, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2678. The method of claim 2642, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2679. The method of claim 2678, wherein at least about 20 heat sources are disposed in the formation for each production well.

2680. The method of claim 2642, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2681. The method of claim 2642, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2682. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation through a production well, wherein the production well is located such that a majority of the mixture produced from the formation comprises non-condensable hydrocarbons and a non-condensable component comprising hydrogen.

2683. The method of claim 2682, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2684. The method of claim 2682, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2685. The method of claim 2682, wherein the production well is less than approximately 6 m from a heat source of the one or more heat sources.

2686. The method of claim 2682, wherein the production well is less than approximately 3 m from a heat source of the one or more heat sources.

2687. The method of claim 2682, wherein the production well is less than approximately 1.5 m from a heat source of the one or more heat sources.

2688. The method of claim 2682, wherein an additional heat source is positioned within a wellbore of the production well.

2689. The method of claim 2682, wherein the one or more heat sources comprise electrical heater.

2690. The method of claim 2682, wherein the one or more heat sources comprise surface burners.

2691. The method of claim 2682, wherein the one or more heat sources comprise flameless distributed combustors.

2692. The method of claim 2682, wherein the one or more heat sources comprise natural distributed combustors.

2693. The method of claim 2682, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2694. The method of claim 2682, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2695. The method of claim 2682, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, PB is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2696. The method of claim 2682, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

2697. The method of claim 2682, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2698. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2699. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2700. The method of claim 2682, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2701. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2702. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2703. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2704. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2705. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2706. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2707. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2708. The method of claim 2682, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2709. The method of claim 2682, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2710. The method of claim 2682, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2711. The method of claim 2682, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2712. The method of claim 2682, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2713. The method of claim 2682, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2714. The method of claim 2713, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2715. The method of claim 2682, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2716. The method of claim 2682, further comprising controlling formation conditions by recirculating a portion of the hydrogen from the mixture into the formation.

2717. The method of claim 2682, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2718. The method of claim 2682, further comprising:

producing condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2719. The method of claim 2682, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2720. The method of claim 2682, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2721. The method of claim 2682, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2722. The method of claim 2682, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2723. The method of claim 2722, wherein at least about 20 heat sources are disposed in the formation for each production well.

2724. The method of claim 2682, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2725. The method of claim 2682, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2726. A method of treating an oil shale formation in situ, comprising:

providing heat to at least a portion of the formation from one or more first heat sources placed within a pattern in the formation;

allowing the heat to transfer from the one or more first heat sources to a first section of the formation;

heating a second section of the formation with at least one second heat source, wherein the second section is located within the first section, and wherein at least the one second heat source is configured to raise an average temperature of a portion of the second section to a higher temperature than an average temperature of the first section; and

producing a mixture from the formation through a production well positioned within the second section, wherein a majority of the produced mixture comprises non-condensable hydrocarbons and a non-condensable component comprising H₂ components.

2727. The method of claim 2726, wherein the one or more first heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the first section of the formation.

2728. The method of claim 2726, further comprising maintaining a temperature within the first section within a pyrolysis temperature range.

2729. The method of claim 2726, wherein at least the one heat source comprises a heater element positioned within the production well.

2730. The method of claim 2726, wherein at least the one second heat source comprises an electrical heater.

2731. The method of claim 2726, wherein at least the one second heat source comprises a surface burner.

2732. The method of claim 2726, wherein at least the one second heat source comprises a flameless distributed combustor.

2733. The method of claim 2726, wherein at least the one second heat source comprises a natural distributed combustor.

2734. The method of claim 2726, further comprising controlling a pressure and a temperature within at least a majority of the first or the second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2735. The method of claim 2726, further comprising controlling the heat such that an average heating rate of the first section is less than about 1°

C. per day during pyrolysis.

2736. The method of claim 2726, wherein providing heat to the formation further comprises:

heating a selected volume (V) of the oil shale formation from the one or more first heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2737. The method of claim 2726, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2738. The method of claim 2726, wherein providing heat from the one or more first heat sources comprises heating the first section such that a thermal conductivity of at least a portion of the first section is greater than about 0.5 W/(m °

C.).

2739. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

2740. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2741. The method of claim 2726, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2742. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2743. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2744. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2745. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2746. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2747. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2748. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2749. The method of claim 2726, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2750. The method of claim 2726, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2751. The method of claim 2726, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2752. The method of claim 2726, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2753. The method of claim 2726, further comprising controlling a pressure within at least a majority of the first or the second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2754. The method of claim 2726, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2755. The method of claim 2754, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2756. The method of claim 2726, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2757. The method of claim 2726, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2758. The method of claim 2726, further comprising:

providing hydrogen (H₂) to the first or second section to hydrogenate hydrocarbons within the first or second section, respectively; and

heating a portion of the first or second section, respectively, with heat from hydrogenation.

2759. The method of claim 2726, further comprising:

producing condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2760. The method of claim 2726, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the first or second section to greater than about 100 millidarcy.

2761. The method of claim 2726, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the first or second section.

2762. The method of claim 2726, wherein heating the first or the second section is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2763. The method of claim 2726, wherein at least about 7 heat sources are disposed in the formation for each production well.

2764. The method of claim 2763, wherein at least about 20 heat sources are disposed in the formation for each production well.

2765. The method of claim 2726, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2766. The method of claim 2726, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2767. A method of treating an oil shale formation in situ, comprising:

providing heat into the formation from a plurality of heat sources placed in a pattern within the formation, wherein a spacing between heat sources is greater than about 6 m;

allowing the heat to transfer from the plurality of heat sources to a selected section of the formation; and

producing a mixture from the formation from a plurality of production wells, wherein the plurality of production wells are positioned within the pattern, and wherein a spacing between production wells is greater than about 12 m.

2768. The method of claim 2767, wherein superposition of heat from the plurality of heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2769. The method of claim 2767, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2770. The method of claim 2767, wherein the plurality of heat sources comprises electrical heaters.

2771. The method of claim 2767, wherein the plurality of heat sources comprises surface burners.

2772. The method of claim 2767, wherein the plurality of heat sources comprises flameless distributed combustors.

2773. The method of claim 2767, wherein the plurality of heat sources comprises natural distributed combustors.

2774. The method of claim 2767, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2775. The method of claim 2767, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

2776. The method of claim 2767, wherein providing heat from the plurality of heat sources comprises:

heating a selected volume (V) of the oil shale formation from the plurality of heat sources, wherein the formation has an average heat capacity (C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

2777. The method of claim 2767, wherein allowing the heat to transfer comprises transferring heat substantially by conduction.

2778. The method of claim 2767, wherein providing heat comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

2779. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 250.

2780. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2781. The method of claim 2767, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2782. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2783. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2784. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2785. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2786. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2787. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2788. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2789. The method of claim 2767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2790. The method of claim 2767, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2791. The method of claim 2767, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2792. The method of claim 2767, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2793. The method of claim 2767, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2794. The method of claim 2767, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H₂ within the mixture is greater than about 0.5 bars.

2795. The method of claim 2794, wherein the partial pressure of H₂ within the mixture is measured when the mixture is at a production well.

2796. The method of claim 2767, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2797. The method of claim 2767, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2798. The method of claim 2767, further comprising:

providing hydrogen (H₂) to the selected section to hydrogenate hydrocarbons within the selected section; and

heating a portion of the selected section with heat from hydrogenation.

2799. The method of claim 2767, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2800. The method of claim 2767, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2801. The method of claim 2767, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

2802. The method of claim 2767, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2803. The method of claim 2767, wherein at least about 7 heat sources are disposed in the formation for each production well.

2804. The method of claim 2803, wherein at least about 20 heat sources are disposed in the formation for each production well.

2805. The method of claim 2767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2806. The method of claim 2767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2807. A system configured to heat an oil shale formation, comprising:

a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2808. The system of claim 2807, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2809. The system of claim 2807, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

2810. The system of claim 2807, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2811. The system of claim 2807, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2812. The system of claim 2807, wherein the conduit is further configured to remove an oxidation product.

2813. The system of claim 2807, wherein the conduit is further configured to remove an oxidation product such that the oxidation product transfers substantial heat to the oxidizing fluid.

2814. The system of claim 2807, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2815. The system of claim 2807, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2816. The system of claim 2807, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2817. The system of claim 2807, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2818. The system of claim 2807, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.

2819. The system of claim 2807, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2820. The system of claim 2807, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configured to heat at least a portion of the formation during application of an electrical current to the conductor.

2821. The system of claim 2807, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configured to heat at least a portion of the formation during application of an electrical current to the insulated conductor.

2822. The system of claim 2807, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configured to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.

2823. The system of claim 2807, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat the oxidizing fluid, wherein the conduit is further configured to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configured to heat at least a portion of the formation during use.

2824. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2825. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2826. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2827. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2828. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2829. The system of claim 2807, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2830. The system of claim 2807, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2831. A system configurable to heat an oil shale formation, comprising:

a heater configurable to be disposed in an opening in the formation, wherein the heater is further configurable to provide heat to at least a portion of the formation during use;

a conduit configurable to be disposed in the opening, wherein the conduit is configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2832. The system of claim 2831, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2833. The system of claim 2831, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

2834. The system of claim 2831, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2835. The system of claim 2831, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2836. The system of claim 2831, wherein the conduit is further configurable to remove an oxidation product.

2837. The system of claim 2831, wherein the conduit is further configurable to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.

2838. The system of claim 2831, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2839. The system of claim 2831, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2840. The system of claim 2831, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2841. The system of claim 2831, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2842. The system of claim 2831, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.

2843. The system of claim 2831, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2844. The system of claim 2831, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configurable to heat at least a portion of the formation during application of an electrical current to the conductor.

2845. The system of claim 2831, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configurable to heat at least a portion of the formation during application of an electrical current to the insulated conductor.

2846. The system of claim 2831, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configurable to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.

2847. The system of claim 2831, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configurable to heat the oxidizing fluid, wherein the conduit is further configurable to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configurable to heat at least a portion of the formation during use.

2848. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2849. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2850. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2851. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2852. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2853. The system of claim 2831, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2854. The system of claim 2831, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2855. The system of claim 2831, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2856. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

2857. The method of claim 2856, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

2858. The method of claim 2856, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

2859. The method of claim 2856, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

2860. The method of claim 2856, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

2861. The method of claim 2856, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

2862. The method of claim 2856, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

2863. The method of claim 2856, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to oxidizing fluid in the conduit.

2864. The method of claim 2856, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2865. The method of claim 2856, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

2866. The method of claim 2856, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

2867. The method of claim 2856, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

2868. The method of claim 2856, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

2869. The method of claim 2856, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2870. The method of claim 2856, wherein heating the portion comprises applying electrical current to a conductor disposed in a conduit, wherein the conduit is disposed within the opening.

2871. The method of claim 2856, wherein heating the portion comprises applying electrical current to an insulated conductor disposed within the opening.

2872. The method of claim 2856, wherein heating the portion comprises applying electrical current to a t least one elongated member disposed within the opening.

2873. The method of claim 2856, wherein heating the portion comprises heating the oxidizing fluid in a heat exchanger disposed external to the formation such that providing the oxidizing fluid into the opening comprises transferring heat from the heated oxidizing fluid to the portion.

2874. The method of claim 2856, further comprising removing water from the formation prior to heating the portion.

2875. The method of claim 2856, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

2876. The method of claim 2856, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2877. The method of claim 2856, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2878. The method of claim 2856, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2879. The method of claim 2856, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2880. The method of claim 2856, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

2881. A system configured to heat an oil shale formation, comprising:

a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configured to remove an oxidation product from the formation during use; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2882. The system of claim 2881, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2883. The system of claim 2881, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

2884. The system of claim 2881, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2885. The system of claim 2881, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2886. The system of claim 2881, wherein the conduit is further configured such that the oxidation product transfers heat to the oxidizing fluid.

2887. The system of claim 2881, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2888. The system of claim 2881, wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2889. The system of claim 2881, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2890. The system of claim 2881, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2891. The system of claim 2881, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use.

2892. The system of claim 2881, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2893. The system of claim 2881, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configured to heat at least a portion of the formation during application of an electrical current to the conductor.

2894. The system of claim 2881, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configured to heat at least a portion of the formation during application of an electrical current to the insulated conductor.

2895. The system of claim 2881, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configured to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.

2896. The system of claim 2881, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat the oxidizing fluid, wherein the conduit is further configured to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configured to heat at least a portion of the formation during use.

2897. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2898. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2899. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2900. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2901. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2902. The system of claim 2881, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2903. The system of claim 2881, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2904. A system configurable to heat an oil shale formation, comprising:

a heater configurable to be disposed in an opening in the formation, wherein the heater is further configurable to provide heat to at least a portion of the formation during use;

a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configurable to remove an oxidation product from the formation during use; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone during use.

2905. The system of claim 2904, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2906. The system of claim 2904, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

2907. The system of claim 2904, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2908. The system of claim 2904, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2909. The system of claim 2904, wherein the conduit is further configurable such that the oxidation product transfers heat to the oxidizing fluid.

2910. The system of claim 2904, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2911. The system of claim 2904, wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2912. The system of claim 2904, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2913. The system of claim 2904, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2914. The system of claim 2904, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use.

2915. The system of claim 2904, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2916. The system of claim 2904, further comprising a conductor disposed in a second conduit, wherein the second conduit is disposed within the opening, and wherein the conductor is configurable to heat at least a portion of the formation during application of an electrical current to the conductor.

2917. The system of claim 2904, further comprising an insulated conductor disposed within the opening, wherein the insulated conductor is configurable to heat at least a portion of the formation during application of an electrical current to the insulated conductor.

2918. The system of claim 2904, further comprising at least one elongated member disposed within the opening, wherein the at least the one elongated member is configurable to heat at least a portion of the formation during application of an electrical current to the at least the one elongated member.

2919. The system of claim 2904, further comprising a heat exchanger disposed external to the formation, wherein the heat exchanger is configurable to heat the oxidizing fluid, wherein the conduit is further configurable to provide the heated oxidizing fluid into the opening during use, and wherein the heated oxidizing fluid is configurable to heat at least a portion of the formation during use.

2920. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2921. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2922. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2923. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2924. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2925. The system of claim 2904, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2926. The system of claim 2904, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2927. The system of claim 2904, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a heater disposed in an opening in the formation, wherein the heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone, and wherein the conduit is further configured to remove an oxidation product from the formation during use; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2928. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing gas to react with at least a portion of the hydrocarbons at the reaction zone to generate heat in the reaction zone;

removing at least a portion of an oxidation product through the opening; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

2929. The method of claim 2928, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

2930. The method of claim 2928, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

2931. The method of claim 2928, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

2932. The method of claim 2928, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially maintained within the reaction zone.

2933. The method of claim 2928, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2934. The method of claim 2928, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit.

2935. The method of claim 2928, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising transferring substantial heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

2936. The method of claim 2928, wherein a conduit is disposed within the opening, wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2937. The method of claim 2928, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

2938. The method of claim 2928, wherein a conduit is disposed within the opening, and wherein removing at least the portion of the oxidation product through the opening comprises removing at least the portion of the oxidation product through the conduit, the method further comprising substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

2939. The method of claim 2928, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

2940. The method of claim 2928, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing at least a portion of the oxidation product through the outer conduit.

2941. The method of claim 2928, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2942. The method of claim 2928, wherein heating the portion comprises applying electrical current to a conductor disposed in a conduit, wherein the conduit is disposed within the opening.

2943. The method of claim 2928, wherein heating the portion comprises applying electrical current to an insulated conductor disposed within the opening.

2944. The method of claim 2928, wherein heating the portion comprises applying electrical current to at least one elongated member disposed within the opening.

2945. The method of claim 2928, wherein heating the portion comprises heating the oxidizing fluid in a heat exchanger disposed external to the formation such that providing the oxidizing fluid into the opening comprises transferring heat from the heated oxidizing fluid to the portion.

2946. The method of claim 2928, further comprising removing water from the formation prior to heating the portion.

2947. The method of claim 2928, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

2948. The method of claim 2928, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2949. The method of claim 2928, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2950. The method of claim 2928, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2951. The method of claim 2928, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2952. The method of claim 2928, wherein the pyrolysis zone is substantially adjacent to the reaction.

2953. A system configured to heat an oil shale formation, comprising:

an electric heater disposed in an opening in the formation, wherein the electric heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2954. The system of claim 2953, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2955. The system of claim 2953, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

2956. The system of claim 2953, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2957. The system of claim 2953, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2958. The system of claim 2953, wherein the conduit is further configured to remove an oxidation product.

2959. The system of claim 2953, wherein the conduit is further configured to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.

2960. The system of claim 2953, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2961. The system of claim 2953, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2962. The system of claim 2953, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2963. The system of claim 2953, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2964. The system of claim 2953, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.

2965. The system of claim 2953, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2966. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2967. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2968. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2969. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2970. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2971. The system of claim 2953, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2972. The system of claim 2953, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2973. A system configurable to heat an oil shale formation, comprising:

an electric heater configurable to be disposed in an opening in the formation, wherein the electric heater is further configurable to provide heat to at least a portion of the formation during use, and wherein at least the portion is located substantially adjacent to the opening;

a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2974. The system of claim 2973, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2975. The system of claim 2973, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

2976. The system of claim 2973, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2977. The system of claim 2973, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

2978. The system of claim 2973, wherein the conduit is further configurable to remove an oxidation product.

2979. The system of claim 2973, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

2980. The system of claim 2973, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

2981. The system of claim 2973, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

2982. The system of claim 2973, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2983. The system of claim 2973, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

2984. The system of claim 2973, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.

2985. The system of claim 2973, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

2986. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

2987. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

2988. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

2989. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

2990. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

2991. The system of claim 2973, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

2992. The system of claim 2973, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

2993. The system of claim 2973, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

an electric heater disposed in an opening in the formation, wherein the electric heater is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2994. A system configured to heat an oil shale formation, comprising:

a conductor disposed in a first conduit, wherein the first conduit is disposed in an opening in the formation, and wherein the conductor is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a second conduit disposed in the opening, wherein the second conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

2995. The system of claim 2994, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

2996. The system of claim 2994, wherein the second conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

2997. The system of claim 2994, wherein the second conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

2998. The system of claim 2994, wherein the second conduit is further configured to be cooled with the oxidizing fluid to reduce heating of the second conduit by oxidation.

2999. The system of claim 2994, wherein the second conduit is further configured to remove an oxidation product.

3000. The system of claim 2994, wherein the second conduit is further configured to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

3001. The system of claim 2994, wherein the second conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the second conduit.

3002. The system of claim 2994, wherein the second conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the second conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3003. The system of claim 2994, wherein the second conduit is further configured to remove an oxidation product, and wherein the oxidation pro duct is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3004. The system of claim 2994, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3005. The system of claim 2994, further comprising a center conduit disposed within the second conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configured to remove an oxidation product during use.

3006. The system of claim 2994, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3007. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3008. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3009. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3010. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3011. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3012. The system of claim 2994, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3013. The system of claim 2994, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3014. A system configurable to heat an oil shale formation, comprising:

a conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed in an opening in the formation, and wherein the conductor is further configurable to provide heat to at least a portion of the formation during use;

a second conduit configurable to be disposed in the opening, wherein the second conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3015. The system of claim 3014, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3016. The system of claim 3014, wherein the second conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

3017. The system of claim 3014, wherein the second conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3018. The system of claim 3014, wherein the second conduit is further configurable to be cooled with the oxidizing fluid to reduce heating of the second conduit by oxidation.

3019. The system of claim 3014, wherein the second conduit is further configurable to remove an oxidation product.

3020. The system of claim 3014, wherein the second conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

3021. The system of claim 3014, wherein the second conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the second conduit.

3022. The system of claim 3014, wherein the second conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the second conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3023. The system of claim 3014, wherein the second conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3024. The system of claim 3014, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3025. The system of claim 3014, further comprising a center conduit disposed within the second conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configurable to remove an oxidation product during use.

3026. The system of claim 3014, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3027. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3028. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3029. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3030. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3031. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3032. The system of claim 3014, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3033. The system of claim 3014, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3034. The system of claim 3014, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conductor disposed in a first conduit, wherein the first conduit is disposed in an opening in the formation, and wherein the conductor is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a second conduit disposed in the opening, wherein the second conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3035. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to a conductor disposed in a first conduit to provide heat to the portion, and wherein the first conduit is disposed within the opening;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3036. The method of claim 3035, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3037. The method of claim 3035, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a second conduit disposed in the opening.

3038. The method of claim 3035, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a second conduit disposed in the opening such that a rate of oxidation is controlled.

3039. The method of claim 3035, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3040. The method of claim 3035, wherein a second conduit is disposed in the opening, the method further comprising cooling the second conduit with the oxidizing fluid to reduce heating of the second conduit by oxidation.

3041. The method of claim 3035, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit.

3042. The method of claim 3035, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the second conduit.

3043. The method of claim 3035, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit, wherein a flow rate of the oxidizing fluid in the second conduit is approximately equal to a flow rate of the oxidation product in the second conduit.

3044. The method of claim 3035, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the second conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the second conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3045. The method of claim 3035, wherein a second conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3046. The method of claim 3035, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3047. The method of claim 3035, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

3048. The method of claim 3035, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3049. The method of claim 3035, further comprising removing water from the formation prior to heating the portion.

3050. The method of claim 3035, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3051. The method of claim 3035, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3052. The method of claim 3035, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3053. The method of claim 3035, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3054. The method of claim 3035, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3055. A system configured to heat an oil shale formation, comprising:

an insulated conductor disposed in an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3056. The system of claim 3055, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3057. The system of claim 3055, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

3058. The system of claim 3055, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3059. The system of claim 3055, wherein the conduit is configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3060. The system of claim 3055, wherein the conduit is further configured to remove an oxidation product.

3061. The system of claim 3055, wherein the conduit is further configured to remove an oxidation product, and wherein the conduit is further configured such that the oxidation product transfers substantial heat to the oxidizing fluid.

3062. The system of claim 3055, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3063. The system of claim 3055, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the second conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3064. The system of claim 3055, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3065. The system of claim 3055, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3066. The system of claim 3055, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.

3067. The system of claim 3055, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3068. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3069. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3070. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3071. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3072. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3073. The system of claim 3055, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3074. The system of claim 3055, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3075. A system configurable to heat an oil shale formation, comprising:

an insulated conductor configurable to be disposed in an opening in the formation, wherein the insulated conductor is further configurable to provide heat to at least a portion of the formation during use;

a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from an oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3076. The system of claim 3075, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3077. The system of claim 3075, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

3078. The system of claim 3075, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3079. The system of claim 3075, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3080. The system of claim 3075, wherein the conduit is further configurable to remove an oxidation product.

3081. The system of claim 3075, wherein the conduit is further configurable to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.

3082. The system of claim 3075, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3083. The system of claim 3075, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3084. The system of claim 3075, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3085. The system of claim 3075, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3086. The system of claim 3075, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.

3087. The system of claim 3075, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3088. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3089. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3090. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3091. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3092. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3093. The system of claim 3075, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3094. The system of claim 3075, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3095. The system of claim 3075, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

an insulated conductor disposed in an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3096. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to an insulated conductor to provide heat to the portion, and wherein the insulated conductor is disposed within the opening;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3097. The method of claim 3096, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3098. The method of claim 3096, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

3099. The method of claim 3096, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

3100. The method of claim 3096, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3101. The method of claim 3096, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

3102. The method of claim 3096, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

3103. The method of claim 3096, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

3104. The method of claim 3096, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3105. The method of claim 3096, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3106. The method of claim 3096, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3107. The method of claim 3096, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3108. The method of claim 3096, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

3109. The method of claim 3096, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3110. The method of claim 3096, further comprising removing water from the formation prior to heating the portion.

3111. The method of claim 3096, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3112. The method of claim 3096, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3113. The method of claim 3096, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3114. The method of claim 3096, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3115. The method of claim 3096, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3116. The method of claim 3096, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

3117. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation, wherein heating comprises applying an electrical current to an insulated conductor to provide heat to the portion, wherein the insulated conductor is coupled to a conduit, wherein the conduit comprises critical flow orifices, and wherein the conduit is disposed within the opening;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3118. The method of claim 3117, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3119. The method of claim 3117, further comprising controlling a flow of the oxidizing fluid with the critical flow orifices such that a rate of oxidation is controlled.

3120. The method of claim 3117, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3121. The method of claim 3117, further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

3122. The method of claim 3117, further comprising removing an oxidation product from the formation through the conduit.

3123. The method of claim 3117, further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

3124. The method of claim 3117, further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3125. The method of claim 3117, further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3126. The method of claim 3117, further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3127. The method of claim 3117, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3128. The method of claim 3117, wherein a center conduit is disposed within the conduit, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the conduit.

3129. The method of claim 3117, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3130. The method of claim 3117, further comprising removing water from the formation prior to heating the portion.

3131. The method of claim 3117, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3132. The method of claim 3117, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3133. The method of claim 3117, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3134. The method of claim 3117, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3135. The method of claim 3117, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3136. The method of claim 3117, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

3137. A system configured to heat an oil shale formation, comprising:

at least one elongated member disposed in an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3138. The system of claim 3137, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3139. The system of claim 3137, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

3140. The system of claim 3137, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3141. The system of claim 3137, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3142. The system of claim 3137, wherein the conduit is further configured to remove an oxidation product.

3143. The system of claim 3137, wherein the conduit is further configured to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

3144. The system of claim 3137, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3145. The system of claim 3137, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3146. The system of claim 3137, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3147. The system of claim 3137, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3148. The system of claim 3137, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.

3149. The system of claim 3137, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3150. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3151. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3152. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3153. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3154. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3155. The system of claim 3137, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3156. The system of claim 3137, wherein the system is further configured such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3157. A system configurable to heat an oil shale formation, comprising:

at least one elongated member configurable to be disposed in an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use;

a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the system is configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3158. The system of claim 3157, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3159. The system of claim 3157, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

3160. The system of claim 3157, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3161. The system of claim 3157, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3162. The system of claim 3157, wherein the conduit is further configurable to remove an oxidation product.

3163. The system of claim 3157, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

3164. The system of claim 3157, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3165. The system of claim 3157, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3166. The system of claim 3157, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3167. The system of claim 3157, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3168. The system of claim 3157, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configurable to remove an oxidation product during use.

3169. The system of claim 3157, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3170. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3171. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3172. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3173. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3174. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3175. The system of claim 3157, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3176. The system of claim 3157, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

3177. The system of claim 3157, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

at least one elongated member disposed in an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed in the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to a reaction zone in the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at the reaction zone during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3178. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises applying an electrical current to at least one elongated member to provide heat to the portion, and wherein at least the one elongated member is disposed within the opening;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3179. The method of claim 3178, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3180. The method of claim 3178, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

3181. The method of claim 3178, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

3182. The method of claim 3178, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3183. The method of claim 3178, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

3184. The method of claim 3178, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

3185. The method of claim 3178, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

3186. The method of claim 3178, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3187. The method of claim 3178, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3188. The method of claim 3178, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3189. The method of claim 3178, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3190. The method of claim 3178, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

3191. The method of claim 3178, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3192. The method of claim 3178, further comprising removing water from the formation prior to heating the portion.

3193. The method of claim 3178, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3194. The method of claim 3178, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3195. The method of claim 3178, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3196. The method of claim 3178, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3197. The method of claim 3178, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3198. The method of claim 3178, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

3199. A system configured to heat an oil shale formation, comprising:

a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat an oxidizing fluid during use;

a conduit disposed in the opening, wherein the conduit is configured to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configured to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3200. The system of claim 3199, wherein the oxidizing fluid is configured to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3201. The system of claim 3199, wherein the conduit comprises orifices, and wherein the orifices are configured to provide the oxidizing fluid into the opening.

3202. The system of claim 3199, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configured to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3203. The system of claim 3199, wherein the conduit is further configured to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3204. The system of claim 3199, wherein the conduit is further configured to remove an oxidation product.

3205. The system of claim 3199, wherein the conduit is further configured to remove an oxidation product, such that the oxidation product transfers heat to the oxidizing fluid.

3206. The system of claim 3199, wherein the conduit is further configured to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3207. The system of claim 3199, wherein the conduit is further configured to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3208. The system of claim 3199, wherein the conduit is further configured to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3209. The system of claim 3199, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3210. The system of claim 3199, further comprising a center conduit disposed within the conduit, wherein the center conduit is configured to provide the oxidizing fluid into the opening during use, and wherein the conduit is further configured to remove an oxidation product during use.

3211. The system of claim 3199, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3212. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3213. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3214. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3215. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3216. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3217. The system of claim 3199, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3218. A system configurable to heat an oil shale formation, comprising:

a heat exchanger configurable to be disposed external to the formation, wherein the heat exchanger is further configurable to heat an oxidizing fluid during use;

a conduit configurable to be disposed in the opening, wherein the conduit is further configurable to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configurable to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the system is further configurable to allow the oxidizing fluid to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and

wherein the system is further configurable to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3219. The system of claim 3218, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

3220. The system of claim 3218, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening.

3221. The system of claim 3218, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled.

3222. The system of claim 3218, wherein the conduit is further configurable to be cooled with the oxidizing fluid such that the conduit is not substantially heated by oxidation.

3223. The system of claim 3218, wherein the conduit is further configurable to remove an oxidation product.

3224. The system of claim 3218, wherein the conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid.

3225. The system of claim 3218, wherein the conduit is further configurable to remove an oxidation product, and wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3226. The system of claim 3218, wherein the conduit is further configurable to remove an oxidation product, and wherein a pressure of the oxidizing fluid in the conduit and a pressure of the oxidation product in the conduit are controlled to reduce contamination of the oxidation product by the oxidizing fluid.

3227. The system of claim 3218, wherein the conduit is further configurable to remove an oxidation product, and wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3228. The system of claim 3218, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone.

3229. The system of claim 3218, further comprising a center conduit disposed within the conduit, wherein the center conduit is configurable to provide the oxidizing fluid into the opening during use, and wherein the second conduit is further configurable to remove an oxidation product during use.

3230. The system of claim 3218, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3231. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3232. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3233. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3234. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3235. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3236. The system of claim 3218, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3237. The system of claim 3218, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a heat exchanger disposed external to the formation, wherein the heat exchanger is configured to heat an oxidizing fluid during use;

a conduit disposed in the opening, wherein the conduit is configured to provide the heated oxidizing fluid from the heat exchanger to at least a portion of the formation during use, wherein the system is configured to allow heat to transfer from the heated oxidizing fluid to at least the portion of the formation during use, and wherein the oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone in the formation during use such that heat is generated at the reaction zone; and

wherein the system is configured to allow heat to transfer substantially by conduction from the reaction zone to a pyrolysis zone of the formation during use.

3238. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises;

heating the oxidizing fluid with a heat exchanger, wherein the heat exchanger is disposed external to the formation;

providing the heated oxidizing fluid from the heat exchanger to the portion of the formation;

allowing heat to transfer from the heated oxidizing fluid to the portion of the formation;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3239. The method of claim 3238, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3240. The method of claim 3238, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

3241. The method of claim 3238, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

3242. The method of claim 3238, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3243. The method of claim 3238, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

3244. The method of claim 3238, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

3245. The method of claim 3238, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

3246. The method of claim 3238, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3247. The method of claim 3238, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3248. The method of claim 3238, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3249. The method of claim 3238, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3250. The method of claim 3238, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

3251. The method of claim 3238, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3252. The method of claim 3238, further comprising removing water from the formation prior to heating the portion.

3253. The method of claim 3238, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3254. The method of claim 3238, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3255. The method of claim 3238, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3256. The method of claim 3238, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3257. The method of claim 3238, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3258. The method of claim 3238, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

3259. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein heating comprises;

oxidizing a fuel gas in a heater, wherein the heater is disposed external to the formation;

providing the oxidized fuel gas from the heater to the portion of the formation;

allowing heat to transfer from the oxidized fuel gas to the portion of the formation;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons at the reaction zone to generate heat at the reaction zone; and

transferring the generated heat substantially by conduction from the reaction zone to a pyrolysis zone in the formation.

3260. The method of claim 3259, further comprising transporting the oxidizing fluid through the reaction zone by diffusion.

3261. The method of claim 3259, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

3262. The method of claim 3259, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

3263. The method of claim 3259, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

3264. The method of claim 3259, wherein a conduit is disposed in the opening, the method further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

3265. The method of claim 3259, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

3266. The method of claim 3259, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

3267. The method of claim 3259, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

3268. The method of claim 3259, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

3269. The method of claim 3259, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

3270. The method of claim 3259, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

3271. The method of claim 3259, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

3272. The method of claim 3259, wherein the portion of the formation extends radially from the opening a width of less than approximately 0.2 m.

3273. The method of claim 3259, further comprising removing water from the formation prior to heating the portion.

3274. The method of claim 3259, further comprising controlling the temperature of the formation to substantially inhibit production of oxides of nitrogen during oxidation.

3275. The method of claim 3259, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3276. The method of claim 3259, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3277. The method of claim 3259, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3278. The method of claim 3259, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

3279. The method of claim 3259, wherein the pyrolysis zone is substantially adjacent to the reaction zone.

3280. A system configured to heat an oil shale formation, comprising:

an insulated conductor disposed within an open wellbore in the formation, wherein the insulated conductor is configured to provide radiant heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3281. The system of claim 3280, wherein the insulated conductor is further configured to generate heat during application of an electrical current to the insulated conductor during use.

3282. The system of claim 3280, further comprising a support member, wherein the support member is configured to support the insulated conductor.

3283. The system of claim 3280, further comprising a support member and a centralizer, wherein the support member is configured to support the insulated conductor, and wherein the centralizer is configured to maintain a location of the insulated conductor on the support member.

3284. The system of claim 3280, wherein the open wellbore comprises a diameter of at least approximately 5 cm.

3285. The system of claim 3280, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3286. The system of claim 3280, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.

3287. The system of claim 3280, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.

3288. The system of claim 3280, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.

3289. The system of claim 3280, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3290. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.

3291. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3292. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3293. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3294. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3295. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3296. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3297. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3298. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3299. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3300. The system of claim 3280, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3301. The system of claim 3280, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configured in a 3-phase Y configuration.

3302. The system of claim 3280, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a series electrical configuration.

3303. The system of claim 3280, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a parallel electrical configuration.

3304. The system of claim 3280, wherein the insulated conductor is configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.

3305. The system of claim 3280, further comprising a support member configured to support the insulated conductor, wherein the support member comprises orifices configured to provide fluid flow through the support member into the open wellbore during use.

3306. The system of claim 3280, further comprising a support member configured to support the insulated conductor, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.

3307. The system of claim 3280, further comprising a tube coupled to the insulated conductor, wherein the tube is configured to provide a flow of fluid into the open wellbore during use.

3308. The system of claim 3280, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.

3309. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.

3310. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3311. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3312. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the open wellbore.

3313. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material is configured to substantially inhibit a flow of fluid between the open wellbore and the overburden casing during use.

3314. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material comprises cement.

3315. The system of claim 3280, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.

3316. The system of claim 3280, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some of the hydrocarbons in the selected section.

3317. A system configurable to heat an oil shale formation, comprising:

an insulated conductor configurable to be disposed within an open wellbore in the formation, wherein the insulated conductor is further configurable to provide radiant heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3318. The system of claim 3317, wherein the insulated conductor is further configurable to generate heat during application of an electrical current to the insulated conductor during use.

3319. The system of claim 3317, further comprising a support member, wherein the support member is configurable to support the insulated conductor.

3320. The system of claim 3317, further comprising a support member and a centralizer, wherein the support member is configurable to support the insulated conductor, and wherein the centralizer is configurable to maintain a location of the insulated conductor on the support member.

3321. The system of claim 3317, wherein the open wellbore comprises a diameter of at least approximately 5 cm.

3322. The system of claim 3317, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3323. The system of claim 3317, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.

3324. The system of claim 3317, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.

3325. The system of claim 3317, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.

3326. The system of claim 3317, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3327. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.

3328. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3329. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3330. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3331. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3332. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3333. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3334. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3335. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.

3336. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3337. The system of claim 3317, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3338. The system of claim 3317, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configurable in a 3-phase Y configuration.

3339. The system of claim 3317, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a series electrical configuration.

3340. The system of claim 3317, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a parallel electrical configuration.

3341. The system of claim 3317, wherein the insulated conductor is configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.

3342. The system of claim 3317, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the open wellbore during use.

3343. The system of claim 3317, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.

3344. The system of claim 3317, further comprising a tube coupled to the insulated conductor, wherein the tube is configurable to provide a flow of fluid into the open wellbore during use.

3345. The system of claim 3317, further comprising a tube coupled to the first insulated conductor, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the open wellbore during use.

3346. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.

3347. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3348. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3349. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a function of the overburden casing and the open wellbore.

3350. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the open wellbore and the overburden casing during use.

3351. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the open wellbore, and wherein the packing material comprises cement.

3352. The system of claim 3317, further comprising an overburden casing coupled to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.

3353. The system of claim 3317, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

3354. The system of claim 3317, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

an insulated conductor disposed within an open wellbore in the formation, wherein the insulated conductor is configured to provide radiant heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3355. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to an insulated conductor to provide radiant heat to at least a portion of the formation, wherein the insulated conductor is disposed within an open wellbore in the formation; and

allowing the radiant heat to transfer from the insulated conductor to a selected section of the formation.

3356. The method of claim 3355, further comprising supporting the insulated conductor on a support member.

3357. The method of claim 3355, farther comprising supporting the insulated conductor on a support member and maintaining a location of the insulated conductor on the support member with a centralizer.

3358. The method of claim 3355, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the open wellbore, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.

3359. The method of claim 3355, wherein an additional insulated conductor is disposed within the open wellbore.

3360. The method of claim 3355, wherein an additional insulated conductor is disposed within the open wellbore, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.

3361. The method of claim 3355, wherein an additional insulated conductor is disposed within the open wellbore, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.

3362. The method of claim 3355, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.

3363. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3364. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3365. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3366. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3367. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3368. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3369. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3370. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3371. The method of claim 3355, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3372. The method of claim 3355, further comprising supporting the insulated conductor on a support member and flowing a fluid into the open wellbore through an orifice in the support member.

3373. The method of claim 3355, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the open wellbore through critical flow orifices in the support member.

3374. The method of claim 3355, wherein a perforated tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a fluid into the open wellbore through the perforated tube.

3375. The method of claim 3355, wherein a tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the open wellbore through critical flow orifices in the tube.

3376. The method of claim 3355, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the open wellbore through an orifice in the support member.

3377. The method of claim 3355, wherein a perforated tube is disposed in the open wellbore proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the open wellbore through the perforated tube.

3378. The method of claim 3355, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.

3379. The method of claim 3355, further comprising monitoring a leakage current of the insulated conductor.

3380. The method of claim 3355, further comprising monitoring the applied electrical current.

3381. The method of claim 3355, further comprising monitoring a voltage applied to the insulated conductor.

3382. The method of claim 3355, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.

3383. The method of claim 3355, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3384. The method of claim 3355, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.

3385. The method of claim 3355, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3386. The method of claim 3355, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation.

3387. The method of claim 3355, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3388. The method of claim 3355, farther comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3389. The method of claim 3355, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the open wellbore.

3390. The method of claim 3355, further comprising coupling an overburden casing to the open wellbore, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the open wellbore and the overburden casing with a packing material.

3391. The method of claim 3355, further comprising heating at least the portion of the formation to pyrolyze at least some hydrocarbons within the formation.

3392. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to an insulated conductor to provide heat to at least a portion of the formation, wherein the insulated conductor is disposed within an opening in the formation; and

allowing the heat to transfer from the insulated conductor to a section of the formation.

3393. The method of claim 3392, further comprising supporting the insulated conductor on a support member.

3394. The method of claim 3392, further comprising supporting the insulated conductor on a support member and maintaining a location of the first insulated conductor on the support member with a centralizer.

3395. The method of claim 3392, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the opening, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.

3396. The method of claim 3392, wherein an additional insulated conductor is disposed within the opening.

3397. The method of claim 3392, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.

3398. The method of claim 3392, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.

3399. The method of claim 3392, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.

3400. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3401. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3402. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3403. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3404. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3405. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3406. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3407. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3408. The method of claim 3392, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3409. The method of claim 3392, further comprising supporting the insulated conductor on a support member and flowing a fluid into the opening through an orifice in the support member.

3410. The method of claim 3392, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.

3411. The method of claim 3392, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a fluid into the opening through the perforated tube.

3412. The method of claim 3392, wherein a tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.

3413. The method of claim 3392, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.

3414. The method of claim 3392, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.

3415. The method of claim 3392, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.

3416. The method of claim 3392, further comprising monitoring a leakage current of the insulated conductor.

3417. The method of claim 3392, further comprising monitoring the applied electrical current.

3418. The method of claim 3392, further comprising monitoring a voltage applied to the insulated conductor.

3419. The method of claim 3392, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.

3420. The method of claim 3392, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3421. The method of claim 3392, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.

3422. The method of claim 3392, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3423. The method of claim 3392, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3424. The method of claim 3392, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3425. The method of claim 3392, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3426. The method of claim 3392, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3427. The method of claim 3392, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3428. The method of claim 3392, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

3429. A system configured to heat an oil shale formation, comprising:

an insulated conductor disposed within an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight; and

wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3430. The system of claim 3429, wherein the insulated conductor is further configured to generate heat during application of an electrical current to the insulated conductor during use.

3431. The system of claim 3429, further comprising a support member, wherein the support member is configured to support the insulated conductor.

3432. The system of claim 3429, further comprising a support member and a centralizer, wherein the support member is configured to support the insulated conductor, and wherein the centralizer is configured to maintain a location of the insulated conductor on the support member.

3433. The system of claim 3429, wherein the opening comprises a diameter of at least approximately 5 cm.

3434. The system of claim 3429, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3435. The system of claim 3429, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.

3436. The system of claim 3429, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.

3437. The system of claim 3429, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.

3438. The system of claim 3429, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3439. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3440. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3441. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3442. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3443. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3444. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3445. The system of claim 3429, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3446. The system of claim 3429, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configured in a 3-phase Y configuration.

3447. The system of claim 3429, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a series electrical configuration.

3448. The system of claim 3429, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configured in a parallel electrical configuration.

3449. The system of claim 3429, wherein the insulated conductor is configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.

3450. The system of claim 3429, further comprising a support member configured to support the insulated conductor, wherein the support member comprises orifices configured to provide fluid flow through the support member into the opening during use.

3451. The system of claim 3429, further comprising a support member configured to support the insulated conductor, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3452. The system of claim 3429, further comprising a tube coupled to the insulated conductor, wherein the tube is configured to provide a flow of fluid into the opening during use.

3453. The system of claim 3429, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3454. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3455. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3456. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3457. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3458. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3459. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3460. The system of claim 3429, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.

3461. The system of claim 3429, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

3462. A system configurable to heat an oil shale formation, comprising:

an insulated conductor configurable to be disposed within an opening in the formation, wherein the insulated conductor is further configurable to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight;

wherein the system is configurable to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3463. The system of claim 3462, wherein the insulated conductor is further configurable to generate heat during application of an electrical current to the insulated conductor during use.

3464. The system of claim 3462, further comprising a support member, wherein the support member is configurable to support the insulated conductor.

3465. The system of claim 3462, further comprising a support member and a centralizer, wherein the support member is configurable to support the insulated conductor, and wherein the centralizer is configurable to maintain a location of the insulated conductor on the support member.

3466. The system of claim 3462, wherein the opening comprises a diameter of at least approximately 5 cm.

3467. The system of claim 3462, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3468. The system of claim 3462, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a rubber insulated conductor.

3469. The system of claim 3462, further comprising a lead-in conductor coupled to the insulated conductor, wherein the lead-in conductor comprises a copper wire.

3470. The system of claim 3462, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor.

3471. The system of claim 3462, further comprising a lead-in conductor coupled to the insulated conductor with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3472. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3473. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3474. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3475. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3476. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.

3477. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3478. The system of claim 3462, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3479. The system of claim 3462, further comprising two additional insulated conductors, wherein the insulated conductor and the two additional insulated conductors are configurable in a 3-phase Y configuration.

3480. The system of claim 3462, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a series electrical configuration.

3481. The system of claim 3462, further comprising an additional insulated conductor, wherein the insulated conductor and the additional insulated conductor are coupled to a support member, and wherein the insulated conductor and the additional insulated conductor are configurable in a parallel electrical configuration.

3482. The system of claim 3462, wherein the insulated conductor is configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.

3483. The system of claim 3462, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the open wellbore during use.

3484. The system of claim 3462, further comprising a support member configurable to support the insulated conductor, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3485. The system of claim 3462, further comprising a tube coupled to the insulated conductor, wherein the tube is configurable to provide a flow of fluid into the opening during use.

3486. The system of claim 3462, further comprising a tube coupled to the insulated conductor, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3487. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3488. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3489. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3490. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3491. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3492. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3493. The system of claim 3462, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.

3494. The system of claim 3462, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

3495. The system of claim 3462, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

an insulated conductor disposed within an opening in the formation, wherein the insulated conductor is configured to provide heat to at least a portion of the formation during use, wherein the insulated conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight; and

wherein the system is configured to allow heat to transfer from the insulated conductor to a selected section of the formation during use.

3496. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to an insulated conductor to provide heat to at least a portion of the formation, wherein the insulated conductor is disposed within an opening in the formation, and wherein the insulated conductor comprises a copper-nickel alloy of approximately 7% nickel by weight to approximately 12% nickel by weight; and

allowing the heat to transfer from the insulated conductor to a selected section of the formation.

3497. The method of claim 3496, further comprising supporting the insulated conductor on a support member.

3498. The method of claim 3496, further comprising supporting the insulated conductor on a support member and maintaining a location of the first insulated conductor on the support member with a centralizer.

3499. The method of claim 3496, wherein the insulated conductor is coupled to two additional insulated conductors, wherein the insulated conductor and the two insulated conductors are disposed within the opening, and wherein the three insulated conductors are electrically coupled in a 3-phase Y configuration.

3500. The method of claim 3496, wherein an additional insulated conductor is disposed within the opening.

3501. The method of claim 3496, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a series configuration.

3502. The method of claim 3496, wherein an additional insulated conductor is disposed within the opening, and wherein the insulated conductor and the additional insulated conductor are electrically coupled in a parallel configuration.

3503. The method of claim 3496, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.

3504. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material.

3505. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3506. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3507. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3508. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3509. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3510. The method of claim 3496, wherein the copper-nickel alloy is disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3511. The method of claim 3496, further comprising supporting the insulated conductor on a support member and flowing a fluid into the opening through an orifice in the support member.

3512. The method of claim 3496, further comprising supporting the insulated conductor on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.

3513. The method of claim 3496, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a fluid into the opening through the perforated tube.

3514. The method of claim 3496, wherein a tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.

3515. The method of claim 3496, further comprising supporting the insulated conductor on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.

3516. The method of claim 3496, wherein a perforated tube is disposed in the opening proximate to the insulated conductor, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.

3517. The method of claim 3496, further comprising determining a temperature distribution in the insulated conductor using an electromagnetic signal provided to the insulated conductor.

3518. The method of claim 3496, further comprising monitoring a leakage current of the insulated conductor.

3519. The method of claim 3496, further comprising monitoring the applied electrical current.

3520. The method of claim 3496, further comprising monitoring a voltage applied to the insulated conductor.

3521. The method of claim 3496, further comprising monitoring a temperature in the insulated conductor with at least one thermocouple.

3522. The method of claim 3496, further comprising electrically coupling a lead-in conductor to the insulated conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3523. The method of claim 3496, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor.

3524. The method of claim 3496, further comprising electrically coupling a lead-in conductor to the insulated conductor using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3525. The method of claim 3496, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3526. The method of claim 3496, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3527. The method of claim 3496, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3528. The method of claim 3496, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3529. The method of claim 3496, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3530. The method of claim 3496, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

3531. A system configured to heat an oil shale formation, comprising:

at least three insulated conductors disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.

3532. The system of claim 3531, wherein at least the three insulated conductors are further configured to generate heat during application of an electrical current to at least the three insulated conductors during use.

3533. The system of claim 3531, further comprising a support member, wherein the support member is configured to support at least the three insulated conductors.

3534. The system of claim 3531, further comprising a support member and a centralizer, wherein the support member is configured to support at least the three insulated conductors, and wherein the centralizer is configured to maintain a location of at least the three insulated conductors on the support member.

3535. The system of claim 3531, wherein the opening comprises a diameter of at least approximately 5 cm.

3536. The system of claim 3531, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3537. The system of claim 3531, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a rubber insulated conductor.

3538. The system of claim 3531, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a copper wire.

3539. The system of claim 3531, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor.

3540. The system of claim 3531, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3541. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.

3542. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3543. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3544. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3545. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3546. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3547. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3548. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3549. The system of claim 3531, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3550. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3551. The system of claim 3531, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3552. The system of claim 3531, wherein at least the three insulated conductors are configured to generate radiant heat of approximately 500 W/m to approximately 1150 W/m of at least the three insulated conductors during use.

3553. The system of claim 3531, further comprising a support member configured to support at least the three insulated conductors, wherein the support member comprises orifices configured to provide fluid flow through the support member into the opening during use.

3554. The system of claim 3531, further comprising a support member configured to support at least the three insulated conductors, wherein the support member comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3555. The system of claim 3531, further comprising a tube coupled to at least the three insulated conductors, wherein the tube is configured to provide a flow of fluid into the opening during use.

3556. The system of claim 3531, further comprising a tube coupled to at least the three insulated conductors, wherein the tube comprises critical flow orifices configured to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3557. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation

3558. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3559. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3560. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3561. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3562. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3563. The system of claim 3531, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configured to couple to the lead-in conductor.

3564. The system of claim 3531, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

3565. A system configurable to heat an oil shale formation, comprising:

at least three insulated conductors configurable to be disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are further configurable to provide heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.

3566. The system of claim 3565, wherein at least the three insulated conductors are further configurable to generate heat during application of an electrical current to at least the three insulated conductors during use.

3567. The system of claim 3565, further comprising a support member, wherein the support member is configurable to support at least the three insulated conductors.

3568. The system of claim 3565, further comprising a support member and a centralizer, wherein the support member is configurable to support at least the three insulated conductors, and wherein the centralizer is configurable to maintain a location of at least the three insulated conductors on the support member.

3569. The system of claim 3565, wherein the opening comprises a diameter of at least approximately 5 cm.

3570. The system of claim 3565, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3571. The system of claim 3565, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a rubber insulated conductor.

3572. The system of claim 3565, further comprising at least one lead-in conductor coupled to at least the three insulated conductors, wherein at least the one lead-in conductor comprises a copper wire.

3573. The system of claim 3565, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor.

3574. The system of claim 3565, further comprising at least one lead-in conductor coupled to at least the three insulated conductors with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3575. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath.

3576. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3577. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3578. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3579. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises a thermally conductive material.

3580. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3581. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3582. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3583. The system of claim 3565, wherein the insulated conductor comprises a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configurable to occupy porous spaces within the magnesium oxide.

3584. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3585. The system of claim 3565, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3586. The system of claim 3565, wherein at least the three insulated conductors are configurable to generate radiant heat of approximately 500 W/m to approximately 1150 W/m during use.

3587. The system of claim 3565, further comprising a support member configurable to support at least the three insulated conductors, wherein the support member comprises orifices configurable to provide fluid flow through the support member into the opening during use.

3588. The system of claim 3565, further comprising a support member configurable to support at least the three insulated conductors, wherein the support member comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3589. The system of claim 3565, further comprising a tube coupled to at least the three insulated conductors, wherein the tube is configurable to provide a flow of fluid into the opening during use.

3590. The system of claim 3565, further comprising a tube coupled to at least the three insulated conductors, wherein the tube comprises critical flow orifices configurable to provide a substantially constant amount of fluid flow through the support member into the opening during use.

3591. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3592. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3593. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3594. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3595. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3596. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3597. The system of claim 3565, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, the system further comprising a wellhead coupled to the overburden casing and a lead-in conductor coupled to the insulated conductor, wherein the wellhead is disposed external to the overburden, wherein the wellhead comprises at least one sealing flange, and wherein at least the one sealing flange is configurable to couple to the lead-in conductor.

3598. The system of claim 3565, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

3599. The system of claim 3565, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

at least three insulated conductors disposed within an opening in the formation, wherein at least the three insulated conductors are electrically coupled in a 3-phase Y configuration, and wherein at least the three insulated conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from at least the three insulated conductors to a selected section of the formation during use.

3600. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to at least three insulated conductors to provide heat to at least a portion of the formation, wherein at least the three insulated conductors are disposed within an opening in the formation; and

allowing the heat to transfer from at least the three insulated conductors to a selected section of the formation.

3601. The method of claim 3600, further comprising supporting at least the three insulated conductors on a support member.

3602. The method of claim 3600, further comprising supporting at least the three insulated conductors on a support member and maintaining a location of at least the three insulated conductors on the support member with a centralizer.

3603. The method of claim 3600, wherein the provided heat comprises approximately 500 W/m to approximately 1150 W/m.

3604. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the conductor comprises a copper-nickel alloy.

3605. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 7% nickel by weight to approximately 12% nickel by weight.

3606. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the conductor comprises a copper-nickel alloy, and wherein the copper-nickel alloy comprises approximately 2% nickel by weight to approximately 6% nickel by weight.

3607. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises magnesium oxide.

3608. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, and wherein the magnesium oxide comprises a thickness of at least approximately 1 mm.

3609. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, and wherein the electrically insulating material comprises aluminum oxide and magnesium oxide.

3610. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the electrically insulating material comprises magnesium oxide, wherein the magnesium oxide comprises grain particles, and wherein the grain particles are configured to occupy porous spaces within the magnesium oxide.

3611. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises a corrosion-resistant material.

3612. The method of claim 3600, wherein at least the three insulated conductors comprise a conductor disposed in an electrically insulating material, wherein the insulating material is disposed in a sheath, and wherein the sheath comprises stainless steel.

3613. The method of claim 3600, further comprising supporting at least the three insulated conductors on a support member and flowing a fluid into the opening through an orifice in the support member.

3614. The method of claim 3600, further comprising supporting at least the three insulated conductors on a support member and flowing a substantially constant amount of fluid into the opening through critical flow orifices in the support member.

3615. The method of claim 3600, wherein a perforated tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a fluid into the opening through the perforated tube.

3616. The method of claim 3600, wherein a tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a substantially constant amount of fluid into the opening through critical flow orifices in the tube.

3617. The method of claim 3600, further comprising supporting at least the three insulated conductors on a support member and flowing a corrosion inhibiting fluid into the opening through an orifice in the support member.

3618. The method of claim 3600, wherein a perforated tube is disposed in the opening proximate to at least the three insulated conductors, the method further comprising flowing a corrosion inhibiting fluid into the opening through the perforated tube.

3619. The method of claim 3600, further comprising determining a temperature distribution in at least the three insulated conductors using an electromagnetic signal provided to the insulated conductor.

3620. The method of claim 3600, further comprising monitoring a leakage current of at least the three insulated conductors.

3621. The method of claim 3600, further comprising monitoring the applied electrical current.

3622. The method of claim 3600, further comprising monitoring a voltage applied to at least the three insulated conductors.

3623. The method of claim 3600, further comprising monitoring a temperature in at least the three insulated conductors with at least one thermocouple.

3624. The method of claim 3600, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3625. The method of claim 3600, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors using a cold pin transition conductor.

3626. The method of claim 3600, further comprising electrically coupling a lead-in conductor to at least the three insulated conductors using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3627. The method of claim 3600, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3628. The method of claim 3600, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3629. The method of claim 3600, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3630. The method of claim 3600, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3631. The method of claim 3600, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3632. The method of claim 3600, further comprising heating at least the portion of the formation to substantially pyrolyze at least some of the hydrocarbons within the formation.

3633. A system configured to heat an oil shale formation, comprising:

a first conductor disposed in a first conduit, wherein the first conduit is disposed within an opening in the formation, and wherein the first conductor is configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first conductor to a section of the formation during use.

3634. The system of claim 3633, wherein the first conductor is further configured to generate heat during application of an electrical current to the first conductor.

3635. The system of claim 3633, wherein the first conductor comprises a pipe.

3636. The system of claim 3633, wherein the first conductor comprises stainless steel.

3637. The system of claim 3633, wherein the first conduit comprises stainless steel.

3638. The system of claim 3633, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit.

3639. The system of claim 3633, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material.

3640. The system of claim 3633, further comprising a centralizer configured to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material and stainless steel.

3641. The system of claim 3633, wherein the opening comprises a diameter of at least approximately 5 cm.

3642. The system of claim 3633, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3643. The system of claim 3633, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises copper.

3644. The system of claim 3633, further comprising a sliding electrical connector coupled to the first conductor.

3645. The system of claim 3633, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit.

3646. The system of claim 3633, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit, and wherein the sliding electrical connector is configured to complete an electrical circuit with the first conductor and the first conduit.

3647. The system of claim 3633, further comprising a second conductor disposed within the first conduit and at least one sliding electrical connector coupled to the first conductor and the second conductor, wherein at least the one sliding electrical connector is configured to generate less heat than the first conductor or the second conductor during use.

3648. The system of claim 3633, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3649. The system of claim 3633, further comprising a fluid disposed within the first conduit, wherein the fluid is configured to maintain a pressure within the first conduit to substantially inhibit deformation of the first conduit during use.

3650. The system of claim 3633, further comprising a thermally conductive fluid disposed within the first conduit.

3651. The system of claim 3633, further comprising a thermally conductive fluid disposed within the first conduit, wherein the thermally conductive fluid comprises helium.

3652. The system of claim 3633, further comprising a fluid disposed within the first conduit, wherein the fluid is configured to substantially inhibit arcing between the first conductor and the first conduit during use.

3653. The system of claim 3633, further comprising a tube disposed within the opening external to the first conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first conduit and the opening to substantially inhibit deformation of the first conduit during use.

3654. The system of claim 3633, wherein the first conductor is further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3655. The system of claim 3633, further comprising a second conductor disposed within a second conduit and a third conductor disposed within a third conduit, wherein the first conduit, the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configured to operate in a 3-phase Y configuration during use.

3656. The system of claim 3633, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.

3657. The system of claim 3633, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit with a connector.

3658. The system of claim 3633, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3659. The system of claim 3633, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3660. The system of claim 3633, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3661. The system of claim 3633, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3662. The system of claim 3633, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3663. The system of claim 3633, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor.

3664. The system of claim 3633, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3665. The system of claim 3633, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configured to support the substantially low resistance conductor within the overburden casing.

3666. The system of claim 3633, wherein the heated section of the formation is substantially pyrolyzed.

3667. A system configurable to heat an oil shale formation, comprising:

a first conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed within an opening in the formation, and wherein the first conductor is further configurable to provide heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from the first conductor to a section of the formation during use.

3668. The system of claim 3667, wherein the first conductor is further configurable to generate heat during application of an electrical current to the first conductor.

3669. The system of claim 3667, wherein the first conductor comprises a pipe.

3670. The system of claim 3667, wherein the first conductor comprises stainless steel.

3671. The system of claim 3667, wherein the first conduit comprises stainless steel.

3672. The system of claim 3667, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit.

3673. The system of claim 3667, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material.

3674. The system of claim 3667, further comprising a centralizer configurable to maintain a location of the first conductor within the first conduit, wherein the centralizer comprises ceramic material and stainless steel.

3675. The system of claim 3667, wherein the opening comprises a diameter of at least approximately 5 cm.

3676. The system of claim 3667, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3677. The system of claim 3667, further comprising a lead-in conductor coupled to the first conductor, wherein the lead-in conductor comprises copper.

3678. The system of claim 3667, further comprising a sliding electrical connector coupled to the first conductor.

3679. The system of claim 3667, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit.

3680. The system of claim 3667, further comprising a sliding electrical connector coupled to the first conductor, wherein the sliding electrical connector is further coupled to the first conduit, and wherein the sliding electrical connector is configurable to complete an electrical circuit with the first conductor and the first conduit.

3681. The system of claim 3667, further comprising a second conductor disposed within the first conduit and at least one sliding electrical connector coupled to the first conductor and the second conductor, wherein at least the one sliding electrical connector is configurable to generate less heat than the first conductor or the second conductor during use.

3682. The system of claim 3667, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3683. The system of claim 3667, further comprising a fluid disposed within the first conduit, wherein the fluid is configurable to maintain a pressure within the first conduit to substantially inhibit deformation of the first conduit during use.

3684. The system of claim 3667, further comprising a thermally conductive fluid disposed within the first conduit.

3685. The system of claim 3667, further comprising a thermally conductive fluid disposed within the first conduit, wherein the thermally conductive fluid comprises helium.

3686. The system of claim 3667, further comprising a fluid disposed within the first conduit, wherein the fluid is configurable to substantially inhibit arcing between the first conductor and the first conduit during use.

3687. The system of claim 3667, further comprising a tube disposed within the opening external to the first conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first conduit and the opening to substantially inhibit deformation of the first conduit during use.

3688. The system of claim 3667, wherein the first conductor is further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3689. The system of claim 3667, further comprising a second conductor disposed within a second conduit and a third conductor disposed within a third conduit, wherein the first conduit, the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configurable to operate in a 3-phase Y configuration during use.

3690. The system of claim 3667, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.

3691. The system of claim 3667, further comprising a second conductor disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit with a connector.

3692. The system of claim 3667, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3693. The system of claim 3667, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3694. The system of claim 3667, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3695. The system of claim 3667, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3696. The system of claim 3667, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3697. The system of claim 3667, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor.

3698. The system of claim 3667, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3699. The system of claim 3667, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configurable to support the substantially low resistance conductor within the overburden casing.

3700. The system of claim 3667, wherein the heated section of the formation is substantially pyrolyzed.

3701. The system of claim 3667, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a first conductor disposed in a first conduit, wherein the first conduit is disposed within an opening in the formation, and wherein the first conductor is configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first conductor to a section of the formation during use.

3702. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to a first conductor to provide heat to at least a portion of the formation, wherein the first conductor is disposed in a first conduit, and wherein the first conduit is disposed within an opening in the formation; and

allowing the heat to transfer from the first conductor to a section of the formation.

3703. The method of claim 3702, wherein the first conductor comprises a pipe.

3704. The method of claim 3702, wherein the first conductor comprises stainless steel.

3705. The method of claim 3702, wherein the first conduit comprises stainless steel.

3706. The method of claim 3702, further comprising maintaining a location of the first conductor in the first conduit with a centralizer.

3707. The method of claim 3702, further comprising maintaining a location of the first conductor in the first conduit with a centralizer, wherein the centralizer comprises ceramic material.

3708. The method of claim 3702, further comprising maintaining a location of the first conductor in the first conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.

3709. The method of claim 3702, further comprising coupling a sliding electrical connector to the first conductor.

3710. The method of claim 3702, further comprising electrically coupling a sliding electrical connector to the first conductor and the first conduit, wherein the first conduit comprises an electrical lead configured to complete an electrical circuit with the first conductor.

3711. The method of claim 3702, further comprising coupling a sliding electrical connector to the first conductor and the first conduit, wherein the first conduit comprises an electrical lead configured to complete an electrical circuit with the first conductor, and wherein the generated heat comprises approximately 20 percent generated by the first conduit.

3712. The method of claim 3702, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

3713. The method of claim 3702, further comprising determining a temperature distribution in the first conduit using an electromagnetic signal provided to the conduit.

3714. The method of claim 3702, further comprising monitoring the applied electrical current.

3715. The method of claim 3702, further comprising monitoring a voltage applied to the first conductor.

3716. The method of claim 3702, further comprising monitoring a temperature in the conduit with at least one thermocouple.

3717. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3718. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3719. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3720. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3721. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3722. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, and wherein the substantially low resistance conductor is electrically coupled to the first conductor.

3723. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3724. The method of claim 3702, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to the first conductor, and wherein the method further comprises maintaining a location of the substantially low resistance conductor in the overburden casing with a centralizer support.

3725. The method of claim 3702, further comprising electrically coupling a lead-in conductor to the first conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3726. The method of claim 3702, further comprising electrically coupling a lead-in conductor to the first conductor, wherein the lead-in conductor comprises copper.

3727. The method of claim 3702, further comprising maintaining a sufficient pressure between the first conduit and the formation to substantially inhibit deformation of the first conduit.

3728. The method of claim 3702, further comprising providing a thermally conductive fluid within the first conduit.

3729. The method of claim 3702, further comprising providing a thermally conductive fluid within the first conduit, wherein the thermally conductive fluid comprises helium.

3730. The method of claim 3702, further comprising inhibiting arcing between the first conductor and the first conduit with a fluid disposed within the first conduit.

3731. The method of claim 3702, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the first conduit in the opening to control a pressure in the opening.

3732. The method of claim 3702, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the first conduit in the opening.

3733. The method of claim 3702, wherein a second conductor is disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor to form an electrical circuit.

3734. The method of claim 3702, wherein a second conductor is disposed within the first conduit, wherein the second conductor is electrically coupled to the first conductor with a connector.

3735. The method of claim 3702, wherein a second conductor is disposed within a second conduit and a third conductor is disposed within a third conduit, wherein the second conduit and the third conduit are disposed in different openings of the formation, wherein the first conductor is electrically coupled to the second conductor and the third conductor, and wherein the first, second, and third conductors are configured to operate in a 3-phase Y configuration.

3736. The method of claim 3702, wherein a second conductor is disposed within the first conduit, wherein at least one sliding electrical connector is coupled to the first conductor and the second conductor, and wherein heat generated by at least the one sliding electrical connector is less than heat generated by the first conductor or the second conductor.

3737. The method of claim 3702, wherein the first conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3738. The method of claim 3702, further comprising flowing an oxidizing fluid through an orifice in the first conduit.

3739. The method of claim 3702, further comprising disposing a perforated tube proximate to the first conduit and flowing an oxidizing fluid through the perforated tube.

3740. The method of claim 3702, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

3741. A system configured to heat an oil shale formation, comprising:

a first conductor disposed in a first conduit, wherein the first conduit is disposed within a first opening in the formation;

a second conductor disposed in a second conduit, wherein the second conduit is disposed within a second opening in the formation;

a third conductor disposed in a third conduit, wherein the third conduit is disposed within a third opening in the formation, wherein the first, second, and third conductors are electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.

3742. The system of claim 3741, wherein the first, second, and third conductors are further configured to generate heat during application of an electrical current to the first conductor.

3743. The system of claim 3741, wherein the first, second, and third conductors comprise a pipe.

3744. The system of claim 3741, wherein the first, second, and third conductors comprise stainless steel.

3745. The system of claim 3741, wherein the first, second, and third openings comprise a diameter of at least approximately 5 cm.

3746. The system of claim 3741, further comprising a first sliding electrical connector coupled to the first conductor and a second sliding electrical connector coupled to the second conductor and a third sliding electrical connector coupled to the third conductor.

3747. The system of claim 3741, further comprising a first sliding electrical connector coupled to the first conductor, wherein the first sliding electrical connector is further coupled to the first conduit.

3748. The system of claim 3741, further comprising a second sliding electrical connector coupled to the second conductor, wherein the second sliding electrical connector is further coupled to the second conduit.

3749. The system of claim 3741, further comprising a third sliding electrical connector coupled to the third conductor, wherein the third sliding electrical connector is further coupled to the third conduit.

3750. The system of claim 3741, wherein each of the first, second, and third conduits comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from each of the first, second, and third conductors to the section along the first section of each of the conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of each of the conduits.

3751. The system of claim 3741, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configured to maintain a pressure within the first conduit to substantially inhibit deformation of the first, second, and third conduits during use.

3752. The system of claim 3741, further comprising a thermally conductive fluid disposed within the first, second, and third conduits.

3753. The system of claim 3741, further comprising a thermally conductive fluid disposed within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.

3754. The system of claim 3741, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configured to substantially inhibit arcing between the first, second, and third conductors and the first, second, and third conduits during use.

3755. The system of claim 3741, further comprising at least one tube disposed within the first, second, and third openings external to the first, second, and third conduits, wherein at least the one tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits during use.

3756. The system of claim 3741, wherein the first, second, and third conductors are further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3757. The system of claim 3741, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation.

3758. The system of claim 3741, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing comprises steel.

3759. The system of claim 3741, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing is further disposed in cement.

3760. The system of claim 3741, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings.

3761. The system of claim 3741, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the first, second, and third openings and at least the one overburden casing during use.

3762. The system of claim 3741, wherein the heated section of the formation is substantially pyrolyzed.

3763. A system configurable to heat an oil shale formation, comprising:

a first conductor configurable to be disposed in a first conduit, wherein the first conduit is configurable to be disposed within a first opening in the formation;

a second conductor configurable to be disposed in a second conduit, wherein the second conduit is configurable to be disposed within a second opening in the formation;

a third conductor configurable to be disposed in a third conduit, wherein the third conduit is configurable to be disposed within a third opening in the formation, wherein the first, second, and third conductors are further configurable to be electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are further configurable to provide heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.

3764. The system of claim 3763, wherein the first, second, and third conductors are further configurable to generate heat during application of an electrical current to the first conductor.

3765. The system of claim 3763, wherein the first, second, and third conductors comprise a pipe.

3766. The system of claim 3763, wherein the first, second, and third conductors comprise stainless steel.

3767. The system of claim 3763, wherein each of the first, second, and third openings comprises a diameter of at least approximately 5 cm.

3768. The system of claim 3763, further comprising a first sliding electrical connector coupled to the first conductor and a second sliding electrical connector coupled to the second conductor and a third sliding electrical connector coupled to the third conductor.

3769. The system of claim 3763, further comprising a first sliding electrical connector coupled to the first conductor, wherein the first sliding electrical connector is further coupled to the first conduit.

3770. The system of claim 3763, further comprising a second sliding electrical connector coupled to the second conductor, wherein the second sliding electrical connector is further coupled to the second conduit.

3771. The system of claim 3763, further comprising a third sliding electrical connector coupled to the third conductor, wherein the third sliding electrical connector is further coupled to the third conduit.

3772. The system of claim 3763, wherein each of the first, second, and third conduits comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from each of the first, second, and third conductors to the section along the first section of each of the conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of each of the conduits.

3773. The system of claim 3763, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configurable to maintain a pressure within the first conduit to substantially inhibit deformation of the first, second, and third conduits during use.

3774. The system of claim 3763, further comprising a thermally conductive fluid disposed within the first, second, and third conduits.

3775. The system of claim 3763, further comprising a thermally conductive fluid disposed within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.

3776. The system of claim 3763, further comprising a fluid disposed within the first, second, and third conduits, wherein the fluid is configurable to substantially inhibit arcing between the first, second, and third conductors and the first, second, and third conduits during use.

3777. The system of claim 3763, further comprising at least one tube disposed within the first, second, and third openings external to the first, second, and third conduits, wherein at least the one tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits during use.

3778. The system of claim 3763, wherein the first, second, and third conductors are further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3779. The system of claim 3763, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation.

3780. The system of claim 3763, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing comprises steel.

3781. The system of claim 3763, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein at least the one overburden casing is further disposed in cement.

3782. The system of claim 3763, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings.

3783. The system of claim 3763, further comprising at least one overburden casing coupled to the first, second, and third openings, wherein at least the one overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of at least the one overburden casing and the first, second, and third openings, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the first, second, and third openings and at least the one overburden casing during use.

3784. The system of claim 3763, wherein the heated section of the formation is substantially pyrolyzed.

3785. The system of claim 3763, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a first conductor disposed in a first conduit, wherein the first conduit is disposed within a first opening in the formation;

a second conductor disposed in a second conduit, wherein the second conduit is disposed within a second opening in the formation;

a third conductor disposed in a third conduit, wherein the third conduit is disposed within a third opening in the formation, wherein the first, second, and third conductors are electrically coupled in a 3-phase Y configuration, and wherein the first, second, and third conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first, second, and third conductors to a selected section of the formation during use.

3786. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to a first conductor to provide heat to at least a portion of the formation, wherein the first conductor is disposed in a first conduit, and wherein the first conduit is disposed within a first opening in the formation;

applying an electrical current to a second conductor to provide heat to at least a portion of the formation, wherein the second conductor is disposed in a second conduit, and wherein the second conduit is disposed within a second opening in the formation;

applying an electrical current to a third conductor to provide heat to at least a portion of the formation, wherein the third conductor is disposed in a third conduit, and wherein the third conduit is disposed within a third opening in the formation; and

allowing the heat to transfer from the first, second, and third conductors to a selected section of the formation.

3787. The method of claim 3786, wherein the first, second, and third conductors comprise a pipe.

3788. The method of claim 3786, wherein the first, second, and third conductors comprise stainless steel.

3789. The method of claim 3786, wherein the first, second, and third conduits comprise stainless steel.

3790. The method of claim 3786, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

3791. The method of claim 3786, further comprising determining a temperature distribution in the first, second, and third conduits using an electromagnetic signal provided to the first, second, and third conduits.

3792. The method of claim 3786, further comprising monitoring the applied electrical current.

3793. The method of claim 3786, further comprising monitoring a voltage applied to the first, second, and third conductors.

3794. The method of claim 3786, further comprising monitoring a temperature in the first, second, and third conduits with at least one thermocouple.

3795. The method of claim 3786, further comprising maintaining a sufficient pressure between the first, second, and third conduits and the first, second, and third openings to substantially inhibit deformation of the first, second, and third conduits.

3796. The method of claim 3786, further comprising providing a thermally conductive fluid within the first, second, and third conduits.

3797. The method of claim 3786, further comprising providing a thermally conductive fluid within the first, second, and third conduits, wherein the thermally conductive fluid comprises helium.

3798. The method of claim 3786, further comprising inhibiting arcing between the first, second, and third conductors and the first, second, and third conduits with a fluid disposed within the first, second, and third conduits.

3799. The method of claim 3786, further comprising removing a vapor from the first, second, and third openings using at least one perforated tube disposed proximate to the first, second, and third conduits in the first, second, and third openings to control a pressure in the first, second, and third openings.

3800. The method of claim 3786, wherein the first, second, and third conduits comprise a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first, second, and third conductors to the section along the first section of the first, second, and third conduits is less than heat radiated from the first, second, and third conductors to the section along the second section of the first, second, and third conduits.

3801. The method of claim 3786, further comprising flowing an oxidizing fluid through an orifice in the first, second, and third conduits.

3802. The method of claim 3786, further comprising heating at least the portion of the formation to substantially pyrolyze at least some of the carbon within the formation.

3803. A system configured to heat an oil shale formation, comprising:

a first conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation; and

a second conductor disposed in the conduit, wherein the second conductor is electrically coupled to the first conductor with a connector, and wherein the first and second conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first and second conductors to a selected section of the formation during use.

3804. The system of claim 3803, wherein the first conductor is further configured to generate heat during application of an electrical current to the first conductor.

3805. The system of claim 3803, wherein the first and second conductors comprise a pipe.

3806. The system of claim 3803, wherein the first and second conductors comprise stainless steel.

3807. The system of claim 3803, wherein the conduit comprises stainless steel.

3808. The system of claim 3803, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit.

3809. The system of claim 3803, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material.

3810. The system of claim 3803, further comprising a centralizer configured to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material and stainless steel.

3811. The system of claim 3803, wherein the opening comprises a diameter of at least approximately 5 cm.

3812. The system of claim 3803, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3813. The system of claim 3803, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises copper.

3814. The system of claim 3803, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3815. The system of claim 3803, further comprising a fluid disposed within the conduit, wherein the fluid is configured to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.

3816. The system of claim 3803, further comprising a thermally conductive fluid disposed within the conduit.

3817. The system of claim 3803, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.

3818. The system of claim 3803, further comprising a fluid disposed within the conduit, wherein the fluid is configured to substantially inhibit arcing between the first and second conductors and the conduit during use.

3819. The system of claim 3803, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.

3820. The system of claim 3803, wherein the first and second conductors are further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3821. The system of claim 3803, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3822. The system of claim 3803, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3823. The system of claim 3803, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3824. The system of claim 3803, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3825. The system of claim 3803, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3826. The system of claim 3803, wherein the heated section of the formation is substantially pyrolyzed.

3827. The system of claim 3803, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a first conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation;

a second conductor disposed in the conduit, wherein the second conductor is electrically coupled to the first conductor with a connector, and wherein the first and second conductors are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the first and second conductors to a selected section of the formation during use.

3828. A system configurable to heat an oil shale formation, comprising:

a first conductor configurable to be disposed in a conduit, wherein the conduit is configurable to be disposed within an opening in the formation; and

a second conductor configurable to be disposed in the conduit, wherein the second conductor is configurable to be electrically coupled to the first conductor with a connector, and wherein the first and second conductors are further configurable to provide heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from the first and second conductors to a selected section of the formation during use.

3829. The system of claim 3828, wherein the first conductor is further configurable to generate heat during application of an electrical current to the first conductor.

3830. The system of claim 3828, wherein the first and second conductors comprise a pipe.

3831. The system of claim 3828, wherein the first and second conductors comprise stainless steel.

3832. The system of claim 3828, wherein the conduit comprises stainless steel.

3833. The system of claim 3828, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit.

3834. The system of claim 3828, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material.

3835. The system of claim 3828, further comprising a centralizer configurable to maintain a location of the first and second conductors within the conduit, wherein the centralizer comprises ceramic material and stainless steel.

3836. The system of claim 3828, wherein the opening comprises a diameter of at least approximately 5 cm.

3837. The system of claim 3828, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3838. The system of claim 3828, further comprising a lead-in conductor coupled to the first and second conductors, wherein the lead-in conductor comprises copper.

3839. The system of claim 3828, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3840. The system of claim 3828, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.

3841. The system of claim 3828, further comprising a thermally conductive fluid disposed within the conduit.

3842. The system of claim 3828, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.

3843. The system of claim 3828, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to substantially inhibit arcing between the first and second conductors and the conduit during use.

3844. The system of claim 3828, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.

3845. The system of claim 3828, wherein the first and second conductors are further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3846. The system of claim 3828, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3847. The system of claim 3828, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3848. The system of claim 3828, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3849. The system of claim 3828, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3850. The system of claim 3828, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3851. The system of claim 3828, wherein the heated section of the formation is substantially pyrolyzed.

3852. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to at least two conductors to provide heat to at least a portion of the formation, wherein at least the two conductors are disposed within a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the two conductors are electrically coupled with a connector; and

allowing heat to transfer from at least the two conductors to a selected section of the formation.

3853. The method of claim 3852, wherein at least the two conductors comprise a pipe.

3854. The method of claim 3852, wherein at least the two conductors comprise stainless steel.

3855. The method of claim 3852, wherein the conduit comprises stainless steel.

3856. The method of claim 3852, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer.

3857. The method of claim 3852, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer, wherein the centralizer comprises ceramic material.

3858. The method of claim 3852, further comprising maintaining a location of at least the two conductors in the conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.

3859. The method of claim 3852, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

3860. The method of claim 3852, further comprising determining a temperature distribution in the conduit using an electromagnetic signal provided to the conduit.

3861. The method of claim 3852, further comprising monitoring the applied electrical current.

3862. The method of claim 3852, further comprising monitoring a voltage applied to at least the two conductors.

3863. The method of claim 3852, further comprising monitoring a temperature in the conduit with at least one thermocouple.

3864. The method of claim 3852, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3865. The method of claim 3852, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3866. The method of claim 3852, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3867. The method of claim 3852, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3868. The method of claim 3852, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3869. The method of claim 3852, further comprising maintaining a sufficient pressure between the conduit and the formation to substantially inhibit deformation of the conduit.

3870. The method of claim 3852, further comprising providing a thermally conductive fluid within the conduit.

3871. The method of claim 3852, further comprising providing a thermally conductive fluid within the conduit, wherein the thermally conductive fluid comprises helium.

3872. The method of claim 3852, further comprising inhibiting arcing between at least the two conductors and the conduit with a fluid disposed within the conduit.

3873. The method of claim 3852, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the conduit in the opening to control a pressure in the opening.

3874. The method of claim 3852, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the conduit in the opening.

3875. The method of claim 3852, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3876. The method of claim 3852, further comprising flowing an oxidizing fluid through an orifice in the conduit.

3877. The method of claim 3852, further comprising disposing a perforated tube proximate to the conduit and flowing an oxidizing fluid through the perforated tube.

3878. The method of claim 3852, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

3879. A system configured to heat an oil shale formation, comprising:

at least one conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the one conductor is configured to provide heat to at least a first portion of the formation during use;

at least one sliding connector, wherein at least the one sliding connector is coupled to at least the one conductor, wherein at least the one sliding connector is configured to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and

wherein the system is configured to allow heat to transfer from at least the one conductor to a section of the formation during use.

3880. The system of claim 3879, wherein at least the one conductor is further configured to generate heat during application of an electrical current to at least the one conductor.

3881. The system of claim 3879, wherein at least the one conductor comprises a pipe.

3882. The system of claim 3879, wherein at least the one conductor comprises stainless steel.

3883. The system of claim 3879, wherein the conduit comprises stainless steel.

3884. The system of claim 3879, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit.

3885. The system of claim 3879, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material.

3886. The system of claim 3879, further comprising a centralizer configured to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material and stainless steel.

3887. The system of claim 3879, wherein the opening comprises a diameter of at least approximately 5 cm.

3888. The system of claim 3879, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3889. The system of claim 3879, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises copper.

3890. The system of claim 3879, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3891. The system of claim 3879, further comprising a fluid disposed within the conduit, wherein the fluid is configured to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.

3892. The system of claim 3879, further comprising a thermally conductive fluid disposed within the conduit.

3893. The system of claim 3879, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.

3894. The system of claim 3879, further comprising a fluid disposed within the conduit, wherein the fluid is configured to substantially inhibit arcing between at least the one conductor and the conduit during use.

3895. The system of claim 3879, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configured to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.

3896. The system of claim 3879, wherein at least the one conductor is further configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3897. The system of claim 3879, farther comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3898. The system of claim 3879, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3899. The system of claim 3879, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3900. The system of claim 3879, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3901. The system of claim 3879, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3902. The system of claim 3879, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.

3903. The system of claim 3879, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3904. The system of claim 3879, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configured to support the substantially low resistance conductor within the overburden casing.

3905. The system of claim 3879, wherein the heated section of the formation is substantially pyrolyzed.

3906. A system configurable to heat an oil shale formation, comprising:

at least one conductor configurable to be disposed in a conduit, wherein the conduit is configurable to be disposed within an opening in the formation, and wherein at least the one conductor is further configurable to provide heat to at least a first portion of the formation during use;

at least one sliding connector, wherein at least the one sliding connector is configurable to be coupled to at least the one conductor, wherein at least the one sliding connector is further configurable to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and

wherein the system is configurable to allow heat to transfer from at least the one conductor to a section of the formation during use.

3907. The system of claim 3906, wherein at least the one conductor is further configurable to generate heat during application of an electrical current to at least the one conductor.

3908. The system of claim 3906, wherein at least the one conductor comprises a pipe

3909. The system of claim 3906, wherein at least the one conductor comprises stainless steel.

3910. The system of claim 3906, wherein the conduit comprises stainless steel.

3911. The system of claim 3906, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit.

3912. The system of claim 3906, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material.

3913. The system of claim 3906, further comprising a centralizer configurable to maintain a location of at least the one conductor within the conduit, wherein the centralizer comprises ceramic material and stainless steel.

3914. The system of claim 3906, wherein the opening comprises a diameter of at least approximately 5 cm.

3915. The system of claim 3906, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

3916. The system of claim 3906, further comprising a lead-in conductor coupled to at least the one conductor, wherein the lead-in conductor comprises copper.

3917. The system of claim 3906, wherein the conduit comprises a first section and a second section, wherein a thickness of the first section is greater than a thickness of the second section such that heat radiated from the first conductor to the section along the first section of the conduit is less than heat radiated from the first conductor to the section along the second section of the conduit.

3918. The system of claim 3906, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to maintain a pressure within the conduit to substantially inhibit deformation of the conduit during use.

3919. The system of claim 3906, further comprising a thermally conductive fluid disposed within the conduit.

3920. The system of claim 3906, further comprising a thermally conductive fluid disposed within the conduit, wherein the thermally conductive fluid comprises helium.

3921. The system of claim 3906, further comprising a fluid disposed within the conduit, wherein the fluid is configurable to substantially inhibit arcing between at least the one conductor and the conduit during use.

3922. The system of claim 3906, further comprising a tube disposed within the opening external to the conduit, wherein the tube is configurable to remove vapor produced from at least the heated portion of the formation such that a pressure balance is maintained between the conduit and the opening to substantially inhibit deformation of the conduit during use.

3923. The system of claim 3906, wherein at least the one conductor is further configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3924. The system of claim 3906, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3925. The system of claim 3906, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3926. The system of claim 3906, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3927. The system of claim 3906, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3928. The system of claim 3906, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3929. The system of claim 3906, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.

3930. The system of claim 3906, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3931. The system of claim 3906, further comprising an overburden casing coupled to the opening and a substantially low resistance conductor disposed within the overburden casing and a centralizer configurable to support the substantially low resistance conductor within the overburden casing.

3932. The system of claim 3906, wherein the heated section of the formation is substantially pyrolyzed.

3933. The system of claim 3906, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

at least one conductor disposed in a conduit, wherein the conduit is disposed within an opening in the formation, and wherein at least the one conductor is configured to provide heat to at least a first portion of the formation during use;

at least one sliding connector, wherein at least the one sliding connector is coupled to at least the one conductor, wherein at least the one sliding connector is configured to provide heat during use, and wherein heat provided by at least the one sliding connector is substantially less than the heat provided by at least the one conductor during use; and

wherein the system is configured to allow heat to transfer from at least the one conductor to a section of the formation during use.

3934. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to at least one conductor and at least one sliding connector to provide heat to at least a portion of the formation, wherein at least the one conductor and at least the one sliding connector are disposed within a conduit, and wherein heat provided by at least the one conductor is substantially greater than heat provided by at least the one sliding connector; and

allowing the heat to transfer from at least the one conductor and at least the one sliding connector to a section of the formation.

3935. The method of claim 3934, wherein at least the one conductor comprises a pipe.

3936. The method of claim 3934, wherein at least the one conductor comprises stainless steel.

3937. The method of claim 3934, wherein the conduit comprises stainless steel.

3938. The method of claim 3934, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer.

3939. The method of claim 3934, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer, wherein the centralizer comprises ceramic material.

3940. The method of claim 3934, further comprising maintaining a location of at least the one conductor in the conduit with a centralizer, wherein the centralizer comprises ceramic material and stainless steel.

3941. The method of claim 3934, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

3942. The method of claim 3934, further comprising determining a temperature distribution in the conduit using an electromagnetic signal provided to the conduit.

3943. The method of claim 3934, further comprising monitoring the applied electrical current.

3944. The method of claim 3934, further comprising monitoring a voltage applied to at least the one conductor.

3945. The method of claim 3934, further comprising monitoring a temperature in the conduit with at least one thermocouple.

3946. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3947. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3948. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3949. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3950. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with a packing material.

3951. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, and wherein the substantially low resistance conductor is electrically coupled to at least the one conductor.

3952. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the substantially low resistance conductor comprises carbon steel.

3953. The method of claim 3934, further comprising coupling an overburden casing to the opening, wherein a substantially low resistance conductor is disposed within the overburden casing, wherein the substantially low resistance conductor is electrically coupled to at least the one conductor, and wherein the method further comprises maintaining a location of the substantially low resistance conductor in the overburden casing with a centralizer support.

3954. The method of claim 3934, further comprising electrically coupling a lead-in conductor to at least the one conductor, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3955. The method of claim 3934, further comprising electrically coupling a lead-in conductor to at least the one conductor, wherein the lead-in conductor comprises copper.

3956. The method of claim 3934, further comprising maintaining a sufficient pressure between the conduit and the formation to substantially inhibit deformation of the conduit.

3957. The method of claim 3934, further comprising providing a thermally conductive fluid within the conduit.

3958. The method of claim 3934, further comprising providing a thermally conductive fluid within the conduit, wherein the thermally conductive fluid comprises helium.

3959. The method of claim 3934, further comprising inhibiting arcing between the conductor and the conduit with a fluid disposed within the conduit.

3960. The method of claim 3934, further comprising removing a vapor from the opening using a perforated tube disposed proximate to the conduit in the opening to control a pressure in the opening.

3961. The method of claim 3934, further comprising flowing a corrosion inhibiting fluid through a perforated tube disposed proximate to the conduit in the opening.

3962. The method of claim 3934, further comprising flowing an oxidizing fluid through an orifice in the conduit.

3963. The method of claim 3934, further comprising disposing a perforated tube proximate to the conduit and flowing an oxidizing fluid through the perforated tube.

3964. The method of claim 3934, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

3965. A system configured to heat an oil shale formation, comprising:

at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.

3966. The system of claim 3965, wherein at least the one elongated member comprises stainless steel.

3967. The system of claim 3965, wherein at least the one elongated member is further configured to generate heat during application of an electrical current to at least the one elongated member.

3968. The system of claim 3965, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member.

3969. The system of claim 3965, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member, and wherein the support member comprises openings.

3970. The system of claim 3965, further comprising a support member coupled to at least the one elongated member, wherein the support member is configured to support at least the one elongated member, wherein the support member comprises openings, wherein the openings are configured to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configured to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.

3971. The system of claim 3965, further comprising a tube disposed in the opening, wherein the tube comprises openings, wherein the openings are configured to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configured to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.

3972. The system of claim 3965, further comprising a centralizer coupled to at least the one elongated member, wherein the centralizer is configured to electrically isolate at least the one elongated member.

3973. The system of claim 3965, further comprising a centralizer coupled to at least the one elongated member and a support member coupled to at least the one elongated member, wherein the centralizer is configured to maintain a location of at least the one elongated member on the support member.

3974. The system of claim 3965, wherein the opening comprises a diameter of at least approximately 5 cm.

3975. The system of claim 3965, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

3976. The system of claim 3965, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.

3977. The system of claim 3965, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.

3978. The system of claim 3965, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.

3979. The system of claim 3965, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

3980. The system of claim 3965, wherein at least the one elongated member is arranged in a series electrical configuration.

3981. The system of claim 3965, wherein at least the one elongated member is arranged in a parallel electrical configuration.

3982. The system of claim 3965, wherein at least the one elongated member is configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

3983. The system of claim 3965, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configured to remove vapor from the opening to control a pressure in the opening during use.

3984. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

3985. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

3986. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

3987. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

3988. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

3989. The system of claim 3965, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

3990. The system of claim 3965, wherein the heated section of the formation is substantially pyrolyzed.

3991. A system configurable to heat an oil shale formation, comprising:

at least one elongated member configurable to be disposed within an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer from at least the one elongated member to a section of the formation during use.

3992. The system of claim 3991, wherein at least the one elongated member comprises stainless steel.

3993. The system of claim 3991, wherein at least the one elongated member is further configurable to generate heat during application of an electrical current to at least the one elongated member.

3994. The system of claim 3991, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member.

3995. The system of claim 3991, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member, and wherein the support member comprises openings.

3996. The system of claim 3991, further comprising a support member coupled to at least the one elongated member, wherein the support member is configurable to support at least the one elongated member, wherein the support member comprises openings, wherein the openings are configurable to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configurable to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.

3997. The system of claim 3991, further comprising a tube disposed in the opening, wherein the tube comp rises openings, wherein the openings are configurable to flow a fluid along a length of at least the one elongated member during use, and wherein the fluid is configurable to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use.

3998. The system of claim 3991, further comprising a centralizer coupled to at least the one elongated member, wherein the centralizer is configurable to electrically isolate at least the one elongated member.

3999. The system of claim 3991, further comprising a centralizer coupled to at least the one elongated member and a support member coupled to at least the one elongated member, wherein the centralizer is configurable to maintain a location of at least the one elongated member on the support member.

4000. The system of claim 3991, wherein the opening comprises a diameter of at least approximately 5 cm.

4001. The system of claim 3991, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

4002. The system of claim 3991, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.

4003. The system of claim 3991, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.

4004. The system of claim 3991, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.

4005. The system of claim 3991, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

4006. The system of claim 3991, wherein at least the one elongated member is arranged in a series electrical configuration.

4007. The system of claim 3991, wherein at least the one elongated member is arranged in a parallel electrical configuration.

4008. The system of claim 3991, wherein at least the one elongated member is configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

4009. The system of claim 3991, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configurable to remove vapor from the opening to control a pressure in the opening during use.

4010. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

4011. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

4012. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

4013. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

4014. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

4015. The system of claim 3991, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

4016. The system of claim 3991, wherein the heated section of the formation is substantially pyrolyzed.

4017. The system of claim 3991, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.

4018. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to at least one elongated member to provide heat to at least a portion of the formation, wherein at least the one elongated member is disposed within an opening of the formation; and

allowing heat to transfer from at least the one elongated member to a section of the formation.

4019. The method of claim 4018, wherein at least the one elongated member comprises a metal strip.

4020. The method of claim 4018, wherein at least the one elongated member comprises a metal rod.

4021. The method of claim 4018, wherein at least the one elongated member comprises stainless steel.

4022. The method of claim 4018, further comprising supporting at least the one elongated member on a center support member.

4023. The method of claim 4018, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises a tube.

4024. The method of claim 4018, further comprising electrically isolating at least the one elongated member with a centralizer.

4025. The method of claim 4018, further comprising laterally spacing at least the one elongated member with a centralizer.

4026. The method of claim 4018, further comprising electrically coupling at least the one elongated member in a series configuration.

4027. The method of claim 4018, further comprising electrically coupling at least the one elongated member in a parallel configuration.

4028. The method of claim 4018, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

4029. The method of claim 4018, further comprising determining a temperature distribution in at least the one elongated member using an electromagnetic signal provided to at least the one elongated member.

4030. The method of claim 4018, further comprising monitoring the applied electrical current.

4031. The method of claim 4018, further comprising monitoring a voltage applied to at least the one elongated member.

4032. The method of claim 4018, further comprising monitoring a temperature in at least the one elongated member with at least one thermocouple.

4033. The method of claim 4018, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises openings, the method further comprising flowing an oxidizing fluid through the openings to substantially inhibit carbon deposition proximate to or on at least the one elongated member.

4034. The method of claim 4018, further comprising flowing an oxidizing fluid through a tube disposed proximate to at least the one elongated member to substantially inhibit carbon deposition proximate to or on at least the one elongated member.

4035. The method of claim 4018, further comprising flowing an oxidizing fluid through an opening in at least the one elongated member to substantially inhibit carbon deposition proximate to or on at least the one elongated member.

4036. The method of claim 4018, further comprising electrically coupling a lead-in conductor to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

4037. The method of claim 4018, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor.

4038. The method of claim 4018, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

4039. The method of claim 4018, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

4040. The method of claim 4018, further comprising coupling an overburden casing to the opening, wherein the overburden casing comprises steel.

4041. The method of claim 4018, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in cement.

4042. The method of claim 4018, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

4043. The method of claim 4018, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with the packing material.

4044. The method of claim 4018, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

4045. A system configured to heat an oil shale formation, comprising:

at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed within the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to the opening during use, and wherein the oxidizing fluid is selected to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and

wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.

4046. The system of claim 4045, wherein at least the one elongated member comprises stainless steel.

4047. The system of claim 4045, wherein at least the one elongated member is further configured to generate heat during application of an electrical current to at least the one elongated member.

4048. The system of claim 4045, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configured to support at least the one elongated member.

4049. The system of claim 4045, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configured to support at least the one elongated member, and wherein the conduit comprises openings.

4050. The system of claim 4045, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configured to electrically isolate at least the one elongated member from the conduit.

4051. The system of claim 4045, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configured to maintain a location of at least the one elongated member on the conduit.

4052. The system of claim 4045, wherein the opening comprises a diameter of at least approximately 5 cm.

4053. The system of claim 4045, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

4054. The system of claim 4045, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.

4055. The system of claim 4045, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.

4056. The system of claim 4045, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.

4057. The system of claim 4045, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

4058. The system of claim 4045, wherein at least the one elongated member is arranged in a series electrical configuration.

4059. The system of claim 4045, wherein at least the one elongated member is arranged in a parallel electrical configuration.

4060. The system of claim 4045, wherein at least the one elongated member is configured to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

4061. The system of claim 4045, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configured to remove vapor from the opening to control a pressure in the opening during use.

4062. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

4063. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

4064. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

4065. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

4066. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

4067. The system of claim 4045, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configured to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

4068. The system of claim 4045, wherein the heated section of the formation is substantially pyrolyzed.

4069. A system configurable to heat an oil shale formation, comprising:

at least one elongated member configurable to be disposed within an opening in the formation, wherein at least the one elongated member is further configurable to provide heat to at least a portion of the formation during use;

a conduit configurable to be disposed within the opening, wherein the conduit is further configurable to provide an oxidizing fluid from the oxidizing fluid source to the opening during use, and wherein the system is configurable to allow the oxidizing fluid to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and

wherein the system is further configurable to allow heat to transfer from at least the one elongated member to a section of the formation during use.

4070. The system of claim 4069, wherein at least the one elongated member comprises stainless steel.

4071. The system of claim 4069, wherein at least the one elongated member is further configurable to generate heat during application of an electrical current to at least the one elongated member.

4072. The system of claim 4069, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configurable to support at least the one elongated member.

4073. The system of claim 4069, wherein at least the one elongated member is coupled to the conduit, wherein the conduit is further configurable to support at least the one elongated member, and wherein the conduit comprises openings.

4074. The system of claim 4069, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configurable to electrically isolate at least the one elongated member from the conduit.

4075. The system of claim 4069, further comprising a centralizer coupled to at least the one elongated member and the conduit, wherein the centralizer is configurable to maintain a location of at least the one elongated member on the conduit.

4076. The system of claim 4069, wherein the opening comprises a diameter of at least approximately 5 cm.

4077. The system of claim 4069, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configurable to generate substantially no heat.

4078. The system of claim 4069, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises a rubber insulated conductor.

4079. The system of claim 4069, further comprising a lead-in conductor coupled to at least the one elongated member, wherein the lead-in conductor comprises copper wire.

4080. The system of claim 4069, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor.

4081. The system of claim 4069, further comprising a lead-in conductor coupled to at least the one elongated member with a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

4082. The system of claim 4069, wherein at least the one elongated member is arranged in a series electrical configuration.

4083. The system of claim 4069, wherein at least the one elongated member is arranged in a parallel electrical configuration.

4084. The system of claim 4069, wherein at least the one elongated member is configurable to generate radiant heat of approximately 650 W/m to approximately 1650 W/m during use.

4085. The system of claim 4069, further comprising a perforated tube disposed in the opening external to at least the one elongated member, wherein the perforated tube is configurable to remove vapor from the opening to control a pressure in the opening during use.

4086. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation.

4087. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

4088. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

4089. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the opening.

4090. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material comprises cement.

4091. The system of claim 4069, further comprising an overburden casing coupled to the opening, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the packing material is further configurable to substantially inhibit a flow of fluid between the opening and the overburden casing during use.

4092. The system of claim 4069, wherein the heated section of the formation is substantially pyrolyzed.

4093. The system of claim 4069, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

at least one elongated member disposed within an opening in the formation, wherein at least the one elongated member is configured to provide heat to at least a portion of the formation during use;

an oxidizing fluid source;

a conduit disposed within the opening, wherein the conduit is configured to provide an oxidizing fluid from the oxidizing fluid source to the opening during use, and wherein the oxidizing fluid is selected to substantially inhibit carbon deposition on or proximate to at least the one elongated member during use; and

wherein the system is configured to allow heat to transfer from at least the one elongated member to a section of the formation during use.

4094. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to at least one elongated member to provide heat to at least a portion of the formation, wherein at least the one elongated member is disposed within an opening in the formation;

providing an oxidizing fluid to at least the one elongated member to substantially inhibit carbon deposition on or proximate to at least the one elongated member; and

allowing heat to transfer from at least the one elongated member to a section of the formation.

4095. The method of claim 4094, wherein at least the one elongated member comprises a metal strip.

4096. The method of claim 4094, wherein at least the one elongated member comprises a metal rod.

4097. The method of claim 4094, wherein at least the one elongated member comprises stainless steel.

4098. The method of claim 4094, further comprising supporting at least the one elongated member on a center support member.

4099. The method of claim 4094, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises a tube.

4100. The method of claim 4094, further comprising electrically isolating at least the one elongated member with a centralizer.

4101. The method of claim 4094, further comprising laterally spacing at least the one elongated member with a centralizer.

4102. The method of claim 4094, further comprising electrically coupling at least the one elongated member in a series configuration.

4103. The method of claim 4094, further comprising electrically coupling at least the one elongated member in a parallel configuration.

4104. The method of claim 4094, wherein the provided heat comprises approximately 650 W/m to approximately 1650 W/m.

4105. The method of claim 4094, further comprising determining a temperature distribution in at least the one elongated member using an electromagnetic signal provided to at least the one elongated member.

4106. The method of claim 4094, further comprising monitoring the applied electrical current.

4107. The method of claim 4094, further comprising monitoring a voltage applied to at least the one elongated member.

4108. The method of claim 4094, further comprising monitoring a temperature in at least the one elongated member with at least one thermocouple.

4109. The method of claim 4094, further comprising supporting at least the one elongated member on a center support member, wherein the center support member comprises openings, wherein providing the oxidizing fluid to at least the one elongated member comprises flowing the oxidizing fluid through the openings in the center support member.

4110. The method of claim 4094, wherein providing the oxidizing fluid to at least the one elongated member comprises flowing the oxidizing fluid through orifices in a tube disposed in the opening proximate to at least the one elongated member.

4111. The method of claim 4094, further comprising electrically coupling a lead-in conductor to at least the one elongated member, wherein the lead-in conductor comprises a low resistance conductor configured to generate substantially no heat.

4112. The method of claim 4094, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor.

4113. The method of claim 4094, further comprising electrically coupling a lead-in conductor to at least the one elongated member using a cold pin transition conductor, wherein the cold pin transition conductor comprises a substantially low resistance insulated conductor.

4114. The method of claim 4094, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in an overburden of the formation.

4115. The method of claim 4094, further comprising coupling an overburden casing to the opening, wherein the overburden casing comprises steel.

4116. The method of claim 4094, further comprising coupling an overburden casing to the opening, wherein the overburden casing is disposed in cement.

4117. The method of claim 4094, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening.

4118. The method of claim 4094, further comprising coupling an overburden casing to the opening, wherein a packing material is disposed at a junction of the overburden casing and the opening, and wherein the method further comprises inhibiting a flow of fluid between the opening and the overburden casing with the packing material.

4119. The method of claim 4094, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

4120. An in situ method for heating an oil shale formation, comprising:

oxidizing a fuel fluid in a heater;

providing at least a portion of the oxidized fuel fluid into a conduit disposed in an opening of the formation;

allowing heat to transfer from the oxidized fuel fluid to a section of the formation; and

allowing additional heat to transfer from an electric heater disposed in the opening to the section of the formation, wherein heat is allowed to transfer substantially uniformly along a length of the opening.

4121. The method of claim 4120, wherein providing at least the portion of the oxidized fuel fluid into the opening comprises flowing the oxidized fuel fluid through a perforated conduit disposed in the opening.

4122. The method of claim 4120, wherein providing at least the portion of the oxidized fuel fluid into the opening comprises flowing the oxidized fuel fluid through a perforated conduit disposed in the opening, the method further comprising removing an exhaust fluid through the opening.

4123. The method of claim 4120, further comprising initiating oxidation of the fuel fluid in the heater with a flame.

4124. The method of claim 4120, further comprising removing the oxidized fuel fluid through the conduit.

4125. The method of claim 4120, further comprising removing the oxidized fuel fluid through the conduit and providing the removed oxidized fuel fluid to at least one additional heater disposed in the formation.

4126. The method of claim 4120, wherein the conduit comprises an insulator disposed on a surface of the conduit, the method further comprising tapering a thickness of the insulator such that heat is allowed to transfer substantially uniformly along a length of the conduit.

4127. The method of claim 4120, wherein the electric heater is an insulated conductor.

4128. The method of claim 4120, wherein the electric heater is a conductor disposed in the conduit.

4129. The method of claim 4120, wherein the electric heater is an elongated conductive member.

4130. A system configured to heat an oil shale formation, comprising:

one or more heat sources disposed within one or more open wellbores in the formation, wherein the one or more heat sources are configured to provide heat to at least a portion of the formation during use; and

wherein the system is configured to allow heat to transfer from the one or more heat sources to a selected section of the formation during use.

4131. The system of claim 4130, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4132. The system of claim 4130, wherein the one or more heat sources comprise electrical heaters.

4133. The system of claim 4130, wherein the one or more heat sources comprise surface burners.

4134. The system of claim 4130, wherein the one or more heat sources comprise flameless distributed combustors.

4135. The system of claim 4130, wherein the one or more heat sources comprise natural distributed combustors.

4136. The system of claim 4130, wherein the one or more open wellbores comprise a diameter of at least approximately 5 cm.

4137. The system of claim 4130, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation.

4138. The system of claim 4130, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

4139. The system of claim 4130, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

4140. The system of claim 4130, further comprising an overburden casing coupled to at an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores.

4141. The system of claim 4130, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores, and wherein the packing material is configured to substantially inhibit a flow of fluid between at least one of the one or more open wellbores and the overburden casing during use.

4142. The system of claim 4130, further comprising an overburden casing coupled to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores, and wherein the packing material comprises cement.

4143. The system of claim 4130, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the selected section.

4144. The system of claim 4130, further comprising a valve coupled to at least one of the one or more heat sources configured to control pressure within at least a majority of the selected section of the formation.

4145. The system of claim 4130, further comprising a valve coupled to a production well configured to control a pressure within at least a majority of the selected section of the formation.

4146. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation, wherein the one or more heat sources are disposed within one or more open wellbores in the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation.

4147. The method of claim 4146, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4148. The method of claim 4146, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range with a lower pyrolysis temperature of about 250°

C. and an upper pyrolysis temperature of about 400°

C.

4149. The method of claim 4146, wherein the one or more heat sources comprise electrical heaters.

4150. The method of claim 4146, wherein the one or more heat sources comprise surface burners.

4151. The method of claim 4146, wherein the one or more heat sources comprise flameless distributed combustors.

4152. The method of claim 4146, wherein the one or more heat sources comprise natural distributed combustors.

4153. The method of claim 4146, wherein the one or more heat sources are suspended within the one or more open wellbores.

4154. The method of claim 4146, wherein a tube is disposed in at least one of the one or more open wellbores proximate to the heat source, the method further comprising flowing a substantially constant amount of fluid into at least one of the one or more open wellbores through critical flow orifices in the tube.

4155. The method of claim 4146, wherein a perforated tube is disposed in at least one of the one or more open wellbores proximate to the heat source, the method further comprising flowing a corrosion inhibiting fluid into at least one of the open wellbores through the perforated tube.

4156. The method of claim 4146, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation.

4157. The method of claim 4146, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

4158. The method of claim 4146, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

4159. The method of claim 4146, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores.

4160. The method of claim 4146, further comprising coupling an overburden casing to at least one of the one or more open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the method further comprises inhibiting a flow of fluid between the at least one of the one or more open wellbores and the overburden casing with a packing material.

4161. The method of claim 4146, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

4162. The method of claim 4146, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

4163. The method of claim 4146, further comprising controlling a pressure with the wellbore.

4164. The method of claim 4146, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to at least one of the one or more heat sources.

4165. The method of claim 4146, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to a production well located in the formation.

4166. The method of claim 4146, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1°

C. per day during pyrolysis.

4167. The method of claim 4146, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity(C_v), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

4168. The method of claim 4146, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

4169. The method of claim 4146, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m °

C.).

4170. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

4171. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4172. The method of claim 4146, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4173. The method of claim 4146, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

4174. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4175. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4176. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4177. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4178. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4179. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4180. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4181. The method of claim 4146, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4182. The method of claim 4146, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

4183. The method of claim 4146, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4184. The method of claim 4146, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

4185. The method of claim 4146, further comprising controlling a pressure within at least a majority of the selected section of the formation.

4186. The method of claim 4146, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

4187. The method of claim 4146, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H₂ within the mixture greater than about 0.5 bars.

4188. The method of claim 4187, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

4189. The method of claim 4146, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

4190. The method of claim 4146, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

4191. The method of claim 4146, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

4192. The method of claim 4146, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

4193. The method of claim 4146, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

4194. The method of claim 4146, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

4195. The method of claim 4146, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

4196. The method of claim 4146, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for the production well.

4197. The method of claim 4196, wherein at least about 20 heat sources are disposed in the formation for each production well.

4198. The method of claim 4146, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4199. The method of claim 4146, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4200. The method of claim 4146, further comprising separating the produced mixture into a gas stream and a liquid stream.

4201. The method of claim 4146, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.

4202. The method of claim 4146, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.

4203. The method of claim 4146, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.

4204. The method of claim 4146, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

4205. The method of claim 4146, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

4206. The method of claim 4146, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H₂.

4207. The method of claim 4146, wherein the selected section is heated to a minimum pyrolysis temperature of about 270°

C.

4208. The method of claim 4146, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

4209. The method of claim 4146, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons.

4210. The method of claim 4146, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.

4211. A mixture produced from a portion of an oil shale formation, the mixture comprising:

an olefin content of less than about 10% by weight; and

an average carbon number less than about 35.

4212. The mixture of claim 4211, further comprising an average carbon number less than about 30.

4213. The mixture of claim 4211, further comprising an average carbon number less than about 25.

4214. The mixture of claim 4211, further comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5; and

wherein a weight ratio of the hydrocarbons having carbon numbers from 2 through 4, to methane, in the mixture is greater than approximately 1.

4215. The mixture of claim 4211, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4216. The mixture of claim 4211, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4217. The mixture of claim 4211, further comprising condensable hydrocarbons, wherein an olefin content of the condensable hydrocarbons is greater than about 0.1% by weight of the condensable hydrocarbons, and wherein the olefin content of the condensable hydrocarbons is less than about 15% by weight of the condensable hydrocarbons.

4218. The mixture of claim 4211, further comprising condensable hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons have a carbon number greater than about 25.

4219. The mixture of claim 4218, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4220. The mixture of claim 4211, further comprising condensable hydrocarbons, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4221. The mixture of claim 4211, further comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than about 5, wherein a weight ratio of the hydrocarbons having carbon number from 2 through 4, to methane, in the mixture is greater than approximately 1;

wherein the non-condensable hydrocarbons further comprise H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂; and

condensable hydrocarbons, comprising;

oxygenated hydrocarbons, wherein greater than about 1.5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons; and

aromatic compounds, wherein greater than about 20% by weight of the condensable hydrocarbons comprises aromatic compounds.

4222. The mixture of claim 4211, further comprising:

condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises hydrocarbons having a carbon number greater than about 25;

wherein the condensable hydrocarbons further comprise;

oxygenated hydrocarbons, wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons; and

aromatic compounds, wherein greater than about 30% by weight of the condensable hydrocarbons comprises aromatic compounds; and

non-condensable hydrocarbons comprising H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.

4223. The mixture of claim 4211, further comprising condensable hydrocarbons, comprising:

olefins, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons comprises olefins; and

asphaltenes, wherein less than about 0.1% by weight of the condensable hydrocarbons comprises asphaltenes.

4224. The mixture of claim 4223, further comprising oxygenated hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4225. The mixture of claim 4224, further comprising oxygenated hydrocarbons, wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4226. The mixture of claim 4211, further comprising condensable hydrocarbons, comprising:

olefins, wherein about 0.1% by weight to about 2% by weight of the condensable hydrocarbons comprises olefins; and

multi-ring aromatics, wherein less than about 2% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4227. The mixture of claim 4211, further comprising:

non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, wherein greater than about 10% by weight of the non-condensable hydrocarbons comprises H₂;

ammonia, wherein greater than about 0.5% by weight of the mixture comprises ammonia; and

hydrocarbons, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.4.

4228. A mixture produced from a portion of an oil shale formation, the mixture, comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5; and

wherein a weight ratio of the hydrocarbons having carbon numbers from 2 through 4, to methane, in the mixture is greater than approximately 1.

4229. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4230. The mixture of claim 4228, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4231. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4232. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4233. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4234. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4235. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4236. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4237. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4238. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise cycloalkanes.

4239. The mixture of claim 4228, wherein the non-condensable hydrocarbons further comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons, and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4240. The mixture of claim 4228, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4241. The mixture of claim 4228, further comprising ammonia, wherein the ammonia is used to produce fertilizer.

4242. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein less than about 15 weight % of the condensable hydrocarbons have a carbon number greater than approximately 25.

4243. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein the condensable hydrocarbons comprise olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.

4244. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein the condensable hydrocarbons comprises olefins, and wherein about 0.1% to about 2.5% by weight of the condensable hydrocarbons comprises olefins.

4245. The mixture of claim 4228, further comprising condensable hydrocarbons, wherein the condensable hydrocarbons comprise oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4246. The mixture of claim 4228, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H_2.

4247. The mixture of claim 4228, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H_2.

4248. The mixture of claim 4228, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.

4249. A mixture produced from a portion of an oil shale formation, the mixture comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1; and

condensable hydrocarbons comprising oxygenated hydrocarbons, wherein greater than about 5% by weight of the condensable component comprises oxygenated hydrocarbons.

4250. The mixture of claim 4249, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4251. The mixture of claim 4249, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4252. The mixture of claim 4249, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4253. The mixture of claim 4249, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4254. The mixture of claim 4249, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4255. The mixture of claim 4249, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4256. The mixture of claim 4249, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4257. The mixture of claim 4249, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4258. The mixture of claim 4249, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4259. The mixture of claim 4249, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4260. The mixture of claim 4249, wherein the non-condensable hydrocarbons comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons, and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4261. The mixture of claim 4249, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4262. The mixture of claim 4249, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

4263. The mixture of claim 4249, wherein less than about 5 weight % of the condensable hydrocarbons in the mixture have a carbon number greater than approximately 25.

4264. The mixture of claim 4249, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.

4265. The mixture of claim 4249, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% to about 2.5% by weight of the condensable hydrocarbons comprises olefins.

4266. The mixture of claim 4249, wherein the non-condensable hydrocarbons further comprise H₂, wherein greater than about 5% by weight of the mixture comprises H₂.

4267. The mixture of claim 4249, wherein the non-condensable hydrocarbons further comprise H₂, wherein greater than about 15% by weight of the mixture comprises H₂.

4268. The mixture of claim 4249, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.

4269. A mixture produced from a portion of an oil shale formation, the mixture comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1;

condensable hydrocarbons;

wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises nitrogen;

wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises oxygen; and

wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons comprises sulfur.

4270. The mixture of claim 4269, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4271. The mixture of claim 4269, wherein less than about 5 weight % of the condensable hydrocarbons have a carbon number greater than approximately 25.

4272. The mixture of claim 4269, wherein the condensable hydrocarbons comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4273. The mixture of claim 4269, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4274. The mixture of claim 4269, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4275. The mixture of claim 4269, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4276. The mixture of claim 4269, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4277. The mixture of claim 4269, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4278. The mixture of claim 4269, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4279. The mixture of claim 4269, wherein the non-condensable hydrocarbons comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4280. The mixture of claim 4269, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4281. The mixture of claim 4269, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4282. The mixture of claim 4269, wherein the condensable hydrocarbons comprises oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable component comprises oxygenated hydrocarbons.

4283. The mixture of claim 4269, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.

4284. The mixture of claim 4269, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the mixture comprises H₂.

4285. The mixture of claim 4269, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater, than about 0.3.

4286. A mixture produced from a portion of an oil shale formation, the mixture comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1;

ammonia, wherein greater than about 0.5% by weight of the mixture comprises ammonia; and

condensable hydrocarbons comprising oxygenated hydrocarbons, wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4287. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4288. The mixture of claim 4286, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4289. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4290. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4291. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4292. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4293. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4294. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise multi-aromatic rings, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4295. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4296. The mixture of claim 4286, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4297. The mixture of claim 4286, wherein the non-condensable hydrocarbons further comprise hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons, and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4298. The mixture of claim 4286, wherein the produced mixture further comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4299. The mixture of claim 4286, wherein the produced mixture further comprises ammonia, and wherein the ammonia is used to produce fertilizer.

4300. The mixture of claim 4286, wherein the condensable hydrocarbons comprise hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately 25.

4301. The mixture of claim 4286, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 5% by weight of the mixture comprises H₂.

4302. The mixture of claim 4286, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 15% by weight of the mixture comprises H₂.

4303. The mixture of claim 4286, wherein the non-condensable hydrocarbons further comprise hydrocarbons having carbon numbers of greater than 2, wherein a weight ratio of hydrocarbons having carbon numbers greater than 2, to methane, is greater than about

4304. A mixture produced from a portion of an oil shale formation, the mixture comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than 5, wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1; and

condensable hydrocarbons comprising olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins.

4305. The mixture of claim 4304, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4306. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4307. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4308. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4309. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4310. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4311. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4312. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4313. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4314. The mixture of claim 4304, wherein the non-condensable hydrocarbons further comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4315. The mixture of claim 4304, wherein the produced mixture further comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4316. The mixture of claim 4304, wherein the produced mixture further comprises ammonia, and wherein the ammonia is used to produce fertilizer.

4317. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15% by weight of the hydrocarbons have a carbon number greater than approximately 25.

4318. The mixture of claim 4304, wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.

4319. The mixture of claim 4304, wherein about 0.1% to about 2% by weight of the condensable component comprises olefins.

4320. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4321. The mixture of claim 4304, wherein the condensable hydrocarbons further comprise oxygenated hydrocarbons, and wherein greater than about 25% by weight of the condensable component comprises oxygenated hydrocarbons.

4322. The mixture of claim 4304, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H_2.

4323. The mixture of claim 4304, wherein the non-condensable hydrocarbons further comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H_2.

4324. The mixture of claim 4304, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.

4325. A mixture produced from a portion of an oil shale formation, comprising:

condensable hydrocarbons, wherein less than about 15 weight % of the condensable hydrocarbons have a carbon number greater than 25; and

wherein the condensable hydrocarbons comprise oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4326. The mixture of claim 4325, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1.

4327. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4328. The mixture of claim 4325, further comprising non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4329. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4330. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4331. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4332. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4333. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4334. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4335. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4336. The mixture of claim 4325, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4337. The mixture of claim 4325, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable hydrocarbons and wherein the hydrogen is less than about 80% by volume of the non-condensable hydrocarbons.

4338. The mixture of claim 4325, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4339. The mixture of claim 4325, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4340. The mixture of claim 4325, wherein the condensable hydrocarbons further comprises olefins, and wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins.

4341. The mixture of claim 4325, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.

4342. The mixture of claim 4325, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.

4343. The mixture of claim 4325, wherein the condensable hydrocarbons further comprises oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable hydrocarbons comprises the oxygenated hydrocarbon.

4344. The mixture of claim 4325, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.

4345. The mixture of claim 4325, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H_2.

4346. The mixture of claim 4325, wherein a weight ratio of hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.

4347. A mixture produced from a portion of an oil shale formation, comprising:

condensable hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons have a carbon number greater than about 25;

wherein less than about 1% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is nitrogen;

wherein less than about 1% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is oxygen; and

wherein less than about 1% by weight of the condensable hydrocarbons, when calculated on an atomic basis, is sulfur.

4348. The mixture of claim 4347, further comprising non-condensable hydrocarbons, wherein the non-condensable component comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1.

4349. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4350. The mixture of claim 4347, further comprising non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4351. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4352. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4353. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise multi-ring aromatic s, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4354. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4355. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4356. The mixture of claim 4347, further comprising non-condensable hydrocarbons, and wherein the non-condensable hydrocarbons comprise hydrogen, and wherein greater than about 10% by volume and less than about 80% by volume of the non-condensable component comprises hydrogen.

4357. The mixture of claim 4347, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4358. The mixture of claim 4347, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4359. The mixture of claim 4347, wherein the condensable component further comprises olefins, and wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.

4360. The mixture of claim 4347, wherein the condensable component further comprises olefins, and wherein about 0.1% to about 2.5% by weight of the condensable component comprises olefins.

4361. The mixture of claim 4347, wherein the condensable hydrocarbons further comprise oxygenated hydrocarbons, and wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4362. The mixture of claim 4347, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.

4363. The mixture of claim 4347, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.

4364. The mixture of claim 4347, further comprising non-condensable hydrocarbons, wherein a weight ratio of compounds within the non-condensable hydrocarbons having greater than about 2 carbon atoms, to methane, is greater than about 0.3.

4365. A mixture produced from a portion of an oil shale formation, comprising:

condensable hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons have a carbon number greater than 20; and

wherein the condensable hydrocarbons comprise olefins, wherein an olefin content of the condensable component is less than about 10% by weight of the condensable component.

4366. The mixture of claim 4365, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1.

4367. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4368. The mixture of claim 4365, further comprising non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4369. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4370. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4371. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4372. The mixture of claim 4365, wherein the condensable hydrocarbons, wherein about % by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4373. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4374. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4375. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4376. The mixture of claim 4365, wherein the condensable hydrocarbons further comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4377. The mixture of claim 4365, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprises hydrogen, and wherein the hydrogen is about 10% by volume to about 80% by volume of the non-condensable hydrocarbons.

4378. The mixture of claim 4365, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4379. The mixture of claim 4365, further comprising ammonia, and wherein the ammonia is used to produce fertilizer

4380. The mixture of claim 4365, wherein about 0.1% to about 5% by weight of the condensable component comprises olefins.

4381. The mixture of claim 4365, wherein about 0.1% to about 2% by weight of the condensable component comprises olefins.

4382. The mixture of claim 4365, wherein the condensable component further comprises oxygenated hydrocarbons, and wherein greater than about 1.5% by weight of the condensable component comprises oxygenated hydrocarbons.

4383. The mixture of claim 4365, wherein the condensable component further comprises oxygenated hydrocarbons, and wherein greater than about 25% by weight of the condensable component comprises oxygenated hydrocarbons.

4384. The mixture of claim 4365, further comprising non-condensable hydrocarbons, wherein th e non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H₂.

4385. The mixture of claim 4365, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.

4386. The mixture of claim 4365, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 0.3.

4387. A mixture produced from a portion of an oil shale formation, comprising:

condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises hydrocarbons having a carbon number greater than about 25; and

wherein the condensable hydrocarbons further comprise aromatic compounds, wherein more than about 20% by weight of the condensable hydrocarbons comprises aromatic compounds.

4388. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1.

4389. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4390. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4391. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4392. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4393. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4394. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4395. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4396. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4397. The mixture of claim 4387, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4398. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise hydrogen, and wherein the hydrogen is greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons.

4399. The mixture of claim 4387, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4400. The mixture of claim 4387, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4401. The mixture of claim 4387, wherein the condensable hydrocarbons further comprise olefins, and wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.

4402. The mixture of claim 4387, wherein the condensable hydrocarbons further comprises olefins, and wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.

4403. The mixture of claim 4387, wherein the condensable hydrocarbons further comprises multi-ring aromatic compounds, and wherein less than about 2% by weight of the condensable hydrocarbons comprises multi-ring aromatic compounds.

4404. The mixture of claim 4387, wherein the condensable hydrocarbons comprises oxygenated hydrocarbons, and wherein greater than about 1.5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4405. The mixture of claim 4387, wherein the condensable hydrocarbons comprises oxygenated hydrocarbons, and wherein greater than about 25% by weight of the condensable component comprises oxygenated hydrocarbons.

4406. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 5% by weight of the non-condensable hydrocarbons comprises H_2.

4407. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, and wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.

4408. The mixture of claim 4387, further comprising non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 0.3.

4409. A mixture produced from a portion of an oil shale formation, comprising:

non-condensable hydrocarbons comprising hydrocarbons having carbon numbers of less than about 5, wherein a weight ratio of the hydrocarbons having carbon number from 2 through 4, to methane, in the mixture is greater than approximately 1;

wherein the non-condensable hydrocarbons further comprise H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂; and

condensable hydrocarbons, comprising;

oxygenated hydrocarbons, wherein greater than about 1.5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons;

olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins; and

aromatic compounds, wherein greater than about 20% by weight of the condensable hydrocarbons comprises aromatic compounds.

4410. The mixture of claim 4409, wherein the non-condensable hydrocarbons further comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4411. The mixture of claim 4409, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4412. The mixture of claim 4409, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4413. The mixture of claim 4409, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4414. The mixture of claim 4409, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4415. The mixture of claim 4409, wherein the condensable hydrocarbons comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4416. The mixture of claim 4409, wherein the condensable hydrocarbons comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4417. The mixture of claim 4409, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4418. The mixture of claim 4409, wherein the non-condensable hydrocarbons further comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons.

4419. The mixture of claim 4409, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4420. The mixture of claim 4409, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4421. The mixture of claim 4409, wherein the condensable hydrocarbons further comprise hydrocarbons having a carbon number of greater than approximately 25, wherein less than about 15% by weight of the hydrocarbons have a carbon number greater than approximately 25.

4422. The mixture of claim 4409, wherein about 0.1% to about 5% by weight of the condensable hydrocarbons comprises olefins.

4423. The mixture of claim 4409, wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.

4424. The mixture of claim 4409, wherein greater than about 25% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4425. The mixture of claim 4409, wherein the mixture comprises hydrocarbons having greater than about 2 carbon atoms, and wherein the weight ratio of hydrocarbons having greater than about 2 carbon atoms to methane is greater than about 0.3.

4426. A mixture produced from a portion of an oil shale formation, comprising:

condensable hydrocarbons, wherein less than about 5% by weight of the condensable hydrocarbons comprises hydrocarbons having a carbon number greater than about 25;

wherein the condensable hydrocarbons further comprise;

oxygenated hydrocarbons, wherein greater than about 5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons;

olefins, wherein less than about 10% by weight of the condensable hydrocarbons comprises olefins; and

aromatic compounds, wherein greater than about 30% by weight of the condensable hydrocarbons comprises aromatic compounds; and

non-condensable hydrocarbons comprising H₂, wherein greater than about 15% by weight of the non-condensable hydrocarbons comprises H₂.

4427. The mixture of claim 4426, wherein the non-condensable hydrocarbons further comprises hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, is greater than approximately 1.

4428. The mixture of claim 4426, wherein the non-condensable hydrocarbons comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4429. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4430. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4431. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4432. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4433. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4434. The mixture of claim 4426, wherein the condensable hydrocarbons further comprise asphaltenes, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4435. The mixture of claim 4426, wherein the condensable hydrocarbons comprise cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4436. The mixture of claim 4426, wherein greater than about 10% by volume and less than about 80% by volume of the non-condensable hydrocarbons comprises hydrogen.

4437. The mixture of claim 4426, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4438. The mixture of claim 4426, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4439. The mixture of claim 4426, wherein about 0.1%to about 5%by weight of the condensable hydrocarbons comprises olefins.

4440. The mixture of claim 4426, wherein about 0.1% to about 2% by weight of the condensable hydrocarbons comprises olefins.

4441. The mixture of claim 4426, wherein the condensable hydrocarbons comprises oxygenated hydrocarbons, and wherein greater than about 15% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4442. The mixture of claim 4426, wherein the mixture comprises hydrocarbons having greater than about 2 carbon atoms, and wherein the weight ratio of hydrocarbons having greater than about 2 carbon atoms to methane is greater than about 0.3.

4443. Condensable hydrocarbons produced from a portion of an oil shale formation, comprising:

olefins, wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons comprises olefins;

oxygenated hydrocarbons, wherein less than about 15% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons; and

asphaltenes, wherein less than about 0.1% by weight of the condensable hydrocarbons comprises asphaltenes.

4444. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises hydrocarbons having a carbon number of greater than approximately 25, and wherein less than about 15 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately 25.

4445. The mixture of claim 4443, wherein about 0.1% by weight to about 5% by weight of the condensable hydrocarbons comprises olefins.

4446. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises non-condensable hydrocarbons, wherein the non-condensable hydrocarbons comprise ethene and ethane, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4447. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4448. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4449. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4450. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4451. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4452. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises multi-ring aromatics, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4453. The mixture of claim 4443, wherein the condensable hydrocarbons further comprises cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4454. The mixture of claim 4443, wherein the condensable hydrocarbons comprises non-condensable hydrocarbons, and wherein the non-condensable hydrocarbons comprise hydrogen, and wherein greater than about 10% by volume of the non-condensable hydrocarbons and less than about 80% by volume of the non-condensable hydrocarbons comprises hydrogen.

4455. The mixture of claim 4443, further comprising ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4456. The mixture of claim 4443, further comprising ammonia, and wherein the ammonia is used to produce fertilizer.

4457. The mixture of claim 4443, wherein about 0.1% by weight to about 2% by weight of the condensable hydrocarbons comprises olefins.

4458. A mixture of condensable hydrocarbons produced from a portion of an oil shale formation, comprising:

olefins, wherein about 0.1% by weight to about 2% by weight of the condensable hydrocarbons comprises olefins;

multi-ring aromatics, wherein less than about 2% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings; and

oxygenated hydrocarbons, wherein greater than about 25% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4459. The mixture of claim 4458, further comprising hydrocarbons having a carbon number of greater than approximately 25, wherein less than about 5 weight % of the hydrocarbons in the mixture have a carbon number greater than approximately 25.

4460. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises nitrogen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4461. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises oxygen containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4462. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises sulfur containing compounds, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4463. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises oxygen containing compounds, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4464. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises aromatic compounds, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4465. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4466. The mixture of claim 4458, wherein the condensable hydrocarbons further comprises cycloalkanes, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4467. The mixture of claim 4458, further comprising ammonia, wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4468. The mixture of claim 4458, further comprising ammonia, wherein the ammonia is used to produce fertilizer.

4469. A mixture produced from a portion of an oil shale formation, comprising:

non-condensable hydrocarbons and H₂, wherein greater than about 10% by volume of the non-condensable hydrocarbons and H₂ comprises H₂;

ammonia and water, wherein greater than about 0.5% by weight of the mixture comprises ammonia; and

condensable hydrocarbons.

4470. The mixture of claim 4469, wherein the non-condensable hydrocarbons further comprise hydrocarbons having carbon numbers of less than 5, and wherein a weight ratio of the hydrocarbons having carbon numbers from 2 through 4 to methane, in the mixture is greater than approximately 1.

4471. The mixture of claim 4469, wherein greater than about 0.1% by weight of the condensable hydrocarbons are olefins, and wherein less than about 15% by weight of the condensable hydrocarbons are olefins.

4472. The mixture of claim 4469, wherein the non-condensable hydrocarbons further comprise ethene and ethane, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is greater than about 0.001, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15.

4473. The mixture of claim 4469, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4474. The mixture of claim 4469, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4475. The mixture of claim 4469, wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4476. The mixture of claim 4469, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4477. The mixture of claim 4469, wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4478. The mixture of claim 4469, wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4479. The mixture of claim 4469, wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

4480. The mixture of claim 4469, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4481. The mixture of claim 4469, wherein the H₂ is less than about 80% by volume of the non-condensable hydrocarbons and H₂.

4482. The mixture of claim 4469, wherein the condensable hydrocarbons further comprise sulfur containing compounds.

4483. The mixture of claim 4469, wherein the ammonia is used to produce fertilizer.

4484. The mixture of claim 4469, wherein less than about 5% of the condensable hydrocarbons have carbon numbers greater than 25.

4485. The mixture of claim 4469, wherein the condensable hydrocarbons comprise olefins, wherein greater than about 0.001% by weight of the condensable hydrocarbons comprise olefins, and wherein less than about 15% by weight of the condensable hydrocarbons comprise olefins.

4486. The mixture of claim 4469, wherein the condensable hydrocarbons comprise olefins, wherein greater than about 0.001% by weight of the condensable hydrocarbons comprise olefins, and wherein less than about 10% by weight of the condensable hydrocarbons comprise olefins.

4487. The mixture of claim 4469, wherein the condensable hydrocarbons comprise oxygenated hydrocarbons, and wherein greater than about 1.5% by weight of the condensable hydrocarbons comprises oxygenated hydrocarbons.

4488. The mixture of claim 4469, wherein the condensable hydrocarbons further comprise nitrogen containing compounds.

4489. A method of treating an oil shale formation in situ comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4490. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, and wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units.

4491. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, and wherein a ratio of heat sources in the repetitive pattern of units to production wells in the repetitive pattern is greater than approximately 5.

4492. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more production wells are located within an area defined by the plurality of units, wherein the three or more production wells are located in the formation in a unit of production wells, and wherein the unit of production wells comprises a triangular pattern.

4493. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more injection wells are located within an area defined by the plurality of units, wherein the three or more injection wells are located in the formation in a unit of injection wells, and wherein the unit of injection wells comprises a triangular pattern.

4494. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more production wells and three or more injection wells are located within an area defined by the plurality of units, wherein the three or more production wells are located in the formation in a unit of production wells, wherein the unit of production wells comprises a first triangular pattern, wherein the three or more injection wells are located in the formation in a unit of injection wells, wherein the unit of injection wells comprises a second triangular pattern, and wherein the first triangular pattern is substantially different than the second triangular pattern.

4495. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a plurality of the units, wherein the plurality of units are repeated over an area of the formation to form a repetitive pattern of units, wherein three or more monitoring wells are located within an area defined by the plurality of units, wherein the three or more monitoring wells are located in the formation in a unit of monitoring wells, and wherein the unit of monitoring wells comprises a triangular pattern.

4496. The method of claim 4489, wherein a production well is located in an area defined by the unit of heat sources.

4497. The method of claim 4489, wherein three or more of the heat sources are located in the formation in a first unit and a second unit, wherein the first unit is adjacent to the second unit, and wherein the first unit is inverted with respect to the second unit.

4498. The method of claim 4489, wherein a distance between each of the heat sources in the unit of heat sources varies by less than about 20%.

4499. The method of claim 4489, wherein a distance between each of the heat sources in the unit of heat sources is approximately equal.

4500. The method of claim 4489, wherein providing heat from three or more heat sources comprises substantially uniformly providing heat to at least the portion of the formation.

4501. The method of claim 4489, wherein the heated portion comprises a substantially uniform temperature distribution.

4502. The method of claim 4489, wherein the heated portion comprises a substantially uniform temperature distribution, and wherein a difference between a highest temperature in the heated portion and a lowest temperature in the heated portion comprises less than about 200°

C.

4503. The method of claim 4489, wherein a temperature at an outer lateral boundary of the triangular pattern and a temperature at a center of the triangular pattern are approximately equal.

4504. The method of claim 4489, wherein a temperature at an outer lateral boundary of the triangular pattern and a temperature at a center of the triangular pattern increase substantially linearly after an initial period of time, and wherein the initial period of time comprises less than approximately 3 months.

4505. The method of claim 4489, wherein a time required to increase an average temperature of the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase the average temperature of the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately equal to a space between each of the heat sources in the hexagonal pattern.

4506. The method of claim 4489, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately equal to a space between each of the heat sources in the hexagonal pattern.

4507. The method of claim 4489, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially less than a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a number of heat sources per unit area in the triangular pattern is equal to the number of heat sources per unit are in the hexagonal pattern of heat sources.

4508. The method of claim 4489, wherein a time required to increase a temperature at a coldest point within the heated portion to a selected temperature with the triangular pattern of heat sources is substantially equal to a time required to increase a temperature at the coldest point within the heated portion to the selected temperature with a hexagonal pattern of heat sources, and wherein a space between each of the heat sources in the triangular pattern is approximately 5 m greater than a space between each of the heat sources in the hexagonal pattern.

4509. The method of claim 4489, wherein providing heat from three or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from three or more of the heat sources, wherein the formation has an average heat capacity (C_v), and wherein heat from three or more of the heat sources pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation;

Pwr=h*V*C_v*ρ

_B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρ

_B is formation bulk density, and wherein the heating rate is less than about 10°

C./day.

4510. The method of claim 4489, wherein three or more of the heat sources comprise electrical heaters.

4511. The method of claim 4489, wherein three or more of the heat sources comprise surface burners.

4512. The method of claim 4489, wherein three or more of the heat sources comprise flameless distributed combustors.

4513. The method of claim 4489, wherein three or more of the heat sources comprise natural distributed combustors.

4514. The method of claim 4489, further comprising:

allowing the heat to transfer from three or more of the heat sources to a selected section of the formation such that heat from three or more of the heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation; and

producing a mixture of fluids from the formation.

4515. The method of claim 4514, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

4516. The method of claim 4514, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0°

C. per day during pyrolysis.

4517. The method of claim 4514, wherein allowing the heat to transfer from three or more of the heat sources to the selected section comprises transferring heat substantially by conduction.

4518. The method of claim 4514, wherein providing heat from three or more of the heat sources to at least the portion of the formation comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/m °

C.

4519. The method of claim 4514, wherein the produced mixture comprises an API gravity of at least 25°

.

4520. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

4521. The method of claim 4514, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

4522. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

4523. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

4524. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

4525. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

4526. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

4527. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

4528. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.1% by weight of the condensable hydrocarbons are asphaltenes.

4529. The method of claim 4514, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

4530. The method of claim 4514, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein greater than about 10% by volume of the non-condensable component comprises hydrogen, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

4531. The method of claim 4514, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

4532. The method of claim 4514, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

4533. The method of claim 4514, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H₂, wherein a partial pressure of H₂ within the mixture is greater than about 2.0 bars absolute.

4534. The method of claim 4514, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

4535. The method of claim 4514, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

4536. The method of claim 4514, further comprising:

providing hydrogen (H₂) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

4537. The method of claim 4514, further comprising:

producing hydrogen from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

4538. The method of claim 4514, wherein allowing the heat to transfer from three or more of the heat sources to the selected section of the formation comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

4539. The method of claim 4514, wherein allowing the heat to transfer from three or more of the heat sources to the selected section of the formation comprises substantially uniformly increasing a permeability of a majority of the selected section.

4540. The method of claim 4514, further comprising controlling the heat from three or more heat sources to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

4541. The method of claim 4514, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

4542. The method of claim 4541, wherein at least about 20 heat sources are disposed in the formation for each production well.

4543. The method of claim 4514, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4544. The method of claim 4514, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4545. A method for in situ production of synthesis gas from an oil shale formation, comprising:

heating a section of the formation to a temperature sufficient to allow synthesis gas generation, wherein a permeability of the section is substantially uniform and greater than a permeability of an unheated section of the formation when the temperature sufficient to allow synthesis gas generation within the formation is achieved;

providing a synthesis gas generating fluid to the section to generate synthesis gas; and

removing synthesis gas from the formation.

4546. The method of claim 4545, wherein the permeability of the section is greater than about 100 millidarcy when the temperature sufficient to allow synthesis gas generation within the formation is achieved.

4547. The method of claim 4545, wherein the temperature sufficient to allow synthesis gas generation ranges from approximately 400°

C. to approximately 1200°

C.

4548. The method of claim 4545, further comprising heating the section when providing the synthesis gas generating fluid to inhibit temperature decrease in the section due to synthesis gas generation.

4549. The method of claim 4545, wherein heating the section comprises convecting an oxidizing fluid into a portion of the section, wherein the temperature within the section is above a temperature sufficient to support oxidation of carbon within the section with the oxidizing fluid, and reacting the oxidizing fluid with carbon in the section to generate heat within the section.

4550. The method of claim 4549, wherein the oxidizing fluid comprises air.

4551. The method of claim 4550, wherein an amount of the oxidizing fluid convected into the section is configured to inhibit formation of oxides of nitrogen by maintaining a reaction temperature below a temperature sufficient to produce oxides of nitrogen compounds.

4552. The method of claim 4545, wherein heating the section comprises diffusing an oxidizing fluid to reaction zones adjacent to wellbores within the formation, oxidizing carbon within the reaction zone to generate heat, and transferring the heat to the section.

4553. The method of claim 4545, wherein heating the section comprises heating the section by transfer of heat from one or more of electrical heaters.

4554. The method of claim 4545, wherein heating the section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to the section comprises introducing steam into the section to heat the formation and to generate synthesis gas.

4555. The method of claim 4545, further comprising controlling the heating of the section and provision of the synthesis gas generating fluid to maintain a temperature within the section above the temperature sufficient to generate synthesis gas.

4556. The method of claim 4545, further comprising:

monitoring a composition of the produced synthesis gas; and

controlling heating of the section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a selected range.

4557. The method of claim 4556, wherein the selected range comprises a ratio of H₂ to CO of about 2:

1.

4558. The method of claim 4545, wherein the synthesis gas generating fluid comprises liquid water.

4559. The method of claim 4545, wherein the synthesis gas generating fluid comprises steam.

4560. The method of claim 4545, wherein the synthesis gas generating fluid comprises water and carbon dioxide, and wherein the carbon dioxide inhibits production of carbon dioxide from hydrocarbon containing material within the section.

4561. The method of claim 4560, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4562. The method of claim 4545, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4563. The method of claim 4562, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4564. The method of claim 4545, wherein providing the synthesis gas generating fluid to the section comprises raising a water table of the formation to allow water to flow into the section.

4565. The method of claim 4545, wherein the synthesis gas is removed from a producer well equipped with a heating source, and wherein a portion of the heating source adjacent to a synthesis gas producing zone operates at a substantially constant temperature to promote production of the synthesis gas wherein the synthesis gas has a selected composition.

4566. The method of claim 4565, wherein the substantially constant temperature is about 700°

C., and wherein the selected composition has a H₂ to CO ratio of about 2;

1.

4567. The method of claim 4545, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the section to increase a H₂ concentration of the generated synthesis gas.

4568. The method of claim 4545, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the section to increase an energy content of the synthesis gas removed from the formation.

4569. The method of claim 4545, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4570. The method of claim 4545, further comprising generating electricity from the synthesis gas using a fuel cell.

4571. The method of claim 4545, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4572. The method of claim 4545, further comprising using a portion of the synthesis gas as a combustion fuel to heat the formation.

4573. The method of claim 4545, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.

4574. The method of claim 4545, further comprising converting at least a portion of the produced synthesis gas to methanol.

4575. The method of claim 4545, further comprising converting at least a portion of the produced synthesis gas to gasoline.

4576. The method of claim 4545, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.

4577. The method of claim 4545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4578. The method of claim 4545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4579. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to substantially uniformly increase a permeability of the portion and to increase a temperature of the portion to a temperature sufficient to allow synthesis gas generation;

providing a synthesis gas generating fluid to at least the portion of the selected section, wherein the synthesis gas generating fluid comprises carbon dioxide;

obtaining a portion of the carbon dioxide of the synthesis gas generating fluid from the formation; and

producing synthesis gas from the formation.

4580. The method of claim 4579, wherein the temperature sufficient to allow synthesis gas generation is within a range from about 400°

C. to about 1200°

C.

4581. The method of claim 4579, further comprising using a second portion of the separated carbon dioxide as a flooding agent to produce hydrocarbon bed methane from an oil shale formation.

4582. The method of claim 4581, wherein the oil shale formation is a deep oil shale formation over 760 m below ground surface.

4583. The method of claim 4581, wherein the oil shale formation adsorbs some of the carbon dioxide to sequester the carbon dioxide.

4584. The method of claim 4579, further comprising using a second portion of the separated carbon dioxide as a flooding agent for enhanced oil recovery.

4585. The method of claim 4579, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons undergo a reaction within the selected section to increase a H₂ concentration within the produced synthesis gas.

4586. The method of claim 4579, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the selected section to increase an energy content of the produced synthesis gas.

4587. The method of claim 4579, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4588. The method of claim 4579, further comprising generating electricity from the synthesis gas using a fuel cell.

4589. The method of claim 4579, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.

4590. The method of claim 4579, further comprising using a portion of the synthesis gas as a combustion fuel for heating the formation.

4591. The method of claim 4579, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.

4592. The method of claim 4579, further comprising converting at least a portion of the produced synthesis gas to methanol.

4593. The method of claim 4579, further comprising converting at least a portion of the produced synthesis gas to gasoline.

4594. The method of claim 4579, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.

4595. The method of claim 4579, wherein a temperature of at least one heat source is maintained at a temperature of less than approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of greater than about 2.

4596. The method of claim 4579, wherein a temperature of at least one heat source is maintained at a temperature of greater than approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of less than about 2.

4597. The method of claim 4579, wherein a temperature of at least one heat source is maintained at a temperature of approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of approximately 2.

4598. The method of claim 4579, wherein a heat source of the one or more of heat sources comprises an electrical heater.

4599. The method of claim 4579, wherein a heat source of the one or more heat sources comprises a natural distributed heater.

4600. The method of claim 4579, wherein a heat source of the one or more heat sources comprises a flameless distributed combustor (FDC) heater, and wherein fluids are produced from the wellbore of the FDC heater through a conduit positioned within the wellbore.

4601. The method of claim 4579, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4602. The method of claim 4579, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4603. A method of in situ synthesis gas production, comprising:

providing heat from one or more flameless distributed combustor heaters to at least a first portion of an oil shale formation;

allowing the heat to transfer from the one or more heaters to a selected section of the formation such that the heat from the one or more heaters substantially uniformly increases a permeability of the selected section, and to raise a temperature of the selected section to a temperature sufficient to generate synthesis gas;

introducing a synthesis gas producing fluid into the selected section to generate synthesis gas; and

removing synthesis gas from the formation.

4604. The method of claim 4603, wherein the one or more heaters comprise at least two heaters, and wherein superposition of heat from at least the two heaters substantially uniformly increases a permeability of the selected section, and raises a temperature of the selected section to a temperature sufficient to generate synthesis gas.

4605. The method of claim 4603, further comprising producing the synthesis gas from the formation under pressure, and generating electricity from the produced synthesis gas by passing the produced synthesis gas through a turbine.

4606. The method of claim 4603, further comprising producing pyrolyzation products from the formation when raising the temperature of the selected section to the temperature sufficient to generate synthesis gas.

4607. The method of claim 4603, further comprising separating a portion of carbon dioxide from the removed synthesis gas, and storing the carbon dioxide within a spent portion of the formation.

4608. The method of claim 4603, further comprising storing carbon dioxide within a spent portion of the formation, wherein an amount of carbon dioxide stored within the spent portion of the formation is equal to or greater than an amount of carbon dioxide within the removed synthesis gas.

4609. The method of claim 4603, further comprising separating a portion of H₂ from the removed synthesis gas;

and using a portion of the separated H₂ as fuel for the one or more heaters.

4610. The method of claim 4603, further comprising using a portion of exhaust products from one or more heaters as a portion of the synthesis gas producing fluid

4611. The method of claim 4603, further comprising using a portion of the removed synthesis gas with a fuel cell to generate electricity.

4612. The method of claim 4611, wherein the fuel cell produces steam, and wherein a portion of the steam is used as a portion of the synthesis gas producing fluid.

4613. The method of claim 4611, wherein the fuel cell produces carbon dioxide, and wherein a portion of the carbon dioxide is introduced into the formation to react with carbon within the formation to produce carbon monoxide.

4614. The method of claim 4611, wherein the fuel cell produces carbon dioxide, and further comprising storing an amount of carbon dioxide within a spent portion of the formation equal or greater to an amount of the carbon dioxide produced by the fuel cell.

4615. The method of claim 4603, further comprising using a portion of the removed synthesis gas as a feed product for formation of hydrocarbons.

4616. The method of claim 4603, wherein the synthesis gas producing fluid comprises hydrocarbons having carbon numbers less than 5, and wherein the hydrocarbons crack within the formation to increase an amount of H₂ within the generated synthesis gas.

4617. The method of claim 4603, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4618. The method of claim 4603, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4619. A method of treating an oil shale formation, comprising:

heating a portion of the formation with one or more electrical heaters to a temperature sufficient to pyrolyze hydrocarbons within the portion;

producing pyrolyzation fluid from the formation;

separating a fuel cell feed stream from the pyrolyzation fluid; and

directing the fuel cell feed stream to a fuel cell to produce electricity.

4620. The method of claim 4619, wherein the fuel cell is a molten carbonate fuel cell.

4621. The method of claim 4619, wherein the fuel cell is a solid oxide fuel cell.

4622. The method of claim 4619, further comprising using a portion of the produced electricity to power the electrical heaters.

4623. The method of claim 4619, wherein heating the portion of the formation is performed at a rate sufficient to increase a permeability of the portion and to produce a substantially uniform permeability within the portion.

4624. The method of claim 4619, wherein the fuel cell feed stream comprises H₂ and hydrocarbons having a carbon number of less than 5.

4625. The method of claim 4619, wherein the fuel cell feed stream comprises H₂ and hydrocarbons having a carbon number of less than 3.

4626. The method of claim 4619, further comprising hydrogenating the pyrolyzation fluid with a portion of H₂ from the pyrolyzation fluid.

4627. The method of claim 4619, wherein the hydrogenation is done in situ by directing the H₂ into the formation.

4628. The method of claim 4619, wherein the hydrogenation is done in a surface unit.

4629. The method of claim 4619, further comprising directing hydrocarbon fluid having carbon numbers less than 5 adjacent to at least one of the electrical heaters, cracking a portion of the hydrocarbons to produce H₂, and producing a portion of the hydrogen from the formation.

4630. The method of claim 4629, further comprising directing an oxidizing fluid adjacent to at least the one of the electrical heaters, oxidizing coke deposited on or near the at least one of the electrical heaters with the oxidizing fluid.

4631. The method of claim 4619, further comprising storing CO₂ generated in the fuel cell within the formation.

4632. The method of claim 4631, wherein the CO₂ is adsorbed to carbon material within a spent portion of the formation.

4633. The method of claim 4619, further comprising cooling the portion to form a spent portion of formation.

4634. The method of claim 4633, wherein cooling the portion comprises introducing water into the portion to produce steam, and removing steam from the formation.

4635. The method of claim 4634, further comprising using a portion of the removed steam to heat a second portion of the formation.

4636. The method of claim 4634, further comprising using a portion of the removed steam as a synthesis gas producing fluid in a second portion of the formation.

4637. The method of claim 4619, further comprising:

heating the portion to a temperature sufficient to support generation of synthesis gas after production of the pyrolyzation fluids;

introducing a synthesis gas producing fluid into the portion to generate synthesis gas; and

removing a portion of the synthesis gas from the formation.

4638. The method of claim 4637, further comprising producing the synthesis gas from the formation under pressure, and generating electricity from the produced synthesis gas by passing the produced synthesis gas through a turbine.

4639. The method of claim 4637, further comprising using a first portion of the removed synthesis gas as fuel cell feed.

4640. The method of claim 4637, further comprising producing steam from operation of the fuel cell, and using the steam as part of the synthesis gas producing fluid.

4641. The method of claim 4637, further comprising using carbon dioxide from the fuel cell as a part of the synthesis gas producing fluid.

4642. The method of claim 4637, further comprising using a portion of the synthesis gas to produce hydrocarbon product.

4643. The method of claim 4637, further comprising cooling the portion to form a spent portion of formation.

4644. The method of claim 4643, wherein cooling the portion comprises introducing water into the portion to produce steam, and removing steam from the formation.

4645. The method of claim 4644, further comprising using a portion of the removed steam to heat a second portion of the formation.

4646. The method of claim 4644, further comprising using a portion of the removed steam as a synthesis gas producing fluid in a second portion of the formation.

4647. The method of claim 4619, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4648. The method of claim 4619, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4649. A method for in situ production of synthesis gas from an oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation;

producing pyrolysis products from the formation;

heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas;

providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and

producing a portion of the synthesis gas from the formation.

4650. The method of claim 4649, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4651. The method of claim 4649, further comprising allowing the heat to transfer from the one or more heat sources to the selected section to substantially uniformly increase a permeability of the selected section.

4652. The method of claim 4649, further comprising controlling heat transfer from the one or more heat sources to produce a permeability within the selected section of greater than about 1100 millidarcy.

4653. The method of claim 4649, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.

4654. The method of claim 4649, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400°

C. to approximately 1200°

C.

4655. The method of claim 4649, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4656. The method of claim 4649, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.

4657. The method of claim 4649, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

4658. The method of claim 4649, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

4659. The method of claim 4649, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.

4660. The method of claim 4649, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

4661. The method of claim 4649, further comprising:

monitoring a composition of the produced synthesis gas; and

controlling heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range.

4662. The method of claim 4649, wherein the synthesis gas generating fluid comprises liquid water.

4663. The method of claim 4649, wherein the synthesis gas generating fluid comprises steam.

4664. The method of claim 4649, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4665. The method of claim 4664, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4666. The method of claim 4649, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4667. The method of claim 4666, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4668. The method of claim 4649, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

4669. The method of claim 4649, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.

4670. The method of claim 4649, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.

4671. The method of claim 4649, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4672. The method of claim 4649, further comprising generating electricity from the synthesis gas using a fuel cell.

4673. The method of claim 4649, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4674. The method of claim 4649, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

4675. The method of claim 4649, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.

4676. The method of claim 4649, further comprising converting at least a portion of the produced synthesis gas to methanol.

4677. The method of claim 4649, further comprising converting at least a portion of the produced synthesis gas to gasoline.

4678. The method of claim 4649, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.

4679. The method of claim 4649, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4680. The method of claim 4649, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4681. A method for in situ production of synthesis gas from an oil shale formation, comprising:

heating a first portion of the formation to pyrolyze some hydrocarbons within the first portion;

allowing the heat to transfer from one or more heat sources to a selected section of the formation, pyrolyzing hydrocarbons within the selected section;

producing fluid from the first portion, wherein the fluid comprises an aqueous fluid and a hydrocarbon fluid;

heating a second portion of the formation to a temperature sufficient to allow synthesis gas generation;

introducing at least a portion of the aqueous fluid to the second section after the section reaches the temperature sufficient to allow synthesis gas generation; and

producing synthesis gas from the formation.

4682. The method of claim 4681, wherein the temperature sufficient to allow synthesis gas generation ranges from approximately 400°

C. to approximately 1200°

C.

4683. The method of claim 4681, further comprising separating ammonia within the aqueous phase from the aqueous phase prior to introduction of at least the portion of the aqueous fluid to the second section.

4684. The method of claim 4681, wherein a permeability of the second portion of the formation is substantially uniform and greater than about 100 millidarcy when the temperature sufficient to allow synthesis gas generation is achieved.

4685. The method of claim 4681, further comprising heating the second portion of the formation during introduction of at least the portion of the aqueous fluid to the second section to inhibit temperature decrease in the second section due to synthesis gas generation.

4686. The method of claim 4681, wherein heating the second portion of the formation comprises convecting an oxidizing fluid into a portion of the second portion that is above a temperature sufficient to support oxidation of carbon within the portion with the oxidizing fluid, and reacting the oxidizing fluid with carbon in the portion to generate heat within the portion.

4687. The method of claim 4681, wherein heating the second portion of the formation comprises diffusing an oxidizing fluid to reaction zones adjacent to wellbores within the formation, oxidizing carbon within the reaction zones to generate heat, and transferring the heat to the second portion.

4688. The method of claim 4681, wherein heating the second portion of the formation comprises heating the second section by transfer of heat from one or more electrical heaters.

4689. The method of claim 4681, wherein heating the second portion of the formation comprises heating the second section with a flameless distributed combustor.

4690. The method of claim 4681, wherein heating the second portion of the formation comprises injecting steam into at least the portion of the formation.

4691. The method of claim 4681, wherein at least the portion of the aqueous fluid comprises a liquid phase.

4692. The method of claim 4681, wherein the aqueous fluid comprises a vapor phase.

4693. The method of claim 4681, further comprising adding carbon dioxide to at least the portion of aqueous fluid to inhibit production of carbon dioxide from carbon within the formation.

4694. The method of claim 4693, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.

4695. The method of claim 4681, further comprising adding hydrocarbons with carbon numbers less than 5 to at least the portion of the aqueous fluid to increase a H₂ concentration within the produced synthesis gas.

4696. The method of claim 4681, further comprising adding hydrocarbons with carbon numbers less than 5 to at least the portion of the aqueous fluid to increase a H₂ concentration within the produced synthesis gas, wherein the hydrocarbons are obtained from the produced fluid.

4697. The method of claim 4681, further comprising adding hydrocarbons with carbon numbers greater than 4 to at least the portion of the aqueous fluid to increase energy content of the produced synthesis gas.

4698. The method of claim 4681, further comprising adding hydrocarbons with carbon numbers greater than 4 to at least the portion of the aqueous fluid to increase energy content of the produced synthesis gas, wherein the hydrocarbons are obtained from the produced fluid.

4699. The method of claim 4681, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4700. The method of claim 4681, further comprising generating electricity from the synthesis gas using a fuel cell.

4701. The method of claim 4681, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.

4702. The method of claim 4681, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

4703. The method of claim 4681, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.

4704. The method of claim 4681, further comprising converting at least a portion of the produced synthesis gas to methanol.

4705. The method of claim 4681, further comprising converting at least a portion of the produced synthesis gas to gasoline.

4706. The method of claim 4681, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.

4707. The method of claim 4681, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4708. The method of claim 4681, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4709. A method for in situ production of synthesis gas from an oil shale formation, comprising:

heating a portion of the formation with one or more heat sources to create increased and substantially uniform permeability within a portion of the formation and to raise a temperature within the portion to a temperature sufficient to allow synthesis gas generation;

providing a synthesis gas generating fluid into the portion through at least one injection wellbore to generate synthesis gas from hydrocarbons and the synthesis gas generating fluid; and

producing synthesis gas from at least one heat source in which is positioned a heat source of the one or more heat sources.

4710. The method of claim 4709, wherein the temperature sufficient to allow synthesis gas generation is within a range from about 400°

C. to about 1200°

C.

4711. The method of claim 4709, wherein creating a substantially uniform permeability comprises heating the portion to a temperature within a range sufficient to pyrolyze hydrocarbons within the portion, raising the temperature within the portion at a rate of less than about 5°

C. per day during pyrolyzation and removing a portion of pyrolyzed fluid from the formation.

4712. The method of claim 4709, further comprising removing fluid from the formation through at least the one injection wellbore prior to heating the selected section to the temperature sufficient to allow synthesis gas generation.

4713. The method of claim 4709, wherein the injection wellbore comprises a wellbore of a heat source in which is positioned a heat source of the one or more heat sources.

4714. The method of claim 4709, further comprising heating the selected portion during providing the synthesis gas generating fluid to inhibit temperature decrease in at least the portion of the selected section due to synthesis gas generation.

4715. The method of claim 4709, further comprising providing a portion of the heat needed to raise the temperature sufficient to allow synthesis gas generation by convecting an oxidizing fluid to hydrocarbons within the selected section to oxidize a portion of the hydrocarbons and generate heat.

4716. The method of claim 4709, further comprising controlling the heating of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within the selected section above the temperature sufficient to generate synthesis gas.

4717. The method of claim 4709, further comprising:

monitoring a composition of the produced synthesis gas; and

controlling heating of the selected section and provision of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range.

4718. The method of claim 4709, wherein the synthesis gas generating fluid comprises liquid water.

4719. The method of claim 4709, wherein the synthesis gas generating fluid comprises steam.

4720. The method of claim 4709, wherein the synthesis gas generating fluid comprises steam to heat the selected section and to generate synthesis gas.

4721. The method of claim 4709, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4722. The method of claim 4721, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.

4723. The method of claim 4709, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4724. The method of claim 4723, wherein a portion of the carbon dioxide comprises carbon dioxide removed from the formation.

4725. The method of claim 4709, wherein providing the synthesis gas generating fluid to the selected section comprises raising a water table of the formation to allow water to enter the selected section.

4726. The method of claim 4709, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons undergo a reaction within the selected section to increase a H₂ concentration within the produced synthesis gas.

4727. The method of claim 4709, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the selected section to increase an energy content of the produced synthesis gas.

4728. The method of claim 4709, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4729. The method of claim 4709, further comprising generating electricity from the synthesis gas using a fuel cell.

4730. The method of claim 4709, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.

4731. The method of claim 4709, further comprising using a portion of the synthesis gas as a combustion fuel for heating the formation.

4732. The method of claim 4709, further comprising converting at least a portion of the produced synthesis gas to condensable hydrocarbons using a Fischer-Tropsch synthesis process.

4733. The method of claim 4709, further comprising converting at least a portion of the produced synthesis gas to methanol.

4734. The method of claim 4709, further comprising converting at least a portion of the produced synthesis gas to gasoline.

4735. The method of claim 4709, further comprising converting at least a portion of the synthesis gas to methane using a catalytic methanation process.

4736. The method of claim 4709, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of less than approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of greater than about 2.

4737. The method of claim 4709, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of greater than approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of less than about 2.

4738. The method of claim 4709, wherein a temperature of at least the one heat source wellbore is maintained at a temperature of approximately 700°

C. to produce a synthesis gas having a ratio of H₂ to carbon monoxide of approximately 2.

4739. The method of claim 4709, wherein a heat source of the one or more heat sources comprises an electrical heater.

4740. The method of claim 4709, wherein a heat source of the one or more heat sources comprises a natural distributed heater.

4741. The method of claim 4709, wherein a heat source of the one or more heat sources comprises a flameless distributed combustor (FDC) heater, and wherein fluids are produced from the wellbore of the FDC heater through a conduit positioned within the wellbore.

4742. The method of claim 4709, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4743. The method of claim 4709, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4744. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least a portion of the hydrocarbon containing material within the selected section of the formation;

producing pyrolysis products from the formation;

heating a first portion of a formation with one or more heat sources to a temperature sufficient to allow generation of synthesis gas;

providing a first synthesis gas generating fluid to the first portion to generate a first synthesis gas;

removing a portion of the first synthesis gas from the formation;

heating a second portion of a formation with one or more heat sources to a temperature sufficient to allow generation of synthesis gas having a H₂ to CO ratio greater than a H₂ to CO ratio of the first synthesis gas;

providing a second synthesis gas generating component to the second portion to generate a second synthesis gas;

removing a portion of the second synthesis gas from the formation; and

blending a portion of the first synthesis gas with a portion of the second synthesis gas to produce a blended synthesis gas having a selected H₂ to CO ratio.

4745. The method of claim 4744, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4746. The method of claim 4744, wherein the first synthesis gas generating fluid and second synthesis gas generating fluid comprise the same component.

4747. The method of claim 4744, further comprising controlling the temperature in the first portion to control a composition of the first synthesis gas.

4748. The method of claim 4744, further comprising controlling the temperature in the second portion to control a composition of the second synthesis gas.

4749. The method of claim 4744, wherein the selected ratio is controlled to be approximately 2:

1H₂ to CO.

4750. The method of claim 4744, wherein the selected ratio is controlled to range from approximately 1.8:

1 to approximately 2.2;

1H₂ to CO.

4751. The method of claim 4744, wherein the selected ratio is controlled to be approximately 3:

1H₂ to CO.

4752. The method of claim 4744, wherein the selected ratio is controlled to range from approximately 2.8:

1 to approximately 3.2;

1H₂ to CO.

4753. The method of claim 4744, further comprising providing at least a portion of the produced blended synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.

4754. The method of claim 4753, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.

4755. The method of claim 4754, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.

4756. The method of claim 4744, further comprising providing at least a portion of the produced blended synthesis gas to a catalytic methanation process to produce methane.

4757. The method of claim 4744, further comprising providing at least a portion of the produced blended synthesis gas to a methanol-synthesis process to produce methanol.

4758. The method of claim 4744, further comprising providing at least a portion of the produced blended synthesis gas to a gasoline-synthesis process to produce gasoline.

4759. The method of claim 4744, wherein removing a portion of the second synthesis gas comprises withdrawing second synthesis gas through a production well, wherein a temperature of the production well adjacent to a second syntheses gas production zone is maintained at a substantially constant temperature configured to produce second synthesis gas having the H₂ to CO ratio greater the first synthesis gas.

4760. The method of claim 4744, wherein the first synthesis gas producing fluid comprises CO₂ and wherein the temperature of the first portion is at a temperature that will result in conversion of CO₂ and carbon from the first portion to CO to generate a CO rich first synthesis gas.

4761. The method of claim 4744, wherein the second synthesis gas producing fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons react within the formation to increase a H₂ concentration within the produced second synthesis gas.

4762. The method of claim 4744, wherein blending a portion of the first synthesis gas with a portion of the second synthesis gas comprises producing an intermediate mixture having a H₂ to CO mixture of less than the selected ratio, and subjecting the intermediate mixture to a shift reaction to reduce an amount of CO and increase an amount of H₂ to produce the selected ratio of H₂ to CO.

4763. The method of claim 4744, further comprising removing an excess of first synthesis gas from the first portion to have an excess of CO, subjecting the first synthesis gas to a shift reaction to reduce an amount of CO and increase an amount of H₂ before blending the first synthesis gas with the second synthesis gas.

4764. The method of claim 4744, further comprising removing the first synthesis gas from the formation under pressure, and passing removed first synthesis gas through a turbine to generate electricity.

4765. The method of claim 4744, further comprising removing the second synthesis gas from the formation under pressure, and passing removed second synthesis gas through a turbine to generate electricity.

4766. The method of claim 4744, further comprising generating electricity from the blended synthesis gas using a fuel cell.

4767. The method of claim 4744, further comprising generating electricity from the blended synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent portion of the formation.

4768. The method of claim 4744, further comprising using at least a portion of the blended synthesis gas as a combustion fuel for heating the formation.

4769. The method of claim 4744, further comprising allowing the heat to transfer from the one or more heat sources to the selected section to substantially uniformly increase a permeability of the selected section.

4770. The method of claim 4744, further comprising controlling heat transfer from the one or more heat sources to produce a permeability within the selected section of greater than about 100 millidarcy.

4771. The method of claim 4744, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.

4772. The method of claim 4744, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400°

C. to approximately 1200°

C.

4773. The method of claim 4744, wherein heating the first a portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4774. The method of claim 4744, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4775. The method of claim 4744, wherein heating the first portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the first portion of the selected section, wherein the first portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the first portion of the selected section to generate heat and raise the temperature of the first portion.

4776. The method of claim 4744, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the second portion of the selected section, wherein the second portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the second portion of the selected section to generate heat and raise the temperature of the second portion.

4777. The method of claim 4744, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

4778. The method of claim 4744, wherein the one or more heat sources comprises one or more natural distributed combustors.

4779. The method of claim 4744, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

4780. The method of claim 4744, wherein heating the first portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a first synthesis gas generating fluid to the first portion of the selected section comprises introducing steam into the first portion.

4781. The method of claim 4744, wherein heating the second portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a second synthesis gas generating fluid to the second portion of the selected section comprises introducing steam into the second portion.

4782. The method of claim 4744, further comprising controlling the heating of the first portion of selected section and provision of the first synthesis gas generating fluid to maintain a temperature within the first portion of the selected section above the temperature sufficient to generate synthesis gas.

4783. The method of claim 4744, further comprising controlling the heating of the second portion of selected section and provision of the second synthesis gas generating fluid to maintain a temperature within the second portion of the selected section above the temperature sufficient to generate synthesis gas.

4784. The method of claim 4744, wherein the first synthesis gas generating fluid comprises liquid water.

4785. The method of claim 4744, wherein the second synthesis gas generating fluid comprises liquid water.

4786. The method of claim 4744, wherein the first synthesis gas generating fluid comprises steam.

4787. The method of claim 4744, wherein the second synthesis gas generating fluid comprises steam.

4788. The method of claim 4744, wherein the first synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4789. The method of claim 4788, wherein a portion of the carbon dioxide within the first synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4790. The method of claim 4744, wherein the second synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4791. The method of claim 4790, wherein a portion of the carbon dioxide within the second synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4792. The method of claim 4744, wherein the first synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4793. The method of claim 4792, wherein a portion of the carbon dioxide within the first synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4794. The method of claim 4744, wherein the second synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4795. The method of claim 4794, wherein a portion of the carbon dioxide within the second synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4796. The method of claim 4744, wherein providing the first synthesis gas generating fluid to the first portion of the selected section comprises raising a water table of the formation to allow water to flow into the first portion of the selected section.

4797. The method of claim 4744, wherein providing the second synthesis gas generating fluid to the second portion of the selected section comprises raising a water table of the formation to allow water to flow into the second portion of the selected section.

4798. The method of claim 4744, wherein the first synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the first portion of the selected section to increase a H₂ concentration within the produced first synthesis gas.

4799. The method of claim 4744, wherein the second synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within the second portion of the selected section to increase a H₂ concentration within the produced second synthesis gas.

4800. The method of claim 4744, wherein the first synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within the first portion of the selected section to increase an energy content of the produced first synthesis gas.

4801. The method of claim 4744, wherein the second synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the second portion of the selected section to increase an energy content of the second produced synthesis gas.

4802. The method of claim 4744, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced blended synthesis gas through a turbine to generate electricity.

4803. The method of claim 4744, further comprising generating electricity from the blended synthesis gas using a fuel cell.

4804. The method of claim 4744, further comprising generating electricity from the blended synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4805. The method of claim 4744, further comprising using a portion of the blended synthesis gas as a combustion fuel for the one or more heat sources.

4806. The method of claim 4744, further comprising using a portion of the first synthesis gas as a combustion fuel for the one or more heat sources.

4807. The method of claim 4744, further comprising using a portion of the second synthesis gas as a combustion fuel for the one or more heat sources.

4808. The method of claim 4744, further comprising using a portion of the blended synthesis gas as a combustion fuel for the one or more heat sources.

4809. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation;

producing pyrolysis products from the formation;

heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas;

controlling a temperature of at least a portion of the selected section to generate synthesis gas having a selected H₂ to CO ratio;

providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and

producing a portion of the synthesis gas from the formation.

4810. The method of claim 4809, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4811. The method of claim 4809, wherein the selected ratio is controlled to be approximately 2:

1H₂ to CO.

4812. The method of claim 4809, wherein the selected ratio is controlled to range from approximately 1.8:

1 to approximately 2.2;

1H₂ to CO.

4813. The method of claim 4809, wherein the selected ratio is controlled to be approximately 3:

1H₂ to CO.

4814. The method of claim 4809, wherein the selected ratio is controlled to range from approximately 2.8:

1 to approximately 3.2;

1H₂ to CO.

4815. The method of claim 4809, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.

4816. The method of claim 4815, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.

4817. The method of claim 4816, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.

4818. The method of claim 4809, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.

4819. The method of claim 4809, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.

4820. The method of claim 4809, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.

4821. The method of claim 4809, further comprising allowing the heat to transfer from the one or more heat sources to the selected section to substantially uniformly increase a permeability of the selected section.

4822. The method of claim 4809, further comprising controlling heat transfer from the one or more heat sources to produce a permeability within the selected section of greater than about 100 millidarcy.

4823. The method of claim 4809, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.

4824. The method of claim 4809, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400°

C. to approximately 1200°

C.

4825. The method of claim 4809, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4826. The method of claim 4809, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.

4827. The method of claim 4809, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

4828. The method of claim 4809, wherein the one or more heat sources comprises one or more natural distributed combustors.

4829. The method of claim 4809, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

4830. The method of claim 4809, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.

4831. The method of claim 4809, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

4832. The method of claim 4809, wherein the synthesis gas generating fluid comprises liquid water.

4833. The method of claim 4809, wherein the synthesis gas generating fluid comprises steam.

4834. The method of claim 4809, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4835. The method of claim 4834, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4836. The method of claim 4809, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4837. The method of claim 4836, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4838. The method of claim 4809, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

4839. The method of claim 4809, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.

4840. The method of claim 4809, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.

4841. The method of claim 4809, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4842. The method of claim 4809, further comprising generating electricity from the synthesis gas using a fuel cell.

4843. The method of claim 4809, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4844. The method of claim 4809, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

4845. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation;

producing pyrolysis products from the formation;

heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas;

controlling a temperature in or proximate to a synthesis gas production well to generate synthesis gas having a selected H₂ to CO ratio;

providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas; and

producing synthesis gas from the formation.

4846. The method of claim 4845, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4847. The method of claim 4845, wherein the selected ratio is controlled to be approximately 2:

1H₂ to CO.

4848. The method of claim 4845, wherein the selected ratio is controlled to range from approximately 1.8:

1 to approximately 2.2;

1H₂ to CO.

4849. The method of claim 4845, wherein the selected ratio is controlled to be approximately 3:

1H₂ to CO.

4850. The method of claim 4845, wherein the selected ratio is controlled to range from approximately 2.8:

1 to approximately 3.2;

1H₂to CO.

4851. The method of claim 4845, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.

4852. The method of claim 4851, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.

4853. The method of claim 4852, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.

4854. The method of claim 4845, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.

4855. The method of claim 4845, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.

4856. The method of claim 4845, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.

4857. The method of claim 4845, further comprising allowing the heat to transfer from the one or more heat sources to the selected section to substantially uniformly increase a permeability of the selected section.

4858. The method of claim 4845, further comprising controlling heat transfer from the one or more heat sources to produce a permeability within the selected section of greater than about 100 millidarcy.

4859. The method of claim 4845, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.

4860. The method of claim 4845, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400°

C. to approximately 1200°

C.

4861. The method of claim 4845, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4862. The method of claim 4845, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.

4863. The method of claim 4845, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

4864. The method of claim 4845, wherein the one or more heat sources comprises one or more natural distributed combustors.

4865. The method of claim 4845, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

4866. The method of claim 4845, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.

4867. The method of claim 4845, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

4868. The method of claim 4845, wherein the synthesis gas generating fluid comprises liquid water.

4869. The method of claim 4845, wherein the synthesis gas generating fluid comprises steam.

4870. The method of claim 4845, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4871. The method of claim 4870, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4872. The method of claim 4845, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4873. The method of claim 4872, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4874. The method of claim 4845, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

4875. The method of claim 4845, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.

4876. The method of claim 4845, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.

4877. The method of claim 4845, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4878. The method of claim 4845, further comprising generating electricity from the synthesis gas using a fuel cell.

4879. The method of claim 4845, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4880. The method of claim 4845, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

4881. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation;

producing pyrolysis products from the formation;

heating at least a portion of the selected section to a temperature sufficient to generate synthesis gas;

controlling a temperature of at least a portion of the selected section to generate synthesis gas having a H₂ to CO ratio different than a selected H₂ to CO ratio;

providing a synthesis gas generating fluid to at least the portion of the selected section to generate synthesis gas;

producing synthesis gas from the formation;

providing at least a portion of the produced synthesis gas to a shift process wherein an amount of carbon monoxide is converted to carbon dioxide; and

separating at least a portion of the carbon dioxide to obtain a gas having a selected H₂ to CO ratio.

4882. The method of claim 4881, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4883. The method of claim 4881, wherein the selected ratio is controlled to be approximately 2:

1 H₂ to CO.

4884. The method of claim 4881, wherein the selected ratio is controlled to range from approximately 1.8:

1 to 2.2;

1H₂to CO.

4885. The method of claim 4881, wherein the selected ratio is controlled to be approximately 3:

1 H₂ to CO.

4886. The method of claim 4881, wherein the selected ratio is controlled to range from approximately 2.8:

1 to 3.2;

1H₂ to CO.

4887. The method of claim 4881, further comprising providing at least a portion of the produced synthesis gas to a condensable hydrocarbon synthesis process to produce condensable hydrocarbons.

4888. The method of claim 4887, wherein the condensable hydrocarbon synthesis process comprises a Fischer-Tropsch process.

4889. The method of claim 4888, further comprising cracking at least a portion of the condensable hydrocarbons to form middle distillates.

4890. The method of claim 4881, further comprising providing at least a portion of the produced synthesis gas to a catalytic methanation process to produce methane.

4891. The method of claim 4881, further comprising providing at least a portion of the produced synthesis gas to a methanol-synthesis process to produce methanol.

4892. The method of claim 4881, further comprising providing at least a portion of the produced synthesis gas to a gasoline-synthesis process to produce gasoline.

4893. The method of claim 4881, further comprising allowing the heat to transfer from the one or more heat sources to the selected section to substantially uniformly increase a permeability of the selected section.

4894. The method of claim 4881, further comprising controlling heat transfer from the one or more heat sources to produce a permeability within the selected section of greater than about 100 millidarcy.

4895. The method of claim 4881, further comprising heating at least the portion of the selected section when providing the synthesis gas generating fluid to inhibit temperature decrease within the selected section during synthesis gas generation.

4896. The method of claim 4881, wherein the temperature sufficient to allow synthesis gas generation is within a range from approximately 400°

C. to approximately 1200°

C.

4897. The method of claim 4881, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with an oxidizing fluid;

introducing the oxidizing fluid to the zones substantially by diffusion;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

4898. The method of claim 4881, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation comprises:

introducing an oxidizing fluid into the formation through a wellbore;

transporting the oxidizing fluid substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with the oxidizing fluid; and

reacting the oxidizing fluid within the portion of the selected section to generate heat and raise the temperature of the portion.

4899. The method of claim 4881, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

4900. The method of claim 4881, wherein the one or more heat sources comprises one or more natural distributed combustors.

4901. The method of claim 4881, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

4902. The method of claim 4881, wherein heating at least the portion of the selected section to a temperature sufficient to allow synthesis gas generation and providing a synthesis gas generating fluid to at least the portion of the selected section comprises introducing steam into the portion.

4903. The method of claim 4881, further comprising controlling the heating of at least the portion of selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

4904. The method of claim 4881, wherein the synthesis gas generating fluid comprises liquid water.

4905. The method of claim 4881, wherein the synthesis gas generating fluid comprises steam.

4906. The method of claim 4881, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

4907. The method of claim 4906, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4908. The method of claim 4881, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

4909. The method of claim 4908, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

4910. The method of claim 4881, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

4911. The method of claim 4881, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers less than 5, and wherein at least a portion of the hydrocarbons are subjected to a reaction within at least the portion of the selected section to increase a H₂ concentration within the produced synthesis gas.

4912. The method of claim 4881, wherein the synthesis gas generating fluid comprises water and hydrocarbons having carbon numbers greater than 4, and wherein at least a portion of the hydrocarbons react within at least the portion of the selected section to increase an energy content of the produced synthesis gas.

4913. The method of claim 4881, further comprising maintaining a pressure within the formation during synthesis gas generation, and passing produced synthesis gas through a turbine to generate electricity.

4914. The method of claim 4881, further comprising generating electricity from the synthesis gas using a fuel cell.

4915. The method of claim 4881, further comprising generating electricity from the synthesis gas using a fuel cell, separating carbon dioxide from a fluid exiting the fuel cell, and storing a portion of the separated carbon dioxide within a spent section of the formation.

4916. The method of claim 4881, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

4917. A method of forming a spent portion of formation within an oil shale formation, comprising:

heating a first portion of the formation to pyrolyze hydrocarbons within the first portion and to establish a substantially uniform permeability within the first portion; and

cooling the first portion.

4918. The method of claim 4917, wherein heating the first portion comprises transferring heat to the first portion from one or more electrical heaters.

4919. The method of claim 4917, wherein heating the first portion comprises transferring heat to the first portion from one or more natural distributed combustors.

4920. The method of claim 4917, wherein heating the first portion comprises transferring heat to the first portion from one or more flameless distributed combustors.

4921. The method of claim 4917, wherein heating the first portion comprises transferring heat to the first portion from heat transfer fluid flowing within one or more wellbores within the formation.

4922. The method of claim 4921, wherein the heat transfer fluid comprises steam.

4923. The method of claim 4921, wherein the heat transfer fluid comprises combustion products from a burner.

4924. The method of claim 4917, wherein heating the first portion comprises transferring heat to the first portion from at least two heater wells positioned within the formation, wherein the at least two heater wells are placed in a substantially regular pattern, wherein the substantially regular pattern comprises repetition of a base heater unit, and wherein the base heater unit is formed of a number of heater wells.

4925. The method of claim 4924, wherein a spacing between a pair of adjacent heater wells is within a range from about 6 m to about 15 m.

4926. The method of claim 4924, further comprising removing fluid from the formation through one or more production wells.

4927. The method of claim 4926, wherein the one or more production wells are located in a pattern, and wherein the one or more production wells are positioned substantially at centers of base heater units.

4928. The method of claim 4924, wherein the heater unit comprises three heater wells positioned substantially at apexes of an equilateral triangle.

4929. The method of claim 4924, wherein the heater unit comprises four heater wells positioned substantially at apexes of a rectangle.

4930. The method of claim 4924, wherein the heater unit comprises five heater wells positioned substantially at apexes of a regular pentagon.

4931. The method of claim 4924, wherein the heater unit comprises six heater wells positioned substantially at apexes of a regular hexagon.

4932. The method of claim 4917, further comprising introducing water to the first portion to cool the formation.

4933. The method of claim 4917, further comprising removing steam from the formation.

4934. The method of claim 4933, further comprising using a portion of the removed steam to heat a second portion of the formation.

4935. The method of claim 4917, further comprising removing pyrolyzation products from the formation.

4936. The method of claim 4917, further comprising generating synthesis gas within the portion by introducing a synthesis gas generating fluid into the portion, and removing synthesis gas from the formation.

4937. The method of claim 4917, further comprising heating a second section of the formation to pyrolyze hydrocarbons within the second portion, removing pyrolyzation fluid from the second portion, and storing a portion of the removed pyrolyzation fluid within the first portion.

4938. The method of claim 4937, wherein the portion of the removed pyrolyzation fluid is stored within the first portion when surface facilities that process the removed pyrolyzation fluid are not able to process the portion of the removed pyrolyzation fluid.

4939. The method of claim 4937, further comprising heating the first portion to facilitate removal of the stored pyrolyzation fluid from the first portion.

4940. The method of claim 4917, further comprising generating synthesis gas within a second portion of the formation, removing synthesis gas from the second portion, and storing a portion of the removed synthesis gas within the first portion.

4941. The method of claim 4940, wherein the portion of the removed synthesis gas from the second portion is stored within the first portion when surface facilities that process the removed synthesis gas are not able to process the portion of the removed synthesis gas.

4942. The method of claim 4940, further comprising heating the first portion to facilitate removal of the stored synthesis gas from the first portion.

4943. The method of claim 4917, further comprising removing at least a portion of hydrocarbon containing material in the first portion and, further comprising using at least a portion of the hydrocarbon containing material removed from the formation in a metallurgical application.

4944. The method of claim 4943, wherein the metallurgical application comprises steel manufacturing.

4945. A method of sequestering carbon dioxide within an oil shale formation, comprising:

heating a portion of the formation to increase permeability and form a substantially uniform permeability within the portion;

allowing the portion to cool; and

storing carbon dioxide within the portion.

4946. The method of claim 4945, wherein the permeability of the portion is increased to over 100 millidarcy.

4947. The method of claim 4945, further comprising raising a water level within the portion to inhibit migration of the carbon dioxide from the portion.

4948. The method of claim 4945, further comprising heating the portion to release carbon dioxide, and removing carbon dioxide from the portion.

4949. The method of claim 4945, further comprising pyrolyzing hydrocarbons within the portion during heating of the portion, and removing pyrolyzation product from the formation.

4950. The method of claim 4945, further comprising producing synthesis gas from the portion during the heating of the portion, and removing synthesis gas from the formation.

4951. The method of claim 4945, wherein heating the portion comprises:

heating hydrocarbon containing material adjacent to one or more wellbores to a temperature sufficient to support oxidation of the hydrocarbon containing material with an oxidizing fluid;

introducing the oxidizing fluid to hydrocarbon containing material adjacent to the one or more wellbores to oxidize the hydrocarbons and produce heat; and

conveying produced heat to the portion.

4952. The method of claim 4951, wherein heating hydrocarbon containing material adjacent to the one or more wellbores comprises electrically heating the hydrocarbon containing material.

4953. The method of claim 4951, wherein the temperature sufficient to support oxidation is in a range from approximately 200°

C. to approximately 1200°

C.

4954. The method of claim 4945, wherein heating the portion comprises circulating heat transfer fluid through one or more heating wells within the formation.

4955. The method of claim 4954, wherein the heat transfer fluid comprises combustion products from a burner.

4956. The method of claim 4954, wherein the heat transfer fluid comprises steam.

4957. The method of claim 4945, further comprising removing fluid from the formation during heating of the formation, and combusting a portion of the removed fluid to generate heat to heat the formation.

4958. The method of claim 4945, further comprising using at least a portion of the carbon dioxide for hydrocarbon bed demethanation prior to storing the carbon dioxide within the portion.

4959. The method of claim 4945, further comprising using a portion of the carbon dioxide for enhanced oil recovery prior to storing the carbon dioxide within the portion.

4960. The method of claim 4945, wherein at least a portion of the carbon dioxide comprises carbon dioxide generated in a fuel cell.

4961. The method of claim 4945, wherein at least a portion of the carbon dioxide comprises carbon dioxide formed as a combustion product.

4962. The method of claim 4945, further comprising allowing the portion to cool by introducing water to the portion;

and removing the water from the formation as steam.

4963. The method of claim 4962, further comprising using the steam as a heat transfer fluid to heat a second portion of the formation.

4964. The method of claim 4945, wherein storing carbon dioxide in the portion comprises adsorbing carbon dioxide to hydrocarbon containing material within the formation.

4965. The method of claim 4945, wherein storing carbon dioxide comprises passing a first fluid stream comprising the carbon dioxide and other fluid through the portion;

adsorbing carbon dioxide onto hydrocarbon containing material within the formation; and

removing a second fluid stream from the formation, wherein a concentration of the other fluid in the second fluid stream is greater than concentration of other fluid in the first stream due to the absence of the adsorbed carbon dioxide in the second stream.

4966. The method of claim 4945, wherein an amount of carbon dioxide stored within the portion is equal to or greater than an amount of carbon dioxide generated within the portion and removed from the formation during heating of the portion.

4967. The method of claim 4945, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4968. The method of claim 4945, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4969. A method of in situ sequestration of carbon dioxide within an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a first portion of the formation;

allowing the heat to transfer from one or more sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least some of the hydrocarbons within the selected section of the formation;

producing pyrolyzation fluids, wherein the pyrolyzation fluids comprise carbon dioxide; and

storing an amount of carbon dioxide in the formation, wherein the amount of stored carbon dioxide is equal to or greater than an amount of carbon dioxide within the pyrolyzation fluids.

4970. The method of claim 4969, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4971. The method of claim 4969, wherein the carbon dioxide is stored within a spent portion of the formation.

4972. The method of claim 4969, wherein a portion of the carbon dioxide stored within the formation is carbon dioxide separated from the pyrolyzation fluids.

4973. The method of claim 4969, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide as a flooding agent in enhanced oil recovery.

4974. The method of claim 4969, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide as a synthesis gas generating fluid for the generation of synthesis gas from a section of the formation that is heated to a temperature sufficient to generate synthesis gas upon introduction of the synthesis gas generating fluid.

4975. The method of claim 4969, further comprising separating a portion of carbon dioxide from the pyrolyzation fluids, and using the carbon dioxide to displace hydrocarbon bed methane.

4976. The method of claim 4975, wherein the hydrocarbon bed is a deep hydrocarbon bed located over 760 m below ground surface.

4977. The method of claim 4975, further comprising adsorbing a portion of the carbon dioxide within the hydrocarbon bed.

4978. The method of claim 4969, further comprising using at least a portion of the pyrolyzation fluids as a feed stream for a fuel cell.

4979. The method of claim 4978, wherein the fuel cell generates carbon dioxide, and further comprising storing an amount of carbon dioxide equal to or greater than an amount of carbon dioxide generated by the fuel cell within the formation.

4980. The method of claim 4969, wherein a spent portion of the formation comprises hydrocarbon containing material within a section of the formation that has been heated and from which condensable hydrocarbons have been produced, and wherein the spent portion of the formation is at a temperature at which carbon dioxide adsorbs onto the hydrocarbon containing material.

4981. The method of claim 4969, further comprising raising a water level within the spent portion to inhibit migration of the carbon dioxide from the portion.

4982. The method of claim 4969, wherein producing fluids from the formation comprises removing pyrolyzation products from the formation.

4983. The method of claim 4969, wherein producing fluids from the formation comprises heating the selected section to a temperature sufficient to generate synthesis gas;

introducing a synthesis gas generating fluid into the selected section; and

removing synthesis gas from the formation.

4984. The method of claim 4983, wherein the temperature sufficient to generate synthesis gas ranges from about 400°

C. to about 1200°

C.

4985. The method of claim 4983, wherein heating the selected section comprises introducing an oxidizing fluid into the selected section, reacting the oxidizing fluid within the selected section to heat the selected section.

4986. The method of claim 4983, wherein heating the selected section comprises:

heating hydrocarbon containing material adjacent to one or more wellbores to a temperature sufficient to support oxidation of the hydrocarbon containing material with an oxidant;

introducing the oxidant to hydrocarbon containing material adjacent to the one or more wellbores to oxidize the hydrocarbons and produce heat; and

conveying produced heat to the portion.

4987. The method of claim 4969, wherein the spent portion of the formation comprises a substantially uniform permeability created by heating the spent formation and removing fluid during formation of the spent portion.

4988. The method of claim 4969, wherein the one or more heat sources comprise electrical heaters.

4989. The method of claim 4969, wherein the one or more heat sources comprise flameless distributed combustors.

4990. The method of claim 4989, wherein a portion of fuel for the one or more flameless distributed combustors is obtained from the formation.

4991. The method of claim 4969, wherein the one or more heat sources comprise heater wells in the formation through which heat transfer fluid is circulated.

4992. The method of claim 4991, wherein the heat transfer fluid comprises combustion products.

4993. The method of claim 4991, wherein the heat transfer fluid comprises steam.

4994. The method of claim 4969, wherein condensable hydrocarbons are produced under pressure, and further comprising generating electricity by passing a portion of the produced fluids through a turbine.

4995. The method of claim 4969, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

4996. The method of claim 4969, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

4997. A method for in situ production of energy from an oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat from the one or more heat sources pyrolyzes at least a portion of the hydrocarbons within the selected section of the formation;

producing pyrolysis products from the formation;

providing at least a portion of the pyrolysis products to a reformer to generate synthesis gas;

producing the synthesis gas from the reformer;

providing at least a portion of the produced synthesis gas to a fuel cell to produce electricity, wherein the fuel cell produces a carbon dioxide containing exit stream; and

storing at least a portion of the carbon dioxide in the carbon dioxide containing exit stream in a subsurface formation.

4998. The method of claim 4997, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

4999. The method of claim 4997, wherein at least a portion of the pyrolysis products are used as fuel in the reformer.

5000. The method of claim 4997, wherein the synthesis gas comprises substantially H₂.

5001. The method of claim 4997, wherein the subsurface formation is a spent portion of the formation.

5002. The method of claim 4997, wherein the subsurface formation is an oil reservoir.

5003. The method of claim 5002, wherein at least a portion of the carbon dioxide is used as a drive fluid for enhanced oil recovery in the oil reservoir.

5004. The method of claim 4997, wherein the subsurface formation is a coal formation.

5005. The method of claim 5004, wherein at least a portion of the carbon dioxide is used to produce methane from the coal formation.

5006. The method of claim 5005, further comprising sequestering at least a portion of the carbon dioxide within the coal formation.

5007. The method of claim 4997, wherein the reformer produces a reformer carbon dioxide containing exit stream.

5008. The method of claim 4997, further comprising storing at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream in the subsurface formation.

5009. The method of claim 5008, wherein the subsurface formation is a spent portion of the formation.

5010. The method of claim 5008, wherein the subsurface formation is an oil reservoir

5011. The method of claim 5010, wherein at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream is used as a drive fluid for enhanced oil recovery in the oil reservoir.

5012. The method of claim 5008, wherein the subsurface formation is a coal formation.

5013. The method of claim 5012, wherein at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream is used to produce methane from the coal formation.

5014. The method of claim 5012, wherein the coal formation is located over about 760 m below ground surface.

5015. The method of claim 5013, further comprising sequestering at least a portion of the carbon dioxide in the reformer carbon dioxide containing exit stream within the coal formation.

5016. The method of claim 4997, wherein the fuel cell is a molten carbonate fuel cell.

5017. The method of claim 4997, wherein the fuel cell is a solid oxide fuel cell.

5018. The method of claim 4997, further comprising using a portion of the produced electricity to power electrical heaters within the formation.

5019. The method of claim 4997, further comprising using a portion of the produced pyrolysis products as a feed stream for the fuel cell.

5020. The method of claim 4997, wherein the one or more heat sources comprise one or more electrical heaters disposed in the formation.

5021. The method of claim 4997, wherein the one or more heat sources comprise one or more flameless distributed combustors disposed in the formation.

5022. The method of claim 5021, wherein a portion of fuel for the flameless distributed combustors is obtained from the formation.

5023. The method of claim 4997, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5024. The method of claim 4997, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

5025. A method for producing ammonia using an oil shale formation, comprising:

separating air to produce an O₂ rich stream and a N₂ rich stream;

heating a selected section of the formation to a temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas;

providing synthesis gas generating fluid and at least a portion of the O₂ rich stream to the selected section;

allowing the synthesis gas generating fluid and O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material in the formation to generate synthesis gas;

producing synthesis gas from the formation, wherein the synthesis gas comprises H₂ and CO;

providing at least a portion of the H₂ in the synthesis gas to an ammonia synthesis process;

providing N₂ to the ammonia synthesis process; and

using the ammonia synthesis process to generate ammonia.

5026. The method of claim 5025, wherein the ratio of the H₂ to N₂ provided to the ammonia synthesis process is approximately 3:

1.

5027. The method of claim 5025, wherein the ratio of the H₂ to N₂ provided to the ammonia synthesis process ranges from approximately 2.8:

1 to approximately 3.2;

1.

5028. The method of claim 5025, wherein the temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas ranges from approximately 400°

C. to approximately 1200°

C.

5029. The method of claim 5025, further comprising separating at least a portion of carbon dioxide in the synthesis gas from at least a portion of the synthesis gas.

5030. The method of claim 5029, wherein the carbon dioxide is separated from the synthesis gas by an amine separator.

5031. The method of claim 5030, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process to produce urea.

5032. The method of claim 5025, wherein at least a portion of the N₂ stream is used to condense hydrocarbons with 4 or more carbon atoms from a pyrolyzation fluid.

5033. The method of claim 5025, wherein at least a portion of the N₂ rich stream is provided to the ammonia synthesis process.

5034. The method of claim 5025, wherein the air is separated by cryogenic distillation.

5035. The method of claim 5025, wherein the air is separated by membrane separation.

5036. The method of claim 5025, wherein fluids produced during pyrolysis of an oil shale formation comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5037. The method of claim 5025, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5038. The method of claim 5025, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.

5039. The method of claim 5025, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.

5040. The method of claim 5025, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising shifting at least a portion of the carbon monoxide to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.

5041. The method of claim 5025, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ in the O₂ rich stream;

introducing the O₂ to the zones substantially by diffusion;

allowing O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

5042. The method of claim 5041, wherein temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ range from approximately 200°

C. to approximately 1200°

C. 1

5043. The method of claim 5041, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.

5044. The method of claim 5041, wherein the one or more heat sources comprises one or more natural distributed combustors.

5045. The method of claim 5041, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5046. The method of claim 5041, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

5047. The method of claim 5025, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises:

introducing the O₂ rich stream into the formation through a wellbore;

transporting O₂ in the O₂ rich stream substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with O₂ in the O₂ rich stream; and

reacting the O₂ within the portion of the selected section to generate heat and raise the temperature of the portion.

5048. The method of claim 5047, wherein the temperature sufficient to support an oxidation reaction with O₂ ranges from approximately 200°

C. to approximately 1200°

C.

5049. The method of claim 5047, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.

5050. The method of claim 5047, wherein the one or more heat sources comprises one or more natural distributed combustors.

5051. The method of claim 5047, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5052. The method of claim 5047, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

5053. The method of claim 5025, further comprising controlling the heating of at least the portion of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

5054. The method of claim 5025, wherein the synthesis gas generating fluid comprises liquid water.

5055. The method of claim 5025, wherein the synthesis gas generating fluid comprises steam.

5056. The method of claim 5025, wherein the synthesis gas generating fluid comprises water and carbon dioxide wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

5057. The method of claim 5056, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

5058. The method of claim 5025, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

5059. The method of claim 5058, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

5060. The method of claim 5025, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

5061. A method for producing ammonia using an oil shale formation, comprising:

generating a first ammonia feed stream from a first portion of the formation;

generating a second ammonia feed stream from a second portion of the formation, wherein the second ammonia feed stream has a H₂ to N₂ ratio greater than a H₂ to N₂ ratio of the first ammonia feed stream;

blending at least a portion of the first ammonia feed stream with at least a portion of the second ammonia feed stream to produce a blended ammonia feed stream having a selected H₂ to N₂ ratio;

providing the blended ammonia feed stream to an ammonia synthesis process; and

using the ammonia synthesis process to generate ammonia.

5062. The method of claim 5061, wherein the selected ratio is approximately 3:

1.

5063. The method of claim 5061, wherein the selected ratio ranges from approximately 2.8:

1 to approximately 3.2;

1.

5064. The method of claim 5061, further comprising separating at least a portion of carbon dioxide in the first ammonia feed stream from at least a portion of the first ammonia feed stream.

5065. The method of claim 5064, wherein the carbon dioxide is separated from the first ammonia feed stream by an amine separator.

5066. The method of claim 5065, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.

5067. The method of claim 5061, further comprising separating at least a portion of carbon dioxide in the blended ammonia feed stream from at least a portion of the blended ammonia feed stream.

5068. The method of claim 5067, wherein the carbon dioxide is separated from the blended ammonia feed stream by an amine separator.

5069. The method of claim 5068, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.

5070. The method of claim 5061, further comprising separating at least a portion of carbon dioxide in the second ammonia feed stream from at least a portion of the second ammonia feed stream.

5071. The method of claim 5070, wherein the carbon dioxide is separated from the second ammonia feed stream by an amine separator.

5072. The method of claim 5071, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.

5073. The method of claim 5061, wherein fluids produced during pyrolysis of an oil shale formation comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5074. The method of claim 5061, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5075. The method of claim 5061, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.

5076. The method of claim 5061, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.

5077. The method of claim 5061, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the blended ammonia feed stream to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.

5078. A method for producing ammonia using an oil shale formation, comprising:

heating a selected section of the formation to a temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas;

providing a synthesis gas generating fluid and an O₂ rich stream to the selected section, wherein the amount of N₂ in the O₂ rich stream is sufficient to generate synthesis gas having a selected ratio of H₂ to N₂;

allowing the synthesis gas generating fluid and O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material in the formation to generate synthesis gas having a selected ratio of H₂ to N₂;

producing the synthesis gas from the formation;

providing at least a portion of the H₂ and N₂ in the synthesis gas to an ammonia synthesis process; and

using the ammonia synthesis process to generate ammonia.

5079. The method of claim 5078, further comprising controlling a temperature of at least a portion of the selected section to generate synthesis gas having the selected H₂ to N₂ ratio.

5080. The method of claim 5078, wherein the selected ratio is approximately 3:

1.

5081. The method of claim 5078, wherein the selected ratio ranges from approximately 2.8:

1 to approximately 3.2;

1.

5082. The method of claim 5078, wherein the temperature sufficient to support reaction of hydrocarbon containing material in the formation to form synthesis gas ranges from approximately 400°

C. to approximately 1200°

C.

5083. The method of claim 5078, wherein the O₂ stream and N₂ stream are obtained by cryogenic separation of air.

5084. The method of claim 5078, wherein the O₂ stream and N₂ stream are obtained by membrane separation of air.

5085. The method of claim 5078, further comprising separating at least a portion of carbon dioxide in the synthesis gas from at least a portion of the synthesis gas.

5086. The method of claim 5085, wherein the carbon dioxide is separated from the synthesis gas by an amine separator.

5087. The method of claim 5086, further comprising providing at least a portion of the carbon dioxide to a urea synthesis process.

5088. The method of claim 5078, wherein fluids produced during pyrolysis of an oil shale formation comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5089. The method of claim 5078, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5090. The method of claim 5078, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.

5091. The method of claim 5078, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.

5092. The method of claim 5078, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the synthesis gas to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.

5093. The method of claim 5078, wherein heating a selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises:

heating zones adjacent to wellbores of one or more heat sources with heaters disposed in the wellbores, wherein the heaters are configured to raise temperatures of the zones to temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ in the O₂ rich stream;

introducing the O₂ to the zones substantially by diffusion;

allowing O₂ in the O₂ rich stream to react with at least a portion of the hydrocarbon containing material within the zones to produce heat in the zones; and

transferring heat from the zones to the selected section.

5094. The method of claim 5093, wherein temperatures sufficient to support reaction of hydrocarbon containing material within the zones with O₂ range from approximately 200°

C. to approximately 1200°

C.

5095. The method of claim 5093, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.

5096. The method of claim 5093, wherein the one or more heat sources comprises one or more natural distributed combustors.

5097. The method of claim 5093, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5098. The method of claim 5093, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

5099. The method of claim 5078, wherein heating the selected section of the formation to a temperature to support reaction of hydrocarbon containing material in the formation to form synthesis gas comprises:

introducing the O₂ rich stream into the formation through a wellbore;

transporting O₂ in the O₂ rich stream substantially by convection into the portion of the selected section, wherein the portion of the selected section is at a temperature sufficient to support an oxidation reaction with O₂ in the O₂ rich stream; and

reacting the O₂ within the portion of the selected section to generate heat and raise the temperature of the portion.

5100. The method of claim 5099, wherein the temperature sufficient to support an oxidation reaction with O₂ ranges from approximately 200°

C. to approximately 1200°

C.

5101. The method of claim 5099, wherein the one or more heat sources comprises one or more electrical heaters disposed in the formation.

5102. The method of claim 5099, wherein the one or more heat sources comprises one or more natural distributed combustors.

5103. The method of claim 5099, wherein the one or more heat sources comprise one or more heater wells, wherein at least one heater well comprises a conduit disposed within the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5104. The method of claim 5099, further comprising using a portion of the synthesis gas as a combustion fuel for the one or more heat sources.

5105. The method of claim 5078, further comprising controlling the heating of at least the portion of the selected section and provision of the synthesis gas generating fluid to maintain a temperature within at least the portion of the selected section above the temperature sufficient to generate synthesis gas.

5106. The method of claim 5078, wherein the synthesis gas generating fluid comprises liquid water.

5107. The method of claim 5078, wherein the synthesis gas generating fluid comprises steam.

5108. The method of claim 5078, wherein the synthesis gas generating fluid comprises water and carbon dioxide, wherein the carbon dioxide inhibits production of carbon dioxide from the selected section.

5109. The method of claim 5108, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

5110. The method of claim 5078, wherein the synthesis gas generating fluid comprises carbon dioxide, and wherein a portion of the carbon dioxide reacts with carbon in the formation to generate carbon monoxide.

5111. The method of claim 5110, wherein a portion of the carbon dioxide within the synthesis gas generating fluid comprises carbon dioxide removed from the formation.

5112. The method of claim 5078, wherein providing the synthesis gas generating fluid to at least the portion of the selected section comprises raising a water table of the formation to allow water to flow into the at least the portion of the selected section.

5113. A method for producing ammonia using an oil shale formation, comprising:

providing a first stream comprising N₂ and carbon dioxide to the formation;

allowing at least a portion of the carbon dioxide in the first stream to adsorb in the formation;

producing a second stream from the formation, wherein the second stream comprises a lower percentage of carbon dioxide than the first stream;

providing at least a portion of the N₂ in the second stream to an ammonia synthesis process.

5114. The method of claim 5113 wherein the second stream comprises H₂ from the formation.

5115. The method of claim 5113, wherein the first stream is produced from an oil shale formation.

5116. The method of claim 5115, wherein the first stream is generated by reacting a oxidizing fluid with hydrocarbon containing material in the formation.

5117. The method of claim 5113, wherein the second stream comprises H₂ from the formation and, further comprising providing such H₂ to the ammonia synthesis process.

5118. The method of claim 5113, further comprising using the ammonia synthesis process to generate ammonia.

5119. The method of claim 5118, wherein fluids produced during pyrolysis of an oil shale formation comprise ammonia and, further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5120. The method of claim 5118, wherein fluids produced during pyrolysis of a hydrocarbon formation are hydrotreated and at least some ammonia is produced during hydrotreating, and further comprising adding at least a portion of such ammonia to the ammonia generated from the ammonia synthesis process.

5121. The method of claim 5118, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea.

5122. The method of claim 5118, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and, further comprising providing carbon dioxide from the formation to the urea synthesis process.

5123. The method of claim 5118, further comprising providing at least a portion of the ammonia to a urea synthesis process to produce urea and further comprising shifting at least a portion of carbon monoxide in the synthesis gas to carbon dioxide in a shift process, and further comprising providing at least a portion of the carbon dioxide from the shift process to the urea synthesis process.

5124. A method for treating hydrocarbons in at least a portion of an oil shale formation, wherein the portion has an average permeability of less than about 10 millidarcy, comprising:

providing heat from three or more heat sources to the formation;

allowing the heat to transfer from three or more of the heat sources to a selected section of the formation such that heat from the heat sources pyrolyzes at least some hydrocarbons within the selected section, and at least three of the heat sources are arranged in a substantially triangular pattern; and

producing a mixture comprising hydrocarbons from the formation.

5125. The method of claim 5124, wherein superposition of heat from at least the three heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

5126. The method of claim 5124, wherein the mixture is produced from a production well located in a triangular region created by at least three heat sources.

5127. The method of claim 5124, further comprising allowing heat to transfer from at least one of the heat sources to the selected section to create thermal fractures in the formation, wherein the thermal fractures substantially increase the permeability of the selected section.

5128. The method of claim 5124, wherein the heat is provided such that an average temperature in the selected section ranges from approximately about 270°

C. to about 375°

C.

5129. The method of claim 5124, wherein at least one of the heat sources comprises a electrical heater located in the formation.

5130. The method of claim 5124, wherein at least one of the heat sources is located in a heater well, and wherein at least one of the heater wells comprises a conduit located in the formation, and further comprising heating the conduit by flowing a hot fluid through the conduit.

5131. The method of claim 5124, wherein at least some of the heat sources are arranged in a triangular pattern.

5132. The method of claim 5124, further comprising:

monitoring a composition of the produced mixture; and

controlling a pressure in at least a portion of the formation to control the composition of the produced mixture.

5133. The method of claim 5132, wherein the pressure is controlled by a valve proximate to a location where the mixture is produced.

5134. The method of claim 5132, wherein the pressure is controlled such that pressure proximate to one or more of the heat sources is greater than a pressure proximate to a location where the fluid is produced.

5135. The method of claim 5124, wherein an average distance between heat sources is between about 2 m and about 8 m.

5136. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use;

at least one centralizer configurable to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use; and

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.

5137. The system of claim 5136, wherein at least one centralizer comprises electrically-insulating material.

5138. The system of claim 5136, wherein at least one centralizer is configurable to inhibit arcing between the conductor and the conduit.

5139. The system of claim 5136, wherein at least one centralizer comprises ceramic material.

5140. The system of claim 5136, wherein at least one centralizer comprises at least one recess, wherein at least one recess is placed at a junction of at least one centralizer and the first conductor, wherein at least one protrusion is formed on the first conductor at the junction to maintain a location of at least one centralizer on the first conductor, and wherein at least one protrusion resides substantially within at least one recess.

5141. The system of claim 5140, wherein at least one protrusion comprises a weld.

5142. The system of claim 5140, wherein an electrically-insulating material substantially covers at least one recess.

5143. The system of claim 5140, wherein a thermal plasma applied coating substantially covers at least one recess.

5144. The system of claim 5140, wherein a thermal plasma applied coating comprises alumina.

5145. The system of claim 5136, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5146. The system of claim 5136, further comprising an insulation layer configurable to be coupled to at least a portion of the conductor or at least one centralizer.

5147. The system of claim 5136, wherein at least one centralizer comprises a neck portion.

5148. The system of claim 5136, wherein at least one centralizer comprises one or more grooves.

5149. The system of claim 5136, wherein at least one centralizer comprises at least two portions, and wherein the portions are configurable to be coupled to the conductor to form at least one centralizer placed on the conductor.

5150. The system of claim 5136, wherein a thickness of the conductor is greater adjacent to a lean zone in the formation than a thickness of the conductor adjacent to a rich zone in the formation such that more heat is provided to the rich zone.

5151. The system of claim 5136, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within the conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use;

at least one centralizer configured to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use; and

wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.

5152. The system of claim 5136, wherein the system heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within the conduit, wherein the conductor provides heat to at least a portion of the formation;

at least one centralizer coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit; and

wherein the system allows heat to transfer from the conductor to a section of the formation.

5153. The system of claim 5136, wherein the system is configurable to be removed from the opening in the formation.

5154. The system of claim 5136, further comprising a moveable thermocouple.

5155. The system of claim 5136, further comprising an isolation block.

5156. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use;

at least one centralizer configurable to be coupled to the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit during use

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use; and

wherein the system is configurable to be removed from the opening in the formation.

5157. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed within a conduit, wherein at least one centralizer is coupled to the conductor to inhibit movement of the conductor within the conduit, and wherein the conduit is placed within an opening in the formation; and

allowing the heat to transfer from the first conductor to a section of the formation.

5158. The method of claim 5157, further comprising pyrolyzing at least some hydrocarbons in the section of the formation.

5159. The method of claim 5157, further comprising inhibiting arcing between the conductor and the conduit.

5160. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use;

an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit during use; and

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use

5161. The system of claim 5160, wherein the insulation layer comprises a spiral insulation layer.

5162. The system of claim 5160, wherein the insulation layer comprises at least one metal oxide.

5163. The system of claim 5160, wherein the insulation layer comprises at least one alumina oxide.

5164. The system of claim 5160, wherein the insulation layer is configurable to be fastened to the conductor with a high temperature glue.

5165. The system of claim 5160, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5166. The system of claim 5160, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use;

an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit during use; and

wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.

5167. The system of claim 5160, wherein the system heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation;

an insulation layer coupled to at least a portion of the conductor, wherein the insulation layer electrically insulates at least a portion of the conductor from the conduit; and

wherein the system allows heat to transfer from the conductor to a section of the formation.

5168. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed within a conduit, wherein an insulation layer is coupled to at least a portion of the conductor to electrically insulate at least a portion of the conductor from the conduit, and wherein the conduit is placed within an opening in the formation; and

allowing the heat to transfer from the first conductor to a section of the formation.

5169. The method of claim 5168, further comprising pyrolyzing at least some hydrocarbons in the section of the formation.

5170. The method of claim 5168, further comprising inhibiting arcing between the conductor and the conduit.

5171. A method for making a conductor-in-conduit heat source for an oil shale formation, comprising:

placing at least one protrusion on a conductor;

placing at least one centralizer on the conductor; and

placing the conductor within a conduit to form a conductor-in-conduit heat source, wherein at least one centralizer maintains a location of the conductor within the conduit.

5172. The method of claim 5171, wherein at least one centralizer comprises at least two portions, and wherein the portions are coupled to the conductor to form at least one centralizer placed on the conductor.

5173. The method of claim 5171, further comprising placing the conductor-in-conduit heat source in an opening in an oil shale formation.

5174. The method of claim 5171, further comprising coupling an insulation layer on the conductor, wherein the insulation layer is configured to electrically insulate at least a portion of the conductor from the conduit

5175. The method of claim 5171, further comprising providing heat from the conductor-in-conduit heat source to at least a portion of the formation.

5176. The method of claim 5171, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.

5177. The method of claim 5171, further comprising producing a mixture from a selected section of the formation.

5178. The method of claim 5171, wherein the conductor-in-conduit heat source is configurable to provide heat to the oil shale formation.

5179. The method of claim 5171, wherein at least one centralizer comprises at least one recess placed at a junction of at least one centralizer on the conductor, and wherein at least one protrusion resides substantially within at least one recess.

5180. The method of claim 5179, further comprising at least partially covering at least one recess with an electrically-insulating material.

5181. The method of claim 5179, further comprising spraying an electrically-insulating material to at least partially cover at least one recess.

5182. The method of claim 5171, wherein placing at least one protrusion on the conductor comprises welding at least one protrusion on the conductor.

5183. The method of claim 5171, further comprising coiling the conductor-in-conduit heat source on a spool after forming the heat source.

5184. The method of claim 5171, further comprising uncoiling the heat source from the spool while placing the heat source in an opening in the formation.

5185. The method of claim 5171, wherein placing the conductor within a conduit comprises placing the conductor within a conduit that has been placed in an opening in the formation.

5186. The method of claim 5171, further comprising coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.

5187. The method of claim 5171, wherein the conductor-in-conduit heat source is configurable to be installed into an opening in an oil shale formation.

5188. The method of claim 5171, wherein the conductor-in-conduit heat source is configurable to be removed from an opening in an oil shale formation.

5189. The method of claim 5171, wherein the conductor-in-conduit heat source is configurable to heat to a section of the oil shale formation, and wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.

5190. The method of claim 5171, wherein a thickness of the conductor configurable to be placed adjacent to a lean zone in the formation is greater than a thickness of the conductor configurable to be placed adjacent to a rich zone in the formation such that more heat is provided to the rich zone during use.

5191. A method for forming an opening in an oil shale formation, comprising:

forming a first opening in the formation;

providing a series of magnetic fields from a plurality of magnets positioned along a portion of the first opening; and

forming a second opening in the formation using magnetic tracking such that the second opening is positioned a selected distance from the first opening.

5192. The method of claim 5191, further comprising providing a magnetic string to a portion of the first opening.

5193. The method of claim 5191, wherein the plurality of magnets is positioned within a casing.

5194. The method of claim 5191, wherein the plurality of magnets is positioned within a heater casing.

5195. The method of claim 5191, wherein the plurality of magnets is positioned within a perforated casing.

5196. The method of claim 5191, further comprising providing a magnetic string to a portion of the first opening, wherein the magnetic string comprises two or more magnetic segments, and wherein the two or more segments are positioned such that the polarity of adjacent segments is reversed.

5197. The method of claim 5191, further comprising moving the magnetic fields within the first opening.

5198. The method of claim 5191, further comprising moving the magnetic fields within the first opening such that the magnetic fields vary with time.

5199. The method of claim 5191, further comprising adjusting a position of the magnetic fields within the first opening to increase a length of the second opening.

5200. The method of claim 5191, further comprising forming a plurality of openings adjacent to the first opening.

5201. The method of claim 5191, wherein the first opening comprises a non-metallic casing.

5202. The method of claim 5191, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic differs from a strength of the second magnetic field.

5203. The method of claim 5191, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic is about a strength of the second magnetic field.

5204. The method of claim 5191, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening.

5205. The method of claim 5191, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening, wherein each of the plurality of openings is positioned at the selected distance from the first opening.

5206. The method of claim 5191, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.

5207. A method for forming an opening in an oil shale formation, comprising:

forming a first opening in the formation;

providing a magnetic string to the first opening, wherein the magnetic string comprises two or more magnetic segments, and wherein the magnetic segments are positioned such that the polarities of the segments are reversed; and

forming a second opening in the formation using magnetic tracking such that the second opening is positioned a selected distance from the first opening.

5208. The method of claim 5207, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.

5209. The method of claim 5207, wherein the two or more segments comprise a plurality of magnets.

5210. The method of claim 5207, further comprising providing a series of magnetic fields along a portion of the first opening.

5211. The method of claim 5207, wherein a length of a segment corresponds to a distance between the first opening and the second opening.

5212. The method of claim 5207, further comprising moving the magnetic fields within the first opening.

5213. The method of claim 5207, further comprising moving the magnetic fields within the first opening such that the magnetic fields vary with time.

5214. The method of claim 5207, further comprising adjusting a position of the magnetic fields within the first opening to increase a length of the second opening.

5215. The method of claim 5207, further comprising forming a plurality of openings adjacent to the first opening.

5216. The method of claim 5207, wherein the first opening comprises a non-metallic casing.

5217. The method of claim 5207, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic field differs from a strength of the second magnetic field.

5218. The method of claim 5207, wherein the series of the magnetic fields comprises a first magnetic field and a second magnetic field and wherein a strength of the first magnetic field is about a strength of the second magnetic field.

5219. The method of claim 5207, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening.

5220. The method of claim 5207, wherein the first opening comprises a center opening in a pattern of openings, and further comprising forming a plurality of openings adjacent to the first opening, wherein each of the plurality of openings is positioned at the selected distance from the first opening.

5221. The method of claim 5207, further comprising providing at least one heating mechanism within the first opening and at least one heating mechanism within the second opening such that the heating mechanisms can provide heat to at least a portion of the formation.

5222. The method of claim 5207, wherein the magnetic string is positioned within a casing.

5223. The method of claim 5207, wherein the magnetic string is positioned within a heater casing.

5224. A system for drilling openings in an oil shale formation, comprising:

a drilling apparatus;

a magnetic string, comprising;

a conduit; and

two or more magnetic segments positionable in the conduit, wherein the magnetic segments comprise a plurality of magnets; and

a sensor configurable to detect a magnetic field within the formation.

5225. The system of claim 5224, wherein the magnetic string further comprises one or more members configurable to inhibit movement of the magnetic segments relative to the conduit.

5226. The system of claim 5224, wherein the one or more magnetic segments are positioned such that a polarity of adjacent segments is reversed.

5227. The system of claim 5224, wherein the magnetic string is positionable within a first opening in the formation.

5228. The system of claim 5224, wherein the magnetic string is positionable within a first opening in the formation and wherein the magnetic string induces a magnetic field in a portion of the first opening.

5229. The system of claim 5224, further comprising at least one heating mechanism within a first opening.

5230. The system of claim 5224, further comprising at least one heating mechanism within a first opening and at least one heating mechanism within a second opening such that the heating mechanisms can provide heat to at least a portion of the formation.

5231. The system of claim 5224, further comprising providing a series of magnetic fields along a portion of a first opening.

5232. The system of claim 5224, wherein a length of a segment corresponds to a distance between the first opening and the second opening.

5233. The system of claim 5224, wherein the magnetic string is movable in a first opening.

5234. The system of claim 5224, wherein a position of the magnetic string in the first opening can be adjusted to increase a length of a second opening.

5235. The system of claim 5224, further comprising a first opening positioned in the formation and wherein the magnetic string is positionable in the first opening.

5236. The system of claim 5224, further comprising a non-metallic casing.

5237. The system of claim 5224, wherein the magnetic segments comprises a first magnetic segment and a second magnetic segment and wherein a length of the first magnetic segment differs from a length of the second magnetic segment.

5238. The system of claim 5224, wherein the magnetic segments comprises a first magnetic segment and a second magnetic segment and wherein a length of the first magnetic segment is about the same as a length of the second magnetic segment.

5239. The system of claim 5224, further comprising a casing and wherein the magnetic string is positioned within the casing.

5240. A method of installing a conductor-in-conduit heat source of a desired length in an oil shale formation, comprising:

assembling a conductor-in-conduit heat source of a desired length, comprising;

placing a conductor within a conduit to form a conductor-in-conduit heat source; and

coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of the desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source;

coiling the conductor-in-conduit heat source of the desired length after forming the heat source; and

placing the conductor-in-conduit heat source of the desired length in an opening in an oil shale formation.

5241. The method of claim 5240, wherein the conductor-in-conduit heat source is configurable to provide heat to the oil shale formation.

5242. The method of claim 5240, wherein the conductor-in-conduit heat source of the desired length is removable from the opening in the oil shale formation.

5243. The method of claim 5240, further comprising uncoiling the conductor-in-conduit heat source of the desired length while placing the heat source in the opening.

5244. The method of claim 5240, further comprising placing at least one centralizer on the conductor.

5245. The method of claim 5240, further comprising placing at least one centralizer on the conductor, wherein at least one centralizer inhibits movement of the conductor within the conduit.

5246. The method of claim 5240, further comprising placing an insulation layer on at least a portion of the conductor.

5247. The method of claim 5240, further comprising coiling the conductor-in-conduit heat source.

5248. The method of claim 5240, further comprising testing the conductor-in-conduit heat source and coiling the heat source.

5249. The method of claim 5240, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.

5250. The method of claim 5240, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source.

5251. The method of claim 5240, wherein coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source comprises shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source, and wherein using shielded active gas welding inhibits changes in the grain structure of the conductor or conduit during coupling.

5252. The method of claim 5240, wherein the assembling of the conductor-in-conduit heat source of the desired length is performed at a location proximate the oil shale formation.

5253. The method of claim 5240, wherein the assembling of the conductor-in-conduit heat source of the desired length takes place sufficiently proximate the oil shale formation such that the conductor-in-conduit heat source can be placed directly in an opening of the formation after the heat source is assembled.

5254. The method of claim 5240, further comprising coupling at least one substantially low resistance conductor to the conductor-in-conduit heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.

5255. The method of claim 5254, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5256. The method of claim 5254, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.

5257. The method of claim 5254, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5258. The method of claim 5254, wherein at least one substantially low resistance conductor is coupled to the conductor-in-conduit heat source of the desired length during assembling of the heat source of the desired length.

5259. The method of claim 5254, wherein at least one substantially low resistance conductor is coupled to the conductor-in-conduit heat source of the desired length after assembling of the heat source of the desired length.

5260. The method of claim 5240, further comprising transporting the coiled conductor-in-conduit heat source of the desired length on a cart or train from an assembly location to the opening in the oil shale formation.

5261. The method of claim 5260, wherein the cart or train can be further used to transport more than one conductor-in-conduit heat source of the desired length to more than one opening in the oil shale formation.

5262. The method of claim 5240, wherein the desired length comprises a length determined for using the conductor-in-conduit heat source in a selected opening in the oil shale formation.

5263. The method of claim 5240, further comprising treating the conductor to increase an emissivity of the conductor.

5264. The method of claim 5263, wherein treating the conductor comprises roughening the surface of the conductor.

5265. The method of claim 5263, wherein treating the conductor comprises heating the conductor to a temperature above about 750°

C. in an oxidizing fluid atmosphere.

5266. The method of claim 5240, further comprising treating the conduit to increase an emissivity of the conduit.

5267. The method of claim 5240, further comprising coating at least a portion of the conductor or at least a portion of the conduit during assembly of the conductor-in-conduit heat source.

5268. The method of claim 5240, further comprising placing an insulation layer on at least a portion of the conductor-in-conduit heat source prior to placing the heat source in the opening in the oil shale formation.

5269. The method of claim 5268, wherein the insulation layer comprises a spiral insulation layer.

5270. The method of claim 5268, wherein the insulation layer comprises at least one metal oxide.

5271. The method of claim 5268, further comprising fastening at least a portion of the insulation layer to at least a portion of the conductor-in-conduit heat source with a high temperature glue.

5272. The method of claim 5240, further comprising providing heat from the conductor-in-conduit heat source of the desired length to at least a portion of the formation.

5273. The method of claim 5240, wherein a thickness of the conductor configurable to be placed adjacent to a lean zone in the formation is greater than a thickness of the conductor configurable to be placed adjacent to a rich zone in the formation such that more heat is provided to the rich zone during use

5274. The method of claim 5240, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.

5275. The method of claim 5240, further comprising producing a mixture from a selected section of the formation.

5276. A method for making a conductor-in-conduit heat source configurable to be used to heat an oil shale formation, comprising:

placing a conductor within a conduit to form a conductor-in-conduit heat source; and

shielded active gas welding the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of a desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source; and

wherein the conductor-in-conduit heat source is configurable to be placed in an opening in the oil shale formation, and wherein the conductor-in-conduit heat source is further configurable to heat a section of the oil shale formation during use.

5277. The method of claim 5276, further comprising providing heat from the conductor-in-conduit heat source of the desired length to at least a portion of the formation.

5278. The method of claim 5276, further comprising pyrolyzing at least some hydrocarbons in a selected section of the formation.

5279. The method of claim 5276, further comprising producing a mixture from a selected section of the formation.

5280. The method of claim 5276, wherein the conductor and the conduit comprise stainless steel.

5281. The method of claim 5276, wherein the conduit comprises stainless steel.

5282. The method of claim 5276, wherein the heat source is configurable to be removed from the formation.

5283. The method of claim 5276, further comprising providing a reducing gas during welding.

5284. The method of claim 5276, wherein the reducing gas comprises molecular hydrogen.

5285. The method of claim 5276, further comprising providing a reducing gas during welding such that welding occurs in an environment comprising less than about 25% reducing gas by volume.

5286. The method of claim 5276, further comprising providing a reducing gas during welding such that welding occurs in an environment comprising about 10% reducing gas by volume.

5287. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within the conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.

5288. The system of claim 5287, wherein the conduit comprises at least two conduit sections coupled by shielded active gas welding.

5289. The system of claim 5287, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5290. The system of claim 5287, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within the conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and

wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.

5291. The system of claim 5287, wherein the system heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within the conduit, wherein the conductor provides heat to at least a portion of the formation during use, and wherein the conductor comprises at least two conductor sections coupled by shielded active gas welding; and

wherein the system allows heat to transfer from the conductor to a section of the formation during use.

5292. The system of claim 5287, wherein the conductor-in-conduit heat source is configurable to be removed from the formation.

5293. A method for installing a heat source of a desired length in an oil shale formation, comprising:

assembling a heat source of a desired length, wherein the assembling of the heat source of the desired length is performed at a location proximate the oil shale formation;

coiling the heat source of the desired length after forming the heat source; and

placing the heat source of the desired length in an opening in an oil shale formation, wherein placing the heat source in the opening comprises uncoiling the heat source while placing the heat source in the opening.

5294. The method of claim 5293, wherein the heat source is configurable to heat a section of the oil shale formation.

5295. The method of claim 5294, wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.

5296. The method of claim 5293, further comprising coupling at least one substantially low resistance conductor to the heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.

5297. The method of claim 5296, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5298. The method of claim 5296, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.

5299. The method of claim 5296, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5300. The method of claim 5293, further comprising transporting the heat source of the desired length on a cart or train from an assembly location to the opening in the oil shale formation.

5301. The method of claim 5300, wherein the cart or train can be further used to transport more than one heat source to more than one opening in the oil shale formation.

5302. The method of claim 5300, wherein the heat source is configurable to removable from the opening.

5303. A method for installing a heat source of a desired length in an oil shale formation, comprising:

assembling a heat source of a desired length, wherein the assembling of the heat source of the desired length is performed at a location proximate the oil shale formation;

coiling the heat source of the desired length after forming the heat source;

placing the heat source of the desired length in an opening in an oil shale formation, wherein placing the heat source in the opening comprises uncoiling the heat source while placing the heat source in the opening; and

wherein the heat source is configurable to be removed from the opening.

5304. The method of claim 5303, wherein the heat source is configurable to heat a section of the oil shale formation.

5305. The method of claim 5304, wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.

5306. The method of claim 5303, further comprising coupling at least one substantially low resistance conductor to the heat source of the desired length, wherein at least one substantially low resistance conductor is configured to be placed in an overburden of the formation.

5307. The method of claim 5306, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5308. The method of claim 5306, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises coupling a threaded end of at least one additional substantially low resistance conductor to a threaded end of at least one substantially low resistance conductor.

5309. The method of claim 5306, further comprising coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor, wherein coupling at least one additional substantially low resistance conductor to at least one substantially low resistance conductor comprises welding at least one additional substantially low resistance conductor to at least one substantially low resistance conductor.

5310. The method of claim 5303, further comprising transporting the heat source of the desired length on a cart or train from an assembly location to the opening in the oil shale formation.

5311. The method of claim 5303, wherein removing the heat source comprises recoiling the heat source.

5312. The method of claim 5303, wherein the heat source can be removed from the opening and installed in an alternate opening in the formation.

5313. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use;

an electrically conductive material configurable to be coupled to at least a portion of the conductor, wherein the electrically conductive material is configurable to lower an electrical resistance of the conductor in the overburden during use; and

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.

5314. The system of claim 5313, further comprising an electrically conductive material configurable to be coupled to at least a portion of an inside surface of the conduit.

5315. The system of claim 5313, further comprising a substantially low resistance conductor configurable to be electrically coupled to the conductor and the electrically conductive material during use, wherein the substantially low resistance conductor is further configurable to be placed within an overburden of the formation.

5316. The system of claim 5315, wherein the low resistance conductor comprises carbon steel.

5317. The system of claim 5313, wherein the electrically conductive material comprises metal tubing configurable to be clad to the conductor.

5318. The system of claim 5313, wherein the electrically conductive material comprises an electrically conductive coating configurable to be applied to the conductor.

5319. The system of claim 5313, wherein the electrically conductive material comprises a thermal plasma applied coating.

5320. The system of claim 5313, wherein the electrically conductive material is configurable to be sprayed on the conductor.

5321. The system of claim 5313, wherein the electrically conductive material comprises aluminum.

5322. The system of claim 5313, wherein the electrically conductive material comprises copper.

5323. The system of claim 5313, wherein the electrically conductive material is configurable to reduce the electrical resistance of the conductor in the overburden by a factor of greater than about 3.

5324. The system of claim 5313, wherein the electrically conductive material is configurable to reduce the electrical resistance of the conductor in the overburden by a factor of greater than about 15.

5325. The system of claim 5313, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5326. The system of claim 5313, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use;

an electrically conductive material configured to be coupled to the conductor, wherein the electrically conductive material is further configured to lower an electrical resistance of the conductor in the overburden during use; and

wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.

5327. The system of claim 5313, wherein the system heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within a conduit, wherein the conductor is provides heat to at least a portion of the formation during use;

an electrically conductive material coupled to the conductor, wherein the electrically conductive material lowers an electrical resistance of the conductor in the overburden during use; and

wherein the system allows heat to transfer from the conductor to a section of the formation during use.

5328. An in situ method for heating an oil shale formation, comprising:

applying an electrical current to a conductor to provide heat to at least a portion of the formation, wherein the conductor is placed in a conduit, and wherein the conduit is placed in an opening in the formation, and wherein the conductor is coupled to an electrically conductive material; and

allowing the heat to transfer from the conductor to a section of the formation.

5329. The method of claim 5328, wherein the electrically conductive material comprises copper.

5330. The method of claim 5328, further comprising coupling an electrically conductive material to an inside surface of the conduit.

5331. The method of claim 5328, wherein the electrically conductive material comprises metal tubing clad to the substantially low resistance conductor.

5332. The method of claim 5328, wherein the electrically conductive material reduces an electrical resistance of the substantially low resistance conductor in the overburden.

5333. The method of claim 5328, further comprising pyrolyzing at least some hydrocarbons within the formation.

5334. A system configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation;

a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and

wherein the system is configurable to allow heat to transfer from the conductor to a section of the formation during use.

5335. The system of claim 5334, wherein at least a portion of the surface of the conductor has been roughened to increase the emissivity of the conductor.

5336. The system of claim 5334, wherein the conductor has been heated to a temperature above about 750°

C. in an oxidizing fluid atmosphere to increase the emissivity of at least a portion of the surface of the conductor.

5337. The system of claim 5334, wherein the conduit has been treated to increase an emissivity of at least a portion of the surface of the conduit.

5338. The system of claim 5334, further comprising an electrically insulative, thermally conductive coating coupled to the conductor.

5339. The system of claim 5338, wherein the electrically insulative, thermally conductive coating is configurable to electrically insulate the conductor from the conduit.

5340. The system of claim 5338, wherein the electrically insulative, thermally conductive coating inhibits emissivity of the conductor from decreasing.

5341. The system of claim 5338, wherein the electrically insulative, thermally conductive coating substantially increases an emissivity of the conductor.

5342. The system of claim 5338, wherein the electrically insulative, thermally conductive coating comprises silicon oxide.

5343. The system of claim 5338, wherein the electrically insulative, thermally conductive coating comprises aluminum oxide.

5344. The system of claim 5338, wherein the electrically insulative, thermally conductive coating comprises refractive cement.

5345. The system of claim 5338, wherein the electrically insulative, thermally conductive coating is sprayed on the conductor.

5346. The system of claim 5334, wherein the system is further configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5347. The system of claim 5334, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and

wherein the system is configured to allow heat to transfer from the conductor to a section of the formation during use.

5348. The system of claim 5334, wherein the system heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor; and

wherein the system allows heat to transfer from the conductor to a section of the formation during use.

5349. A heat source configurable to heat an oil shale formation, comprising:

a conduit configurable to be placed within an opening in the formation; and

a conductor configurable to be placed within a conduit, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.

5350. The heat source of claim 5349, wherein at least a portion of the surface of the conductor has been roughened to increase the emissivity the conductor.

5351. The heat source of claim 5349, wherein the conductor has been heated to a temperature above about 750°

C. in an oxidizing fluid atmosphere to increase the emissivity of at least at least a portion of the surface of the conductor.

5352. The heat source of claim 5349, wherein the conduit has been treated to increase an emissivity of at least a portion of the surface of the conduit.

5353. The heat source of claim 5349, further comprising an electrically insulative, thermally conductive coating placed on the conductor.

5354. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating is configurable to electrically insulate the conductor from the conduit.

5355. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating substantially maintains an emissivity of the conductor.

5356. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating substantially increases an emissivity of the conductor.

5357. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating comprises silicon oxide.

5358. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating comprises aluminum oxide.

5359. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating comprises refractive cement.

5360. The heat source of claim 5353, wherein the electrically insulative, thermally conductive coating is sprayed on the conductor.

5361. The heat source of claim 5349, wherein the conductor is further configurable to provide heat to at least a portion of the formation during use such that at least some hydrocarbons pyrolyze in the heated section of the formation during use.

5362. The heat source of claim 5349, wherein the heat source is configured to heat an oil shale formation, and wherein the system comprises:

a conduit configured to be placed within an opening in the formation;

a conductor configured to be placed within a conduit, wherein the conductor is further configured to provide heat to at least a portion of the formation during use, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.

5363. The heat source of claim 5349, wherein the heat source heats an oil shale formation, and wherein the system comprises:

a conduit placed within an opening in the formation;

a conductor placed within a conduit, wherein the conductor provides heat to at least a portion of the formation, and wherein the conductor has been treated to increase an emissivity of at least a portion of a surface of the conductor.

5364. A method for forming an increased emissivity conductor-in-conduit heat source, comprising:

treating a surface of a conductor to increase an emissivity of at least the surface of the conductor;

placing the conductor within a conduit to form a conductor-in-conduit heat source; and

wherein the conductor-in-conduit heat source is configurable to heat an oil shale formation.

5365. The method of claim 5364, wherein treating the surface of the conductor comprises roughening at least a portion of the surface of the conductor.

5366. The method of claim 5364, wherein treating the surface of the conductor comprises heating the conductor to a temperature above about 750°

C. in an oxidizing fluid atmosphere.

5367. The method of claim 5364, further comprising treating a surface of the conduit to increase an emissivity of at least a portion of the surface of the conduit.

5368. The method of claim 5364, further comprising placing the conductor-in-conduit heat source of the desired length in an opening in an oil shale formation.

5369. The method of claim 5364, further comprising assembling a conductor-in-conduit heat source of a desired length, the assembling comprising:

coupling the conductor-in-conduit heat source to at least one additional conductor-in-conduit heat source to form a conductor-in-conduit heat source of a desired length, wherein the conductor is electrically coupled to the conductor of at least one additional conductor-in-conduit heat source and the conduit is electrically coupled to the conduit of at least one additional conductor-in-conduit heat source;

coiling the conductor-in-conduit heat source of the desired length after forming the heat source; and

placing the conductor-in-conduit heat source of the desired length in an opening in an oil shale formation.

5370. The method of claim 5364, wherein the conductor-in-conduit heat source is configurable to heat to a section of the oil shale formation, and wherein the heat pyrolyzes at least some hydrocarbons in the section of the formation during use.

5371. A system configurable to heat an oil shale formation, comprising:

a heat source configurable to be placed in an opening in the formation, wherein the heat source is further configurable to provide heat to at least a portion of the formation during use;

an expansion mechanism configurable to be coupled to the heat source, wherein the expansion mechanism is configurable to allow for movement of the heat source during use; and

wherein the system is configurable to allow heat to transfer to a section of the formation during use.

5372. The system of claim 5371, wherein the expansion mechanism is configurable to allow for expansion of the heat source during use.

5373. The system of claim 5371, wherein the expansion mechanism is configurable to allow for contraction of the heat source during use.

5374. The system of claim 5371, wherein the expansion mechanism is configurable to allow for expansion of at least one component of the heat source during use.

5375. The system of claim 5371, wherein the expansion mechanism is configurable to allow for expansion and contraction of the heat source within a wellbore during use.

5376. The system of claim 5371, wherein the expansion mechanism comprises spring loading.

5377. The system of claim 5371, wherein the expansion mechanism comprises an accordion mechanism.

5378. The system of claim 5371, wherein the expansion mechanism is configurable to be coupled to a bottom of the heat source.

5379. The system of claim 5371, wherein the heat source is configurable to allow at least some hydrocarbons to pyrolyze in the heated section of the formation during use.

5380. The system of claim 5371, wherein the system is configured to heat an oil shale formation, and wherein the system comprises:

a heat source configured to be placed in an opening in the formation, wherein the heat source is further configured to provide heat to at least a portion of the formation during use;

an expansion mechanism configured to be coupled to the heat source, wherein the expansion mechanism is configured to allow for movement of the heat source during use; and

wherein the system is configured to allow heat to transfer to a section of the formation during use.

5381. The system of claim 5371, wherein the system heats an oil shale formation, and wherein the system comprises:

a heat source placed in an opening in the formation, wherein the heat source provides heat to at least a portion of the formation during use;

an expansion mechanism coupled to the heat source, wherein the expansion mechanism allows for movement of the heat source during use; and

wherein the system allows heat to transfer to a section of the formation during use.

5382. The system of claim 5371, wherein the heat source is removable.

5383. A system configurable to provide heat to an oil shale formation, comprising:

a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and

an oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the conduit.

5384. The system of claim 5383, wherein heat from the oxidizer pyrolyzes at least some hydrocarbons in the selected section.

5385. The system of claim 5383, wherein the conduit is positioned in the opening.

5386. The system of claim 5383, wherein the oxidizer is positionable in the conduit.

5387. The system of claim 5383, wherein the oxidizer is positioned in the conduit, and wherein the oxidizer is configured to heat the selected section.

5388. The system of claim 5383, wherein the oxidizer comprises a ring burner.

5389. The system of claim 5383, wherein the oxidizer comprises an inline burner.

5390. The system of claim 5383, wherein the oxidizer is configurable to provide heat in the conduit.

5391. The system of claim 5383, further comprising an annulus formed between a wall of the conduit and a wall of the opening.

5392. The system of claim 5383, wherein the oxidizer comprises a first oxidizer and a second oxidizer, and further comprising an annulus formed between a wall of the conduit and a wall of the opening, wherein the second oxidizer is positionable in the annulus.

5393. The system of claim 5392, wherein the first oxidizer is configurable to provide heat in the conduit, and wherein the second oxidizer is configurable to provide heat outside of the conduit.

5394. The system of claim 5392, wherein heat provided by the first oxidizer transfers in the first conduit in a direction opposite of heat provided by the second oxidizer.

5395. The system of claim 5392, wherein heat provided by the first oxidizer transfers in the first conduit in a same direction as heat provided by the second oxidizer.

5396. The system of claim 5383, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the conduit to a fuel source.

5397. The system of claim 5383, wherein the oxidizer comprises a first oxidizer positioned in the conduit and a second oxidizer positioned in an annulus formed between a wall of the conduit and a wall of the opening, wherein the oxidizers are configurable to oxidize fuel to generate heat, and further comprising:

a first recycle conduit configurable to recycle at least some of the fuel in the conduit to the second oxidizer; and

a second recycle conduit configurable to recycle at least some of the fuel in the annulus to the first oxidizer.

5398. The system of claim 5383, further comprising insulation positionable proximate the oxidizer.

5399. An in situ method for heating an oil shale formation, comprising:

providing heat to a conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and

allowing the heat in the conduit to transfer through the opening and to a surrounding portion of the formation.

5400. The method of claim 5399, further comprising:

providing fuel to an oxidizer;

oxidizing at least some of the fuel; and

allowing oxidation products to migrate through the opening, wherein the oxidation products comprise heat.

5401. The method of claim 5400, wherein the fuel is provided to the oxidizer proximate the first location, and wherein the oxidation products migrate towards the second location.

5402. The method of claim 5399, wherein the oxidizer comprises a ring burner.

5403. The method of claim 5399, wherein the oxidizer comprises an inline burner.

5404. The method of claim 5399, further comprising recycling at least some fuel in the conduit.

5405. A system configurable to provide heat to an oil shale formation, comprising:

a conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location;

an annulus formed between a wall of the conduit and a wall of the opening; and

a oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the annulus.

5406. The system of claim 5405, wherein heat from the oxidizer pyrolyzes at least some hydrocarbons in the selected section.

5407. The system of claim 5405, wherein the conduit is positioned in the opening.

5408. The system of claim 5405, wherein the oxidizer comprises a first oxidizer and a second oxidizer, wherein the second oxidizer is positioned in the conduit, and wherein the second oxidizer is configured to heat the selected section.

5409. The system of claim 5408, wherein heat provided by the first oxidizer transfers in the first conduit in a direction opposite of heat provided by the second oxidizer.

5410. The system of claim 5405, wherein the oxidizer comprises a ring burner.

5411. The system of claim 5405, wherein the oxidizer comprises an inline burner.

5412. The system of claim 5405, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the conduit to a fuel source.

5413. The system of claim 5405, further comprising insulation positionable proximate the oxidizer.

5414. The system of claim 5405, wherein the conduit is positioned in the opening.

5415. The system of claim 5405, wherein the oxidizer is positioned in the annulus, and wherein the oxidizer is configured to heat the selected section.

5416. The system of claim 5405, wherein the oxidizer comprises a first oxidizer and a second oxidizer.

5417. The system of claim 5416, wherein heat provided by the first oxidizer transfers through the opening in a direction opposite of heat provided by the second oxidizer.

5418. The system of claim 5416, wherein a first mixture of oxidation products generated by the first oxidizer flows countercurrent to a second mixture of oxidation products generated by the second heater.

5419. The system of claim 5416, wherein fuel is oxidized by the oxidizers to generate heat, and further comprising a first recycle conduit to recycle fuel in the first conduit proximate the second location to the second conduit.

5420. The system of claim 5416, wherein fuel is oxidized by the oxidizers to generate heat, and further comprising a second recycle conduit to recycle fuel in the second conduit proximate the first location to the first conduit.

5421. The system of claim 5405, wherein the oxidizer is configurable to oxidize fuel to generate heat, and further comprising a recycle conduit configurable to recycle at least some of the fuel in the annulus to a fuel source.

5422. The system of claim 5405, further comprising insulation positionable proximate the oxidizer.

5423. The system of claim 5405, further comprising a casing, wherein the conduit is positionable in the casing.

5424. The system of claim 5405, wherein the oxidizer comprises a first oxidizer positioned in the annulus and a second oxidizer positioned in the conduit, wherein the oxidizers are configurable to oxidize fuel to generate heat, and further comprising:

a first recycle conduit configurable to recycle at least some of the fuel in the annulus to the second oxidizer; and

a second recycle conduit configurable to recycle at least some of the fuel in the conduit to the first oxidizer.

5425. An in situ method for heating an oil shale formation, comprising:

providing heat to an annulus formed between a wall of an opening in the formation and a wall of a conduit in the opening, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and

allowing the heat in the annulus to transfer through the opening and to a surrounding portion of the formation.

5426. The method of claim 5425, further comprising:

providing fuel to an oxidizer;

oxidizing at least some of the fuel; and

allowing oxidation products to migrate through the opening, wherein the oxidation products comprise heat.

5427. The method of claim 5426, wherein the fuel is provided the oxidizer proximate the first location, and wherein the oxidation products migrate towards the second location.

5428. The method of claim 5425, wherein the oxidizer comprises a ring burner.

5429. The method of claim 5425, wherein the oxidizer comprises an inline burner.

5430. The method of claim 5425, further comprising recycling at least some fuel in the conduit.

5431. A system configurable to provide heat to an oil shale formation, comprising:

a first conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location;

a second conduit positionable in the opening;

a first oxidizer configurable to provide heat to a selected section of the formation by transferring heat through the first conduit; and

a second oxidizer configurable to provide heat to the selected section of the formation by transferring heat through the second conduit.

5432. The system of claim 5431, wherein the first oxidizer is positionable in the first conduit.

5433. The system of claim 5431, wherein the second oxidizer is positionable in the second conduit.

5434. The system of claim 5431, further comprising a casing positionable in the opening.

5435. The system of claim 5431, wherein at least a portion of the second conduit is positionable in the first conduit, and further comprising an annulus formed between a wall of the first conduit and a wall of the second conduit.

5436. The system of claim 5431, wherein a portion of the second conduit is positionable proximate a portion of the first conduit.

5437. The system of claim 5431, wherein the first oxidizer or the second oxidizer provide heat to at least a portion of the formation.

5438. The system of claim 5431, wherein the first oxidizer and the second oxidizer provide heat to at least a portion of the formation concurrently.

5439. The system of claim 5431, wherein the first oxidizer is positioned in the first conduit, wherein the second oxidizer is positioned in the second conduit, wherein the first oxidizer and the second oxidizer comprise oxidizers, and wherein a first flow of oxidation products from the first oxidizer flows in a direction opposite of a second flow of oxidation products from the second oxidizer.

5440. The system of claim 5431, further comprising:

a first recycle conduit configurable to recycle at least some of the fuel in the first conduit to the second oxidizer; and

a second recycle conduit configurable to recycle at least some of the fuel in the second conduit to the first oxidizer.

5441. An in situ method for heating an oil shale formation, comprising:

providing heat to a first conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location;

providing heat to a second conduit positioned in the opening in the formation;

allowing the heat in the first conduit to transfer through the opening and to a surrounding portion of the formation; and

allowing the heat in the second conduit to transfer through the opening and to a surrounding portion of the formation;

5442. The method of claim 5441, wherein providing heat to the first conduit comprises providing fuel to an oxidizer.

5443. The method of claim 5441, wherein providing heat to the second conduit comprises providing fuel to an oxidizer.

5444. The method of claim 5441, wherein the first fuel is provided to the first conduit proximate the first location, and wherein the second fuel is provided to the second conduit proximate the second location.

5445. The method of claim 5441, wherein the first oxidizer or the second oxidizer comprises a ring burner.

5446. The method of claim 5441, wherein the first oxidizer or the second oxidizer an inline burner.

5447. The method of claim 5441, further comprising:

transferring heat through the first conduit in a first direction; and

transferring heat in the second conduit in a second direction.

5448. The method of claim 5441, further comprising recycling at least some fuel in the first conduit to the second conduit;

and recycling at least some fuel in the second conduit to the first conduit.

5449. A system configurable to provide heat to an oil shale formation, comprising:

a first conduit positionable in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, wherein a second end of the opening contacts the earth surface at a second location;

a second conduit positionable in the first conduit; and

at least one surface unit configurable to provide heat to the first conduit.

5450. The system of claim 5449, wherein the surface unit comprises a furnace.

5451. The system of claim 5449, wherein the surface unit comprises a burner.

5452. The system of claim 5449, wherein at least one surface unit is configurable to provide heat to the second conduit.

5453. The system of claim 5452, wherein the first conduit and the second conduit provide heat to at least a portion of the formation.

5454. The system of claim 5452, wherein the first conduit provides heat to at least a portion of the formation.

5455. The system of claim 5452, wherein the second conduit provides heat to at least a portion of the formation.

5456. The system of claim 5449, further comprising a casing positionable in the opening.

5457. The method of claim 5449, wherein the first conduit and the second conduit are concentric.

5458. An in situ method for heating an oil shale formation, comprising:

heating a fluid using at least one surface unit;

providing the heated fluid to a first conduit wherein a portion of the first conduit is positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location;

allowing the heated fluid to flow into a second conduit, wherein the first conduit is positioned within the second conduit; and

allowing heat from the first and second conduit to transfer to a portion of the formation.

5459. The method of claim 5458, further comprising providing additional heat to the heated fluid using at least one surface unit proximate the second location.

5460. The method of claim 5458, wherein the fluid comprises an oxidizing fluid.

5461. The method of claim 5458, wherein the fluid comprises air.

5462. The method of claim 5458, wherein the fluid comprises flue gas.

5463. The method of claim 5458, wherein the fluid comprises steam.

5464. The method of claim 5458, wherein the fluid comprises fuel.

5465. The method of claim 5458, further comprising compressing the fluid prior to heating.

5466. The method of claim 5458, wherein the surface unit comprises a furnace.

5467. The method of claim 5458, wherein the surface unit comprises an indirect furnace.

5468. The method of claim 5458, wherein the surface unit comprises a burner.

5469. The method of claim 5458, wherein the first conduit and the second conduit are concentric.

5470. A system configurable to provide heat to an oil shale formation, comprising:

a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and

at least two oxidizers configurable to provide heat to a portion of the formation.

5471. The system of claim 5470, wherein heat from the oxidizers pyrolyzes at least some hydrocarbons in the selected section.

5472. The system of claim 5470, wherein the conduit comprises a fuel conduit.

5473. The system of claim 5470, wherein at least one oxidizer is positionable proximate the conduit.

5474. The system of claim 5470, wherein at least one oxidizer comprises a ring burner.

5475. The system of claim 5470, wherein at least one oxidizer comprises an inline burner.

5476. The system of claim 5470, further comprising insulation positionable proximate at least one oxidizer.

5477. The system of claim 5470, further comprising a casing comprising insulation proximate at least one oxidizer.

5478. An in situ method for heating an oil shale formation, comprising:

providing fuel to a conduit positioned in an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location;

providing an oxidizing fluid to the opening;

oxidizing fuel in at least one oxidizer positioned proximate the conduit; and

allowing heat to transfer to a portion of the formation.

5479. The method of claim 5478, further comprising providing steam to the conduit.

5480. The method of claim 5478, further comprising inhibiting coking within the conduit.

5481. The method of claim 5478, wherein the oxidizing fluid comprises air.

5482. The method of claim 5478, wherein the oxidizing fluid comprises oxygen.

5483. The method of claim 5478, further comprising allowing oxidation products to exit the opening proximate the second location.

5484. The method of claim 5478, wherein the fuel is provided to proximate the first location, and wherein the oxidation products migrate towards the second location.

5485. The method of claim 5478, wherein the oxidizer comprises a ring burner.

5486. The method of claim 5478, wherein the oxidizer comprises an inline burner.

5487. The method of claim 5478, further comprising recycling at least some fuel in the conduit.

5488. The system of claim 5478, wherein the opening comprises a casing and further comprising insulating a portion of the casing proximate at least one oxidizer.

5489. The system of claim 5478, further comprising at least two oxidizers, wherein the oxidizers are positioned about 30 m apart.

5490. A system configurable to provide heat to an oil shale formation, comprising:

a conduit positionable in at least a portion of an opening in the formation, wherein a first end of the opening contacts an earth surface at a first location, and wherein a second end of the opening contacts the earth surface at a second location; and

an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation.

5491. The system of claim 5490, wherein the conduit comprises a conductor and wherein the conductor is configured to generate heat during application of an electrical current to the conduit.

5492. The system of claim 5490, wherein the conduit comprises a low resistance conductor and wherein at least some of the low resistance conductor is positionable in an overburden.

5493. The system of claim 5490, wherein the oxidizing fluid source is configurable to provide at least some oxidizing fluid to the conduit at the first location and at the second location.

5494. The system of claim 5490, wherein the opening is configurable to allow products of oxidation to be produced from the formation.

5495. The system of claim 5490, wherein the oxidizing fluid reacts with at least some hydrocarbons and wherein the oxidizing fluid source is configurable to provide at least some oxidizing fluid to the first location and to the second location.

5496. The system of claim 5490, wherein the heat source is configurable to heat a reaction zone of the selected section to a temperature sufficient to support reaction of hydrocarbons in the selected section with an oxidizing fluid.

5497. The system of claim 5496, wherein the heat source is configurable to provide an oxidizing fluid to the selected section of the formation to generate heat during use.

5498. The system of claim 5496, wherein the generated heat transfers to a pyrolysis zone of the formation.

5499. The system of claim 5490, further comprising an oxidizing fluid source configurable to provide an oxidizing fluid to the heat source, and wherein the conduit is configurable to provide the oxidizing fluid to the selected section of the formation during use.

5500. The system of claim 5490, wherein the conduit comprises a low resistance conductor and a conductor, and wherein the conductor is further configured to generate heat during application of an electrical current to the conduit.

5501. An in situ method for heating an oil shale formation, comprising:

providing an electrical current to a conduit positioned in an opening in the formation;

allowing heat to transfer from the conduit to a reaction zone of the formation;

providing at least some oxidizing fluid to the conduit;

allowing the oxidizing fluid to transfer from the conduit to the reaction zone in the formation;

allowing the oxidizing fluid to oxidize at least some hydrocarbons in the reaction zone to generate heat; and

allowing at least some of the generated heat to transfer to a pyrolysis zone in the formation.

5511. A method for treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a first section of the formation such that the heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the first section; and

producing a mixture through a second section of the formation, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the first section, and wherein the second section comprises a higher permeability than the first section.

5512. The method of claim 5511, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

5513. The method of claim 5511, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

5514. The method of claim 5511, wherein at least one heat source comprises a heater.

5515. The method of claim 5511, further comprising increasing permeability within the second section by allowing heat to transfer from the one or more heat sources to the second section.

5516. The method of claim 5511, wherein the second section has a higher permeability than the first section before providing heat to the formation.

5517. The method of claim 5511, wherein the second section comprises an average permeability thickness product of greater than about 100 millidarcy feet.

5518. The method of claim 5511, wherein the first section comprises an initial average permeability thickness product of less than about 10 millidarcy feet.

5519. The method of claim 5511, wherein the second section comprises an average permeability thickness product that is at least twice an initial average permeability thickness product of the first section.

5520. The method of claim 5511, wherein the second section comprises an average permeability thickness product that is at least ten times an initial average permeability thickness product of the first section.

5521. The method of claim 5511, wherein the one or more heat sources are placed within at least one uncased wellbore in the formation.

5522. The method of claim 5521, further comprising allowing at least some hydrocarbons from the first section to propagate through at least one uncased wellbore into the second section.

5523. The method of claim 5521, further comprising producing at least some hydrocarbons through at least one uncased wellbore.

5524. The method of claim 5511, further comprising forming one or more fractures that propagate between the first section and the second section.

5525. The method of claim 5524, further comprising allowing at least some hydrocarbons from the first section to propagate through the one or more fractures into the second section.

5526. The method of claim 5511, further comprising producing the mixture from the formation through a production well placed in the second section.

5527. The method of claim 5511, further comprising producing the mixture from the formation through a production well placed in the first section and the second section.

5528. The method of claim 5511, further comprising inhibiting fracturing of a section of the formation that is substantially adjacent to an environmentally sensitive area.

5529. The method of claim 5511, further comprising producing at least some hydrocarbons through the second section to maintain a pressure in the formation below a litbostatic pressure of the formation.

5530. The method of claim 5511, further comprising producing at least some hydrocarbons through a production well placed in the first section.

5531. The method of claim 5511, further comprising pyrolyzing at least some hydrocarbons within the second section.

5532. The method of claim 5511, wherein the first section and the second section are substantially adjacent.

5533. The method of claim 5511, further comprising allowing migration of fluids between the first second and the second section.

5534. The method of claim 5511, wherein at least one heat source has a thickness of a conductor that is adjusted to provide more heat to the first section than the second section.

5536. The method of claim 5521, further comprising allowing at least some hydrocarbons from the first section to propagate through at least one uncased wellbore into the second section.

5537. The method of claim 5521, further comprising producing at least some hydrocarbons through at least one uncased wellbore.

5535. A method for treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation, wherein one or more of such heat sources is placed within at least one uncased wellbore in the formation;

allowing the heat to transfer from the one or more heat sources to a first section of the formation such that the heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the first section; and

producing a mixture through a second section of the formation, wherein the produced mixture comprises at least some pyrolyzed hydrocarbons from the first section, and wherein the second section comprises a higher permeability than the first section.

5538. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing at least one property of the formation to the computer system;

providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.

5539. The method of claim 5538, wherein at least one process characteristic is assessed as function of time.

5540. The method of claim 5538, wherein the simulation method is a body-fitted finite difference simulation method.

5541. The method of claim 5538, wherein the simulation method is a space-fitted finite difference simulation method.

5542. The method of claim 5538, wherein the simulation method is a reservoir simulation method.

5543. The method of claim 5538, wherein the simulation method simulates heat transfer by conduction.

5544. The method of claim 5538, wherein the simulation method simulates heat transfer by convection.

5545. The method of claim 5538, wherein the simulation method simulates heat transfer by radiation.

5546. The method of claim 5538, wherein the simulation method simulates heat transfer in a near wellbore region.

5547. The method of claim 5538, wherein the simulation method assesses a temperature distribution in the formation.

5548. The method of claim 5538, wherein at least one property of the formation comprises one or more materials from the formation.

5549. The method of claim 5548, wherein one material comprises mineral matter.

5550. The method of claim 5548, wherein one material comprises organic matter.

5551. The method of claim 5538, wherein at least one property of the formation comprises one or more phases.

5552. The method of claim 5551, wherein one phase comprises a water phase.

5553. The method of claim 5551, wherein one phase comprises an oil phase.

5554. The method of claim 5553, wherein the oil phase comprises one or more components.

5555. The method of claim 5551, wherein one phase comprises a gas phase.

5556. The method of claim 5555, wherein the gas phase comprises one or more components.

5557. The method of claim 5538, wherein at least one property of the formation comprises a porosity of the formation.

5558. The method of claim 5538, wherein at least one property of the formation comprises a permeability of the formation.

5559. The method of claim 5558, wherein the permeability depends on the composition of the formation.

5560. The method of claim 5538, wherein at least one property of the formation comprises a saturation of the formation.

5561. The method of claim 5538, wherein at least one property of the formation comprises a density of the formation.

5562. The method of claim 5538, wherein at least one property of the formation comprises a thermal conductivity of the formation.

5563. The method of claim 5538, wherein at least one property of the formation comprises a volumetric heat capacity of the formation.

5564. The method of claim 5538, wherein at least one property of the formation comprises a compressibility of the formation.

5565. The method of claim 5538, wherein at least one property of the formation comprises a composition of the formation.

5566. The method of claim 5538, wherein at least one property of the formation comprises a thickness of the formation.

5567. The method of claim 5538, wherein at least one property of the formation comprises a depth of the formation.

5568. The method of claim 5538, wherein at least one property comprises one or more chemical components.

5569. The method of claim 5568, wherein one component comprises a pseudo-component.

5570. The method of claim 5538, wherein at least property comprises one or more kinetic parameters.

5571. The method of claim 5538, wherein at least one property comprises one or more chemical reactions.

5572. The method of claim 5571, wherein a rate of at least one chemical reaction depends on a pressure of the formation.

5573. The method of claim 5571, wherein a rate of at least one chemical reaction depends on a temperature of the formation.

5574. The method of claim 5571, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.

5575. The method of claim 5571, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.

5576. The method of claim 5571, wherein at least one chemical reaction comprises a coking reaction.

5577. The method of claim 5571, wherein at least one chemical reaction comprise a cracking reaction.

5578. The method of claim 5571, wherein at least one chemical reaction comprises a S synthesis gas reaction.

5579. The method of claim 5538, wherein at least one process characteristic comprises an API gravity of produced fluids.

5580. The method of claim 5538, wherein at least one process characteristic comprises an olefin content of produced fluids.

5581. The method of claim 5538, wherein at least one process characteristic comprises a carbon number distribution of produced fluids.

5582. The method of claim 5538, wherein at least one process characteristic comprises an ethene to ethane ratio of produced fluids.

5583. The method of claim 5538, wherein at least one process characteristic comprises an atomic carbon to hydrogen ratio of produced fluids.

5584. The method of claim 5538, wherein at least one process characteristic comprises a ratio of non-condensable hydrocarbons to condensable hydrocarbons of produced fluids.

5585. The method of claim 5538, wherein at least one process characteristic comprises a pressure in the formation

5586. The method of claim 5538, wherein at least one process characteristic comprises total mass recovery from the formation.

5587. The method of claim 5538, wherein at least one process characteristic comprises a production rate of fluid produced from the formation.

5588. The method of claim 5538, wherein at least one operating condition comprises a pressure.

5589. The method of claim 5538, wherein at least one operating condition comprises a temperature.

5590. The method of claim 5538, wherein at least one operating condition comprises a heating rate.

5591. The method of claim 5538, wherein at least one operating condition comprises a process time.

5592. The method of claim 5538, wherein at least one operating condition comprises a location of producer wells.

5593. The method of claim 5538, wherein at least one operating condition comprises an orientation of producer wells.

5594. The method of claim 5538, wherein at least one operating condition comprises a ratio of producer wells to heater wells.

5595. The method of claim 5538, wherein at least one operating condition comprises a spacing between heater wells.

5596. The method of claim 5538, wherein at least one operating condition comprises a distance between an overburden and horizontal heater wells.

5597. The method of claim 5538, wherein at least one operating condition comprises a pattern of heater wells.

5598. The method of claim 5538, wherein at least one operating condition comprises an orientation of heater wells.

5599. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation;

providing at least one desired parameter of the in situ process to the computer system; and

controlling the heat input rate from the heat sources to achieve at least one desired parameter.

5600. The method of claim 5599, wherein the heat is allowed to transfer from the heat sources substantially by conduction.

5601. The method of claim 5599, wherein the heat input rate is simulated with a body-fitted finite difference simulation method.

5602. The method of claim 5599, wherein simulating the heat input rate from two or more heat sources comprises simulating a model of one or more heat sources with symmetry boundary conditions.

5603. The method of claim 5599, wherein superposition of heat from the two or more heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

5604. The method of claim 5599, wherein at least one desired parameter comprises a selected process characteristic.

5605. The method of claim 5599, wherein at least one desired parameter comprises a selected temperature.

5606. The method of claim 5599, wherein at least one desired parameter comprises a selected heating rate.

5607. The method of claim 5599, wherein at least one desired parameter comprises a desired product mixture produced from the formation.

5608. The method of claim 5599, wherein at least one desired parameter comprises a desired product mixture produced from the formation, and wherein the desired product mixture comprises a selected composition.

5609. The method of claim 5599, wherein at least one desired parameter comprises a selected pressure.

5610. The method of claim 5599, wherein at least one desired parameter comprises a selected heating time.

5611. The method of claim 5599, wherein at least one desired parameter comprises a market parameter.

5612. The method of claim 5599, wherein at least one desired parameter comprises a price of crude oil.

5613. The method of claim 5599, wherein at least one desired parameter comprises an energy cost.

5614. The method of claim 5599, wherein at least one desired parameter comprises a selected molecular hydrogen to carbon monoxide volume ratio.

5615. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing at least one heat input property to the computer system;

assessing heat injection rate data for the formation using a first simulation method on the computer system;

providing at least one property of the formation to the computer system;

assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5616. The method of claim 5615, wherein at least one process characteristic is assessed as a function of time.

5617. The method of claim 5615, wherein assessing heat injection rate data comprises simulating heating of the formation.

5618. The method of claim 5615, wherein the heating is controlled to obtain a desired parameter.

5619. The method of claim 5615, wherein determining at least one process characteristic comprises simulating heating of the formation.

5620. The method of claim 5619, wherein the heating is controlled to obtain a desired parameter.

5621. The method of claim 5615, wherein the first simulation method is a body-fitted finite difference simulation method.

5622. The method of claim 5615, wherein the second simulation method is a space-fitted finite difference simulation method.

5623. The method of claim 5615, wherein the second simulation method is a reservoir simulation method.

5624. The method of claim 5615, wherein the first simulation method simulates heat transfer by conduction.

5625. The method of claim 5615, wherein the first simulation method simulates heat transfer by convection.

5626. The method of claim 5615, wherein the first simulation method simulates heat transfer by radiation.

5627. The method of claim 5615, wherein the second simulation method simulates heat transfer by conduction.

5628. The method of claim 5615, wherein the second simulation method simulates heat transfer by convection.

5629. The method of claim 5615, wherein the first simulation method simulates heat transfer in a near wellbore region.

5630. The method of claim 5615, wherein the first simulation method determines a temperature distribution in the formation.

5631. The method of claim 5615, wherein at least one heat input property comprises a property of the formation.

5632. The method of claim 5615, wherein at least one heat input property comprises a heat transfer property.

5633. The method of claim 5615, wherein at least one heat input property comprises an initial property of the formation.

5634. The method of claim 5615, wherein at least one heat input property comprises a heat capacity.

5635. The method of claim 5615, wherein at least one heat input property comprises a thermal conductivity.

5636. The method of claim 5615, wherein the heeat injection rate data comprises a temperature distribution within the formation.

5637. The method of claim 5615, wherein the heat injection rate data comprises a heat input rate.

5638. The method of claim 5637, wherein the heat input rate is controlled to maintain a specified maximum temperature at a point in the formation.

5639. The method of claim 5615, wherein the heat injection rate data comprises heat flux data.

5640. The method of claim 5615, wherein at least one property of the formation comprises one or more materials in the formation.

5641. The method of claim 5640, wherein one material comprises mineral matter.

5642. The method of claim 5640, wherein one material comprises organic matter.

5643. The method of claim 5615, wherein at least one property of the formation comprises one or more phases.

5644. The method of claim 5643, wherein one phase comprises a water phase.

5645. The method of claim 5643, wherein one phase comprises an oil phase.

5646. The method of claim 5645, wherein the oil phase comprises one or more components.

5647. The method of claim 5643, wherein one phase comprises a gas phase.

5648. The method of claim 5647, wherein the gas phase comprises one or more components.

5649. The method of claim 5615, wherein at least one property of the formation comprises a porosity of the formation.

5650. The method of claim 5615, wherein at least one property of the formation comprises a permeability of the formation.

5651. The method of claim 5650, wherein the permeability depends on the composition of the formation.

5652. The method of claim 5615, wherein at least one property of the formation comprises a saturation of the formation.

5653. The method of claim 5615, wherein at least one property of the formation comprises a density of the formation.

5654. The method of claim 5615, wherein at least one property of the formation comprises a thermal conductivity of the formation.

5655. The method of claim 5615, wherein at least one property of the formation comprises a volumetric heat capacity of the formation.

5656. The method of claim 5615, wherein at least one property of the formation comprises a compressibility of the formation.

5657. The method of claim 5615, wherein at least one property of the formation comprises a composition of the formation.

5658. The method of claim 5615, wherein at least one property of the formation comprises a thickness of the formation.

5659. The method of claim 5615, wherein at least one property of the formation comprises a depth of the formation.

5660. The method of claim 5615, wherein at least one property of the formation comprises one or more chemical components.

5661. The method of claim 5660, wherein at least one chemical component comprises a pseudo-component.

5662. The method of claim 5615, wherein at least one property of the formation comprises one or more kinetic parameters.

5663. The method of claim 5615, wherein at least one property of the formation comprises one or more chemical reactions.

5664. The method of claim 5663, wherein a rate of at least one chemical reaction depends on a pressure of the formation.

5665. The method of claim 5663, wherein a rate of at least one chemical reaction depends on a temperature of the formation.

5666. The method of claim 5663, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.

5667. The method of claim 5663, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.

5668. The method of claim 5663, wherein at least one chemical reaction comprises a coking reaction.

5669. The method of claim 5663, wherein at least one chemical reaction comprises a cracking reaction.

5670. The method of claim 5663, wherein at least one chemical reaction comprises a synthesis gas reaction.

5671. The method of claim 5615, wherein at least one process characteristic comprises an API gravity of produced fluids.

5672. The method of claim 5615, wherein at least one process characteristic comprises an olefin content of produced fluids.

5673. The method of claim 5615, wherein at least one process characteristic comprises a carbon number distribution of produced fluids.

5674. The method of claim 5615, wherein at least one process characteristic comprises an ethene to ethane ratio of produced fluids.

5675. The method of claim 5615, wherein at least one process characteristic comprises an atomic carbon to hydrogen ratio of produced fluids.

5676. The method of claim 5615, wherein at least one process characteristic comprises a ratio of non-condensable hydrocarbons to condensable hydrocarbons of produced fluids.

5677. The method of claim 5615, wherein at least one process characteristic comprises a pressure in the formation.

5678. The method of claim 5615, wherein at least one process characteristic comprises a total mass recovery from the formation.

5679. The method of claim 5615, wherein at least one process characteristic comprises a production rate of fluid produced from the formation.

5680. The method of claim 5615, further comprising:

assessing modified heat injection rate data using the first simulation method at a specified time of the second simulation method based on at least one heat input property of the formation at the specified time;

assessing at least one process characteristic of the in situ process as a function of time from the modified heat injection rate data and at least one property of the formation at the specified time using the second simulation method.

5681. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing one or more model parameters for the in situ process to the computer system;

assessing one or more simulated process characteristics based on one or more model parameters using a simulation method;

modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

5682. The method of claim 5681, further comprising using the simulation method with the modified model parameters to determine at least one operating condition of the in situ process to achieve a desired parameter.

5683. The method of claim 5681, wherein the simulation method comprises a body-fitted finite difference simulation method.

5684. The method of claim 5681, wherein the simulation method comprises a space-fitted finite difference simulation method.

5685. The method of claim 5681, wherein the simulation method comprises a reservoir simulation method.

5686. The method of claim 5681, wherein the real process characteristics comprise process characteristics obtained from laboratory experiments of the in situ process.

5687. The method of claim 5681, wherein the real process characteristics comprise process characteristics obtained from field test experiments of the in situ process.

5688. The method of claim 5681, further comprising comparing the simulated process characteristics to the real process characteristics as a function of time.

5689. The method of claim 5681, further comprising associating differences between the simulated process characteristics and the real process characteristics with one or more model parameters.

5690. The method of claim 5681, wherein at least one model parameter comprises a chemical component.

5691. The method of claim 5681, wherein at least one model parameter comprises a kinetic parameter.

5692. The method of claim 5691, wherein the kinetic parameter comprises an order of a reaction.

5693. The method of claim 5691, wherein the kinetic parameter comprises an activation energy.

5694. The method of claim 5691, wherein the kinetic parameter comprises a reaction enthalpy.

5695. The method of claim 5691, wherein the kinetic parameter comprises a frequency factor.

5696. The method of claim 5681, wherein at least one model parameter comprises a chemical reaction.

5697. The method of claim 5696, wherein at least one chemical reaction comprises a pre-pyrolysis water generation reaction.

5698. The method of claim 5696, wherein at least one chemical reaction comprises a hydrocarbon generating reaction.

5699. The method of claim 5696, wherein at least one chemical reaction comprises a coking reaction.

5700. The method of claim 5696, wherein at least one chemical reaction comprises a cracking reaction.

5701. The method of claim 5696, wherein at least one chemical reaction comprises a synthesis gas reaction.

5702. The method of claim 5681, wherein one or more model parameters comprise one or more properties.

5703. The method of claim 5681, wherein at least one model parameter comprises a relationship for the dependence of a property on a change in conditions in the formation.

5704. The method of claim 5681, wherein at least one model parameter comprises an expression for the dependence of porosity on pressure in the formation.

5705. The method of claim 5681, wherein at least one model parameter comprises an expression for the dependence of permeability on porosity.

5706. The method of claim 5681, wherein at least one model parameter comprises an expression for the dependence of thermal conductivity on composition of the formation.

5707. A method of using a computer sys tem for modeling an in situ process for treating an oil shale formation, comprising.

assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter;

modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5708. The method of claim 5707, wherein at least one operating condition is assessed to achieve at least one desired parameter.

5709. The method of claim 5707, wherein the real process characteristic comprises a process characteristic from a field test of the in situ process.

5710. The method of claim 5707, wherein the simulation method comprises a body-fitted finite difference simulation method.

5711. The method of claim 5707, wherein the simulation method comprises a space-fitted finite difference simulation method.

5712. The method of claim 5707, wherein the simulation method comprises a reservoir simulation method.

5713. A method of modeling a process of treating an oil shale formation in situ using a computer system, comprising:

providing one or more model parameters to the computer system;

assessing one or more first process characteristics based on the one or more model parameters using a first simulation method on the computer system;

assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system;

modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

5714. The method of claim 5713, further comprising assessing one or more third process characteristics based on the one or more modified model parameters using the second simulation method.

5715. The method of claim 5713, wherein modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic further comprises:

assessing at least one set of first process characteristics based on at least one set of modified model parameters using the first simulation method; and

assessing the set of modified model parameters that results in at least one first process characteristic that matches or approximates at least one second process characteristic.

5716. The method of claim 5713, wherein the first simulation method comprises a body-fitted finite difference simulation method.

5717. The method of claim 5713, wherein the second simulation method comprises a space-fitted finite difference simulation method.

5718. The method of claim 5713, wherein at least one first process characteristic comprises a process characteristic at a sharp interface in the formation.

5719. The method of claim 5713, wherein at least one first process characteristic comprises a process characteristic at a combustion front in the formation.

5720. The method of claim 5713, wherein modifying the one or more model parameters comprises changing the order of a chemical reaction.

5721. The method of claim 5713, wherein modifying the one or more model parameters comprises adding one or more chemical reactions.

5722. The method of claim 5713, wherein modifying the one or more model parameters comprises changing an activation energy.

5723. The method of claim 5713, wherein modifying the one or more model parameters comprises changing a frequency factor.

5724. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method;

providing a desired value of at least one process characteristic for the in situ process to the computer system; and

assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.

5725. The method of claim 5724, further comprising operating the in situ system using the desired value of at least one operating condition.

5726. The method of claim 5724, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation.

5727. The method of claim 5724, wherein the process comprises allowing heat to transfer from one or more heat sources to a selected section of the formation.

5728. The method of claim 5724, wherein a value of at least one process characteristic comprises the process characteristic as a function of time.

5729. The method of claim 5724, further comprising determining a value of at least one process characteristic based on the desired value of at least one operating condition using the simulation method.

5730. The method of claim 5724, wherein determining the desired value of at least one operating condition comprises interpolating the desired value from the determined values of at least one process characteristic and the provided values of at least one operating condition.

5731. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.

5732. The method of claim 5731, further comprising operating the in situ system using the desired value of at least one operating condition.

5733. The method of claim 5731, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation.

5734. The method of claim 5731, wherein the process comprises providing heat to transfer from one or more heat sources to a selected section of the formation.

5735. The method of claim 5731, wherein the relationship is determined from one or more simulations of the in situ process using a simulation method.

5736. The method of claim 5731, wherein the relationship comprises one or more values of at least one process characteristic and corresponding values of at least one operating condition.

5737. The method of claim 5731, wherein the relationship comprises an analytical function.

5738. The method of claim 5731, wherein determining the value of at least one operating condition comprises interpolating the value of at least one operating condition from the relationship.

5739. The method of claim 5731, wherein at least one process characteristic comprises a selected composition of produced fluids.

5740. The method of claim 5731, wherein at least one operating condition comprises a pressure.

5741. The method of claim 5731, wherein at least one operating condition comprises a heat input rate.

5742. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing at least one property of the formation to the computer system;

providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.

5743. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing at least one property of the formation to the computer system;

providing at least one operating condition of the process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing at least one process characteristic of the in situ process using a simulation method on the computer system, and using at least one property of the formation and at least one operating condition.

5744. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation;

providing at least one desired parameter of the in situ process to the computer system; and

controlling the heat input rate from the heat sources to achieve at least one desired parameter.

5745. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

simulating a heat input rate to the formation from two or more heat sources on the computer system, wherein heat is allowed to transfer from the heat sources to a selected section of the formation;

providing at least one desired parameter of the in situ process to the computer system; and

controlling the heat input rate from the heat sources to achieve at least one desired parameter.

5746. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing at least one heat input property to the computer system;

assessing heat injection rate data for the formation using a first simulation method on the computer system;

providing at least one property of the formation to the computer system;

assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5747. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing at least one heat input property to the computer system;

assessing heat injection rate data for the formation using a first simulation method on the computer system;

providing at least one property of the formation to the computer system;

assessing at least one process characteristic of the in situ process from the heat injection rate data and at least one property of the formation using a second simulation method; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5748. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing one or more model parameters for the in situ process to the computer system;

assessing one or more simulated process characteristics based on one or more model parameters using a simulation method;

modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

5749. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing one or more model parameters for the in situ process to the computer system;

assessing one or more simulated process characteristics based on one or more model parameters using a simulation method;

modifying one or more model parameters such that at least one simulated process characteristic matches or approximates at least one real process characteristic;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

5750. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter;

modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation simulated process characteristics based on the modified model parameters.

5751. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

assessing at least one operating condition of the in situ process using a simulation method based on one or more model parameter;

modifying at least one model parameter such that at least one simulated process characteristic of the in situ process matches or approximates at least one real process characteristic of the in situ process;

assessing one or more modified simulated process characteristics based on the modified model parameters; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5752. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing one or more model parameters to the computer system;

assessing one or more first process characteristics based on one or more model parameters using a first simulation method on the computer system;

assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system;

modifying one or more model parameters such that at least one first process characteristic matches or approximates at least one second process characteristic; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation

5753. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing one or more model parameters to the computer system;

assessing one or more first process characteristics based on one or more model parameters using a first simulation method on the computer system;

assessing one or more second process characteristics based on one or more model parameters using a second simulation method on the computer system;

modifying one or more model parameters such that at least one first process characteristic matches at least one second process characteristic; and

wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

5754. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method;

providing a desired value of at least one process characteristic for the in situ process to the computer system; and

assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.

5755. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing to the computer system one or more values of at least one operating condition of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

assessing one or more values of at least one process characteristic corresponding to one or more values of at least one operating condition using a simulation method;

providing a desired value of at least one process characteristic for the in situ process to the computer system; and

assessing a desired value of at least one operating condition to achieve the desired value of at least one process characteristic from the assessed values of at least one process characteristic and the provided values of at least one operating condition.

5756. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.

5757. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing a desired value of at least one process characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing a value of at least one operating condition to achieve the desired value of at least one process characteristic, wherein such assessing comprises using a relationship between at least one process characteristic and at least one operating condition for the in situ process, wherein such relationship is stored on a database accessible by the computer system.

5758. A method of using a computer system for operating an in situ process for treating an oil shale formation, comprising:

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system; and

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.

5759. The method of claim 5758, wherein one or more of the operating parameters comprise a thickness of a treated portion of the formation.

5760. The method of claim 5758, wherein one or more of the operating parameters comprise an area of a treated portion of the formation.

5761. The method of claim 5758, wherein one or more of the operating parameters comprise a volume of a treated portion of the formation.

5762. The method of claim 5758, wherein one or more of the operating parameters comprise a property of the formation.

5763. The method of claim 5758, wherein one or more of the operating parameters comprise a heat capacity of the formation.

5764. The method of claim 5758, wherein one or more of the operating parameters comprise a permeability of the formation.

5765. The method of claim 5758, wherein one or more of the operating parameters comprise a density of the formation.

5766. The method of claim 5758, wherein one or more of the operating parameters comprise a thermal conductivity of the formation.

5767. The method of claim 5758, wherein one or more of the operating parameters comprise a porosity of the formation.

5768. The method of claim 5758, wherein one or more of the operating parameters comprise a pressure.

5769. The method of claim 5758, wherein one or more of the operating parameters comprise a temperature.

5770. The method of claim 5758, wherein one or more of the operating parameters comprise a heating rate.

5771. The method of claim 5758, wherein one or more of the operating parameters comprise a process time.

5772. The method of claim 5758, wherein one or more of the operating parameters comprises a location of producer wells.

5773. The method of claim 5758, wherein one or more of the operating parameters comprise an orientation of producer wells.

5774. The method of claim 5758, wherein one or more of the operating parameters comprise a ratio of producer wells to heater wells.

5775. The method of claim 5758, wherein one or more of the operating parameters comprise a spacing between heater wells.

5776. The method of claim 5758, wherein one or more of the operating parameters comprise a distance between an overburden and horizontal heater wells.

5777. The method of claim 5758, wherein one or more of the operating parameters comprise a type of pattern of heater wells.

5778. The method of claim 5758, wherein one or more of the operating parameters comprise an orientation of heater wells.

5779. The method of claim 5758, wherein one or more of the operating parameters comprise a mechanical property.

5780. The method of claim 5758, wherein one or more of the operating parameters comprise subsidence of the formation.

5781. The method of claim 5758, wherein one or more of the operating parameters comprise fracture progression in the formation.

5782. The method of claim 5758, wherein one or more of the operating parameters comprise heave of the formation.

5783. The method of claim 5758, wherein one or more of the operating parameters comprise compaction of the formation.

5784. The method of claim 5758, wherein one or more of the operating parameters comprise shear deformation of the formation.

5785. The method of claim 5758, wherein the assessed information comprises information relating to properties of the formation.

5786. The method of claim 5758, wherein the assessed information comprises a relationship between one or more operating parameters and at least one other operating parameter.

5787. The method of claim 5758, wherein the computer system is remote from the in situ process.

5788. The method of claim 5758, wherein the computer system is located at or near the in situ process.

5789. The method of claim 5758, wherein at least one parameter is provided to the computer system using hardwire communication.

5790. The method of claim 5758, wherein at least one parameter is provided to the computer system using internet communication.

5791. The method of claim 5758, wherein at least one parameter is provided to the computer system using wireless communication.

5792. The method of claim 5758, wherein the one or more parameters are monitored using sensors in the formation.

5793. The method of claim 5758, wherein at least one parameter is provided automatically to the computer system.

5794. The method of claim 5758, wherein using at least one parameter with a simulation method comprises performing a simulation and obtaining properties of the formation.

5795. A method of using a computer system for operating an in situ process for treating an oil shale formation, comprising:

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and

using the assessed information to operate the in situ process.

5796. The method of claim 5795, further comprising providing the assessed information to a computer system used for controlling the in situ process.

5797. The method of claim 5795, wherein the computer system is remote from the in situ process.

5798. The method of claim 5795, wherein the computer system is located at or near the in situ process.

5799. The method of claim 5795, wherein using the assessed information to operate the in situ process comprises:

modifying at least one operating parameter; and

operating the in situ process with at least one modified operating parameter.

5800. A method of using a computer system for operating an in situ process for treating an oil shale formation, comprising

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and

obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.

5801. The method of claim 5800, further comprising using the obtained information to operate the in situ process.

5802. The method of claim 5800, wherein the first simulation method is the same as the second simulation method.

5803. The method of claim 5800, further comprising providing the obtained information to a computer system used for controlling the in situ process.

5804. The method of claim 5800, wherein using the obtained information to operate the in situ process comprises:

modifying at least one operating parameter; and

operating the in situ process with at least one modified operating parameter.

5805. The method of claim 5800, wherein the obtained information comprises at least one operating parameter for use in the in situ process that achieves the desired parameter.

5806. The method of claim 5800, wherein the computer system is remote from the in situ process.

5807. The method of claim 5800, wherein the computer system is located at or near the in situ process.

5808. The method of claim 5800, wherein the desired parameter comprises a selected gas to oil ratio.

5809. The method of claim 5800, wherein the desired parameter comprises a selected production rate of fluid produced from the formation.

5810. The method of claim 5800, wherein the desired parameter comprises a selected production rate of fluid at a selected time produced from the formation.

5811. The method of claim 5800, wherein the desired parameter comprises a selected olefin content of produced fluids.

5812. The method of claim 5800, wherein the desired parameter comprises a selected carbon number distribution of produced fluids.

5813. The method of claim 5800, wherein the desired parameter comprises a selected ethene to ethane ratio of produced fluids.

5814. The method of claim 5800, wherein the desired parameter comprises a desired atomic carbon to hydrogen ratio of produced fluids.

5815. The method of claim 5800, wherein the desired parameter comprises a selected gas to oil ratio of produced fluids.

5816. The method of claim 5800, wherein the desired parameter comprises a selected pressure in the formation.

5817. The method of claim 5800, wherein the desired parameter comprises a selected total mass recovery from the formation.

5818. The method of claim 5800, wherein the desired parameter comprises a selected production rate of fluid produced from the formation.

5819. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating an oil shale formation, comprising;

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system; and

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.

5820. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system; and

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process.

5821. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating an oil shale formation, comprising;

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and

using the assessed information to operate the in situ process.

5822. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a simulation method and the computer system to provide assessed information about the in situ process; and

using the assessed information to operate the in situ process.

5823. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for operating an in situ process for treating an oil shale formation, comprising;

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and

obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.

5824. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

operating the in situ process using one or more operating parameters, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing at least one operating parameter of the in situ process to the computer system;

using at least one parameter with a first simulation method and the computer system to provide assessed information about the in situ process; and

obtaining information from a second simulation method and the computer system using the assessed information and a desired parameter.

5825. A method of modeling one or more stages of a process for treating an oil shale formation in situ with a simulation method using a computer system, comprising:

providing at least one property of the formation to the computer system;

providing at least one operating condition for the one or more stages of the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

assessing at least one process characteristic of the one or more stages using the simulation method.

5826. The method of claim 5825, wherein the simulation method is a body-fitted finite difference simulation method.

5827. The method of claim 5825, wherein the simulation method is a reservoir simulation method.

5828. The method of claim 5825, wherein the simulation method is a space-fitted finite difference simulation method.

5829. The method of claim 5825, wherein the simulation method simulates heating of the formation.

5830. The method of claim 5825, wherein the simulation method simulates fluid flow in the formation.

5831. The method of claim 5825, wherein the simulation method simulates mass transfer in the formation.

5832. The method of claim 5825, wherein the simulation method simulates heat transfer in the formation.

5833. The method of claim 5825, wherein the simulation method simulates chemical reactions in the one or more stages of the process in the formation.

5834. The method of claim 5825, wherein the simulation method simulates removal of contaminants from the formation.

5835. The method of claim 5825, wherein the simulation method simulates recovery of heat from the formation.

5836. The method of claim 5825, wherein the simulation method simulates injection of fluids into the formation.

5837. The method of claim 5825, wherein the one or more stages comprise heating of the formation.

5838. The method of claim 5825, wherein the one or more stages comprise generation of pyrolyzation fluids.

5839. The method of claim 5825, wherein the one or more stages comprise remediation of the formation.

5840. The method of claim 5825, wherein the one or more stages comprise shut-in of the formation.

5841. The method of claim 5825, wherein at least one operating condition of a remediation stage is the flow rate of ground water into the formation.

5842. The method of claim 5825, wherein at least one operating condition of a remediation stage is the flow rate of injected fluids into the formation.

5843. The method of claim 5825, wherein at least one process characteristic of a remediation stage is the concentration of contaminants in the formation.

5844. The method of claim 5825, further comprising:

providing to the computer system at least one set of operating conditions for at least one of the stages of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing to the computer system at least one desired process characteristic for at least one of the stages of the in situ process; and

assessing at least one additional operating condition for at least one of the stages that achieves at least one desired process characteristic for at least one of the stages.

5845. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing at least one property of the formation to a computer system;

providing at least one operating condition to the computer system;

assessing at least one process characteristic of the in situ process, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.

5846. The method of claim 5845, wherein the in situ process comprises two or more heat sources.

5847. The method of claim 5845, wherein the in situ process provides heat from one or more heat sources to at least one portion of the formation.

5848. The method of claim 5845, wherein the simulation method comprises a finite element simulation method.

5849. The method of claim 5845, wherein the formation comprises a treated portion and an untreated portion.

5850. The method of claim 5845, wherein at least one deformation characteristic comprises subsidence.

5851. The method of claim 5845, wherein at least one deformation characteristic comprises heave.

5852. The method of claim 5845, wherein at least one deformation characteristic comprises compaction.

5853. The method of claim 5845, wherein at least one deformation characteristic comprises shear deformation.

5854. The method of claim 5845, wherein at least one operating condition comprises a pressure.

5855. The method of claim 5845, wherein at least one operating condition comprises a temperature.

5856. The method of claim 5845, wherein at least one operating condition comprises a process time.

5857. The method of claim 5845, wherein at least one operating condition comprises a rate of pressure increase.

5858. The method of claim 5845, wherein at least one operating condition comprises a heating rate.

5859. The method of claim 5845, wherein at least one operating condition comprises a width of a treated portion of the formation.

5860. The method of claim 5845, wherein at least one operating condition comprises a thickness of a treated portion of the formation.

5861. The method of claim 5845, wherein at least one operating condition comprises a thickness of an overburden of the formation.

5862. The method of claim 5845, wherein at least one process characteristic comprises a pore pressure distribution in the formation.

5863. The method of claim 5845, wherein at least one process characteristic comprises a temperature distribution in the formation.

5864. The method of claim 5845, wherein at least one process characteristic comprises a heat input rate.

5865. The method of claim 5845, wherein at least one property comprises a physical property of the formation.

5866. The method of claim 5845, wherein at least one property comprises richness of the formation.

5867. The method of claim 5845, wherein at least one property comprises a heat capacity.

5868. The method of claim 5845, wherein at least one property comprises a thermal conductivity.

5869. The method of claim 5845, wherein at least one property comprises a coefficient of thermal expansion.

5870. The method of claim 5845, wherein at least one property comprises a mechanical property.

5871. The method of claim 5845, wherein at least one property comprises an elastic modulus.

5872. The method of claim 5845, wherein at least one property comprises a Poisson'"'"'s ratio.

5873. The method of claim 5845, wherein at least one property comprises cohesion stress.

5874. The method of claim 5845, wherein at least one property comprises a friction angle.

5875. The method of claim 5845, wherein at least one property comprises a cap eccentricity.

5876. The method of claim 5845, wherein at least one property comprises a cap yield stress.

5877. The method of claim 5845, wherein at least one property comprises a cohesion creep multiplier.

5878. The method of claim 5845, wherein at least one property comprises a thermal expansion coefficient.

5879. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing to the computer system at least one desired deformation characteristic for the in situ process; and

assessing at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.

5880. The method of claim 5879, further comprising operating the in situ system using at least one additional operating condition.

5881. The method of claim 5879, wherein the in situ process comprises two or more heat sources.

5882. The method of claim 5879, wherein the in situ process provides heat from one or more heat sources to at least one portion of the formation.

5883. The method of claim 5879, wherein the in situ process allows heat to transfer from one or more heat sources to a selected section of the formation.

5884. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of pressures.

5885. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of temperatures.

5886. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of heating rates.

5887. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of overburden thicknesses.

5888. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of thicknesses of a treated portion of the formation.

5889. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of widths of a treated portion of the formation.

5890. The method of claim 5879, wherein at least one set of operating conditions comprises at least one set of radii of a treated portion of the formation.

5891. The method of claim 5879, wherein at least one desired deformation characteristic comprises a selected subsidence.

5892. The method of claim 5879, wherein at least one desired deformation characteristic comprises a selected heave.

5893. The method of claim 5879, wherein at least one desired deformation characteristic comprises a selected compaction.

5894. The method of claim 5879, wherein at least one desired deformation characteristic comprises a selected shear deformation.

5895. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing one or more values of at least one operating condition;

assessing one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition;

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.

5896. The method of claim 5895, further comprising operating the in situ process using the desired value of at least one operating condition.

5897. The method of claim 5895, wherein the in situ process comprises two or more heat sources.

5898. The method of claim 5895, wherein at least one operating condition comprises a pressure.

5899. The method of claim 5895, wherein at least one operating condition comprises a heat input rate.

5900. The method of claim 5895, wherein at least one operating condition comprises a temperature.

5901. The method of claim 5895, wherein at least one operating condition comprises a heating rate.

5902. The method of claim 5895, wherein at least one operating condition comprises an overburden thickness.

5903. The method of claim 5895, wherein at least one operating condition comprises a thickness of a treated portion of the formation.

5904. The method of claim 5895, wherein at least one operating condition comprises a width of a treated portion of the formation.

5905. The method of claim 5895, wherein at least one operating condition comprises a radius of a treated portion of the formation.

5906. The method of claim 5895, wherein at least one deformation characteristic comprises subsidence.

5907. The method of claim 5895, wherein at least one deformation characteristic comprises heave.

5908. The method of claim 5895, wherein at least one deformation characteristic comprises compaction.

5909. The method of claim 5895, wherein at least one deformation characteristic comprises shear deformation.

5910. The method of claim 5895, wherein a value of at least one formation characteristic comprises the formation characteristic as a function of time.

5911. The method of claim 5895, further comprising determining a value of at least one deformation characteristic based on the desired value of at least one operating condition using the simulation method.

5912. The method of claim 5895, wherein determining the desired value of at least one operating condition comprises interpolating the desired value from the determined values of at least one formation characteristic and the provided values of at least one operating condition.

5913. A method of using a computer system for modeling an in situ process for treating an oil shale formation, comprising:

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the in situ process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the in situ process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

assessing a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one deformation characteristic and at least one operating condition for the in situ process.

5914. The method of claim 5913, further comprising operating the in situ system using the desired value of at least one operating condition.

5915. The method of claim 5913, wherein the in situ system comprises two or more heat sources.

5916. The method of claim 5913, wherein the relationship is determined from one or more simulations of the in situ process using a simulation method.

5917. The method of claim 5913, wherein the relationship comprises one or more values of at least one deformation characteristic and corresponding values of at least one operating condition.

5918. The method of claim 5913, wherein the relationship comprises an analytical function.

5919. The method of claim 5913, wherein determining a value of at least one operating condition comprises interpolating a value of at least one operating condition from the relationship.

5920. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing at least one property of the formation to a computer system;

providing at least one operating condition to the computer system;

determining at least one process characteristic of the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.

5921. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing at least one property of the formation to a computer system;

providing at least one operating condition to the computer system;

determining at least one process characteristic of the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining at least one deformation characteristic of the formation using a simulation method from at least one property, at least one operating condition, and at least one process characteristic.

5922. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing to the computer system at least one desired deformation characteristic for the in situ process; and

determining at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.

5923. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing to the computer system at least one set of operating conditions for the in situ process, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing to the computer system at least one desired deformation characteristic for the in situ process; and

determining at least one additional operating condition of the formation that achieves at least one desired deformation characteristic.

5924. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing one or more values of at least one operating condition;

determining one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition;

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.

5925. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing one or more values of at least one operating condition;

determining one or more values of at least one deformation characteristic using a simulation method based on the one or more values of at least one operating condition;

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining a desired value of at least one operating condition that achieves the desired value of at least one deformation characteristic from the determined values of at least one deformation characteristic and the provided values of at least one operating condition.

5926. A system, comprising:

a CPU;

a data memory coupled to the CPU; and

a system memory coupled to the CPU, wherein the system memory is configured to store one or more computer programs executable by the CPU, and wherein the computer programs are executable to implement a method of using a computer system for modeling an in situ process for treating an oil shale formation, the method comprising;

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one formation characteristic and at least one operating condition for the in situ process.

5927. A carrier medium comprising program instructions, wherein the program instructions are computer-executable to implement a method comprising:

providing a desired value of at least one deformation characteristic for the in situ process to the computer system, wherein the process comprises providing heat from one or more heat sources to at least one portion of the formation, and wherein the process comprises allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

determining a value of at least one operating condition to achieve the desired value of at least one deformation characteristic from a database in memory on the computer system comprising a relationship between at least one formation characteristic and at least one operating condition for the in situ process.

5928. A system configurable to provide heat to an oil shale formation, comprising:

a first oxidizer configurable to be placed in an opening in the formation, wherein the first oxidizer is configurable to oxidize a first fuel during use;

a second oxidizer configurable to be placed in the opening, wherein the second oxidizer is configurable to oxidize a second fuel during use; and

wherein the system is configurable to allow heat from oxidation of the first fuel or the second fuel to transfer to the formation during use.

5929. The system of claim 5928, wherein the system is configured to provide heat to the oil shale formation.

5930. The system of claim 5928, wherein the first oxidizer is configured to be placed in an opening in the formation and wherein the first oxidizer is configured to oxidize the first fuel during use.

5931. The system of claim 5928, wherein the second oxidizer is configured to be placed in the opening and wherein the second oxidizer is configured to oxidize the second fuel during use.

5932. The system of claim 5928, wherein the system is configured to allow the heat from the oxidation to transfer to the formation during use.

5933. The system of claim 5928, wherein the first oxidizer comprises a burner.

5934. The system of claim 5928, wherein the first oxidizer comprises an inline burner.

5935. The system of claim 5928, wherein the second oxidizer comprises a burner.

5936. The system of claim 5928, wherein the second oxidizer comprises a ring burner.

5937. The system of claim 5928, wherein a distance between the first oxidizer and the second oxidizer is less than about 250 meters.

5938. The system of claim 5928, further comprising a conduit configurable to be placed in the opening.

5939. The system of claim 5928, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide an oxidizing fluid to the first oxidizer during use.

5940. The system of claim 5928, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the first fuel to the first oxidizer during use.

5941. The system of claim 5928, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide an oxidizing fluid to the second oxidizer during use.

5942. The system of claim 5928, further comprising a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the second fuel to the second oxidizer during use.

5943. The system of claim 5928, further comprising a third oxidizer configurable to be placed in the opening, wherein the third oxidizer is configurable to oxidize a third fuel during use.

5944. The system of claim 5928, further comprising a fuel source, wherein the fuel source is configurable to provide the first fuel to the first oxidizer or the second fuel to the second oxidizer during use.

5945. The system of claim 5928, wherein the first fuel is different from the second fuel.

5946. The system of claim 5928, wherein the first fuel is different from the second fuel, wherein the second fuel comprises hydrogen.

5947. The system of claim 5928, wherein a flow of the first fuel is separately controlled from a flow of the second fuel.

5948. The system of claim 5928, wherein the first oxidizer is configurable to be placed proximate an upper portion of the opening.

5949. The system of claim 5928, wherein the second oxidizer is configurable to be placed proximate a lower portion of the opening.

5950. The system of claim 5928, further comprising insulation configurable to be placed proximate the first oxidizer.

5951. The system of claim 5928, further comprising insulation configurable to be placed proximate the second oxidizer.

5952. The system of claim 5928, wherein products from oxidation of the first fuel or the second fuel are removed from the formation through the opening during use.

5953. The system of claim 5928, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.

5954. The system of claim 5928, wherein the system is configured to allow the heat from the oxidation of the first fuel or the second fuel to transfer to the formation during use.

5955. The system of claim 5928, wherein the system is configured to allow the heat from the oxidation to transfer to a pyrolysis zone in the formation during use.

5956. The system of claim 5928, wherein the system is configured to allow the heat from the oxidation to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat causes pyrolysis of at least some hydrocarbons in the pyrolysis zone during use.

5957. The system of claim 5928, wherein at least some of the heat from the oxidation is generated at the first oxidizer.

5958. The system of claim 5928, wherein at least some of the heat from the oxidation is generated at the second oxidizer

5959. The system of claim 5928, wherein a combination of heat from the first oxidizer and heat from the second oxidizer substantially uniformly heats a portion of the formation during use.

5960. The system of claim 5928, further comprising a first conduit configurable to be placed in the opening of the formation, wherein the first conduit is configurable to provide a first oxidizing fluid to the first oxidizer in the opening during use, and wherein the first conduit is further configurable to provide a second oxidizing fluid to the second oxidizer in the opening during use.

5961. The system of claim 5960, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide the first fuel to the first oxidizer during use.

5962. The system of claim 5961, wherein the fuel conduit is further configurable to be placed in the first conduit.

5963. The system of claim 5961, wherein the first conduit is further configurable to be placed in the fuel conduit.

5964. The system of claim 5960, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide the second fuel to the second oxidizer during use.

5965. The system of claim 5960, wherein the first conduit is further configurable to provide the first fuel to the first oxidizer during use.

5966. An in situ method for heating an oil shale formation, comprising:

providing a first oxidizing fluid to a first oxidizer placed in an opening in the formation;

providing a first fuel to the first oxidizer;

oxidizing at least some of the first fuel in the first oxidizer;

providing a second oxidizing fluid to a second oxidizer placed in the opening in the formation;

providing a second fuel to the second oxidizer;

oxidizing at least some of the second fuel in the second oxidizer; and

allowing heat from oxidation of the first fuel and the second fuel to transfer to a portion of the formation.

5502. The method of claim 5966, wherein at least a portion of the conduit is configured to generate heat during application of the electrical current to the conduit.

5503. The method of claim 5966, further comprising:

providing at least some oxidizing fluid to the conduit proximate a first end of the conduit;

providing at least some oxidizing fluid to the conduit proximate a second end of the conduit; and

wherein the first end of the conduit is positioned at a first location on a surface of the formation and wherein the second end of the conduit is positioned at a second location on the surface.

5504. The method of claim 5966, further comprising allowing the oxidizing fluid to move out of the conduit through orifices positioned on the conduit.

5505. The method of claim 5966, further comprising removing products of oxidation through the opening during use.

5506. The method of claim 5966, wherein a first end of the opening is positioned at a first location on a surface of the formation and wherein a second end of the opening is positioned at a second location on the surface.

5507. The method of claim 5966, further comprising heating the reaction zone to a temperature sufficient to support reaction of hydrocarbons with an oxidizing fluid.

5508. The method of claim 5966, further comprising controlling a flow rate of the oxidizing fluid into the formation.

5509. The method of claim 5966, further comprising controlling a temperature in the pyrolysis zone.

5510. The method of claim 5966, further comprising removing products from oxidation through an opening in the formation during use.

5967. The method of claim 5966, wherein the first oxidizing fluid is provided to the first oxidizer through a conduit placed in the opening.

5968. The method of claim 5966, wherein the second oxidizing fluid is provided to the second oxidizer through a conduit placed in the opening.

5969. The method of claim 5966, wherein the first fuel is provided to the first oxidizer through a conduit placed in the opening.

5970. The method of claim 5966, wherein the first fuel is provided to the second oxidizer through a conduit placed in the opening.

5971. The method of claim 5966, wherein the first oxidizing fluid and the first fuel are provided to the first oxidizer through a conduit placed in the opening.

5972. The method of claim 5966, further comprising using exhaust fluid from the first oxidizer as a portion of the second fuel used in the second oxidizer.

5973. The method of claim 5966, further comprising allowing the heat to transfer substantially by conduction from the portion of the formation to a pyrolysis zone of the formation.

5974. The method of claim 5966, further comprising initiating oxidation of the second fuel in the second oxidizer with an ignition source.

5975. The method of claim 5966, further comprising removing exhaust fluids through the opening.

5976. The method of claim 5966, further comprising removing exhaust fluids through the opening, wherein the exhaust fluids comprise heat and allowing at least some heat in the exhaust fluids to transfer from the exhaust fluids to the first oxidizing fluid prior to oxidation in the first oxidizer.

5977. The method of claim 5966, further comprising removing exhaust fluids comprising heat through the opening, allowing at least some heat in the exhaust fluids to transfer from the exhaust fluids to the first oxidizing fluid prior to oxidation, and increasing a thermal efficiency of heating the oil shale formation.

5978. The method of claim 5966, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening.

5979. The method of claim 5966, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening and providing at least a portion of the exhaust fluids to a fourth oxidizer to be used as a fourth fuel in a fourth oxidizer, wherein the fourth oxidizer is located in a separate opening in the formation.

5980. A system configurable to provide heat to an oil shale formation, comprising:

an opening placed in the formation, wherein the opening comprises a first elongated portion, a second elongated portion, and a third elongated portion, wherein the second elongated portion diverges from the first elongated portion in a first direction, wherein the third elongated portion diverges from the first elongated portion in a second direction, and wherein the first direction is substantially different than the second direction;

a first heater configurable to be placed in the second elongated portion, wherein the first heater is configurable to heat at least a portion of the formation during use;

a second heater configurable to be placed in the third elongated portion, wherein the second heater is configurable to heat to at least a portion of the formation during use; and

wherein the system is configurable to allow heat to transfer to the formation during use.

5981. The system of claim 5980, wherein the first heater and the second heater are configurable to heat to at least a portion of the formation during use.

5982. The system of claim 5980, wherein the second and the third elongated portions are oriented substantially horizontally within the formation.

5983. The system of claim 5980, wherein the first direction is about 180°

opposite the second direction.

5984. The system of claim 5980, wherein the first elongated portion is placed substantially within an overburden of the formation.

5985. The system of claim 5980, wherein the transferred heat substantially uniformly heats a portion of the formation during use.

5986. The system of claim 5980, wherein the first heater or the second heater comprises a downhole combustor.

5987. The system of claim 5980, wherein the first heater or the second heater comprises an insulated conductor heater.

5988. The system of claim 5980, wherein the first heater or the second heater comprises a conductor-in-conduit heater.

5989. The system of claim 5980, wherein the first heater or the second heater comprises an elongated member heater.

5990. The system of claim 5980, wherein the first heater or the second heater comprises a natural distributed combustor heater.

5991. The system of claim 5980, wherein the first heater or the second heater comprises a flameless distributed combustor heater.

5992. The system of claim 5980, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer.

5993. The system of claim 5992, wherein the second elongated portion has a length of less than about 175 meters.

5994. The system of claim 5992, wherein the third elongated portion has a length of less than about 175 meters.

5995. The system of claim 5992, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the first oxidizer during use.

5996. The system of claim 5992, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the second oxidizer during use.

5997. The system of claim 5992, further comprising a fuel source, wherein the fuel source is configurable to provide fuel to the first oxidizer or the second oxidizer during use.

5998. The system of claim 5992, further comprising a third oxidizer placed within the first elongated portion of the opening.

5999. The system of claim 5998, further comprising a fuel conduit configurable to be placed in the opening, wherein the fuel conduit is further configurable to provide fuel to the third oxidizer during use.

6000. The system of claim 5998, further comprising a first fuel source configurable to provide a first fuel to the first fuel conduit, a second fuel source configurable to provide a second fuel to a second fuel conduit, and a third fuel source configurable to provide a third fuel to a third fuel conduit.

6001. The system of claim 6000, wherein the first fuel has a composition substantially different from the second fuel or the third fuel.

6002. The system of claim 5980, further comprising insulation configurable to be placed proximate the first heater.

6003. The system of claim 5980, further comprising insulation configurable to be placed proximate the second heater.

6004. The system of claim 5980, wherein a fuel is oxidized in the first heater or the second heater to generate heat and wherein products from oxidation are removed from the formation through the opening during use.

6005. The system of claim 5980, wherein a fuel is oxidized in the first heater and the second heater and wherein products from oxidation are removed from the formation through the opening during use.

6006. The system of claim 5980, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.

6007. The system of claim 5992, wherein the system is configured to allow the heat from oxidation of fuel to transfer to the formation during use.

6008. The system of claim 5980, wherein the system is configured to allow heat to transfer to a pyrolysis zone in the formation during use.

6009. The system of claim 5980, wherein the system is configured to allow heat to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat causes pyrolysis of at least some hydrocarbons within the pyrolysis zone during use.

6010. The system of claim 5980, wherein a combination of the heat generated from the first heater and the heat generated from the second heater substantially uniformly heats a portion of the formation during use.

6011. The system of claim 5980, further comprising a third heater placed in the second elongated portion.

6012. The system of claim 6011, wherein the third heater comprises a downhole combustor.

6013. The system of claim 6011, further comprising a fourth heater placed in the third elongated portion.

6014. The system of claim 6013, wherein the fourth heater comprises a downhole combustor.

6015. The system of claim 5980, wherein the first heater is configured to be placed in the second elongated portion, wherein the first heater is configured to provide heat to at least a portion of the formation during use, wherein the second heater is configured to be placed in the third elongated portion, wherein the second heater is configured to provide heat to at least a portion of the formation during use, and wherein the system is configured to allow heat to transfer to the formation during use.

6016. The system of claim 5980, wherein the second and the third elongated portions are located in a substantially similar plane.

6017. The system of claim 6016, wherein the opening comprises a fourth elongated portion and a fifth elongated portion, wherein the fourth elongated portion diverges from the first elongated portion in a third direction, wherein the fifth elongated portion diverges from the first elongated portion in a fourth direction, and wherein the third direction is substantially different than the fourth direction.

6018. The system of claim 6017, wherein the fourth and fifth elongated portions are located in a plane substantially different than the second and the third elongated portions.

6019. The system of claim 6017, wherein a third heater is configurable to be placed in the fourth elongated portion, and wherein a fourth heater is configurable to be placed in the fifth elongated portion.

6020. An in situ method for heating an oil shale formation, comprising:

providing heat from two or more heaters placed in an opening in the formation, wherein the opening comprises a first elongated portion, a second elongated portion, and a third elongated portion, wherein the second elongated portion diverges from the first elongated portion in a first direction, wherein the third elongated portion diverges from the first elongated portion in a second direction, and wherein the first direction is substantially different than the second direction;

allowing heat from the two or more heaters to transfer to a portion of the formation; and

wherein the two or more heaters comprise a first heater placed in the second elongated portion and a second heater placed in the third elongated portion.

6021. The method of claim 6020, wherein the second and the third elongated portions are oriented substantially horizontally within the formation.

6022. The method of claim 6020, wherein the first elongated portion is located substantially within an overburden of the formation.

6023. The method of claim 6020, further comprising substantially uniformly heating a portion of the formation.

6024. The method of claim 6020, wherein the first heater or the second heater comprises a downhole combustor.

6025. The method of claim 6020, wherein the first heater or the second heater comprises an insulated conductor heater.

6026. The method of claim 6020, wherein the first heater or the second heater comprises a conductor-in-conduit heater.

6027. The method of claim 6020, wherein the first heater or the second heater comprises an elongated member heater.

6028. The method of claim 6020, wherein the first heater or the second heater comprises a natural distributed combustor heater.

6029. The method of claim 6020, wherein the first heater or the second heater comprises a flameless distributed combustor heater.

6030. The method of claim 6020, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer.

6031. The method of claim 6020, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer and further comprising providing fuel to the first oxidizer through a fuel conduit placed in the opening.

6032. The method of claim 6020, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer and further comprising providing fuel to the second oxidizer through a fuel conduit placed in the opening.

6033. The method of claim 6020, wherein the two or more heaters comprise oxidizers and further comprising providing fuel to the oxidizers from a fuel source.

6034. The method of claim 6030, further comprising providing heat to a portion of the formation using a third oxidizer placed within the first elongated portion of the opening.

6035. The method of claim 6020, wherein the first heater comprises a first oxidizer and the second heater comprises a second oxidizer further comprising:

providing heat to a portion of the formation using a third oxidizer placed within the first elongated portion of the opening; and

providing fuel to the third oxidizer through a fuel conduit placed in the opening.

6036. The method of claim 6020, wherein the two or more heaters comprise oxidizers, and further comprising providing heat by oxidizing a fuel within the oxidizers and removing products of oxidation of fuel through the opening.

6037. The method of claim 6020, wherein the two or more heaters comprise oxidizers, and further comprising removing products from oxidation of fuel through an exhaust conduit coupled to the opening.

6038. The method of claim 6020, further comprising allowing the heat to transfer from the portion to a pyrolysis zone in the formation.

6039. The method of claim 6020, further comprising allowing the heat to transfer from the portion to a pyrolysis zone in the formation and pyrolyzing at least some hydrocarbons within the pyrolysis zone with the transferred heat.

6040. The method of claim 6020, further comprising allowing the heat to transfer to from the portion to a pyrolysis zone in the formation, pyrolyzing at least some hydrocarbons within the pyrolysis zone with the transferred heat, and producing a portion of the pyrolyzed hydrocarbons through a conduit placed in the first elongated portion.

6041. The method of claim 6020, further comprising providing heat to a portion of the formation using a third heater placed in the second elongated portion.

6042. The method of claim 6041, wherein the third heater comprises a downhole combustor.

6043. The method of claim 6041, further comprising providing heat to a portion of the formation using a fourth heater placed in the third elongated portion.

6044. The method of claim 6043, wherein the fourth heater comprises a downhole combustor.

6045. A system configurable to provide heat to an oil shale formation, comprising:

an oxidizer configurable to be placed in an opening in the formation, wherein the oxidizer is configurable to oxidize fuel to generate heat during use;

a first conduit configurable to be placed in the opening of the formation, wherein the first conduit is configurable to provide oxidizing fluid to the oxidizer in the opening during use;

a heater configurable to be placed in the opening and configurable to provide additional heat; and

wherein the system is configurable to allow the generated heat and the additional heat to transfer to the formation during use.

6046. The system of claim 6045, wherein the heater comprises an insulated conductor.

6047. The system of claim 6045, wherein the heater comprises a conductor-in-conduit heater.

6048. The system of claim 6045, wherein the heater comprises an elongated member heater.

6049. The system of claim 6045, wherein the heater comprises a flameless distributed combustor.

6050. The system of claim 6045, wherein the oxidizer is configurable to be placed proximate an upper portion of the opening.

6051. The system of claim 6045, further comprising insulation configurable to be placed proximate the oxidizer.

6052. The system of claim 6045, wherein the heater is configurable to be coupled to the first conduit.

6053. The system of claim 6045, wherein products from the oxidation of the fuel are removed from the formation through the opening during use.

6054. The system of claim 6045, further comprising an exhaust conduit configurable to be coupled to the opening to allow exhaust fluid to flow from the formation through the exhaust conduit during use.

6055. The system of claim 6045, wherein the system is configured to allow the generated heat and the additional heat to transfer to the formation during use.

6056. The system of claim 6045, wherein the system is configured to allow the generated heat and the additional heat to transfer to a pyrolysis zone in the formation during use.

6057. The system of claim 6045, wherein the system is configured to allow the generated heat and the additional heat to transfer to a pyrolysis zone in the formation during use, and wherein the transferred heat pyrolyzes of at least some hydrocarbons within the pyrolysis zone during use.

6058. The system of claim 6045, wherein a combination of the generate heat and the additional heat substantially uniformly heats a portion of the formation during use.

6059. The system of claim 6045, wherein the oxidizer is configured to be placed in the opening in the formation and wherein the oxidizer is configured to oxidize at least some fuel during use.

6060. The system of claim 6045, wherein the first conduit is configured to be placed in the opening of the formation and wherein the first conduit is configured to provide oxidizing fluid to the oxidizer in the opening during use.

6061. The system of claim 6045, wherein the heater is configured to be placed in the opening and wherein the heater is configurable to provide heat to a portion of the formation during use

6062. The system of claim 6045, wherein the system is configured to allow the heat from the oxidation of at least some fuel and from the heater to transfer to the formation during use.

6063. An in situ method for heating an oil shale formation, comprising:

allowing heat to transfer from a heater placed in an opening to a portion of the formation, providing oxidizing fluid to an oxidizer placed in the opening in the formation;

providing fuel to the oxidizer;

oxidizing at least some fuel in the oxidizer; and

allowing additional heat from oxidation of at least some fuel to transfer to the portion of the formation.

6064. The method of claim 6063, wherein the heater comprises an insulated conductor.

6065. The method of claim 6063, wherein the heater comprises a conductor-in-conduit heater.

6066. The method of claim 6063, wherein the heater comprises an elongated member heater.

6067. The method of claim 6063, wherein the heater comprises a flameless distributed combustor.

6068. The method of claim 6063, wherein the oxidizer is placed proximate an upper portion of the opening.

6069. The method of claim 6063, further comprising allowing the additional heat to transfer from the portion to a pyrolysis zone in the formation.

6070. The method of claim 6063, further comprising allowing the additional heat to transfer from the portion to a pyrolysis zone in the formation and pyrolyzing at least some hydrocarbons within the pyrolysis zone.

6071. The method of claim 6063, further comprising substantially uniformly heating the portion of the formation.

6072. The method of claim 6063, further comprising removing exhaust fluids through the opening.

6073. The method of claim 6063, further comprising removing exhaust fluids through an exhaust annulus in the formation.

6074. The method of claim 6063, further comprising removing exhaust fluids through an exhaust conduit coupled to the opening.

6075. A system configurable to provide heat to an oil shale formation, comprising:

a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to heat a portion of the formation to a temperature sufficient to sustain oxidation of hydrocarbons during use;

an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation to oxidize at least some hydrocarbons in the reaction zone during use such that heat is generated in the reaction zone, and wherein at least some of the reaction zone has been previously heated by the heater;

a first conduit configurable to be placed in the opening, wherein the first conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use, wherein the flow of oxidizing fluid can be controlled along at least a segment of the first conduit; and

wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.

6076. The system of claim 6075, wherein the system is configurable to provide hydrogen to the reaction zone during use.

6077. The system of claim 6075, wherein the oxidizing fluid is transported through the reaction zone substantially by diffusion.

6078. The system of claim 6075, wherein the system is configurable to allow the generated heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.

6079. The system of claim 6075, wherein the system is configurable to allow the generated heat to transfer substantially by conduction from the reaction zone to the formation during use.

6080. The system of claim 6075, wherein a temperature within the reaction zone can be controlled along at least a segment of the first conduit during use.

6081. The system of claim 6075, wherein a heating rate in at least a section of the formation proximate at least a segment of the first conduit be controlled.

6082. The system of claim 6075, wherein the oxidizing fluid is configurable to be transported through the reaction zone substantially by diffusion, and wherein a rate of diffusion of the oxidizing fluid can controlled by a temperature within the reaction zone.

6083. The system of claim 6075, wherein the first conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.

6084. The system of claim 6075, wherein the first conduit comprises critical flow orifices, and wherein the critical flow orifices are positioned on the first conduit such that a flow rate of the oxidizing fluid is controlled at a selected rate during use.

6085. The system of claim 6075, further comprising a second conduit configurable to remove an oxidation product during use.

6086. The system of claim 6085, wherein the second conduit is further configurable to allow heat within the oxidation product to transfer to the oxidizing fluid in the first conduit during use.

6087. The system of claim 6085, wherein a pressure of the oxidizing fluid in the first conduit and a pressure of the oxidation product in the second conduit are controlled during use such that a concentration of the oxidizing fluid along the length of the first conduit is substantially uniform.

6088. The system of claim 6085, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.

6089. The system of claim 6075, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.

6090. The system of claim 6075, wherein the portion of the formation extends radially from the opening a distance of less than approximately 3 m.

6091. The system of claim 6075, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.

6092. The system of claim 6075, wherein the system is configurable to pyrolyze at least some hydrocarbons in a pyrolysis zone of the formation.

6093. The system of claim 6075, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide the heat to at least the portion of the formation during use.

6094. The system of claim 6075, wherein a first conduit is configured to be placed in the opening and wherein the first conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.

6095. The system of claim 6075, wherein the flow of oxidizing fluid is controlled along at least a segment of the length of the first conduit and wherein the system is configured to allow the additional heat to transfer from the reaction zone to the formation during use.

6096. An in situ method for providing heat to an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons with an oxidizing fluid within the portion of the formation;

providing the oxidizing fluid to a reaction zone in the formation;

controlling a flow of the oxidizing fluid along at least a length of the reaction zone;

generating heat within the reaction zone; and

allowing the generated heat to transfer to the formation.

6097. The method of claim 6096, further comprising allowing the oxidizing fluid to react with at least some of the hydrocarbons in the reaction zone to generate the heat in the reaction zone.

6098. The method of claim 6096, wherein at least a section of the reaction zone is proximate an opening in the formation.

6099. The method of claim 6096, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion.

6100. The method of claim 6096, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion, and controlling a rate of diffusions of the oxidizing fluid by controlling a temperature within the reaction zone.

6101. The method of claim 6096, wherein the generated heat transfers from the reaction zone to a pyrolysis zone in the formation.

6102. The method of claim 6096, wherein the generated heat transfers from the reaction zone to the formation substantially by conduction.

6103. The method of claim 6096, further comprising controlling a temperature along at least a length of the reaction zone.

6104. The method of claim 6096, further comprising controlling a flow of the oxidizing fluid along at least a length of the reaction zone, and controlling a temperature along at least a length of the reaction zone.

6105. The method of claim 6096, further comprising controlling a heating rate along at least a length of the reaction zone.

6106. The method of claim 6096, wherein the oxidizing fluid is provided through a conduit placed within an opening in the formation, wherein the conduit comprises orifices.

6107. The method of claim 6096, further comprising controlling a rate of oxidation by providing the oxidizing fluid to the reaction zone from a conduit having critical flow orifices.

6108. The method of claim 6096, wherein the oxidizing fluid is provided to the reaction zone through a conduit placed within the formation, and further comprising positioning critical flow orifices on the conduit such that the flow rate of the oxidizing fluid to at least a length of the reaction zone is controlled at a selected flow rate.

6109. The method of claim 6096, wherein the oxidizing fluid is provided to the reaction zone from a conduit placed within an opening in the formation, and further comprising sizing critical flow orifices on the conduit such that the flow rate of the oxidizing fluid to at least a length of the reaction zone is controlled at a selected flow rate.

6110. The method of claim 6096, further comprising increasing a volume of the reaction zone, and increasing the flow of the oxidizing fluid to the reaction zone such that a rate of oxidation within the reaction zone is substantially constant over time.

6111. The method of claim 6096, further comprising maintaining a substantially constant rate of oxidation within the reaction zone over time.

6112. The method of claim 6096, wherein a conduit is placed in an opening in the formation, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

6113. The method of claim 6096, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation.

6114. The method of claim 6096, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation and substantially inhibiting the oxidation product from flowing into a surrounding portion of the formation.

6115. The method of claim 6096, further comprising inhibiting the oxidizing fluid from flowing into a surrounding portion of the formation.

6116. The method of claim 6096, further comprising removing at least some water from the formation prior to heating the portion.

6117. The method of claim 6096, further comprising providing additional heat to the formation from an electric heater placed in the opening.

6118. The method of claim 6096, further comprising providing additional heat to the formation from an electric heater placed in an opening in the formation such that the oxidizing fluid continuously oxidizes at least a portion of the hydrocarbons in the reaction zone.

6119. The method of claim 6096, further comprising providing additional heat to the formation from an electric heater placed in the opening to maintain a constant heat rate in the formation.

6120. The method of claim 6119, further comprising providing electricity to the electric heater using a wind powered device.

6121. The method of claim 6119, further comprising providing electricity to the electric heater using a solar powered device.

6122. The method of claim 6096, further comprising maintaining a temperature within the portion above about the temperature sufficient to support the reaction of hydrocarbons with the oxidizing fluid.

6123. The method of claim 6096, further comprising providing additional heat to the formation from an electric heater placed in the opening and controlling the additional heat such that a temperature of the portion is greater than about the temperature sufficient to support the reaction of hydrocarbons with the oxidizing fluid.

6124. The method of claim 6096, further comprising removing oxidation products from the formation, and generating electricity using oxidation products removed from the formation.

6125. The method of claim 6096, further comprising removing oxidation products from the formation, and using at least some of the removed oxidation products in an air compressor.

6126. The method of claim 6096, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone over time.

6127. The method of claim 6096, further comprising assessing a temperature in or proximate an opening in the formation, wherein the flow of oxidizing fluid along at least a section of the reaction zone is controlled as a function of the assessed temperature.

6128. The method of claim 6096, further comprising assessing a temperature in or proximate an opening in the formation, and increasing the flow of oxidizing fluid as the assessed temperature decreases.

6129. The method of claim 6096, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate an opening in the formation at a temperature less than a pre-selected temperature.

6130. A system configurable to provide heat to an oil shale formation, comprising:

a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to provide heat to at least a portion of the formation during use;

an oxidizing fluid source configurable to provide an oxidizing fluid to a reaction zone of the formation to generate heat in the reaction zone during use, wherein at least a portion of the reaction zone has been previously heated by the heater during use;

a conduit configurable to be placed in the opening, wherein the conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use;

wherein the system is configurable to provide molecular hydrogen to the reaction zone during use; and

wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.

6131. The system of claim 6130, wherein the system is configurable to allow the oxidizing fluid to be transported through the reaction zone substantially by diffusion during use.

6132. The system of claim 6130, wherein the system is configurable to allow the generated heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.

6133. The system of claim 6130, wherein the system is configurable to allow the generated heat to transfer substantially by conduction from the reaction zone to the formation during use.

6134. The system of claim 6130, wherein the flow of oxidizing fluid can be controlled along at least a segment of the conduit such that a temperature can be controlled along at least a segment of the conduit during use.

6135. The system of claim 6130, wherein a flow of oxidizing fluid can be controlled along at least a segment of the conduit such that a heating rate in at least a section of the formation can be controlled.

6136. The system of claim 6130, wherein the oxidizing fluid is configurable to move through the reaction zone substantially by diffusion during use, wherein a rate of diffusion can controlled by a temperature of the reaction zone.

6137. The system of claim 6130, wherein the conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.

6138. The system of claim 6130, wherein the conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled during use.

6139. The system of claim 6130, wherein the conduit comprises a first conduit and a second conduit, wherein the second conduit is configurable to remove an oxidation product during use.

6140. The system of claim 6130, wherein the oxidizing fluid is substantially inhibited from flowing from the reaction zone into a surrounding portion of the formation.

6141. The system of claim 6130, wherein at least the portion of the formation extends radially from the opening a distance of less than approximately 3 m.

6142. The system of claim 6130, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.

6143. The system of claim 6130, wherein the system is configurable to allow transferred heat to pyrolyze at least some hydrocarbons in a pyrolysis zone of the formation.

6144. The system of claim 6130, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.

6145. The system of claim 6130, wherein the conduit is configured to be placed in the opening to provide at least some of the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use, and wherein the flow of at least some of the oxidizing fluid can be controlled along at least a segment of the first conduit.

6146. The system of claim 6130, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.

6147. The system of claim 6130, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.

6148. The system of claim 6130, wherein the conduit is configured to be placed in the opening and wherein the conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.

6149. The system of claim 6130, wherein the flow of oxidizing fluid can be controlled along at least a segment of the conduit.

6150. The system of claim 6130, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.

6151. The system of claim 6130, wherein at least some of the provided hydrogen is produced in the pyrolysis zone during use.

6152. The system of claim 6130, wherein at least some of the provided hydrogen is produced in the reaction zone during use.

6153. The system of claim 6130, wherein at least some of the provided hydrogen is produced in at least the heated portion of the formation during use.

6154. The system of claim 6130, wherein the system is configurable to provide hydrogen to the reaction zone during use such that production of carbon dioxide in the reaction zone is inhibited.

6155. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons in the reaction zone to generate heat in the reaction zone;

providing molecular hydrogen to the reaction zone; and

transferring the generated heat from the reaction zone to a pyrolysis zone in the formation.

6156. The method of claim 6155, further comprising producing the molecular hydrogen in the pyrolysis zone.

6157. The method of claim 6155, further comprising producing the molecular hydrogen in the reaction zone.

6158. The method of claim 6155, further comprising producing the molecular hydrogen in at least the heated portion of the formation.

6159. The method of claim 6155, further comprising inhibiting production of carbon dioxide in the reaction zone.

6160. The method of claim 6155, further comprising allowing the oxidizing fluid to transfer through the reaction zone substantially by diffusion.

6161. The method of claim 6155, further comprising allowing the oxidizing fluid to transfer through the reaction zone by diffusion, wherein a rate of diffusion is controlled by a temperature of the reaction zone.

6162. The method of claim 6155, wherein at least some of the generated heat transfers to the pyrolysis zone substantially by conduction.

6163. The method of claim 6155, further comprising controlling a flow of the oxidizing fluid along at least a segment reaction zone such that a temperature is controlled along at least a segment of the reaction zone.

6164. The method of claim 6155, further comprising controlling a flow of the oxidizing fluid along at least a segment of the reaction zone such that a heating rate is controlled along at least a segment of the reaction zone.

6165. The method of claim 6155, further comprising allowing at least some oxidizing fluid to flow into the formation through orifices in a conduit placed in an opening in the formation.

6166. The method of claim 6155, further comprising controlling a flow of the oxidizing fluid into the formation using critical flow orifices on a conduit placed in the opening such that a rate of oxidation is controlled.

6167. The method of claim 6155, further comprising controlling a flow of the oxidizing fluid into the formation with a spacing of critical flow orifices on a conduit placed in an opening in the formation.

6168. The method of claim 6155, further comprising controlling a flow of the oxidizing fluid with a diameter of critical flow orifices in a conduit placed in an opening in the formation.

6169. The method of claim 6155, further comprising increasing a volume of the reaction zone, and increasing the flow of the oxidizing fluid to the reaction zone such that a rate of oxidation within the reaction zone is substantially constant over time

6170. The method of claim 6155, wherein a conduit is placed in an opening in the formation, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

6171. The method of claim 6155, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation.

6172. The method of claim 6155, further comprising removing an oxidation product from the formation through a conduit placed in an opening in the formation and inhibiting the oxidation product from flowing into a surrounding portion of the formation beyond the reaction zone.

6173. The method of claim 6155, further comprising inhibiting the oxidizing fluid from flowing into a surrounding portion of the formation beyond the reaction zone.

6174. The method of claim 6155, further comprising removing at least some water from the formation prior to heating the portion.

6175. The method of claim 6155, further comprising providing additional heat to the formation from an electric heater placed in the opening.

6176. The method of claim 6155, further comprising providing additional heat to the formation from an electric heater placed in the opening and continuously oxidizing at least a portion of the hydrocarbons in the reaction zone.

6177. The method of claim 6155, further comprising providing additional heat to the formation from an electric heater placed in an opening in the formation and maintaining a constant heat rate within the pyrolysis zone.

6178. The method of claim 6155, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidation of at least a portion of the hydrocarbons does not bum out.

6179. The method of claim 6155, further comprising removing oxidation products from the formation and generating electricity using at least some oxidation products removed from the formation.

6180. The method of claim 6155, further comprising removing oxidation products from the formation and using at least some oxidation products removed from the formation in an air compressor.

6181. The method of claim 6155, further comprising increasing a flow of the oxidizing fluid in the reaction zone to accommodate an increase in a volume of the reaction zone over time.

6182. The method of claim 6155, further comprising increasing a volume of the reaction zone such that an amount of heat provided to the formation increases.

6183. The method of claim 6155, further comprising assessing a temperature in or proximate the opening, and controlling the flow of oxidizing fluid as a function of the assessed temperature.

6184. The method of claim 6155, further comprising assessing a temperature in or proximate the opening, and increasing the flow of oxidizing fluid as the assessed temperature decreases.

6185. The method of claim 6155, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate the opening at a temperature less than a pre-selected temperature.

6186. A system configurable to heat an oil shale formation, comprising:

a heater configurable to be placed in an opening in the formation, wherein the heater is configurable to provide heat to at least a portion of the formation during use;

an oxidizing fluid source, wherein an oxidizing fluid is selected to oxidize at least some hydrocarbons at a reaction zone during use such that heat is generated in the reaction zone;

a first conduit configurable to be placed in the opening, wherein the first conduit is configurable to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use; and

;

a second conduit configurable to be placed in the opening, wherein the second conduit is configurable to remove a product of oxidation from the opening during use; and

wherein the system is configurable to allow the generated heat to transfer from the reaction zone to the formation during use.

6187. The system of claim 6186, wherein the second conduit is configurable to control the concentration of oxygen in the opening during use such that the concentration of oxygen in the opening is substantially constant in the opening.

6188. The system of claim 6186, wherein the second conduit comprises orifices, and wherein the second conduit comprises a greater concentration of orifices towards an upper end of the second conduit.

6189. The system of claim 6186, wherein the first conduit comprises orifices that direct oxidizing fluid in a direction substantially opposite the second conduit.

6190. The system of claim 6186, wherein the second conduit comprises orifices that remove the oxidation product from a direction substantially opposite the first conduit.

6191. The system of claim 6186, wherein the second conduit is configurable to remove a product of oxidation from the opening during use such that the reaction zone comprises a substantially uniform temperature profile.

6192. The system of claim 6186, wherein a flow of the oxidizing fluid can be varied along a portion of a length of the first conduit,

6193. The system of claim 6186, wherein the oxidizing fluid is configurable to generate heat in the reaction zone such that the oxidizing fluid is transported through the reaction zone substantially by diffusion.

6194. The system of claim 6186, wherein the system is configurable to allow heat to transfer from the reaction zone to a pyrolysis zone in the formation during use.

6195. The system of claim 6186, wherein the system is configurable to allow heat to transfer substantially by conduction from the reaction zone to the formation during use.

6196. The system of claim 6186, wherein a flow of oxidizing fluid can be controlled along at least a portion of a length of the first conduit such that a temperature can be controlled along at least a portion of the length of the first conduit during use.

6197. The system of claim 6186, wherein a flow of oxidizing fluid can be controlled along at least a portion of the length of the first conduit such that a heating rate in at least a portion of the formation can be controlled.

6198. The system of claim 6186, wherein the oxidizing fluid is configurable to generate heat in the reaction zone during use such that the oxidizing fluid is transported through the reaction zone during use substantially by diffusion, wherein a rate of diffusion can controlled by a temperature of the reaction zone.

6199. The system of claim 6186, wherein the first conduit comprises orifices, and wherein the orifices are configurable to provide the oxidizing fluid into the opening during use.

6200. The system of claim 6186, wherein the first conduit comprises critical flow orifices, and wherein the critical flow orifices are configurable to control a flow of the oxidizing fluid such that a rate of oxidation in the formation is controlled during use.

6201. The system of claim 6186, wherein the second conduit is further configurable to remove an oxidation product such that the oxidation product transfers heat to the oxidizing fluid in the first conduit during use.

6202. The system of claim 6186, wherein a pressure of the oxidizing fluid in the first conduit and a pressure of the oxidation product in the second conduit are controlled during use such that a concentration of the oxidizing fluid in along the length of the conduit is substantially uniform.

6203. The system of claim 6186, wherein the oxidation product is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.

6204. The system of claim 6186, wherein the oxidizing fluid is substantially inhibited from flowing into portions of the formation beyond the reaction zone during use.

6205. The system of claim 6186, wherein the portion of the formation extends radially from the opening a distance of less than approximately 3 m.

6206. The system of claim 6186, wherein the reaction zone extends radially from the opening a distance of less than approximately 3 m.

6207. The system of claim 6186, wherein the system is further configurable such that transferred heat can pyrolyze at least some hydrocarbons in the pyrolysis zone.

6208. The system of claim 6186, wherein the heater is configured to be placed in an opening in the formation and wherein the heater is configured to provide heat to at least a portion of the formation during use.

6209. The system of claim 6186, wherein the first conduit is configured to be placed in the opening, and wherein the first conduit is configured to provide the oxidizing fluid from the oxidizing fluid source to the reaction zone in the formation during use.

6210. The system of claim 6186, wherein the flow of oxidizing fluid can be controlled along at least a segment of the first conduit.

6211. The system of claim 6186, wherein the second conduit is configured to be placed in the opening, and wherein the second conduit is configured to remove a product of oxidation from the opening during use.

6212. The system of claim 6186, wherein the system is configured to allow heat to transfer from the reaction zone to the formation during use.

6213. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid;

providing the oxidizing fluid to a reaction zone in the formation;

allowing the oxidizing fluid to react with at least a portion of the hydrocarbons in the reaction zone to generate heat in the reaction zone;

removing an oxidation product from the opening; and

transferring the generated heat from the reaction zone to the formation.

6214. The method of claim 6213, further comprising removing the oxidation product such that a concentration of oxygen in the opening is substantially constant in the opening.

6215. The method of claim 6213, further comprising removing the oxidation product from the opening and maintaining a substantially uniform temperature profile within the reaction zone.

6216. The method of claim 6213, further comprising transporting the oxidizing fluid through the reaction zone substantially by diffusion.

6217. The method of claim 6213, further comprising transporting the oxidizing fluid through the reaction zone by diffusion, wherein a rate of diffusion is controlled by a temperature of the reaction zone.

6218. The method of claim 6213, further comprising allowing heat to transfer from the reaction zone to a pyrolysis zone in the formation.

6219. The method of claim 6213, further comprising allowing heat to transfer from the reaction zone to the formation substantially by conduction.

6220. The method of claim 6213, further comprising controlling a flow of the oxidizing fluid along at least a portion of the length of the reaction zone such that a temperature is controlled along at least a portion of the length of the reaction zone.

6221. The method of claim 6213, further comprising controlling a flow of the oxidizing fluid along at least a portion of the length of the reaction zone such that a heating rate is controlled along at least a portion of the length of the reaction zone.

6222. The method of claim 6213, further comprising allowing at least a portion of the oxidizing fluid into the opening through orifices of a conduit placed in the opening.

6223. The method of claim 6213, further comprising controlling a flow of the oxidizing fluid with critical flow orifices in a conduit placed in the opening such that a rate of oxidation is controlled.

6224. The method of claim 6213, further comprising controlling a flow of the oxidizing fluid with a spacing of critical flow orifices in a conduit placed in the opening.

6225. The method of claim 6213, further comprising controlling a flow of the oxidizing fluid with a diameter of critical flow orifices in a conduit placed in the opening.

6226. The method of claim 6213, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone such that a rate of oxidation is substantially constant over time within the reaction zone.

6227. The method of claim 6213, wherein a conduit is placed in the opening, and further comprising cooling the conduit with the oxidizing fluid to reduce heating of the conduit by oxidation.

6228. The method of claim 6213, further comprising removing an oxidation product from the formation through a conduit placed in the opening.

6229. The method of claim 6213, further comprising removing an oxidation product from the formation through a conduit placed in the opening and substantially inhibiting the oxidation product from flowing into portions of the formation beyond the reaction zone.

6230. The method of claim 6213, further comprising substantially inhibiting the oxidizing fluid from flowing into portions of the formation beyond the reaction zone.

6231. The method of claim 6213, further comprising removing water from the formation prior to heating the portion.

6232. The method of claim 6213, further comprising providing additional heat to the formation from an electric heater placed in the opening.

6233. The method of claim 6213, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidizing fluid continuously oxidizes at least a portion of the hydrocarbons in the reaction zone.

6234. The method of claim 6213, further comprising providing additional heat to the formation from an electric heater placed in the opening such that a constant heat rate in the formation is maintained.

6235. The method of claim 6213, further comprising providing additional heat to the formation from an electric heater placed in the opening such that the oxidation of at least a portion of the hydrocarbons does not bum out.

6236. The method of claim 6213, further comprising generating electricity using oxidation products removed from the formation.

6237. The method of claim 6213, further comprising using oxidation products removed from the formation in an air compressor.

6238. The method of claim 6213, further comprising increasing a flow of the oxidizing fluid in the opening to accommodate an increase in a volume of the reaction zone over time.

6239. The method of claim 6213, further comprising increasing the amount of heat provided to the formation by increasing the reaction zone.

6240. The method of claim 6213, further comprising assessing a temperature in or proximate the opening, and controlling the flow of oxidizing fluid as a function of the assessed temperature.

6241. The method of claim 6213, further comprising assessing a temperature in or proximate the opening, and increasing the flow of oxidizing fluid as the assessed temperature decreases.

6242. The method of claim 6213, further comprising controlling the flow of oxidizing fluid to maintain a temperature in or proximate the opening at a temperature less than a pre-selected temperature.

6243. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375°

C.;

producing a mixture from the formation from a production well; and

controlling heating in or proximate the production well to produce a selected yield of non-condensable hydrocarbons in the produced mixture.

6244. The method of claim 6243, further comprising controlling heating in or proximate the production well to produce a selected yield of condensable hydrocarbons in the produced mixture.

6245. The method of claim 6243, wherein the mixture comprises more than about 50 weight percent non-condensable hydrocarbons.

6246. The method of claim 6243, wherein the mixture comprises more than about 50 weight percent condensable hydrocarbons.

6247. The method of claim 6243, wherein the average temperature and a pressure within the formation are controlled such that production of carbon dioxide is substantially inhibited.

6248. The method of claim 6243, heating in or proximate the production well is controlled such that production of carbon dioxide is substantially inhibited.

6249. The method of claim 6243, wherein at least a portion of the mixture produced from a first portion of the formation at a lower temperature is recycled into a second portion of the formation at a higher temperature such that production of carbon dioxide is substantially inhibited.

6250. The method of claim 6243, wherein the mixture comprises a volume ratio of molecular hydrogen to carbon monoxide of about 2 to 1, and wherein producing the mixture is controlled such that the volume ratio is maintained between about 1.8 to 1 and about 2.2 to 1.

6251. The method of claim 6243, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6252. The method of claim 6243, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6253. The method of claim 6243, wherein at least one heat source comprises a heater.

6254. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375°

C.; and

producing a mixture from the formation.

6255. The method of claim 6254, removing a fluid from the formation through a production well.

6256. The method of claim 6254, further comprising removing a liquid through a production well.

6257. The method of claim 6254, further comprising removing water through a production well.

6258. The method of claim 6254, further comprising removing a fluid through a production well prior to providing heat to the formation.

6259. The method of claim 6254, further comprising removing water from the formation through a production well prior to providing heat to the formation.

6260. The method of claim 6254, further comprising removing the fluid through a production well using a pump.

6261. The method of claim 6254, further comprising removing a fluid through a conduit.

6262. The method of claim 6254, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6263. The method of claim 6254, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6264. The method of claim 6254, wherein at least one heat source comprises a heater.

6265. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a selected section of the formation is less than about 375°

C.;

measuring a temperature within a wellbore placed in the formation; and

producing a mixture from the formation.

6266. The method of claim 6265, further comprising measuring the temperature using a moveable thermocouple.

6267. The method of claim 6265, further comprising measuring the temperature using an optical fiber assembly.

6268. The method of claim 6265, further comprising measuring the temperature within a production well.

6269. The method of claim 6265, further comprising measuring the temperature within a heater well.

6270. The method of claim 6265, further comprising measuring the temperature within a monitoring well.

6271. The method of claim 6265, further comprising providing a pressure wave from a pressure wave source into the wellbore, wherein the wellbore comprises a plurality of discontinuities along a length of the wellbore, measuring a reflection signal of the pressure wave, and using the reflection signal to assess at least one temperature between at least two discontinuities.

6272. The method of claim 6265, further comprising assessing an average temperature in the formation using one or more temperatures measured within at least one wellbore.

6273. The method of claim 6265, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6274. The method of claim 6265, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6275. The method of claim 6265, wherein at least one heat source comprises a heater.

6276. An in situ method of measuring assessing a temperature within a wellbore in an oil shale formation, comprising:

providing a pressure wave from a pressure wave source into the wellbore, wherein the wellbore comprises a plurality of discontinuities along a length of the wellbore;

measuring a reflection signal of the pressure wave; and

using the reflection signal to assess at least one temperature between at least two discontinuities.

6277. The method of claim 6276, wherein the plurality of discontinuities are placed along a length of a conduit placed in the wellbore.

6278. The method of claim 6277, wherein the pressure wave is propagated through a wall of the conduit.

6279. The method of claim 6277, wherein the plurality of discontinuities comprises collars placed within the conduit.

6280. The method of claim 6277, wherein the plurality of discontinuities comprises welds placed within the conduit.

6281. The method of claim 6276, wherein determining the at least one temperature between at least the two discontinuities comprises relating a velocity of the pressure wave between discontinuities to the at least one temperature.

6282. The method of claim 6276, further comprising measuring a reference signal of the pressure wave within the wellbore at an ambient temperature.

6283. The method of claim 6276, further comprising measuring a reference signal of the pressure wave within the wellbore at an ambient temperature, and then determining the at least one temperature between at least the two discontinuities by comparing the measured signal to the reference signal.

6284. The method of claim 6276, wherein the at least one temperature is a temperature of a gas between at least the two discontinuities.

6285. The method of claim 6276, wherein the wellbore comprises a production well.

6286. The method of claim 6276, wherein the wellbore comprises a heater well.

6287. The method of claim 6276, wherein the wellbore comprises a monitoring well.

6288. The method of claim 6276, wherein the pressure wave source comprises a solenoid valve.

6289. The method of claim 6276, wherein the pressure wave source comprises an explosive device.

6290. The method of claim 6276, wherein the pressure wave source comprises a sound device.

6291. The method of claim 6276, wherein the pressure wave is propagated through the wellbore.

6292. The method of claim 6276, wherein the plurality of discontinuities have a spacing between each discontinuity of about 5 m.

6293. The method of claim 6276, further comprising repeatedly providing the pressure wave into the wellbore at a selected frequency and continuously measuring the reflected signal to increase a signal-to-noise ratio of the reflected signal.

6294. The method of claim 6276, further comprising providing heat from one or more heat sources to a portion of the formation.

6295. The method of claim 6276, further comprising pyrolyzing at least some hydrocarbons within a portion of the formation.

6296. The method of claim 6276, further comprising generating synthesis gas in at least a portion of the formation.

6297. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375°

C.; and

producing a mixture from the formation through a heater well.

6298. The method of claim 6297, wherein producing the mixture through the heater well increases a production rate of the mixture from the formation.

6299. The method of claim 6297, further comprising providing heat using at least 2 heat sources.

6300. The method of claim 6297, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6301. The method of claim 6297, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6302. The method of claim 6297, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375°

C.

6303. The method of claim 6297, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6304. The method of claim 6297, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6305. The method of claim 6297, wherein at least one heat source comprises a heater.

6306. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein heating is provided from at least a first heat source and at least a second heat source, wherein the first heat source has a first heating cost and the second heat source has a second heating cost;

controlling a heating rate of at least a portion of the selected section to preferentially use the first heat source when the first heating cost is less than the second heating cost; and

controlling the heat from the one or more heat sources to pyrolyze at least some hydrocarbon in the selected section of the formation.

6307. The method of claim 6306, further comprising controlling the heating rate such that a temperature within at least a majority of the selected section of the formation is less than about 375°

C.

6308. The method of claim 6306, further comprising providing heat using at least 2 heat sources.

6309. The method of claim 6306, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6310. The method of claim 6306, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6311. The method of claim 6306, further comprising controlling the heating to preferentially use the second heat source when the second heating cost is less than the first heating cost.

6312. The method of claim 6306, further comprising producing a mixture from the formation.

6313. The method of claim 6306, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375°

C.

6314. The method of claim 6306, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6315. The method of claim 6306, wherein at least one heat source comprises a heater.

6316. The method of claim 6306, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6317. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein heating is provided from at least a first heat source and at least a second heat source, wherein the first heat source has a first heating cost and the second heat source has a second heating cost;

controlling a heating rate of at least a portion of the selected section such that a cost associated with heating the selected section is minimized; and

controlling the heat from the one or more heat sources to pyrolyze at least some hydrocarbon in at least a portion of the selected section of the formation.

6318. The method of claim 6317, wherein the heating rate is varied within a day depending on a cost associated with heating at various times in the day.

6319. The method of claim 6317, further comprising controlling the heating rate such that a temperature within at least a majority of the selected section of the formation is less than about 375°

C.

6320. The method of claim 6317, further comprising providing heat using at least 2 heat sources.

6321. The method of claim 6317, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6322. The method of claim 6317, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6323. The method of claim 6317, further comprising producing a mixture from the formation.

6324. The method of claim 6317, wherein heating of a majority of selected section is controlled such that a temperature of the majority of the selected section is less than about 375°

C.

6325. The method of claim 6317, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6326. The method of claim 6317, wherein at least one heat source comprises a heater.

6327. The method of claim 6317, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6328. A method for controlling an in situ system of treating an oil shale formation, comprising:

monitoring at least one acoustic event within the formation using at least one acoustic detector placed within a wellbore in the formation;

recording at least one acoustic event with an acoustic monitoring system;

analyzing at least one acoustic event to determine at least one property of the formation; and

controlling the in situ system based on the analysis of the at least one acoustic event.

6329. The method of claim 6328, wherein the at least one acoustic event comprises a seismic event.

6330. The method of claim 6328, wherein the method is continuously operated.

6331. The method of claim 6328, wherein the acoustic monitoring system comprises a seismic monitoring system.

6332. The method of claim 6328, further comprising recording the at least one acoustic event with the acoustic monitoring system.

6333. The method of claim 6328, further comprising monitoring more than one acoustic event simultaneously with the acoustic monitoring system.

6334. The method of claim 6328, further comprising monitoring the at least one acoustic event at a sampling rate of about at least once every 0.25 milliseconds.

6335. The method of claim 6328, wherein analyzing the at least one acoustic event comprises interpreting the at least one acoustic event.

6336. The method of claim 6328, wherein the at least one property of the formation comprises a location of at least one fracture in the formation.

6337. The method of claim 6328, wherein the at least one property of the formation comprises an extent of at least one fracture in the formation.

6338. The method of claim 6328, wherein the at least one property of the formation comprises an orientation of at least one fracture in the formation.

6339. The method of claim 6328, wherein the at least one property of the formation comprises a location and an extent of at least one fracture in the formation.

6340. The method of claim 6328, wherein controlling the in situ system comprises modifying a temperature of the in situ system.

6341. The method of claim 6328, wherein controlling the in situ system comprises modifying a pressure of the in situ system.

6342. The method of claim 6328, wherein the at least one acoustic detector comprises a geophone.

6343. The method of claim 6328, wherein the at least one acoustic detector comprises a hydrophone.

6344. The method of claim 6328, further comprising providing heat to at least a portion of the formation.

6345. The method of claim 6328, further comprising pyrolyzing hydrocarbons within at least a portion of the formation.

6346. The method of claim 6328, further comprising providing heat from one or more heat sources to a portion of the formation.

6347. The method of claim 6328, further comprising pyrolyzing at least some hydrocarbons within a portion of the formation.

6348. The method of claim 6328, further comprising generating synthesis gas in at least a portion of the formation.

6349. A method of predicting characteristics of a formation fluid produced from an in situ process, wherein the in situ process is used for treating an oil shale formation, comprising:

determining an isothermal experimental temperature that can be used when treating a sample of the formation, wherein the isothermal experimental temperature is correlated to a selected in situ heating rate for the formation; and

treating a sample of the formation at the determined isothermal experimental temperature, wherein the experiment is used to assess at least one product characteristic of the formation fluid produced from the formation for the selected heating rate.

6350. The method of claim 6349, further comprising determining the at least one product characteristic at a selected pressure.

6351. The method of claim 6349, further comprising modifying the selected heating rate so that at least one desired product characteristic of the formation fluid is obtained.

6352. The method of claim 6349, further comprising using a selected well spacing in the formation to determine the selected heating rate.

6353. The method of claim 6349, further comprising using a selected heat input into the formation to determine the selected heating rate.

6354. The method of claim 6349, further comprising using at least one property of the formation to determine the selected heating rate.

6355. The method of claim 6349, further comprising selecting a desired heating rate such that at least one desired product characteristic of the formation fluid is obtained.

6356. The method of claim 6349, further comprising determining the isothermal temperature using an equation that estimates a temperature in which a selected amount of hydrocarbons in the formation are converted.

6357. The method of claim 6349, wherein the selected heating rate is less than about 1°

C. per day.

6358. The method of claim 6349, wherein the sample is treated in an insulated vessel.

6359. The method of claim 6349, wherein at least one assessed produced characteristic is used to design at least one surface processing system, wherein the surface processing system is used to treat produced fluids on the surface.

6360. The method of claim 6349, wherein the formation is treated using a heating rate of about the selected heating rate.

6361. The method of claim 6349, further comprising using at least one product characteristic to assess a pressure to be maintained in the formation during treatment.

6362. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

adding hydrogen to the selected section after a temperature of the selected section is at least about 270°

C.; and

producing a mixture from the formation.

6363. The method of claim 6362, wherein the temperature of the selected section is at least about 290°

C.

6364. The method of claim 6362, wherein the temperature of the selected section is at least about 320°

C.

6365. The method of claim 6362, wherein the temperature of the selected section is less than about 375°

C.

6366. The method of claim 6362, wherein the temperature of the selected section is less than about 400°

C.

6367. The method of claim 6362, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6368. The method of claim 6362, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6369. The method of claim 6362, wherein at least one heat source comprises a heater.

6370. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling a temperature of a majority of the selected section by selectively adding hydrogen to the formation.

6371. The method of claim 6370, further comprising controlling the temperature such that the temperature is less than about 375°

C.

6372. The method of claim 6370, further comprising controlling the temperature such that the temperature is less than about 400°

C.

6373. The method of claim 6370, further comprising controlling a heating rate such that the temperature is less than about 375°

C.

6374. The method of claim 6370, wherein the one or more heat sources comprise a pattern of heat sources in a formation, and wherein superposition of heat from the pattern of heat sources pyrolyzes at least some hydrocarbons with the selected section of the formation.

6375. The method of claim 6370, further comprising producing a mixture from the formation.

6376. The method of claim 6370, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6377. The method of claim 6370, further comprising producing a mixture from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6378. The method of claim 6370, wherein at least one heat source comprises a heater.

6379. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least the portion to a selected section of the formation; and

producing fluids from the formation wherein at least a portion of the produced fluids have been heated by the heat provided by one or more of the heat sources, and wherein at least a portion of the produced fluids are produced at a temperature greater than about 200°

C.

6380. The method of claim 6379 wherein at least a portion of the produced fluids are produced at a temperature greater than about 250°

C.

6381. The method of claim 6379 wherein at least a portion of the produced fluids are produced at a temperature greater than about 300°

C.

6382. The method of claim 6379, further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids.

6383. The method of claim 6379 wherein the produced fluids are produced from a well comprising at least one of the heat sources, and further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids.

6384. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit.

6385. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, and further comprising varying the heat provided to the one or more heat sources to vary heat in at least a portion of the produced fluids provided to the hydrotreating unit.

6386. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, and using heat in the produced fluids when hydrotreating at least a portion of the produced fluids.

6387. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, and hydrotreating at least a portion of the produced fluids without using a surface heater to heat produced fluids.

6388. The method of claim 6379, further comprising:

providing at least a portion of the produced fluids to a hydrotreating unit; and

hydrotreating at least a portion of the produced fluids;

wherein at least 50% of heat used for hydrotreating is provided by heat in the produced fluids.

6389. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, wherein at least a portion of the produced fluids are provided to the hydrotreating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6390. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit, wherein at least a portion of the produced fluids are provided to the hydrotreating unit via a heated conduit.

6391. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the hydrotreating unit at a temperature that is within about 50°

C. of the temperature of the produced fluids at the wellhead.

6392. The method of claim 6379, further comprising hydrotreating at least a portion of the produced fluids such that the volume of hydrotreated produced fluids is about 4% greater than a volume of the produced fluids.

6393. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids comprise molecular hydrogen, and using the molecular hydrogen in the produced fluids to hydrotreat at least a portion of the produced fluids.

6394. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids comprise molecular hydrogen, hydrotreating at least a portion of the produced fluids, and wherein at least 50% of molecular hydrogen used for hydrotreating is provided by the molecular hydrogen in the produced fluids.

6395. The method of claim 6379 wherein the produced fluids comprise molecular hydrogen, separating at least a portion of the molecular hydrogen from the produced fluids, and providing at least a portion of the separated molecular hydrogen to a surface treatment unit.

6396. The method of claim 6379 wherein the produced fluids comprise molecular hydrogen, separating at least a portion of the molecular hydrogen from the produced fluids, and providing at least a portion of the separated molecular hydrogen to an in situ treatment area.

6397. The method of claim 6379 further comprising providing a portion of the produced fluids to an olefin generating unit.

6398. The method of claim 6379 further comprising providing a portion of the produced fluids to a steam cracking unit.

6399. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.

6400. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.

6401. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and generating olefins from at least a portion of the produced fluids without using a surface heater to heat produced fluids.

6402. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and generating olefins from at least a portion of the produced fluids, and wherein at least 50% of the heat used for generating olefins is provided by heat in the produced fluids.

6403. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6404. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.

6405. The method of claim 6379, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the olefin generating unit at a temperature that is within about 50°

C. of the temperature of the produced fluids at the wellhead.

6406. The method of claim 6379 further comprising removing heat from the produced fluids in a heat exchanger.

6407. The method of claim 6379 further comprising separating the produced fluids into two or more streams comprising at least a synthetic condensate stream, and a non-condensable fluid stream.

6408. The method of claim 6379 further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into two or more streams.

6409. The method of claim 6379 further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into two or more streams, and further comprising separating at least one of such streams into two or more substreams.

6410. The method of claim 6379 further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into three or more streams, and wherein such streams comprise at least a top stream, a bottom stream, and a middle stream.

6411. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the separating unit.

6412. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and using heat in the produced fluids when separating at least a portion of the produced fluids.

6413. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids without using a surface heater to heat produced fluids.

6414. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids, and wherein at least 50% of the heat used for separating is provided by heat in the produced fluids.

6415. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit wherein at least a portion of the produced fluids are provided to the separating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6416. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit wherein at least a portion of the produced fluids are provided to the separating unit via a heated conduit.

6417. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the separating unit at a temperature that is within about 50°

C. of the temperature of the produced fluids at the wellhead.

6418. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into four or more streams, and wherein such streams comprise at least a top stream, a bottoms stream, and at least two middle streams wherein one of the middle streams is heavier than the other middle stream.

6419. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a separating unit, and separating at least a portion of the produced fluids into five or more streams, and wherein such streams comprise at least a top stream, a bottoms stream, a naphtha stream, diesel stream, and a jet fuel stream.

6420. The method of claim 6379, further comprising providing at least a portion of the produced fluids to a distillation column, and using heat in the produced fluids when distilling at least a portion of the produced fluids.

6421. The method of claim 6379 wherein the produced fluids comprise pyrolyzation fluids.

6422. The method of claim 6379 wherein the produced fluids comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids.

6423. The method of claim 6379 wherein the produced fluids comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids, and utilizing at least some carbon dioxide in one or more treatment processes.

6424. The method of claim 6379 wherein the produced fluids comprise molecular hydrogen and wherein the molecular hydrogen is used when treating the produced fluids.

6425. The method of claim 6379 wherein the produced fluids comprise steam and wherein the steam is used when treating the produced fluids.

6426. The method of claim 6379, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6427. The method of claim 6379, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6428. The method of claim 6379, wherein at least one heat source comprises a heater.

6429. A method of converting formation fluids into olefins, comprising:

converting formation fluids into olefins, wherein the formation fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from one or more heat sources to a selected section of the formation such that at least some hydrocarbons in the formation are pyrolyzed; and

producing formation fluids from the formation.

6430. The method of claim 6429 wherein the produced fluids comprise steam.

6431. The method of claim 6429 wherein the produced fluids comprise steam and wherein the steam in the produced fluids comprises at least a portion of steam used in the olefin generating unit.

6432. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit.

6433. The method of claim 6429, further comprising providing at least a portion of the produced fluids to a steam cracking unit.

6434. The method of claim 6429 wherein olefins comprise ethylene.

6435. The method of claim 6429 wherein olefins comprise propylene.

6436. The method of claim 6429, further comprising separating liquids from the produced fluids, and then separating olefin generating compounds from the produced fluids, and then providing at least a portion of the olefin generating compounds to an olefin generating unit.

6437. The method of claim 6429 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids prior to using the produced fluids to produce olefins.

6438. The method of claim 6429 wherein the produced fluids comprise molecular hydrogen, and further comprising separating at least a portion of the molecular hydrogen from the produced fluids, and utilizing at least a portion of the separated molecular hydrogen in one or more treatment processes.

6439. The method of claim 6429 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a hydrogen removal unit prior to using the produced fluids to produce olefins.

6440. The method of claim 6429 wherein the produced fluids comprises molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a membrane prior to using the produced fluids to produce olefins.

6441. The method of claim 6429, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to one or more hydrotreating units.

6442. The method of claim 6429, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to an in situ treatment area.

6443. The method of claim 6429, further comprising generating molecular hydrogen during production of olefins, and providing at least a portion of the generated molecular hydrogen to one or more fuel cells. The method of claim 6429, further comprising generating molecular hydrogen during production of olefins, and using at least a portion of the generated molecular hydrogen to hydrotreat pyrolysis liquids generated in the olefin generation plant.

6444. The method of claim 6429 wherein the produced fluids are at least 200°

C., and further comprising using heat in the produced fluids to produce olefins.

6445. The method of claim 6429, further comprising providing at least a portion of the produced fluids to a hydrotreating unit wherein the produced fluids are produced at a wellhead, and wherein at least a portion of the produced fluids are provided to the olefins generating unit at a temperature that is within about 50°

C. of the temperature of the produced fluids at the wellhead.

6446. The method of claim 6429 wherein the produced fluids can be used to make olefins without substantial hydrotreating of the produced fluids.

6447. The method of claim 6429, further comprising separating liquids from the produced fluids, and then using at least a portion of the produced fluids to produce olefins.

6448. The method of claim 6429, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.

6449. The method of claim 6429, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.

6450. The method of claim 6429, further comprising controlling a temperature profile within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.

6451. The method of claim 6429, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefin generating compounds in the produced fluids.

6452. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.

6453. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.

6454. The method of claim 6429 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.

6455. The method of claim 6429 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, generating olefins from at least a portion of the produced fluids, and wherein at least some steam used for generating olefins is provided by the steam in the produced fluids.

6456. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6457. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.

6458. The method of claim 6429, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an olefin generating unit.

6459. The method of claim 6429, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 8, and further comprising providing the olefin generating fraction to a olefin generating unit.

6460. The method of claim 6429, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise an olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 6, and further comprising providing the olefin generating fraction to a olefin generating unit.

6461. The method of claim 6429, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, and then providing the reduced component fluid stream to an olefin generating unit.

6462. The method of claim 6461, wherein the component comprises a metal.

6463. The method of claim 6461, wherein the component comprises arsenic.

6464. The method of claim 6461, wherein the component comprises mercury.

6465. The method of claim 6461, wherein the component comprises lead.

6466. The method of claim 6429, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, then providing the reduced component fluid stream to a molecular hydrogen separating unit such that a molecular hydrogen stream and a reduced hydrogen fluid stream are formed, then providing the molecular hydrogen stream to a hydrotreating unit, and then providing the reduced hydrogen produced fluid stream to an olefin generating unit.

6467. The method of claim 6429 wherein the produced fluids comprise molecular hydrogen and wherein the molecular hydrogen is used when treating the produced fluids.

6468. The method of claim 6429 wherein the produced fluids comprise steam and wherein the steam is used when treating the produced fluids.

6469. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.

6470. The method of claim 6429 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.

6471. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6472. The method of claim 6429, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.

6473. The method of claim 6429, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6474. The method of claim 6429, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6475. The method of claim 6429, wherein at least one heat source comprises a heater.

6476. A method of separating olefins from fluids produced from an oil shale formation, comprising:

separating olefins from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise olefins.

6477. The method of claim 6476 wherein olefins comprise ethylene.

6478. The method of claim 6476 wherein olefins comprise propylene.

6479. The method of claim 6476, further comprising separating liquids from the produced fluids.

6480. The method of claim 6476 wherein the produced fluids comprise molecular hydrogen, and further comprising separating at least a portion of the molecular hydrogen from the produced fluids, and utilizing at least a portion of the separated molecular hydrogen in one or more treatment processes.

6481. The method of claim 6476 wherein the produced fluids comprise molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a hydrogen removal unit.

6482. The method of claim 6476 wherein the produced fluids comprises molecular hydrogen, and further comprising removing at least a portion of the molecular hydrogen from the produced fluids using a membrane.

6483. The method of claim 6476, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefins in the produced fluids.

6484. The method of claim 6476, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefins in the produced fluids.

6485. The method of claim 6476, further comprising controlling a temperature profile within at least a portion of the formation to enhance production of olefins in the produced fluids.

6486. The method of claim 6476, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefins in the produced fluids.

6487. The method of claim 6476, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and further comprising varying heat provided to the one or more heat sources to vary the heat in at least a portion of the produced fluids provided to the olefin generating unit.

6488. The method of claim 6476, further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using heat in the produced fluids when generating olefins from at least a portion of the produced fluids.

6489. The method of claim 6476 wherein the produced fluids comprise steam, and further comprising providing at least a portion of the produced fluids to an olefin generating unit, and using steam in the produced fluids when generating olefins from at least a portion of the produced fluids.

6490. The method of claim 6476, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via an insulated conduit, and wherein the insulated conduit is insulated to inhibit heat loss from the produced fluids.

6491. The method of claim 6476, further comprising providing at least a portion of the produced fluids to an olefin generating unit wherein at least a portion of the produced fluids are provided to the olefin generating unit via a heated conduit.

6492. The method of claim 6476, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an olefin generating unit.

6493. The method of claim 6476, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise a olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 8, and further comprising providing the olefin generating fraction to a olefin generating unit.

6494. The method of claim 6476, further comprising separating at least a portion of the produced fluids into one or more fractions wherein the one or more fractions comprise an olefin generating fraction wherein the olefin generating fraction comprises hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 6, and further comprising providing the olefin generating fraction to a olefin generating unit.

6495. The method of claim 6476, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, and then providing the reduced component fluid stream to an olefin generating unit.

6496. The method of claim 6495 wherein the component comprises a metal.

6497. The method of claim 6495 wherein the component comprises arsenic.

6498. The method of claim 6495 wherein the component comprises mercury.

6499. The method of claim 6495 wherein the component comprises lead.

6500. The method of claim 6476, further comprising providing at least the portion of the produced fluids to a component removal unit such that at least one component stream and a reduced component fluid stream are formed, then providing the reduced component fluid stream to a molecular hydrogen separating unit such that a molecular hydrogen stream and a reduced hydrogen fluid stream are formed, then providing the molecular hydrogen stream to a hydrotreating unit, and then providing the reduced hydrogen produced fluid stream to an olefin generating unit.

6501. The method of claim 6476, further comprising controlling a temperature gradient within at least a portion of the formation to enhance production of olefins in the produced fluids.

6502. The method of claim 6476, further comprising controlling a fluid pressure within at least a portion of the formation to enhance production of olefins in the produced fluids.

6503. The method of claim 6476, further comprising controlling a temperature within at least a portion of the formation to enhance production of olefins in the produced fluids.

6504. The method of claim 6476, further comprising controlling a heating rate within at least a portion of the formation to enhance production of olefins in the produced fluids.

6505. The method of claim 6476, further comprising separating the olefins from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.

6506. The method of claim 6476, further comprising removing at least a portion of the olefins prior to hydrotreating produced fluids.

6526. The method of claim 6476, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6527. The method of claim 6476, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6528. The method of claim 6476, wherein at least one heat source comprises a heater.

6507. A method of enhancing phenol production from an in situ oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of phenols in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least the portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6508. The method of claim 6507, further comprising separating at least a portion of the phenols from the produced fluids.

6509. The method of claim 6507 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6510. The method of claim 6507 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6511. The method of claim 6507 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6512. The method of claim 6507 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6513. The method of claim 6507 wherein the at least one condition in the formation is controlled such that an average carbon number of the produced fluids is lowered.

6514. The method of claim 6507, further comprising separating at least a portion of the produced fluids into a phenols fraction at a wellhead using condensation.

6515. The method of claim 6507, further comprising separating at least a portion of the produced fluids into a phenols fraction at a wellhead using fractionation.

6516. The method of claim 6507, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an extraction unit, and separating at least some phenols from the naphtha fraction.

6517. The method of claim 6507, further comprising separating the produced fluids into a gas stream and a liquid stream, separating the liquid stream into a phenols fraction and a hydrocarbon containing fraction, and providing the hydrocarbon containing fraction to a pipeline.

6518. The method of claim 6507, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a phenols fraction, and further comprising providing the phenols fraction to an extraction unit, and separating at least some phenols from the phenols fluids.

6519. The method of claim 6507, further comprising separating the phenols from the produced fluids with a water/methanol extraction process.

6520. The method of claim 6507, further comprising separating the phenols from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.

6521. The method of claim 6507 wherein controlling a condition comprises lowering the average carbon number of the produced fluids.

6522. The method of claim 6507, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids.

6523. The method of claim 6507, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids, and wherein removing at least the portion reduces an amount of molecular hydrogen required in a hydrotreating unit.

6525. The method of claim 6507, wherein the selected section has been selected for heating using an oxygen content of at least some hydrocarbons in the selected section.

6524. The method of 6507, further comprising reacting at least a portion of the phenols with molecular hydrogen to form phenol.

6529. A method of controlling phenol production from an oil shale formation, comprising;

converting at least a portion of formation fluid into phenol, wherein the formation fluids in situ are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section; and

producing formation fluids from the formation.

6532. The method of claim 6529, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6533. The method of claim 6529, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6534. The method of claim 6529, wherein at least one heat source comprises a heater.

6530. The method of 6529, wherein the formation fluids comprise phenols.

6531. The method of 6529, wherein converting at least a portion of formation fluid into phenol comprises reacting at least a portion of the phenols with molecular hydrogen to form phenol.

6535. A method of separating phenols from fluids produced from an oil shale formation, comprising:

separating phenols from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise phenols.

6536. The method of claim 6535, further comprising controlling a fluid pressure within at least a portion of the formation.

6537. The method of claim 6535, further comprising controlling a temperature gradient within at least a portion of the formation.

6538. The method of claim 6535, further comprising controlling a temperature within at least a portion of the formation.

6539. The method of claim 6535, further comprising controlling a heating rate within at least a portion of the formation.

6540. The method of claim 6535 wherein separating the phenols from the produced fluids, further comprises removing a naphtha fraction from the produced fluids, and separating phenols from the naphtha fraction.

6541. The method of claim 6535 wherein separating the phenols from the produced fluids, further comprises removing a phenols fraction from the produced fluids, and separating at least some phenols from the phenols fraction.

6542. The method of claim 6535 wherein separating the phenols from the produced fluids, further comprises removing phenols with a water/methanol extraction.

6543. The method of claim 6535 wherein separating the phenols from the produced fluids decreases an amount of molecular hydrogen utilized in one or more downstream hydrotreating units.

6544. The method of claim 6535, wherein controlling a condition comprises lowering the average carbon number of the produced fluids.

6545. The method of claim 6535, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids.

6546. The method of claim 6535, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids, and wherein removing at least the portion reduces an amount of molecular hydrogen required in a hydrotreating unit.

6547. The method of claim 6535, further comprising reacting at least a portion of the phenols with molecular hydrogen to form phenol.

6548. The method of claim 6535, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6549. The method of claim 6535, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6550. The method of claim 6535, wherein at least one heat source comprises a heater.

6551. A method of enhancing phenol production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of phenols in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6552. The method of claim 6551, further comprising separating at least a portion of the phenols from the produced fluids.

6553. The method of claim 6551, further comprising controlling at least one condition in situ such that an average carbon number of the produced fluids is lowered.

6554. The method of claim 6551, further comprising controlling a temperature gradient within at least a portion of the formation.

6555. The method of claim 6551, further comprising controlling a fluid pressure within at least a portion of the formation.

6556. The method of claim 6551, further comprising controlling a temperature within at least a portion of the formation.

6557. The method of claim 6551, further comprising controlling a heating rate within at least a portion of the formation.

6558. The method of claim 6551, further comprising separating at least a portion of the produced fluids into a phenols fraction at a wellhead using condensation.

6559. The method of claim 6551, further comprising separating at least a portion of the produced fluids into a phenols fraction at a wellhead using fractionation.

6560. The method of claim 6551, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to an extraction unit, and separating at least some phenols from the naphtha fraction.

6561. The method of claim 6551, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a phenols fraction, and further comprising providing the phenols fraction to an extraction unit, and separating at least some phenols from the phenols fluids.

6562. The method of claim 6551, further comprising separating the phenols from the produced fluids with a water/methanol extraction process.

6563. The method of claim 6551, further comprising separating the phenols from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.

6564. The method of claim 6551, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids.

6565. The method of claim 6551, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids, and wherein removing at least the portion reduces an amount of molecular hydrogen required in a hydrotreating unit.

6566. The method of claim 6551, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6567. The method of claim 6551, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6568. The method of claim 6551, wherein at least one heat source comprises a heater.

6569. A method of enhancing BTEX compounds production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of BTEX compounds in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6570. The method of claim 6569, further comprising separating at least a portion of the BTEX compounds from the produced fluids.

6571. The method of claim 6569, further comprising separating at least a portion of the BTEX compounds from the produced fluids via solvent extraction.

6572. The method of claim 6569, further comprising separating at least a portion of the BTEX compounds from the produced fluids via distillation.

6573. The method of claim 6569, further comprising separating at least a portion of the BTEX compounds from the produced fluids via condensation.

6574. The method of claim 6569, further comprising separating at least a portion of the BTEX compounds from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.

6575. The method of claim 6569, wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6576. The method of claim 6569, wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6577. The method of claim 6569, wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6578. The method of claim 6569, wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6579. The method of claim 6569, further comprising removing at least a portion of the BTEX compounds prior to hydrotreating produced fluids.

6580. The method of claim 6569, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids, and wherein removing at least the portion reduces an amount of molecular hydrogen required in a hydrotreating unit.

6581. The method of claim 6569, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6582. The method of claim 6569, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6583. The method of claim 6569, wherein at least one heat source comprises a heater.

6584. A method of separating BTEX compounds from formation fluid from an oil shale formation, comprising:

separating at least a portion of the BTEX compounds from the formation fluid wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise BTEX compounds.

6585. The method of claim 6584, further comprising hydrotreating at least a portion of the produced fluids after the BTEX compounds have been separated from same.

6586. The method of claim 6584 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises extracting at least the portion of the BTEX compounds from the produced fluids via solvent extraction.

6587. The method of claim 6584 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises distilling at least the portion of the BTEX compounds from the produced fluids.

6588. The method of claim 6584 wherein separating at least a portion of the BTEX compounds from the produced fluids comprises condensing at least the portion of the BTEX compounds from the produced fluids

6589. The method of claim 6584 wherein separating at least a portion of the BTEX compounds from the produced fluids such that an amount of molecular hydrogen utilized in one or more downstream hydrotreating units decreases.

6590. The method of claim 6584, further comprising controlling a fluid pressure within at least a portion of the formation.

6591. The method of claim 6584, further comprising controlling a temperature gradient within at least a portion of the formation.

6592. The method of claim 6584, further comprising controlling a temperature within at least a portion of the formation.

6593. The method of claim 6584, further comprising controlling a heating rate within at least a portion of the formation.

6594. The method of claim 6584 wherein separating at least the portion of BTEX compounds from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least the portion of BTEX compounds from the naphtha fraction.

6595. The method of claim 6584, wherein separating at least the portion of BTEX compounds from the produced fluids, further comprises removing a BTEX fraction from the produced fluids, and separating at some BTEX compounds from the BTEX fraction.

6596. The method of claim 6584, wherein separating at least the portion of BTEX compounds from the produced fluids decreases an amount of molecular hydrogen utilized in one or more downstream hydrotreating units.

6597. A method of in situ converting at least a portion of formation fluid into BTEX compounds, comprising:

in situ converting at least the portion of the formation fluid into BTEX compounds, wherein the formation fluid are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation such that at least some hydrocarbons in the formation are pyrolyzed; and

producing formation fluid from the formation.

6598. The method of claim 6597, further comprising providing at least a portion of the formation fluid to an BTEX generating unit.

6599. The method of claim 6597, further comprising providing at least a portion of the formation fluid to a catalytic reforming unit.

6600. The method of claim 6597, further comprising hydrotreating at least some of the formation fluid, and then separating the hydrotreated mixture into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a reformate comprising BTEX compounds, and then separating at least a portion of the BTEX compounds from the reformate.

6601. The method of claim 6597, further comprising hydrotreating at least some of the formation fluid, and then separating the hydrotreated mixture into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a molecular hydrogen stream and a reformate comprising BTEX compounds, and then separating at least a portion of the BTEX compounds from the reformate, and then utilizing the molecular hydrogen stream to hydrotreat at least some of the formation fluid.

6602. The method of claim 6597, further comprising hydrotreating the formation fluid, and then separating the hydrotreated formation fluid into one more streams comprising a naphtha stream, and then reforming at least a portion the naphtha stream to form a reformate comprising BTEX compounds, and then separating at least a portion of the reformate into two or more streams comprising a raffinate and a BTEX stream.

6603. The method of claim 6597 wherein the formation fluid is at least 200°

C., and further comprising using heat in the formation fluid to hydrotreat at least a portion of the formation fluid.

6604. The method of claim 6597, further comprising separating at least a portion of the formation fluid into one or more fractions wherein the one or more fractions comprise a naphtha fraction, and further comprising providing the naphtha fraction to a catalytic reforming unit.

6605. The method of claim 6597, further comprising separating at least a portion of the formation fluid into one or more fractions wherein the one or more fractions comprise a BTEX compound generating fraction wherein the BTEX compound generating fraction comprises hydrocarbons, and further comprising providing the BTEX compound generating fraction to a catalytic reforming unit.

6606. The method of claim 6597, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6607. The method of claim 6597, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6608. The method of claim 6597, wherein at least one heat source comprises a heater.

6609. A method of enhancing naphthalene production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of naphthalene in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6610. The method of claim 6609, further comprising separating at least a portion of the naphthalene from the produced fluids.

6611. The method of claim 6609 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6612. The method of claim 6609 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6613. The method of claim 6609 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6614. The method of claim 6609 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6615. The method of claim 6609, further comprising separating the produced fluids into one or more fractions using distillation.

6616. The method of claim 6609, further comprising separating the produced fluids into one or more fractions using condensation.

6617. The method of claim 6609, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some naphthalene from the heart cut.

6618. The method of claim 6609, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a naphthalene fraction, and further comprising providing the naphthalene fraction to an extraction unit, and separating at least some naphthalene from the naphthalene fraction.

6619. The method of claim 6609, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6620. The method of claim 6609, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6621. The method of claim 6609, wherein at least one heat source comprises a heater.

6622. A method of separating naphthalene from fluids produced from an oil shale formation, comprising:

separating naphthalene from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise naphthalene.

6623. The method of claim 6622, further comprising controlling a fluid pressure within at least a portion of the formation.

6624. The method of claim 6622, further comprising controlling a temperature gradient within at least a portion of the formation.

6625. The method of claim 6622, further comprising controlling a temperature within at least a portion of the formation.

6626. The method of claim 6622, further comprising controlling a heating rate within at least a portion of the formation.

6627. The method of claim 6622 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.

6628. The method of claim 6622 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.

6629. The method of claim 6622 wherein separating at least some naphthalene from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the naphthalene from the heart cut.

6630. The method of claim 6622 wherein separating at least some naphthalene from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the naphthalene from the naphtha fraction.

6631. The method of claim 6622, wherein separating at least some naphthalene from the produced fluids further comprises removing an naphthalene fraction from the produced fluids, and separating at least a portion of the naphthalene from the naphthalene fraction.

6632. The method of claim 6622 wherein separating the naphthalene from the produced fluids further comprises removing naphthalene using distillation.

6633. The method of claim 6622 wherein separating the naphthalene from the produced fluids further comprises removing naphthalene using crystallization.

6634. The method of claim 6622, further comprising removing at least a portion of the naphthalene prior to hydrotreating produced fluids.

6635. The method of claim 6622, further comprising removing at least a portion of the phenols prior to hydrotreating produced fluids, and wherein removing at least the portion reduces an amount of molecular hydrogen required in a hydrotreating unit.

6636. The method of claim 6622, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6637. The method of claim 6622, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6638. The method of claim 6622, wherein at least one heat source comprises a heater.

6639. A method of enhancing anthracene production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of anthracene in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6640. The method of claim 6639, further comprising separating at least a portion of the anthracene from the produced fluids.

6641. The method of claim 6639 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6642. The method of claim 6639 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6643. The method of claim 6639 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6644. The method of claim 6639 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6645. The method of claim 6639, further comprising separating the produced fluids into one or more fractions using distillation.

6646. The method of claim 6639, further comprising separating the produced fluids into one or more fractions using condensation.

6647. The method of claim 6639, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some anthracene from the heart cut.

6648. The method of claim 6639, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a anthracene fraction, and further comprising providing the anthracene fraction to an extraction unit, and separating at least some anthracene from the anthracene fraction.

6649. The method of claim 6639, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6650. The method of claim 6639, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6651. The method of claim 6639, wherein at least one heat source comprises a heater.

6652. A method of separating anthracene from fluids produced from an oil shale formation, comprising:

separating anthracene from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise anthracene.

6653. The method of claim 6652, further comprising controlling a fluid pressure within at least a portion of the formation.

6654. The method of claim 6652, further comprising controlling a temperature gradient within at least a portion of the formation.

6655. The method of claim 6652, further comprising controlling a temperature within at least a portion of the formation.

6656. The method of claim 6652, further comprising controlling a heating rate within at least a portion of the formation

6657. The method of claim 6652, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.

6658. The method of claim 6652, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.

6659. The method of claim 6652, wherein separating at least some anthracene from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the anthracene from the heart cut.

6660. The method of claim 6652, wherein separating at least some anthracene from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the anthracene from the naphtha fraction.

6661. The method of claim 6652, wherein separating at least some anthracene from the produced fluids further comprises removing an anthracene fraction from the produced fluids, and separating at least a portion of the anthracene from the anthracene fraction.

6662. The method of claim 6652, wherein separating the anthracene from the produced fluids further comprises removing anthracene using distillation.

6663. The method of claim 6652, wherein separating the anthracene from the produced fluids further comprises removing anthracene using crystallization.

6664. The method of claim 6652, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6665. The method of claim 6652, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6666. The method of claim 6652, wherein at least one heat source comprises a heater.

6667. A method of separating ammonia from fluids produced from an oil shale formation, comprising:

separating at least a portion of the ammonia from the produced fluid, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation.

6668. The method of claim 6667 wherein the produced fluids are pyrolyzation fluids.

6669. The method of claim 6667 wherein separating at least a portion of the ammonia from the produced fluids further comprises providing at least a portion of the produced fluids to a sour water stripper.

6670. The method of claim 6667 wherein separating at least a portion of the ammonia from the produced fluids further comprises separating the produced fluids into one or more fractions, and providing at least a portion of the one or more fractions to a stripping unit.

6671. The method of claim 6667, further comprising using at least a portion of the separated ammonia to generate ammonium sulfate.

6672. The method of claim 6667, further comprising using at least a portion of the separated ammonia to generate urea.

6673. The method of claim 6667 wherein the produced fluids comprise carbon dioxide, and further comprising separating the carbon dioxide from the produced fluids, and reacting the carbon dioxide with at least some ammonia to form urea.

6674. The method of claim 6667 wherein the produced fluids comprise hydrogen sulfide, and further comprising separating the hydrogen sulfide from the produced fluids, converting at least some hydrogen sulfide into sulfuric acid, and reacting at lest some sulfuric acid with at lease some ammonia to form ammonium sulfate.

6675. The method of claim 6667 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, and converting at least some hydrogen sulfide into sulfuric acid.

6676. The method of claim 6667, further comprising generating ammonium bicarbonate using separated ammonia.

6677. The method of claim 6667, further comprising providing separated ammonia to a fluid comprising carbon dioxide to generate ammonium bicarbonate.

6678. The method of claim 6667, further comprising providing separated ammonia to at least some synthesis gas to generate ammonium bicarbonate.

6679. The method of claim 6667, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6680. The method of claim 6667, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6681. The method of claim 6667, wherein at least one heat source comprises a heater.

6682. A method of generating ammonia from fluids produced from an oil shale formation, comprising:

hydrotreating at least a portion of the produced fluids to generate ammonia wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation.

6683. The method of claim 6682 wherein the produced fluids are pyrolyzation fluids.

6684. The method of claim 6682, further comprising separating at least a portion of the ammonia from the hydrotreated fluids.

6685. The method of claim 6682, further comprising using at least a portion of the ammonia to generate ammonium sulfate.

6686. The method of claim 6682, further comprising using at least a portion of the ammonia to generate urea.

6687. The method of claim 6682 wherein the produced fluids further comprise carbon dioxide, and further comprising separating at least a portion of the carbon dioxide from the produced fluids, and reacting at least the portion of the carbon dioxide with at least a portion of ammonia to form urea.

6688. The method of claim 6682 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, converting at least some hydrogen sulfide into sulfuric acid, and reacting at least some sulfuric acid with at least a portion of the ammonia to form ammonium sulfate.

6689. The method of claim 6682 wherein the produced fluids further comprise hydrogen sulfide, and further comprising separating at least a portion of the hydrogen sulfide from the produced fluids, and converting at least some hydrogen sulfide into sulfuric acid.

6690. The method of claim 6682, further comprising generating ammonium bicarbonate using at least a portion of the ammonia.

6691. The method of claim 6682, further comprising providing at least a portion of the ammonia to a fluid comprising carbon dioxide to generate ammonium bicarbonate.

6692. The method of claim 6682, further comprising providing at least a portion of the ammonia to at least some synthesis gas to generate ammonium bicarbonate

6693. The method of claim 6682, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6694. The method of claim 6682, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6695. The method of claim 6682, wherein at least one heat source comprises a heater.

6696. A method of enhancing pyridines production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of pyridines in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6697. The method of claim 6696, further comprising separating at least a portion of the pyridines from the produced fluids.

6698. The method of claim 6696 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6699. The method of claim 6696 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6700. The method of claim 6696 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6701. The method of claim 6696 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6702. The method of claim 6696, further comprising separating the produced fluids into one or more fractions using distillation.

6703. The method of claim 6696, further comprising separating the produced fluids into one or more fractions using condensation.

6704. The method of claim 6696, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some pyridines from the heart cut.

6705. The method of claim 6696, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a pyridines fraction, and further comprising providing the pyridines fraction to an extraction unit, and separating at least some pyridines from the pyridines fraction.

6706. The method of claim 6696, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6707. The method of claim 6696, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6708. The method of claim 6696, wherein at least one heat source comprises a heater.

6709. A method of separating pyridines from fluids produced from an oil shale formation, comprising:

separating pyridines from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise pyridines.

6710. The method of claim 6709, further comprising controlling a fluid pressure within at least a portion of the formation.

6711. The method of claim 6709, further comprising controlling a temperature gradient within at least a portion of the formation.

6712. The method of claim 6709, further comprising controlling a temperature within at least a portion of the formation.

6713. The method of claim 6709, further comprising controlling a heating rate within at least a portion of the formation

6714. The method of claim 6709 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.

6715. The method of claim 6709 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.

6716. The method of claim 6709 wherein separating at least some pyridines from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the pyridines from the heart cut.

6717. The method of claim 6709 wherein separating at least some pyridines from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the pyridines from the naphtha fraction.

6718. The method of claim 6709, wherein separating at least some pyridines from the produced fluids further comprises removing an pyridines fraction from the produced fluids, and separating at least a portion of the pyridines from the pyridines fraction.

6719. The method of claim 6709, wherein separating the pyridines from the produced fluids further comprises removing pyridines using distillation.

6720. The method of claim 6709, wherein separating the pyridines from the produced fluids further comprises removing pyridines using crystallization.

6721. The method of claim 6709, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6722. The method of claim 6709, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6723. The method of claim 6709, wherein at least one heat source comprises a heater.

6724. A method of enhancing pyrroles production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of pyrroles in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6725. The method of claim 6724, further comprising separating at least a portion of the pyrroles from the produced fluids.

6726. The method of claim 6724 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6727. The method of claim 6724 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6728. The method of claim 6724 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6729. The method of claim 6724 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6730. The method of claim 6724, further comprising separating the produced fluids into one or more fractions using distillation.

6731. The method of claim 6724, further comprising separating the produced fluids into one or more fractions using condensation.

6732. The method of claim 6724, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some pyrroles from the heart cut.

6733. The method of claim 6724, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a pyrroles fraction, and further comprising providing the pyrroles fraction to an extraction unit, and separating at least some pyrroles from the pyrroles fraction.

6734. The method of claim 6724, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6735. The method of claim 6724, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6736. The method of claim 6724, wherein at least one heat source comprises a heater.

6737. A method of separating pyrroles from fluids produced from an oil shale formation, comprising:

separating pyrroles from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise pyrroles.

6738. The method of claim 6737, further comprising controlling a fluid pressure within at least a portion of the formation.

6739. The method of claim 6737, further comprising controlling a temperature gradient within at least a portion of the formation.

6740. The method of claim 6737, further comprising controlling a temperature within at least a portion of the formation.

6741. The method of claim 6737, further comprising controlling a heating rate within at least a portion of the formation

6742. The method of claim 6737 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.

6743. The method of claim 6737 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.

6744. The method of claim 6737 wherein separating at least some pyrroles from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the pyrroles from the heart cut.

6745. The method of claim 6737 wherein separating at least some pyrroles from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the pyrroles from the naphtha fraction.

6746. The method of claim 6737, wherein separating at least some pyrroles from the produced fluids further comprises removing an pyrroles fraction from the produced fluids, and separating at least a portion of the pyrroles from the pyrroles fraction.

6747. The method of claim 6737, wherein separating the pyrroles from the produced fluids further comprises removing pyrroles using distillation.

6748. The method of claim 6737, wherein separating the pyrroles from the produced fluids further comprises removing pyrroles using crystallization.

6749. The method of claim 6737, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6750. The method of claim 6737, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6751. The method of claim 6737, wherein at least one heat source comprises a heater.

6752. A method of enhancing thiophenes production from an oil shale formation, comprising:

controlling at least one condition within at least a portion of the formation to enhance production of thiophenes in formation fluid, wherein the formation fluid is obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing formation fluids from the formation.

6753. The method of claim 6752, further comprising separating at least a portion of the thiophenes from the produced fluids.

6754. The method of claim 6752 wherein controlling at least one condition in the formation comprises controlling a fluid pressure within at least a portion of the formation.

6755. The method of claim 6752 wherein controlling at least one condition in the formation comprises controlling a temperature gradient within at least a portion of the formation.

6756. The method of claim 6752 wherein controlling at least one condition in the formation comprises controlling a temperature within at least a portion of the formation.

6757. The method of claim 6752 wherein controlling at least one condition in the formation comprises controlling a heating rate within at least a portion of the formation.

6758. The method of claim 6752, further comprising separating the produced fluids into one or more fractions using distillation.

6759. The method of claim 6752, further comprising separating the produced fluids into one or more fractions using condensation.

6760. The method of claim 6752, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and further comprising providing the heart cut to an extraction unit, and separating at least some thiophenes from the heart cut.

6761. The method of claim 6752, further comprising separating the produced fluids into one or more fractions wherein the one or more fractions comprise a thiophenes fraction, and further comprising providing the thiophenes fraction to an extraction unit, and separating at least some thiophenes from the thiophenes fraction.

6762. The method of claim 6752, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6763. The method of claim 6752, wherein the formation fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6764. The method of claim 6752, wherein at least one heat source comprises a heater.

6777. The method of claim 6752, wherein the heat provided from at least one heat source is transferred to the formation substantially by conduction.

6778. The method of claim 6752, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6779. The method of claim 6752, wherein at least one heat source comprises a heater.

6765. A method of separating thiophenes from fluids produced from an oil shale formation, comprising:

separating thiophenes from the produced fluids, wherein the produced fluids are obtained by;

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least one or more heat sources to a selected section of the formation; and

producing fluids from the formation wherein the produced fluids comprise thiophenes.

6766. The method of claim 6765, further comprising controlling a fluid pressure within at least a portion of the formation.

6767. The method of claim 6765, further comprising controlling a temperature gradient within at least a portion of the formation.

6768. The method of claim 6765, further comprising controlling a temperature within at least a portion of the formation.

6769. The method of claim 6765, further comprising controlling a heating rate within at least a portion of the formation

6770. The method of claim 6765 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions using distillation.

6771. The method of claim 6765 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions using condensation.

6772. The method of claim 6765 wherein separating at least some thiophenes from the produced fluids further comprises separating the produced fluids into one or more fractions wherein the one or more fractions comprise a heart cut, and extracting at least a portion of the thiophenes from the heart cut.

6773. The method of claim 6765 wherein separating at least some thiophenes from the produced fluids further comprises removing a naphtha fraction from the produced fluids, and separating at least a portion of the thiophenes from the naphtha fraction.

6774. The method of claim 6765 wherein separating at least some thiophenes from the produced fluids further comprises removing an thiophenes fraction from the produced fluids, and separating at least a portion of the thiophenes from the thiophenes fraction.

6775. The method of claim 6765 wherein separating the thiophenes from the produced fluids further comprises removing thiophenes using distillation.

6776. The method of claim 6765 wherein separating the thiophenes from the produced fluids further comprises removing thiophenes using crystallization.

6780. A method of treating an oil shale formation comprising:

providing a barrier to at least a portion of the formation to inhibit migration of fluids into or out of a treatment area of the formation;

providing heat from one or more heat sources to the treatment area;

allowing the heat to transfer from the treatment area to a selected section of the formation; and

producing fluids from the formation.

6781. The method of claim 6780, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.

6782. The method of claim 6780, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6783. The method of claim 6780, wherein at least one of the one or more of the heat sources comprises a heater.

6784. The method of claim 6780, further comprising hydraulically isolating the treatment area from a surrounding portion of the formation.

6785. The method of claim 6780, further comprising pyrolyzing at least a portion of hydrocarbon containing material within the treatment area.

6786. The method of claim 6780, further comprising generating synthesis gas in at least a portion of the treatment area.

6787. The method of claim 6780, further comprising controlling a pressure within the treatment area.

6788. The method of claim 6780, further comprising controlling a temperature within the treatment area.

6789. The method of claim 6780, further comprising controlling a heating rate within the treatment area.

6790. The method of claim 6780, further comprising controlling an amount of fluid removed from the treatment area.

6791. The method of claim 6780, wherein at least section of the barrier comprises one or more sulfur wells.

6792. The method of claim 6780, wherein at least section of the barrier comprises one or more dewatering wells.

6793. The method of claim 6780, wherein at least section of the barrier comprises one or more injection wells and one or more dewatering wells.

6794. The method of claim 6780, wherein providing a barrier comprises:

providing a circulating fluid to the a portion of the formation surrounding the treatment area; and

removing the circulating fluid proximate the treatment area.

6795. The method of claim 6780, wherein at least section of the barrier comprises a ground cover on a surface of the earth.

6796. The method of claim 6795, wherein at least section of the ground cover is sealed to a surface of the earth.

6797. The method of claim 6780, further comprising inhibiting a release of formation fluid to the earth'"'"'s atmosphere with a ground cover;

and freezing at least a portion of the ground cover to a surface of the earth.

6798. The method of claim 6780, further comprising inhibiting a release of formation fluid to the earth'"'"'s atmosphere.

6799. The method of claim 6780, further comprising inhibiting fluid seepage from a surface of the earth into the treatment area.

6800. The method of claim 6780, wherein at least a section of the barrier is naturally occurring.

6801. The method of claim 6780, wherein at least a section of the barrier comprises a low temperature zone.

6802. The method of claim 6780, wherein at least a section of the barrier comprises a frozen zone.

6803. The method of claim 6780, wherein the barrier comprises an installed portion and a naturally occurring portion.

6804. The method of claim 6780, further comprising:

hydraulically isolating the treatment area from a surrounding portion of the formation; and

maintaining a fluid pressure within the treatment area at a pressure greater than about a fluid pressure within the surrounding portion of the formation.

6805. The method of claim 6780, wherein at least a section of the barrier comprises an impermeable section of the formation.

6806. The method of claim 6780, wherein the barrier comprises a self-sealing portion.

6807. The method of claim 6780, wherein the one or more heat sources are positioned at a distance greater than about 5 m from the barrier.

6808. The method of claim 6780, wherein at least one of the one or more heat sources is positioned at a distance less than about 1.5 m from the barrier.

6809. The method of claim 6780, wherein at least a portion of the barrier comprises a low temperature zone, and further comprising lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water.

6810. The method of claim 6780, wherein the barrier comprises a barrier well and further comprising positioning at least a portion of the barrier well below a water table of the formation.

6811. The method of claim 6780, wherein the treatment area comprises a first treatment area and a second treatment area, and further comprising:

treating the first treatment area using a first treatment process; and

treating the second treatment area using a second treatment process.

6812. A method of treating an oil shale formation in situ, comprising:

providing a refrigerant to a plurality of barrier wells placed in a portion of the formation;

establishing a frozen barrier zone to inhibit migration of fluids into or out of a treatment area;

providing heat from one or more heat sources to the treatment area;

allowing the heat to transfer from the treatment area to a selected section; and

producing fluids from the formation.

6813. The method of claim 6812, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.

6814. The method of claim 6812, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6815. The method of claim 6812, wherein at least one of the one or more of the heat sources comprises a heater.

6816. The method of claim 6812, further comprising controlling a fluid pressure within the treatment area;

6817. The method of claim 6812, wherein the frozen barrier zone is proximate the treatment area of the formation

6818. The method of claim 6812, further comprising hydraulically isolating the treatment area from a surrounding portion of the formation.

6819. The method of claim 6812, further comprising thermally isolating the treatment area from a surrounding portion of the formation

6821. The method of claim 6812, further comprising removing liquid water from at least a portion of the treatment area.

6822. The method of claim 6812, wherein the treatment area is below a water table of the formation.

6823. The method of claim 6812, wherein at least one barrier well of the plurality of barrier wells comprises a corrosion inhibitor.

6824. The method of claim 6812, wherein heating is initiated after formation of the frozen barrier zone.

6825. The method of claim 6812, wherein the refrigerant comprises one or more hydrocarbons.

6826. The method of claim 6812, wherein the refrigerant comprises propane.

6827. The method of claim 6812, wherein the refrigerant comprises isobutane.

6828. The method of claim 6812, wherein the refrigerant comprises cyclopentane.

6829. The method of claim 6812, wherein the refrigerant comprises ammonia.

6830. The method of claim 6812, wherein the refrigerant comprises an aqueous salt mixture.

6831. The method of claim 6812, wherein the refrigerant comprises an organic acid salt.

6832. The method of claim 6812, wherein the refrigerant comprises a salt of an organic acid.

6833. The method of claim 6812, wherein the refrigerant comprises an organic acid.

6834. The method of claim 6812, wherein the refrigerant has a freezing point of less than about minus 60 degrees Celsius.

6835. The method of claim 6812, wherein the refrigerant comprises calcium chloride.

6836. The method of claim 6812, wherein the refrigerant comprises lithium chloride.

6837. The method of claim 6812, wherein the refrigerant comprises liquid nitrogen.

6838. The method of claim 6812, wherein the refrigerant is provided at a temperature of less than about minus 50 degrees Celsius.

6839. The method of claim 6812, wherein the refrigerant comprises carbon dioxide.

6840. The method of claim 6812, wherein at least one of the plurality of barrier wells is located along strike of a hydrocarbon containing portion of the formation.

6841. The method of claim 6812, wherein at least one of the plurality of barrier wells is located along dip of a hydrocarbon containing portion of the formation.

6842. The method of claim 6812, wherein the one or more heat sources are placed greater than about 5 m from a frozen barrier zone.

6843. The method of claim 6812, wherein at least one of the one or more heat sources is positioned less than about 1.5 m from a frozen barrier zone.

6844. The method of claim 6812, wherein a distance between a center of at least one barrier well and a center of at least one adjacent barrier well is greater than about 2 m.

6845. The method of claim 6812, further comprising desorbing methane from the formation.

6846. The method of claim 6812, further comprising pyrolyzing at least some hydrocarbon containing material within the treatment area.

6847. The method of claim 6812, further comprising producing synthesis gas from at least a portion of the formation.

6848. The method of claim 6812, further comprising:

providing a solvent to the treatment area such that the solvent dissolves a component in the treatment area; and

removing the solvent from the treatment area, wherein the removed solvent comprises the component.

6849. The method of claim 6812, further comprising sequestering a compound in at least a portion of the treatment area.

6850. The method of claim 6812, further comprising thawing at least a portion of the frozen barrier zone;

and wherein material in a thawed barrier zone area is substantially unaltered by the application of heat.

6851. The method of claim 6812, wherein a location of the frozen barrier zone has been selected using a flow rate of groundwater and wherein the selected groundwater flow rate is less than about 50 m/day.

6852. The method of claim 6812, further comprising providing water to the frozen barrier zone.

6853. The method of claim 6812, further comprising positioning one or more monitoring wells outside the frozen barrier zone, and then providing a tracer to the treatment area, and then monitoring for movement of the tracer at the monitoring wells.

6854. The method of claim 6812, further comprising:

positioning one or more monitoring wells outside the frozen barrier zone;

then providing an acoustic pulse to the treatment area; and

then monitoring for the acoustic pulse at the monitoring wells.

6855. The method of claim 6812, wherein a fluid pressure within the treatment area can be controlled at fluid pressures different from a fluid pressure that exists in a surrounding portion of the formation.

6856. The method of claim 6812, wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist in a surrounding portion of the formation.

6857. The method of claim 6812, further comprising controlling compositions of fluids produced from the formation by controlling the fluid pressure within an area at least partially bounded by the frozen barrier zone.

6858. The method of claim 6812, wherein a portion of at least one of the plurality of barrier wells is positioned below a water table of the formation.

6820. The method of 6812, further comprising maintaining the fluid pressure above a hydrostatic pressure of the formation

6859. A method of treating an oil shale formation comprising:

providing a refrigerant to one or more barrier wells placed in a portion of the formation;

establishing a low temperature zone proximate a treatment area of the formation;

providing heat from one or more heat sources to a treatment area of the formation;

allowing the heat to transfer from the treatment area to a selected section of the formation; and

producing fluids from the formation.

6860. The method of claim 6859, further comprising forming a frozen barrier zone within the low temperature zone, wherein the frozen barrier zone hydraulically isolates the treatment area from a surrounding portion of the formation.

6861. The method of claim 6859, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled at different fluid pressures from the fluid pressures that exist outside of the frozen barrier zone.

6862. The method of claim 6859, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist outside of the frozen barrier zone.

6863. The method of claim 6859, further comprising forming a frozen barrier zone within the low temperature zone, and wherein fluid pressure within an area at least partially bounded by the frozen barrier zone can be controlled higher than, or lower than, hydrostatic pressures that exist outside of the frozen barrier zone, and further comprising controlling compositions of fluids produced from the formation by controlling the fluid pressure within the area at least partially bounded by the frozen barrier zone.

6864. The method of claim 6859, further comprising thawing at least a portion of the low temperature zone, wherein material within the thawed portion is substantially unaltered by the application of heat such that the structural integrity of the oil shale formation is substantially maintained.

6865. The method of claim 6859, wherein an inner boundary of the low temperature zone is determined by monitoring a pressure wave using one or more piezometers.

6866. The method of claim 6859, further comprising controlling a fluid pressure within the treatment area at a pressure less than about a formation fracture pressure.

6867. The method of claim 6859, further comprising positioning one or more monitoring wells outside the frozen barrier zone, and then providing an acoustic pulse to the treatment area, and then monitoring for the acoustic pulse at the monitoring wells.

6868. The method of claim 6859, further comprising positioning a segment of at least one of the one or more barrier wells below a water table of the formation.

6869. The method of claim 6859, further comprising positioning the one or more barrier wells to establish a continuous low temperature zone.

6870. The method of claim 6859, wherein the refrigerant comprises one or more hydrocarbons.

6871. The method of claim 6859, wherein the refrigerant comprises propane.

6872. The method of claim 6859, wherein the refrigerant comprises isobutane.

6873. The method of claim 6859, wherein the refrigerant comprises cyclopentane.

6874. The method of claim 6859, wherein the refrigerant comprises ammonia.

6875. The method of claim 6859, wherein the refrigerant comprises an aqueous salt mixture.

6876. The method of claim 6859, wherein the refrigerant comprises an organic acid salt.

6877. The method of claim 6859, wherein the refrigerant comprises a salt of an organic acid.

6878. The method of claim 6859, wherein the refrigerant comprises an organic acid.

6879. The method of claim 6859, wherein the refrigerant has a freezing point of less than about minus 60 degrees Celsius.

6880. The method of claim 6859, wherein the refrigerant is provided at a temperature of less than about minus 50 degrees Celsius.

6881. The method of claim 6859, wherein the refrigerant is provided at a temperature of less than about minus 25 degrees Celsius.

6882. The method of claim 6859, wherein the refrigerant comprises carbon dioxide.

6883. The method of claim 6859, further comprising:

cooling at least a portion of the refrigerant in an absorption refrigeration unit; and

providing a thermal energy source to the absorption refrigeration unit.

6884. The method of claim 6859, wherein the thermal energy source comprises water.

6885. The method of claim 6859, wherein the thermal energy source comprises steam.

6886. The method of claim 6859, wherein the thermal energy source comprises at least a portion of the produced fluids.

6887. The method of claim 6859, wherein the thermal energy source comprises exhaust gas.

6888. A method of treating an oil shale formation, comprising:

inhibiting migration of fluids into or out of a treatment area of the formation from a surrounding portion of the formation;

providing heat from one or more heat sources to at least a portion of the treatment area;

allowing the heat to transfer from at least the portion to a selected section of the formation; and

producing fluids from the formation.

6889. The method of claim 6888, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.

6890. The method of claim 6888, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6891. The method of claim 6888, wherein at least one of the one or more of the heat sources comprises a heater.

6892. The method of claim 6888, further comprising providing a barrier to at least a portion of the formation.

6893. The method of claim 6892, wherein at least section of the barrier comprises one or more sulfur wells.

6894. The method of claim 6892, wherein at least section of the barrier comprises one or more pumping wells.

6895. The method of claim 6892, wherein at least section of the barrier comprises one or more injection wells and one or more pumping wells.

6896. The method of claim 6892, wherein at least a section of the barrier is naturally occurring.

6897. The method of claim 6888, further comprises establishing a barrier in at least a portion of the formation, and wherein heat is provided after at least a portion of the barrier has been established.

6898. The method of claim 6888, further comprising establishing a barrier in at least a portion of the formation, and wherein heat is provided while at least a portion of the barrier is being established.

6899. The method of claim 6888, further comprising providing a barrier to at least a portion of the formation, and wherein heat is provided before the barrier is established.

6900. The method of claim 6888, further comprising controlling an amount of fluid removed from the treatment area

6901. The method of claim 6888, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a low temperature zone to at least a portion of the formation.

6902. The method of claim 6888, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a frozen barrier zone to at least a portion of the formation.

6903. The method of claim 6888, wherein isolating a treatment area from a surrounding portion of the formation comprises providing a grout wall.

6904. The method of claim 6888, further comprising inhibiting flow of water into or out of at least a portion of a treatment area.

6905. The method of claim 6888, further comprising:

providing a material to the treatment area; and

storing at least some of the material within the treatment area.

6906. A method of treating an oil shale formation, comprising:

providing a barrier to a portion of the formation, wherein the portion has previously undergone an in situ conversion process; and

inhibiting migration of fluids into and out of the converted portion to a surrounding portion of the formation.

6907. The method of claim 6906, wherein the barrier comprises a frozen barrier zone.

6908. The method of claim 6906, wherein the barrier comprises a low temperature zone.

6909. The method of claim 6906, wherein the barrier comprises a sealing mineral phase.

6910. The method of claim 6906, wherein the barrier comprises a sulfur barrier.

6911. The method of claim 6906, wherein the contaminant comprises a metal.

6912. The method of claim 6906, wherein the contaminant comprises organic residue.

6913. A method of treating an oil shale formation, comprising:

introducing a first fluid into at least a portion of the formation, wherein the portion has previously undergone an in situ conversion process;

producing a mixture of the first fluid and a second fluid from the formation; and

providing at least a portion of the mixture to an energy producing unit.

6914. The method of claim 6913, wherein the first fluid is selected to recover heat from the formation.

6915. The method of claim 6913, wherein the first fluid is selected to recover heavy compounds from the formation.

6916. The method of claim 6913, wherein the first fluid is selected to recover hydrocarbons from the formation.

6917. The method of claim 6913, wherein the mixture comprises an oxidizable heat recovery fluid.

6918. The method of claim 6913, wherein producing the mixture remediates the portion of the formation by removing contaminants from the formation in the mixture.

6919. The method of claim 6913, wherein the first fluid comprises a hydrocarbon fluid.

6920. The method of claim 6913, wherein the first fluid comprises methane.

6921. The method of claim 6913, wherein the first fluid comprises ethane.

6922. The method of claim 6913, wherein the first fluid comprises molecular hydrogen.

6923. The method of claim 6913, wherein the energy producing unit comprises a turbine, and generating electricity by passing mixture through the energy producing unit.

6924. The method of claim 6913, further comprising combusting mixture within the energy producing unit.

6925. The method of claim 6913, further comprising inhibiting spread of the mixture from the portion of the formation with a barrier.

6926. A method of treating an oil shale formation, comprising:

providing a first fluid to at least a portion of a treatment area, wherein the treatment area includes one or more components;

producing a fluid from the formation wherein the produced fluid comprises first fluid and at least some of the one or more components; and

wherein the treatment area is obtained by providing heat from heat sources to a portion of an oil shale formation to convert a portion of hydrocarbons to desired products and removing a portion of the desired hydrocarbons from the formation.

6927. The method of claim 6926, wherein the first fluid comprises water.

6928. The method of claim 6926, wherein the first fluid comprises carbon dioxide.

6929. The method of claim 6926, wherein the first fluid comprises steam.

6930. The method of claim 6926, wherein the first fluid comprises air.

6931. The method of claim 6926, wherein the first fluid comprises a combustible gas.

6932. The method of claim 6926, wherein the first fluid comprises hydrocarbons.

6933. The method of claim 6926, wherein the first fluid comprises methane.

6934. The method of claim 6926, wherein the first fluid comprises ethane.

6935. The method of claim 6926, wherein the first fluid comprises molecular hydrogen.

6936. The method of claim 6926, wherein the first fluid comprises propane.

6937. The method of claim 6926, further comprising reacting a portion of the contaminants with the first fluid.

6938. The method of claim 6926, further comprising providing at least a portion of the produced fluid to an energy generating unit to generate electricity.

6939. The method of claim 6926, further comprising providing at least a portion of the produced fluid to a combustor.

6940. The method of claim 6926, where in a frozen barrier defines at least a segment of a barrier within the formation, allowing a portion of the frozen barrier to thaw prior to providing the first fluid to the treatment area, and providing at least some of the first fluid into the thawed portion of the barrier.

6941. The method of claim 6926, wherein a volume of first fluid provided to the treatment area is greater than about one pore volume of the treatment area.

6942. The method of claim 6926, further comprising separating contaminants from the first fluid.

6943. A method of recovering thermal energy from a heated oil shale formation, comprising:

injecting a heat recovery fluid into a heated portion of the formation;

allowing heat from the portion of the formation to transfer to the heat recovery fluid; and

producing fluids from the formation.

6944. The method of claim 6943, wherein the heat recovery fluid comprises water.

6945. The method of claim 6943, wherein the heat recovery fluid comprises saline water.

6946. The method of claim 6943, wherein the heat recovery fluid comprises non-potable water.

6947. The method of claim 6943, wherein the heat recovery fluid comprises alkaline water.

6948. The method of claim 6943, wherein the heat recovery fluid comprises hydrocarbons.

6949. The method of claim 6943, wherein the heat recovery fluid comprises an inert gas.

6950. The method of claim 6943, wherein the heat recovery fluid comprises carbon dioxide.

6951. The method of claim 6943, wherein the heat recovery fluid comprises a product stream produced by an in situ conversion process.

6952. The method of claim 6943, further comprising vaporizing at least some of the heat recovery fluid.

6953. The method of claim 6943, wherein an average temperature of the portion of the post treatment formation prior to injection of heat recovery fluid is greater than about 300°

C.

6954. The method of claim 6943, further comprising providing the heat recovery fluid to the formation through a heater well.

6955. The method of claim 6943, wherein fluids are produced from one or more production wells in the formation.

6956. The method of claim 6943, further comprising providing at least some of the produced fluids to a treatment process in a section of the formation.

6957. The method of claim 6943, further comprising recovering at least some of the heat from the produced fluids.

6958. The method of claim 6943, further comprising providing at least some of the produced fluids to a power generating unit.

6959. The method of claim 6943, further comprising providing at least some of the produced fluids to a heat exchange mechanism.

6960. The method of claim 6943, further comprising providing at least some of the produced fluids to a steam cracking unit.

6961. The method of claim 6943, further comprising providing at least some of the produced fluids to a hydrotreating unit.

6962. The method of claim 6943, further comprising providing at least some of the produced fluids to a distillation column.

6963. The method of claim 6943, wherein the heat recovery fluid comprises carbon dioxide, and wherein at least some of the carbon dioxide is adsorbed onto the surface of carbon in the formation.

6964. The method of claim 6943, wherein the heat recovery fluid comprises carbon dioxide, and further comprising:

allowing at least some hydrocarbons within the formation to desorb from the formation; and

producing at least some of the desorbed hydrocarbons from the formation.

6965. The method of claim 6943, further comprising providing at least some of the produced fluids to a treatment process in a section of the formation.

6966. The method of claim 6943, wherein the heat recovery fluid is saline water, and further comprising:

providing carbon dioxide to the portion of the formation; and

precipitating carbonate compounds.

6967. The method of claim 6943, further comprising reducing an average temperature of the formation to a temperature less than about an ambient boiling temperature of water at a post treatment pressure.

6968. The method of claim 6943, wherein the produced fluids comprise low molecular weight hydrocarbons.

6969. The method of claim 6943, wherein the produced fluids comprise hydrocarbons.

6970. The method of claim 6943, wherein the produced fluids comprise heat recovery fluid.

6971. A method of treating an oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling at least one condition within the selected section;

producing a mixture from the formation; and

wherein at least the one condition is controlled such that the mixture comprises a carbon dioxide emission level less than about a selected carbon dioxide emission level.

6972. The method of claim 6971, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

6973. The method of claim 6971, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6974. The method of claim 6971, wherein at least one of the one or more of the heat sources comprises a heater.

6975. The method of claim 6971, wherein the selected carbon dioxide emission level is less than about 5.6×

10<sup>−

8</sup> kg CO₂ produced for every Joule of energy.

6976. The method of claim 6971, wherein the selected carbon dioxide emission level is less than about 1.6×

10<sup>−

8</sup> kg CO₂ produced for every Joule of energy.

6977. The method of claim 6971, wherein the selected carbon dioxide emission level is less than about 1.6×

10<sup>−

10</sup> kg CO₂ produced for every Joule of energy.

6978. The method of claim 6971, further comprising blending the mixture with a fluid to form a blended product comprising a carbon dioxide emission level less than about the selected baseline carbon dioxide emission level.

6979. The method of claim 6971, wherein controlling conditions within a selected section comprises controlling a pressure within the selected section.

6980. The method of claim 6971, wherein controlling conditions within a selected section comprises controlling an average temperature within the selected section.

6981. The method of claim 6971, wherein controlling conditions within a selected section comprises controlling an average heating rate within the selected section.

6982. A method for producing molecular hydrogen from an oil shale formation, comprising:

providing heat from one or more heat sources to at least one portion of the formation such that carbon dioxide production is minimized;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture comprising molecular hydrogen from the formation; and

controlling the heat from the one or more heat sources to enhance production of molecular hydrogen.

6983. The method of claim 6982, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

6984. The method of claim 6982, wherein at least one of the one or more of the heat sources comprises a heater.

6985. The method of claim 6982, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

6986. The method of claim 6982, wherein controlling the heat comprises controlling a temperature proximate the production wellbore at or above a decomposition temperature of methane.

6987. The method of claim 6982, wherein heat is generated by oxidizing molecular hydrogen in at least one heat source.

6988. The method of claim 6982, wherein heat is generated by electricity produced from wind power.

6989. The method of claim 6982, wherein heat is generated from electrical power.

6990. The method of claim 6982, wherein the heat sources form an array of heat sources.

6991. The method of claim 6982, further comprising heating at least a portion of the selected section of the formation to greater than about 600°

C.

6992. The method of claim 6982, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 600°

C.

6993. The method of claim 6982, wherein the produced mixture is produced from a production wellbore, and further comprising heating at least a portion of the formation with a heater proximate the production wellbore.

6994. The method of claim 6982, further comprising recycling at least a portion of the produced molecular hydrogen into the formation.

6995. The method of claim 6982, wherein the produced mixture comprises methane, and further comprising oxidizing at least a portion of the methane to provide heat to the formation.

6996. The method of claim 6982, wherein controlling the heat comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

6997. The method of claim 6982, wherein the one or more heat sources comprise one or more electrical heaters powered by a fuel cell, and wherein at least a portion of the molecular hydrogen in the produced mixture is used in the fuel cell.

6998. The method of claim 6982, further comprising controlling a pressure within at least a majority of the selected section of the formation.

6999. The method of claim 6982, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3°

C. per day during pyrolysis.

7000. The method of claim 6982, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

7001. The method of claim 6982, wherein at least 50% by volume of the produced mixture comprises molecular hydrogen.

7002. The method of claim 6982, wherein less than about 3.3×

10<sup>−

8</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7003. The method of claim 6982, wherein less than about 1.6×

10<sup>−

10</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7004. The method of claim 6982, wherein less than about 3.3×

10<sup>−

10</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7005. The method of claim 6982, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 500°

C.

7006. The method of claim 6982, wherein the produced mixture comprises methane and molecular hydrogen, and further comprising:

separating at least a portion of the molecular hydrogen from the produced mixture; and

providing at least a portion of the separated mixture to at least one of the one or more heat sources for use as fuel.

7007. The method of claim 6982, wherein the produced mixture comprises methane and molecular hydrogen, and further comprising:

separating at least a portion of the molecular hydrogen from the produced mixture; and

providing at least some of the molecular hydrogen to a fuel cell to generate electricity.

7008. A method for producing methane from an oil shale formation in situ while minimizing production of CO₂, comprising:

providing heat from one or more heat sources to at least one portion of the formation such that CO₂ production is minimized;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture comprising methane from the formation; and

controlling the heat from the one or more heat sources to enhance production of methane.

7009. The method of claim 7008, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.

7010. The method of claim 7008, wherein at least one of the one or more of the heat sources comprises a heater.

7011. The method of claim 7008, wherein controlling the heat comprises controlling a temperature proximate the production wellbore at or above a decomposition temperature of ethane.

7012. The method of claim 7008, wherein heat is generated by oxidizing methane in at least one heat source.

7013. The method of claim 7008, wherein heat is generated by electricity produced from wind power.

7014. The method of claim 7008, wherein heat is generated from electrical power.

7015. The method of claim 7008, wherein the heat sources form an array of heat sources.

7016. The method of claim 7008, further comprising heating at least a portion of the selected section of the formation to greater than about 400°

C.

7017. The method of claim 7008, wherein the produced mixture is produced from a production wellbore, and further comprising controlling the heat from one or more heat sources such that the temperature in the formation proximate the production wellbore is at least about 400°

C.

7018. The method of claim 7008, wherein the produced mixture is produced from a production wellbore, and further comprising heating at least a portion of the formation with a heater proximate the production wellbore.

7019. The method of claim 7008, further comprising recycling at least a portion of the produced methane into the formation.

7020. The method of claim 7008, wherein the produced mixture comprises methane, and further comprising oxidizing at least a portion of the methane to provide heat to the formation.

7021. The method of claim 7008, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

7022. The method of claim 7008, wherein controlling the heat comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

7023. The method of claim 7008, wherein the one or more heat sources comprise one or more electrical heaters powered by a fuel cell, and wherein at least a portion of the molecular hydrogen in the produced mixture is used in the fuel cell.

7024. The method of claim 7008, further comprising controlling a pressure within at least a majority of the selected section of the formation.

7025. The method of claim 7008, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3°

C. per day during pyrolysis.

7026. The method of claim 7008, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

7027. The method of claim 7008, wherein less than about 8.4×

10<sup>−

8</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7028. The method of claim 7008, wherein less than about 7.4×

10<sup>−

8</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7029. The method of claim 7008, wherein less than about 5.6×

10<sup>−

8</sup> kg CO₂ is produced for every Joule of energy in the produced mixture.

7030. A method for upgrading hydrocarbons in an oil shale formation, comprising:

providing heat from one or more heat sources to a portion of the formation;

allowing the heat to transfer from the first portion to a selected section of the formation;

providing hydrocarbons to the selected section; and

producing a mixture from the formation, wherein the mixture comprises hydrocarbons that were provided to the selected section and upgraded in the formation.

7031. The method of claim 7030, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7032. The method of claim 7030, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7033. The method of claim 7030, wherein at least one of the one or more of the heat sources comprises a heater.

7034. The method of claim 7030, wherein the provided hydrocarbons comprise heavy hydrocarbons.

7035. The method of claim 7030, wherein the provided hydrocarbons comprise naphtha.

7036. The method of claim 7030, wherein the provided hydrocarbons comprise asphaltenes.

7037. The method of claim 7030, wherein the provided hydrocarbons comprise crude oil.

7038. The method of claim 7030, wherein the provided hydrocarbons comprise surface mined tar from relatively permeable formations.

7039. The method of claim 7030 wherein the provided hydrocarbons comprise an emulsion produced from a relatively permeable formation, and further comprising providing the produced emulsion to the first portion after a temperature in the selected section is greater than about a pyrolysis temperature.

7040. The method of claim 7030, further comprising providing steam to the selected section.

7041. The method of claim 7030, further comprising:

producing formation fluids from the formation;

separating the produced formation fluids into one or more components; and

wherein the provided hydrocarbons comprise at least one of the one or more components.

7042. The method of claim 7030, further comprising:

providing steam to the selected section, wherein the provided hydrocarbons are mixed with the steam; and

controlling an amount of steam such that a residence time of the provided hydrocarbons within the selected section is controlled.

7043. The method of claim 7030, wherein the produced mixture comprises upgraded hydrocarbons, and further comprising controlling a residence time of the provided hydrocarbons within the selected section to control a molecular weight distribution within the upgraded hydrocarbons.

7044. The method of claim 7030, wherein the produced mixture comprises upgraded hydrocarbons, and further comprising controlling a residence time of the provided hydrocarbons in the selected section to control an API gravity of the upgraded hydrocarbons.

7045. The method of claim 7030, further comprising steam cracking in at least a portion of the selected section.

7046. The method of claim 7030, wherein the provided hydrocarbons are produced from a second portion of the formation.

7047. The method of claim 7030, further comprising allowing some of the provided hydrocarbons to crack in the formation to generate upgraded hydrocarbons.

7048. The method of claim 7030, further comprising controlling a temperature of the first portion of the formation by controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

7049. The method of claim 7030, further comprising controlling a pressure within at least a majority of the selected section of the formation.

7050. The method of claim 7030, wherein a temperature in the first portion is greater than about a pyrolysis temperature.

7051. The method of claim 7030, further comprising:

controlling the heat such that a temperature of the first portion is greater than about a pyrolysis temperature of hydrocarbons; and

producing at least some of the provided hydrocarbons from the first portion of the formation.

7052. The method of claim 7030, further comprising producing at least some of the provided hydrocarbons from a second portion of the formation.

7053. The method of claim 7030, further comprising:

controlling the heat such that a temperature of a second portion is less than about a pyrolysis temperature of hydrocarbons; and

producing at least some of the provided hydrocarbons from the second portion of the formation.

7054. The method of claim 7030, further comprising producing at least some of the provided hydrocarbons from a second portion of the formation and wherein a temperature of the second portion is about an ambient temperature of the formation.

7055. The method of claim 7030, wherein the upgraded hydrocarbons are produced from a production well and wherein the heat is controlled such that the upgraded hydrocarbons can be produced from the formation as a vapor.

7056. A method for producing methane from an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing hydrocarbon fluids to at least the selected section of the formation; and

producing mixture comprising methane from the formation.

7057. The method of claim 7056, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7058. The method of claim 7056, wherein at least one of the one or more of the heat sources comprises a heater.

7059. The method of claim 7056, further comprising controlling heat from at least one of the heat sources to enhance production of methane from the hydrocarbon fluids.

7060. The method of claim 7056, further comprising controlling a temperature within at least a selected section in a range to from greater than about 400°

C. to less than about 600°

C.

7061. The method of claim 7056, further comprising cooling the mixture to inhibit further reaction of the methane.

7062. The method of claim 7056, further comprising controlling at least some condition in the formation to enhance production of methane.

7063. The method of claim 7056, further comprising adding water to the formation.

7064. The method of claim 7056, further comprising separating at least a portion of the methane from the mixture and recycling at least some of the separated mixture to the formation.

7065. The method of claim 7056, further comprising cracking the hydrocarbon fluids to form methane.

7066. The method of claim 7056, wherein the mixture is produced from the formation through a production well, and wherein the heat is controlled such that the mixture can be produced from the formation as a vapor.

7067. The method of claim 7056, wherein the mixture is produced from the formation through a production well, and further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

7068. The method of claim 7056, wherein the mixture is produced from the formation through a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture.

7069. A method for hydrotreating a fluid in a heated formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing a fluid to the selected section;

controlling a H₂ partial pressure in the selected section of the formation;

hydrotreating at least some of the fluid in the selected section; and

producing a mixture comprising hydrotreated fluids from the formation.

7070. The method of claim 7069, wherein the mixture is produced from the formation when a partial pressure of hydrogen in the selected section is at least about 0.5 bars absolute.

7071. The method of claim 7069, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.

7072. The method of claim 7069, wherein at least one of the one or more of the heat sources comprises a heater.

7073. The method of claim 7069, further comprising providing hydrogen to the selected section of the formation.

7074. The method of claim 7069, further comprising controlling the heat such that a temperature within the selected section is in a range from about 200°

C. to about 450°

C.

7075. The method of claim 7069, wherein the provided fluid comprises an olefin.

7076. The method of claim 7069, wherein the provided fluid comprises pitch.

7077. The method of claim 7069, wherein the provided fluid comprises oxygenated compounds.

7078. The method of claim 7069, wherein the provided fluid comprises sulfur containing compounds.

7079. The method of claim 7069, wherein the provided fluid comprises nitrogen containing compounds.

7080. The method of claim 7069, wherein the provided fluid comprises crude oil.

7081. The method of claim 7069, wherein the provided fluid comprises synthetic crude oil.

7082. The method of claim 7069, wherein the produced mixture comprises a hydrocarbon mixture.

7083. The method of claim 7069, wherein the produced mixture comprises less than about 1% by weight ammonia.

7084. The method of claim 7069, wherein the produced mixture comprises less than about 1% by weight hydrogen sulfide.

7085. The method of claim 7069, wherein the produced mixture comprises less than about 1% oxygenated compounds.

7086. The method of claim 7069, further comprising producing the mixture from the formation through a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

7087. A method for producing hydrocarbons from a heated formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that at least some of the selected section comprises a temperature profile;

providing a hydrocarbon mixture to the selected section;

separating the hydrocarbon mixture into one or more mixtures of components; and

producing the one or more mixtures of components from one or more production wells.

7088. The method of claim 7087, wherein the heat provided from at least one of the one or more heat source is transferred to at least a portion of the formation substantially by conduction.

7089. The method of claim 7087, wherein the one or more of the heat sources comprise heaters.

7090. The method of claim 7087, wherein at least one of the one or more mixtures is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7091. The method of claim 7087, further comprising controlling a pressure within at least a majority of the selected section.

7092. The method of claim 7087, wherein the temperature profile extends horizontally through the formation.

7093. The method of claim 7087, wherein the temperature profile extends vertically through the formation.

7094. The method of claim 7087, wherein the selected section comprises a spent formation.

7095. The method of claim 7087, wherein the production well comprises a plurality of production wells placed at various distances from at least one of the one or more heat sources along the temperature gradient zone.

7096. The method of claim 7087, wherein the production well comprises a first production well and a second production well, further comprising:

positioning the first production well at a first distance from a heat source of the one or more heat sources;

positioning the second production well at a second distance from the heat source of the one or more heat sources;

producing a first component of the one or more portions from the first production well; and

producing a second component of the one or more portions from the second production well.

7097. The method of claim 7087, further comprising heating a wellbore of the production well to inhibit condensation of at least the one component within the wellbore.

7098. The method of claim 7087, wherein the one or more components comprise hydrocarbons.

7099. The method of claim 7087, wherein separating the one or more components further comprises:

producing a low molecular weight component of the one or more components from the formation;

allowing a high molecular weight component of the one or more components to remain within the formation;

providing additional heat to the formation; and

producing at least some of the high molecular weight component.

7100. The method of claim 7087, further comprising producing at least the one component from the formation through a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

7101. A method of utilizing heat of a heated formation, comprising:

placing a conduit in the formation,;

allowing heat from the formation to transfer to at least a portion of the conduit;

generating a region of reaction in the conduit;

allowing a material to flow through the region of reaction;

reacting at least some of the material in the region of reaction; and

producing a mixture from the conduit.

7102. The method of claim 7101, wherein a conduit input is located separately from a conduit output

7103. The method of claim 7101, wherein the conduit is configured to inhibit contact between the material and the formation.

7104. The method of claim 7101, wherein the conduit comprises a u-shaped conduit, and further comprising placing the u-shaped conduit within a heater well in the heated formation.

7105. The method of claim 7101, wherein the material comprises a first hydrocarbon and wherein the first hydrocarbon reacts to form a second hydrocarbon.

7106. The method of claim 7101, wherein the material comprises water.

7107. The method of claim 7101, wherein the produced mixture comprises hydrocarbons.

7108. A method for storing fluids within an oil shale formation, comprising:

providing a barrier to a portion of the formation to form an in situ storage area, wherein at least a portion of the in situ storage area has previously undergone an in situ conversion process, and wherein migration of fluids into or out of the storage area is inhibited;

providing a material to the in situ storage area;

storing at least some of the provided fluids within the in situ storage area; and

wherein one or more conditions of the in situ storage area inhibits reaction within the material.

7109. The method of claim 7108, further comprising producing at least some of the stored material from the in situ storage area.

7110. The method of claim 7108, further comprising producing at least some of the stored material from the in situ storage area as a liquid.

7111. The method of claim 7108, further comprising producing at least some of the stored material from the in situ storage area as a gas.

7112. The method of claim 7108, wherein the stored material is a solid, and further comprising:

providing a solvent to the in situ storage area;

allowing at least a portion of the stored material to dissolve; and

producing at least some of the dissolved material from the in situ storage area.

7113. The method of claim 7108, wherein the material comprises inorganic compounds.

7114. The method of claim 7108, wherein the material comprises organic compounds.

7115. The method of claim 7108, wherein the material comprises hydrocarbons.

7116. The method of claim 7108, wherein the material comprises formation fluids

7117. The method of claim 7108, wherein the material comprises synthesis gas.

7118. The method of claim 7108, wherein the material comprises a solid.

7119. The method of claim 7108, wherein the material comprises a liquid.

7120. The method of claim 7108, wherein the material comprises a gas.

7121. The method of claim 7108, wherein the material comprises natural gas.

7122. The method of claim 7108, wherein the material comprises compressed air.

7123. The method of claim 7108, wherein the material comprises compressed air, and wherein the compressed air is used as a supplement for electrical power generation.

7124. The method of claim 7108, further comprising:

producing at least some of the material from the in situ treatment area through a production well; and

heating at least a portion of a wellbore of the production well to inhibit condensation of the material within the wellbore.

7125. The method of claim 7108, wherein the in situ conversion process comprises pyrolysis.

7126. The method of claim 7108, wherein the in situ conversion process comprises synthesis gas generation.

7127. The method of claim 7108, wherein the in situ conversion process comprises solution mining.

7128. A method of filtering water within an oil shale formation comprising:

providing water to at least a portion of the formation, wherein the portion has previously undergone an in situ conversion process, and wherein the water comprises one or more components;

removing at least one of the one or more components from the provided water; and

producing at least some of the water from the formation.

7129. The method of claim 7128, wherein at least one of the one or more components comprises a dissolved cation, and further comprising:

converting at least some of the provided water to steam;

allowing at least some of the dissolved cation to remain in the portion of the formation; and

producing at least a portion of the steam from the formation.

7130. The method of claim 7128, wherein the portion of the formation is above the boiling point temperature of the provided water at a pressure of the portion, wherein at least one of the one or more components comprises mineral cations, and wherein the provided water is converted to steam such that the mineral cations are deposited within the formation.

7131. The method of claim 7128 further comprising converting at least a portion of the provided water into steam and wherein at least one of the one or more components is separated from the water as the provided water is converted into steam.

7132. The method of claim 7128, wherein a temperature of the portion of the formation is greater than about 90°

C., and further comprising sterilizing at least some of the provided water within the portion of the formation.

7133. The method of claim 7128, wherein a temperature within the portion is less than about a boiling temperature of the provided water at a fluid pressure of the portion.

7134. The method of claim 7128, further comprising remediating at least the one portion of the formation.

7135. The method of claim 7128, wherein the one or more components comprise cations.

7136. The method of claim 7128, wherein the one or more components comprise calcium.

7137. The method of claim 7128, wherein the one or more components comprise magnesium.

7138. The method of claim 7128, wherein the one or more components comprise a microorganism.

7139. The method of claim 7128, wherein the converted portion of the formation further comprises a pore size such that at least one of the one or more components is removed from the provided water.

7140. The method of claim 7128, wherein the converted portion of the formation adsorbs at least one of the one or more components in the provided water.

7141. The method of claim 7128, wherein the provided water comprises formation water.

7142. The method of claim 7128, wherein the in situ conversion process comprises pyrolysis.

7143. The method of claim 7128, wherein the in situ conversion process comprises synthesis gas generation.

7144. The method of claim 7128, wherein the in situ conversion process comprises solution mining.

7145. A method for sequestering carbon dioxide in an oil shale formation, comprising:

providing carbon dioxide to a portion of the formation, wherein the portion has previously undergone an in situ conversion process;

providing a fluid to the portion;

allowing at least some of the provided carbon dioxide to contact the fluid in the portion; and

precipitating carbonate compounds.

7146. The method of claim 7145, wherein providing a solution to the portion comprises allowing groundwater to flow into the portion.

7147. The method of claim 7145, wherein the solution comprises one or more dissolved ions.

7148. The method of claim 7145, wherein the solution comprises a solution obtained from a formation aquifer.

7149. The method of claim 7145, wherein the solution comprises a man-made industrial solution.

7150. The method of claim 7145, wherein the solution comprises agricultural run-off.

7151. The method of claim 7145, wherein the solution comprises seawater.

7152. The method of claim 7145, wherein the solution comprises a brine solution.

7153. The method of claim 7145, further comprising controlling a temperature within the portion.

7154. The method of claim 7145, further comprising controlling a pressure within the portion.

7155. The method of claim 7145, further comprising removing at least some of the solution from the formation.

7156. The method of claim 7145, further comprising removing at least some of the solution from the formation and recycling at least some of the removed solution into the formation.

7157. The method of claim 7145, further comprising providing a buffering compound to the solution.

7158. The method of claim 7145, further comprising:

providing the solution to the formation; and

allowing at least some of the solution to migrate through the formation to increase a contact time between the solution and the provided carbon dioxide.

7159. The method of claim 7145, wherein the solution is provided to the formation after carbon dioxide has been provided to the formation.

7160. The method of claim 7145, further comprising providing heat to the portion.

7161. The method of claim 7145, wherein providing carbon dioxide to a portion of the formation comprises providing carbon dioxide to a first location, wherein providing a solution to the portion comprises providing the solution to a second location, and wherein the first location is downdip of the second location.

7162. The method of claim 7145, wherein allowing at least some of the provided carbon dioxide to contact the solution in the portion comprises allowing at least some of the carbon dioxide and at least some of the solution to migrate past each other.

7163. The method of claim 7145, wherein the solution is provided to the formation prior to providing the carbon dioxide, and further comprising providing at least some of the carbon dioxide to a location positioned proximate a lower surface of the portion such that some of the carbon dioxide may migrate up through the portion.

7164. The method of claim 7145, wherein the solution is provided to the formation prior to providing the carbon dioxide, and further comprising allowing at least some carbon dioxide to migrate through the portion.

7165. The method of claim 7145, further comprising:

providing heat to the portion, wherein the portion comprises a temperature greater than about a boiling point of the solution;

vaporizing at least some of the solution;

producing a fluid from the formation.

7166. The method of claim 7145, further comprising decreasing leaching of metals from the formation into groundwater.

7167. A method of treating an oil shale formation, comprising:

injecting a recovery fluid into a portion of the formation;

allowing heat within the recovery fluid, and heat from one or more heat sources, to transfer to a selected section of the formation, wherein the selected section comprises hydrocarbons;

mobilizing at least some of the hydrocarbons within the selected section; and

producing a mixture from the formation.

7168. The method of claim 7167, wherein the portion has been previously produced.

7169. The method of claim 7167, wherein the portion has previously undergone an in situ conversion process.

7170. The method of claim 7167, further comprising upgrading at least some hydrocarbons within the selected section to decrease a viscosity of the hydrocarbons.

7171. The method of claim 7167, wherein the produced mixture comprises hydrocarbons having an average API gravity greater than about 25°

.

7172. The method of claim 7167, further comprising vaporizing at least some of the hydrocarbons within the selected section.

7173. The method of claim 7167, wherein the recovery fluid comprises water.

7174. The method of claim 7167, wherein the recovery fluid comprises hydrocarbons.

7175. The method of claim 7167, wherein the mixture comprises pyrolyzation fluids.

7176. The method of claim 7167, wherein the mixture comprises hydrocarbons.

7177. The method of claim 7167, wherein the mixture is produced from a production well and further comprising controlling a pressure such that a fluid pressure proximate to the production well is less than about a fluid pressure proximate to a location where the fluid is injected.

7178. The method of claim 7167, further comprising:

monitoring a composition of the produced mixture; and

controlling a fluid pressure in at least a portion of the formation to control the composition of the produced mixture.

7179. The method of claim 7167, further comprising pyrolyzing at least some of the hydrocarbons within the selected section of the formation.

7180. The method of claim 7167, wherein the average temperature of the selected section is between about 275°

C. to about 375°

C., and wherein a fluid pressure of the recovery fluid is between about 60 bars to about 220 bars, and wherein the recovery fluid comprises steam.

7181. The method of claim 7167, further comprising controlling pressure within the selected section such that a fluid pressure within the selected section is at least about a hydrostatic pressure of a surrounding portion of the formation.

7182. The method of claim 7167, further comprising controlling pressure within the selected section such that a fluid pressure within the selected section is greater than about a hydrostatic pressure of a surrounding portion of the formation.

7183. The method of claim 7167, wherein a depth of the selected section is between about 300 m to about 400 m.

7184. The method of claim 7167, wherein the mixture comprises pyrolysis products.

7185. The method of claim 7167, further comprising vaporizing at least some of the hydrocarbons within the selected section and wherein the vaporized hydrocarbons comprise hydrocarbons having a carbon number greater than about 1 and a carbon number less than about 4.

7186. The method of claim 7167, further comprising allowing the injected recovery fluid to contact a substantial portion of a volume of the selected section.

7187. The method of claim 7167, wherein the recovery fluid comprises steam, and wherein the pressure of the injected steam is at least about 90 bars, and wherein the temperature of the injected steam is at least about 300°

C.

7188. The method of claim 7167, further comprising upgrading at least a portion of the hydrocarbons within the selected section of the formation such that a viscosity of the portion of the hydrocarbons is decreased.

7189. The method of claim 7167, further comprising separating the recovery fluid from pyrolyzation fluid and distilled hydrocarbons in the formation, and further comprising producing the pyrolyzation fluid and distilled hydrocarbons.

7190. The method of claim 7167, wherein the transfer fluid and vaporized hydrocarbons are separated with membranes.

7191. The method of claim 7167, wherein the selected section comprises a first selected section and a second selected section and further comprising:

mobilizing at least some of the hydrocarbons within the selected first section of the formation;

allowing at least some of the mobilized hydrocarbons to flow from the selected first section of the formation to a selected second section of the formation, and wherein the selected second section comprises hydrocarbons; and

heating at least a portion of the formation using one ore more heat sources;

pyrolyzing at least some of the hydrocarbons within the selected second section of the formation; and

producing a mixture from the formation.

7192. The method of claim 7167, wherein a residence time of the recovery fluid in the formation is greater than about one month and less than about six months.

7193. The method of claim 7167, further comprising:

allowing the recovery fluid to soak in the selected section of the formation for a selected time period; and

producing at least a portion of the recovery fluid from the formation.

7194. A method of treating oil shale formation in situ, comprising:

injecting a recovery fluid into the formation;

providing heat from one or more heat sources to the formation;

allowing the heat to transfer from one or more of the heat sources to a selected section of the formation, wherein the selected section comprises hydrocarbons;

mobilizing at least some of the hydrocarbons; and

producing a mixture from the formation, wherein the produced mixture comprises hydrocarbons having an average API gravity greater than about 25°

.

7195. The method of claim 7194, wherein the heat provided from at least one of the one or more heat sources is transferred to at least a portion of the formation substantially by conduction.

7196. The method of claim 7194, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7197. The method of claim 7194, wherein at least one of the one or more of the heat sources comprises a heater.

7198. The method of claim 7194, further comprising pyrolyzing at least some of the hydrocarbons within selected section.

7199. The method of claim 7194, further comprising pyrolyzing at least some of the mobilized hydrocarbons.

7200. The method of claim 7194, wherein the recovery fluid comprises water.

7201. The method of claim 7194, wherein the recovery fluid comprises hydrocarbons.

7202. The method of claim 7194, wherein the mixture comprises pyrolyzation fluids.

7203. The method of claim 7194, wherein the mixture comprises steam.

7204. The method of claim 7194, wherein a pressure is controlled such that a fluid pressure proximate to one or more of the heat sources is greater than a fluid pressure proximate to a location where the fluid is produced

7205. The method of claim 7194, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

7206. The method of claim 7194, wherein the heat is provided such that an average temperature in the selected section ranges from approximately about 270°

C. to about 375°

C.

7207. The method of claim 7194, further comprising:

monitoring a composition of the produced mixture; and

controlling a pressure in at least a portion of the formation to control the composition of the produced mixture.

7208. The method of claim 7207, wherein the pressure is controlled by a valve proximate to a location where the mixture is produced.

7209. The method of claim 7207, wherein the pressure is controlled such that pressure proximate to one or more of the heat sources is greater than a pressure proximate to a location where the mixture is produced.

7210. The method of claim 7194, wherein a residence time of the recovery fluid in the formation is less than about one month to greater than about six months.

7211. The method of claim 7194, further comprising:

allowing the recovery fluid to soak in the selected section of the formation for a selected time period; and

producing at least a portion of the recovery fluid from the formation.

7212. A method of recovering methane from an oil shale formation, comprising:

providing heat from one or more heat sources to at least one portion of the formation, wherein the portion comprises methane;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing fluids from the formation, wherein the produced fluids comprise methane.

7213. The method of claim 7212, further comprising providing a barrier to at least a segment of the formation.

7214. The method of claim 7212, further comprising:

providing a refrigerant to a plurality of barrier wells to form a low temperature zone around the portion of the formation;

lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water; and

removing water from the portion of the formation.

7215. The method of claim 7212, wherein an average temperature of the selected section is less than about 100°

C.

7216. The method of claim 7212, wherein an average temperature of the selected section is less than about a boiling point of water at an ambient pressure in the formation. The method of claim 7212, wherein an amount of methane produced from the formation is in a range from about 1 m³ of methane per ton of formation to about 30 m³ of methane per ton of formation.

7217. The method of claim 7212, wherein the methane produced from the formation is used as fuel for an in situ treatment of an oil shale formation.

7218. The method of claim 7212, wherein the methane produced from the formation is used to generate power for electrical heater wells.

7219. The method of claim 7212, wherein the methane produced from the formation is used as fuel for gas fired heater wells.

7220. The method of claim 7212, further comprising providing carbon dioxide to the treatment area and allowing at least a portion of the methane to desorb.

7221. The method of claim 7212, wherein the fluids are produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7222. The method of claim 7212, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7223. The method of claim 7212, wherein the one or more of the heat sources comprise heaters.

7224. A method of recovering methane from an oil shale formation, comprising:

providing a barrier to a portion of the formation, wherein the portion comprises methane;

removing the water from the portion; and

producing fluids from the formation, wherein the produced fluids comprise methane.

7225. The method of claim 7224, wherein removing water from the portion comprises pumping at least some water from the formation.

7226. The method of claim 7224, wherein the barrier inhibits migration of fluids into or out of a treatment area of the formation.

7227. The method of claim 7224, further comprising decreasing a fluid pressure within the portion and allowing at least some of the methane to desorb.

7228. The method of claim 7224, further comprising providing carbon dioxide to the portion and allowing at least some of the methane to desorb.

7229. The method of claim 7224, wherein providing a barrier comprises:

providing refrigerant to a plurality of freeze wells to form a low temperature zone around the portion; and

lowering a temperature within the low temperature zone to a temperature less than about a freezing temperature of water.

7230. The method of claim 7224, wherein providing a barrier comprises providing refrigerant to a plurality of freeze wells to form a frozen barrier zone and wherein the frozen barrier zone hydraulically isolates the treatment area from a surrounding portion of the formation.

7231. The method of claim 7224, further comprising:

providing heat from one or more heat sources to at least one portion of the formation; and

allowing the heat to transfer from the one or more heat sources to a selected section of the formation.

7232. The method of claim 7224, wherein an average temperature of the selected section is less than about 100°

C.

7233. The method of claim 7224, wherein an average temperature of the selected section is less than about a boiling point of water at an ambient pressure in the formation.

7234. A method of shutting-in an in situ treatment process in an oil shale formation, comprising:

terminating heating from one or more heat sources providing heat to a portion of the formation;

monitoring a pressure in at least a portion of the formation;

controlling the pressure in the portion of the formation such that the pressure is maintained approximately below a fracturing or breakthrough pressure of the formation.

7235. The method of claim 7234, wherein monitoring the pressure in the formation comprises detecting fractures with passive acoustic monitoring.

7236. The method of claim 7234, wherein controlling the pressure in the portion of the formation comprises:

producing hydrocarbon vapor from the formation when the pressure is greater than approximately the fracturing or breakthrough pressure of the formation; and

allowing produced hydrocarbon vapor to oxidize at a surface of the formation.

7237. The method of claim 7234, wherein controlling the pressure in the portion of the formation comprises:

producing hydrocarbon vapor from the formation when the pressure is greater than approximately the fracturing or breakthrough pressure of the formation; and

storing at least a portion of the produced hydrocarbon vapor.

7238. A method of shutting-in an in situ treatment process in an oil shale formation, comprising:

terminating heating from one or more heat sources providing heat to a portion of the formation;

producing hydrocarbon vapor from the formation; and

injecting at least a portion of the produced hydrocarbon vapor into a portion of a storage formation.

7239. The method of claim 7238, wherein the storage formation comprises a spent formation.

7240. The method of claim 7239, wherein an average temperature of the portion of the spent formation is less than about 100°

C.

7241. The method of claim 7239, wherein a substantial portion of condensable compounds in the injected hydrocarbon vapor condense in the spent formation.

7242. The method of claim 7238, wherein the storage formation comprises a relatively high temperature formation, and further comprising converting a substantial portion of injected hydrocarbons into coke and molecular hydrogen.

7243. The method of claim 7242, wherein the average temperature of the portion of the relatively high temperature formation is greater than about 300°

C.

7244. The method of claim 7242, further comprising:

producing at least a portion of the H₂ from the relatively high temperature formation; and

allowing the produced molecular hydrogen to oxidize at a surface of the relatively high temperature formation.

7245. The method of claim 7238, wherein the storage formation comprises a depleted formation.

7246. The method of claim 7245, wherein the depleted formation comprises an oil field.

7247. The method of claim 7245, wherein the depleted formation comprises a gas field.

7248. The method of claim 7245, wherein the depleted formation comprises a water zone comprising seal and trap integrity.

7249. A method of producing a soluble compound from a soluble compound containing oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of a hydrocarbon containing layer;

producing a mixture comprising hydrocarbons from the formation;

using heat from the formation, heat from the mixture produced from the formation, or a component from the mixture produced from the formation to adjust a quality of a first fluid;

providing the first fluid to a soluble compound containing formation; and

producing a second fluid comprising a soluble compound from the soluble compound containing formation.

7250. The method of claim 7249, further comprising pyrolyzing at least some hydrocarbons in the hydrocarbon containing layer.

7251. The method of claim 7249, further comprising dissolving the soluble compound in the soluble compound containing formation.

7252. The method of claim 7249, wherein the soluble compound comprises a phosphate.

7253. The method of claim 7249, wherein the soluble compound comprises alumina.

7254. The method of claim 7249, wherein the soluble compound comprises a metal.

7255. The method of claim 7249, wherein the soluble compound comprises a carbonate.

7256. The method of claim 7249, further comprising separating at least a portion of the soluble compound from the second fluid.

7257. The method of claim 7249, further comprising separating at least a portion of the soluble compound from the second fluid, and then recycling a portion of the second fluid into the soluble compound containing formation.

7258. The method of claim 7249, wherein heat is provided from the heated formation, or from the mixture produced from the formation, in the form of hot water or steam.

7259. The method of claim 7249, wherein the quality of the first fluid that is adjusted is pH.

7260. The method of claim 7249, wherein the quality of the first fluid that is adjusted is temperature.

7261. The method of claim 7249, further comprising adding a dissolving compound to the first fluid that facilitates dissolution of the soluble compound in the soluble containing formation.

7262. The method of claim 7249, wherein CO₂ produced from the hydrocarbon containing layer is used to adjust acidity of the solution.

7263. The method of claim 7249, wherein the soluble compound containing formation is at a different depth than the portion of the hydrocarbon containing layer.

7264. The method of claim 7249, wherein heat from the portion of the hydrocarbon containing layer migrates and heats at least a portion of the soluble compound containing formation.

7265. The method of claim 7249, wherein the soluble compound containing formation is at a different location than the portion of the hydrocarbon containing layer.

7266. The method of claim 7249, further comprising using openings for providing the heat sources, and further comprising using at least a portion of these openings to provide the first fluid to the soluble compound containing formation.

7267. The method of claim 7249, further comprising providing the solution to the soluble compound containing formation in one or more openings that were previously used to (a) provide heat to the hydrocarbon containing layer, or (b) produce the mixture from the hydrocarbon containing layer.

7268. The method of claim 7249, further comprising providing heat to the hydrocarbon containing layer, or producing the mixture from the hydrocarbon containing layer, using one or more openings that were previously used to provide a solution to a soluble compound containing formation.

7269. The method of claim 7249, further comprising:

separating at least a portion of the soluble compound from the second fluid;

providing heat to at least the portion of the soluble compound; and

wherein the provided heat is generated in part using one or more products of an in situ conversion process.

7270. The method of claim 7249, further comprising producing the second fluid when a partial pressure of hydrogen in the portion of the hydrocarbon containing layer is at least about 0.5 bars absolute.

7271. The method of claim 7249, wherein the heat provided from at least one heat source is transferred to at least a part of the hydrocarbon containing layer substantially by conduction.

7272. The method of claim 7249, wherein one or more of the heat sources comprise heaters.

7273. The method of claim 7249, wherein the soluble compound containing formation comprises nahcolite.

7274. The method of claim 7249, wherein greater than about 10% by weight of the soluble compound containing formation comprises nahcolite.

7275. The method of claim 7249, wherein the soluble compound containing formation comprises dawsonite.

7276. The method of claim 7249, wherein greater than about 2% by weight of the soluble compound containing formation comprises dawsonite.

7277. The method of claim 7249, wherein the first fluid comprises steam.

7278. The method of claim 7249, wherein the first fluid comprises steam, and further comprising providing heat to the soluble compound containing formation by injecting the steam into the formation.

7279. The method of claim 7249, wherein the soluble compound containing formation is heated and then the first fluid is provided to the formation.

7280. A method of treating an oil shale formation in situ, comprising:

providing heat to at least a portion of the formation;

allowing the heat to transfer from at least the portion to a selected section of the formation such that dissociation of carbonate minerals is inhibited;

injecting a first fluid into the selected section;

producing a second fluid from the formation; and

conducting an in situ conversion process in the selected section.

7281. The method of claim 7280, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7282. The method of claim 7280, wherein the heat is provided from at least one heat source, and wherein the heat is transferred to at least the portion of the formation substantially by conduction.

7283. The method of claim 7280, wherein the in situ conversion process comprises:

providing additional heat to a least a portion of the formation;

pyrolyzing at least some hydrocarbons in the portion; and

producing a mixture from the formation.

7284. The method of claim 7280, wherein the selected section comprises nahcolite.

7285. The method of claim 7280, wherein the selected section comprises dawsonite.

7286. The method of claim 7280, wherein the selected section comprises trona.

7287. The method of claim 7280, wherein the selected section comprises gaylussite.

7288. The method of claim 7280, wherein the selected section comprises carbonates.

7289. The method of claim 7280, wherein the selected section comprises carbonate phosphates.

7290. The method of claim 7280, wherein the selected section comprises carbonate chlorides.

7291. The method of claim 7280, wherein the selected section comprises silicates.

7292. The method of claim 7280, wherein the selected section comprises borosilicates.

7293. The method of claim 7280, wherein the selected section comprises halides.

7294. The method of claim 7280, wherein the first fluid comprises a pH greater than about 7.

7295. The method of claim 7280, wherein the first fluid comprises a temperature less than about 110°

C.

7296. The method of claim 7280, wherein the portion has previously undergone an in situ conversion process prior to the injection of the first fluid.

7297. The method of claim 7280, wherein the second fluid comprises hydrocarbons.

7298. The method of claim 7280, wherein the second fluid comprises hydrocarbons, and further comprising:

fragmenting at least some of the portion prior to providing the first fluid;

generating hydrocarbons; and

providing at least some of the second fluid to a surface treatment unit, wherein the second fluid comprises at least some of the generated hydrocarbons.

7299. The method of claim 7280, further comprising removing mass from the selected section in the second fluid.

7300. The method of claim 7280, further comprising removing mass from the selected section in the second fluid such that a permeability of the selected section increases.

7301. The method of claim 7280, further comprising removing mass from the selected section in the second fluid and decreasing a heat transfer time in the selected section.

7302. The method of claim 7280, further comprising controlling the heat such that the selected section has a temperature of above about 120°

C.

7303. The method of claim 7280, wherein the selected section comprises nahcolite, and further comprising controlling the heat such that the selected section has a temperature less than about a dissociation temperature of nahcolite.

7304. The method of claim 7280, wherein the second fluid comprises soda ash, and further comprising removing at least a portion of the soda ash from the second fluid as sodium carbonate.

7305. The method of claim 7280, wherein the in situ conversion process comprises pyrolyzing hydrocarbon containing material in the selected section.

7306. The method of claim 7280, wherein the second fluid comprises nahcolite, and further comprising:

separating at least a portion of the nahcolite from the second fluid;

providing heat to at least some of the separated nahcolite to form a sodium carbonate solution;

providing at least some of the sodium carbonate solution to at least the portion of the formation; and

producing a third fluid comprising alumina from the formation.

7307. The method of claim 7280, further comprising providing a barrier to at least the portion of the formation to inhibit migration of fluids into or out of the portion.

7308. The method of claim 7280, further comprising controlling the heat such that a temperature within the selected section of the portion is less than about 100°

C.

7309. The method of claim 7280, further comprising:

providing additional heat from the one or more heat sources to at least the portion of the formation;

allowing the additional heat to transfer from at least the portion to the selected section of the formation;

pyrolyzing at least some hydrocarbons within the selected section of the formation;

producing a mixture from the formation;

reducing a temperature of the selected section of the formation injecting a third fluid into the selected section; and

producing a fourth fluid from the formation.

7310. The method of claim 7309, wherein the third fluid comprises water.

7311. The method of claim 7309, wherein the third fluid comprises steam.

7312. The method of claim 7309, wherein the fourth fluid comprises a metal.

7313. The method of claim 7309, wherein the fourth fluid comprises a mineral.

7314. The method of claim 7309, wherein the fourth fluid comprises aluminum.

7315. The method of claim 7309, wherein the fourth fluid comprises a metal, and further comprising producing the metal from the second fluid.

7316. The method of claim 7309, further comprising producing a non-hydrocarbon material from the fourth fluid.

7317. The method of claim 7280, wherein the first fluid comprises steam.

7318. The method of claim 7280, wherein the second fluid comprises a metal.

7319. The method of claim 7280, wherein the second fluid comprises a mineral.

7320. The method of claim 7280, wherein the second fluid comprises aluminum.

7321. The method of claim 7280, wherein the second fluid comprises a metal, and further comprising separating the metal from the second fluid.

7322. The method of claim 7280, further comprising producing a non-hydrocarbon material from the second fluid.

7323. The method of claim 7280, wherein greater than about 10% by weight of the selected section comprises nahcolite.

7324. The method of claim 7280, wherein greater than about 2% by weight of the selected section comprises dawsonite.

7325. The method of claim 7280, wherein the provided heat comprises waste heat from another portion of the formation.

7326. The method of claim 7280, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.

7327. The method of claim 7280, further comprising providing heat to the formation by injecting the first fluid into the formation.

7328. The method of claim 7280, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 90°

C.

7329. The method of claim 7280, further comprising controlling a temperature of the selected section while injecting the first fluid, wherein the temperature is less than about a temperature at which nahcolite will dissociate.

7330. The method of claim 7280, wherein a temperature within the selected section is less than about 90°

C. prior to injecting the first fluid to the formation.

7331. The method of claim 7280, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits the flow of water into the formation.

7332. A method of treating an oil shale formation in situ, comprising:

injecting a first fluid into the selected section;

producing a second fluid from the formation;

providing heat from one or more heat sources to at least a portion of the formation, wherein the heat is provided after production of the second fluid has begun;

allowing the heat to transfer from at least a portion of the formation;

pyrolyzing at least some hydrocarbons within the selected section; and

producing a mixture from the formation.

7333. The method of claim 7332, wherein the selected section comprises nahcolite.

7334. The method of claim 7332, wherein the selected section comprises dawsonite.

7335. The method of claim 7332, wherein the selected section comprises trona.

7336. The method of claim 7332, wherein the selected section comprises gaylussite.

7337. The method of claim 7332, wherein the selected section comprises carbonates.

7338. The method of claim 7332, wherein the selected section comprises carbonate phosphates.

7339. The method of claim 7332, wherein the selected section comprises carbonate chlorides.

7340. The method of claim 7332, wherein the selected section comprises silicates.

7341. The method of claim 7332, wherein the selected section comprises borosilicates.

7342. The method of claim 7332, wherein the selected section comprises halides.

7343. The method of claim 7332, wherein the first fluid comprises a pH greater than about 7.

7344. The method of claim 7332, wherein the first fluid comprises a temperature less than about 110°

C.

7345. The method of claim 7332, wherein the second fluid comprises hydrocarbons.

7346. The method of claim 7332, wherein the second fluid comprises hydrocarbons, and further comprising:

fragmenting at least some of the portion prior to providing the first fluid;

generating hydrocarbons; and

providing at least some of the second fluid to a surface treatment unit, wherein the second fluid comprises at least some of the generated hydrocarbons.

7347. The method of claim 7332, further comprising removing mass from the selected section in the second fluid.

7348. The method of claim 7332, further comprising removing mass from the selected section in the second fluid such that a permeability of the selected section increases.

7349. The method of claim 7332, further comprising removing mass from the selected section in the second fluid and decreasing a heat transfer time in the selected section.

7350. The method of claim 7332, further comprising controlling the heat such that the selected section has a temperature of above about 270°

C.

7351. The method of claim 7332, wherein the second fluid comprises soda ash, and further comprising removing at least a portion of the soda ash from the second fluid as sodium carbonate.

7352. The method of claim 7332, wherein the second fluid comprises nahcolite, and further comprising:

separating at least a portion of the nahcolite from the second fluid;

providing heat to at least some of the separated nahcolite to form a sodium carbonate solution;

providing at least some of the sodium carbonate solution to at least the portion of the formation; and

producing a third fluid comprising alumina from the formation.

7353. The method of claim 7332, further comprising providing a barrier to at least the portion of the formation to inhibit migration of fluids into or out of the portion.

7354. The method of claim 7332, wherein the first fluid comprises steam.

7355. The method of claim 7332, wherein the second fluid comprises a metal.

7356. The method of claim 7332, wherein the second fluid comprises a mineral.

7357. The method of claim 7332, wherein the second fluid comprises aluminum.

7358. The method of claim 7332, wherein the second fluid comprises a metal, and further comprising separating the metal from the second fluid.

7359. The method of claim 7332, further comprising producing a non-hydrocarbon material from the second fluid.

7360. The method of claim 7332, wherein greater than about 10% by weight of the selected section comprises nahcolite.

7361. The method of claim 7332, wherein greater than about 2% by weight of the selected section comprises dawsonite.

7362. The method of claim 7332, wherein at least some of the provided heat comprises waste heat from another portion of the formation.

7363. The method of claim 7332, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.

7364. The method of claim 7332, further comprising providing heat to the formation by injecting the first fluid into the formation.

7365. The method of claim 7332, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 900 C.

7366. The method of claim 7332, further comprising controlling a temperature of the selected section while injecting the first fluid, wherein the temperature is less than about a temperature at which nahcolite will dissociate.

7367. The method of claim 7332, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits the flow of water into the formation.

7368. The method of claim 7332, wherein the mixture is produced from the formation when a partial pressure of hydrogen in at least a portion the formation is at least about 0.5 bars absolute.

7369. The method of claim 7332, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7370. The method of claim 7332, wherein the one or more of the heat sources comprise heaters.

7371. A method of solution mining alumina from an in situ oil shale formation, comprising:

providing heat from one or more heat sources to a least a portion of the formation;

pyrolyzing at least some hydrocarbons in the portion; and

producing a mixture from the formation providing a brine solution to a portion of the formation; and

producing a mixture comprising alumina from the formation.

7372. The method of claim 7371, wherein the selected section comprises dawsonite.

7373. The method of claim 7371, further comprising:

separating at least a portion of the alumina from the mixture; and

providing heat to at least the portion of the alumina to generate aluminum.

7374. The method of claim 7371, further comprising:

separating at least a portion of the alumina from the mixture;

providing heat to at least the portion of the alumina to generate aluminum; and

wherein the provided heat is generated in part using one or more products of an in situ conversion process.

7375. The method of claim 7371, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.

7376. The method of claim 7371, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7377. The method of claim 7371, wherein one or more of the heat sources comprise heaters.

7378. A method of treating an oil shale formation in situ, comprising:

allowing a temperature of a portion of the formation to decrease, wherein the portion has previously undergone an in situ conversion process;

injecting a first fluid into the selected section; and

producing a second fluid from the formation.

7379. The method of claim 7378, wherein the in situ conversion process comprises:

providing heat to a least a portion of the formation;

pyrolyzing at least some hydrocarbons in the portion; and

producing a mixture from the formation.

7380. The method of claim 7378, wherein the first fluid comprises water.

7381. The method of claim 7378, wherein the second fluid comprises a metal.

7382. The method of claim 7378, wherein the second fluid comprises a mineral.

7383. The method of claim 7378, wherein the second fluid comprises aluminum.

7384. The method of claim 7378, wherein the second fluid comprises a metal, and further comprising producing the metal from the second fluid.

7385. The method of claim 7378, further comprising producing a non-hydrocarbon material from the second fluid.

7386. The method of claim 7378, wherein the selected section comprises nahcolite.

7387. The method of claim 7378, wherein greater than about 10% by weight of the selected section comprises nahcolite.

7388. The method of claim 7378, wherein the selected section comprises dawsonite.

7389. The method of claim 7378, wherein greater than about 2% by weight of the selected section comprises dawsonite.

7390. The method of claim 7378, wherein the provided heat comprises waste heat from another portion of the formation.

7391. The method of claim 7378, wherein the first fluid comprises steam.

7392. The method of claim 7378, wherein the first fluid comprises steam, and further comprising providing heat to the formation by injecting the steam into the formation.

7393. The method of claim 7378, further comprising providing heat to the formation by injecting the first fluid into the formation.

7394. The method of claim 7378, further comprising providing heat to the formation by injecting the first fluid into the formation, wherein the first fluid is at a temperature above about 90°

C.

7395. The method of claim 7378, wherein the reduced temperature of the selected section is less than about 90°

C.

7396. The method of claim 7378, wherein an average richness of at least the portion of the selected section is greater than about 0.10 liters per kilogram.

7397. A method for treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section;

selectively limiting a temperature proximate a selected portion of a heat source wellbore to inhibit coke formation at or near the selected portion; and

producing at least some hydrocarbons through the selected portion of the heat source wellbore.

7398. The method of claim 7397, further comprising generating water in the selected portion to inhibit coke formation at or near the selected portion of the heat source wellbore.

7399. The method of claim 7397, wherein the heat source wellbore is placed substantially horizontally within the selected section.

7400. The method of claim 7397, wherein selectively limiting the temperature comprises providing less heat at the selected portion of the heat source wellbore than other portions of the heat source wellbore in the selected section.

7401. The method of claim 7397, wherein selectively limiting the temperature comprises maintaining the temperature proximate the selected portion below pyrolysis temperatures.

7402. The method of claim 7397, further comprising producing a mixture from the selected section through a production well.

7403. The method of claim 7397, further comprising providing at least some heat to an overburden section of the heat source wellbore to maintain the produced hydrocarbons in a vapor phase.

7404. The method of claim 7397, further comprising maintaining a pressure in the selected section below about 150 bars absolute.

7405. The method of claim 7397, further comprising producing hydrocarbons when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.

7406. The method of claim 7397, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7407. The method of claim 7397, wherein one or more of the heat sources comprise heaters.

7408. The method of claim 7397, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about 5.

7409. The method of claim 7397, wherein the produced mixture comprises an acid number less than about 1.

7410. A method for treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section;

controlling operating conditions at a production well to inhibit coking in or proximate the production well; and

producing a mixture from the selected section through the production well.

7411. The method of claim 7410, wherein controlling the operating conditions at the production well comprises controlling heat output from at least one heat source proximate the production well.

7412. The method of claim 7410, wherein controlling the operating conditions at the production well comprises reducing or turning off heat provided from at least one of the heat sources for at least part of a time in which the mixture is produced through the production well.

7413. The method of claim 7410, wherein controlling the operating conditions at the production well comprises increasing or turning on heat provided from at least one of the heat sources to maintain a desired quality in the produced mixture.

7414. The method of claim 7410, wherein controlling the operating conditions at the production well comprises producing the mixture at a location sufficiently spaced from at least one heat source such that coking is inhibited at the production well.

7415. The method of claim 7410, further comprising adding steam to the selected section to inhibit coking at the production well.

7416. The method of claim 7410, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.

7417. The method of claim 7410, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7418. The method of claim 7410, wherein one or more of the heat sources comprise heaters.

7419. The method of claim 7410, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about 5.

7420. The method of claim 7410, wherein the produced mixture comprises an acid number less than about 1.

7421. A method for treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the oil shale formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that the heat pyrolyzes at least some hydrocarbons within the selected section;

producing a mixture from the selected section; and

controlling a quality of the produced mixture by varying a location for producing the mixture.

7422. The method of claim 7421, wherein varying the location for producing the mixture comprises varying a production location within a production well in or proximate the selected section.

7423. The method of claim 7422, wherein varying the production location within the production well comprises varying a packing height within the production well.

7424. The method of claim 7422, wherein varying the production location within the production well comprises varying a location of perforations used to produce the mixture within the production well.

7425. The method of claim 7421, wherein varying the location for producing the mixture comprises varying a production location along a length of a production wellbore placed in the formation.

7426. The method of claim 7421, wherein varying the location for producing the mixture comprises varying a location of a production well within the formation.

7427. The method of claim 7421, wherein varying the location for producing the mixture comprises varying a number of production wells in the formation.

7428. The method of claim 7421, wherein varying the location for producing the mixture comprises varying a distance between a production well and one or more heat sources.

7429. The method of claim 7421, further comprising increasing the quality of the produced mixture by producing the mixture from an upper portion of the selected section.

7430. The method of claim 7421, further comprising increasing a total mass recovery from the selected section by producing the mixture from a lower portion of the selected section.

7431. The method of claim 7421, further comprising selecting the location for production based on a price characteristic for produced hydrocarbons.

7432. The method of claim 7431, wherein the price characteristic is determined by multiplying a production rate of the produced mixture at a selected API gravity from the selected section by a price obtainable for selling the produced mixture with the selected API gravity.

7433. The method of claim 7431, further comprising adjusting the location for production based on a change in the price characteristic.

7434. The method of claim 7421, wherein the quality of the produced mixture comprises an API gravity of the produced mixture.

7435. The method of claim 7421, wherein the produced mixture comprises an acid number less than about 1.

7436. The method of claim 7421, further comprising controlling the quality of the produced mixture by controlling the heat provided from at least one heat source.

7437. The method of claim 7421, further comprising controlling the quality of the produced mixture such that the produced mixture comprises a selected minimum API gravity.

7438. The method of claim 7421, further comprising producing the mixture when a partial pressure of hydrogen in the formation is at least about 0.5 bars absolute.

7439. The method of claim 7421, wherein the heat provided from at least one heat source is transferred to at least a portion of the formation substantially by conduction.

7440. The method of claim 7421, wherein one or more of the heat sources comprise heaters.

7441. The method of claim 7421, wherein a ratio of energy output of the produced mixture to energy input into the formation is at least about 5.