In situ thermal processing through an open wellbore in an oil shale formation

• US 7,051,811 B2
• Filed: 04/24/2002
• Issued: 05/30/2006
• Est. Priority Date: 04/24/2001
• Status: Expired due to Fees

• Current Assignee: Shell Oil Company (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: Karanikas, John Michael, de Rouffignac, Eric Pierre, Vinegar, Harold J., Wellington, Scott Lee, Ryan, Robert Charles, Fowler, Thomas David, Berchenko, Ilya Emil, Zhang, Etuan, Keedy, Charles Robert, Hunsucker, Bruce Gerard
• Primary Examiner(s): KRECK, JOHN J
• Application Number:
  US10/131,351
• Publication Number:
  US 20030141068A1
• Time in Patent Office: 1,497 Days
• Field of Search: 166/302, 166/245, 166/256, 166/57, 166/60, 166/61, 166/59
• US Class Current: 166/302
• 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 the treatment area from one or more heat sources. A heat source may be positioned in an uncased wellbore. Heat may be allowed to transfer from the heat source to a section of the formation. Subsequently, hydrocarbons, H₂, and/or other formation fluids may be produced from the formation.

Claims

1. A system configured to heat an oil shale formation, comprising:

heaters disposed within one or more open wellbores in the formation, wherein the heaters are configured to provide heat to at least a portion of the formation during use;

wherein the system is configured to allow heat to transfer from the heaters to a part of the formation during use; and

wherein superposition of heat from at least two of the heaters pyrolyzes at least some hydrocarbons in the part of the formation.

2. The system of claim 1, wherein at least one of the heaters comprises an electrical heater.

3. The system of claim 1, wherein at least one of the heaters comprises a surface burner.

4. The system of claim 1, wherein at least one of the heaters comprises a flameless distributed combustor.

5. The system of claim 1, wherein at least one of the heaters comprises a natural distributed combustor.

6. The system of claim 1, wherein the one or more open wellbores comprise a diameter of at least approximately 5 cm.

7. The system of claim 1, 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.

8. The system of claim 1, 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.

9. The system of claim 1, 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.

10. The system of claim 1, 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 a packing material is disposed at a junction of the overburden casing and the at least one of the one or more open wellbores.

11. The system of claim 1, 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.

12. The system of claim 1, 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.

13. The system of claim 1, wherein the system is further configured to transfer heat such that the transferred heat can pyrolyze at least some hydrocarbons in the part of the formation.

14. The system of claim 1, further comprising a valve coupled to a production well configured to control a pressure within at least a majority of the part of the formation.

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

providing heat from heaters to at least one portion of the formation, wherein at least one of the heaters is disposed within one of one or more open wellbores in the formation;

allowing the heat to transfer from the heaters to a part of the formation, wherein superposition of heat from at least two of the heaters pyrolyzes at least some hydrocarbons in the part of the formation; and

producing a mixture from the formation.

16. The method of claim 15, further comprising maintaining a temperature within the part of the formation within a pyrolysis temperature range with a lower pyrolysis temperature of about 250°

C. and an upper pyrolysis temperature of about 400°

C.

17. The method of claim 15, wherein at least one of the heaters comprises an electrical heater.

18. The method of claim 15, wherein at least one of the heaters comprises a surface burner.

19. The method of claim 15, wherein at least one of the heaters comprises a flameless distributed combustor.

20. The method of claim 15, wherein at least one of the heaters comprises a natural distributed combustor.

21. The method of claim 15, wherein at least one of the heaters is suspended within one of the open wellbores.

22. The method of claim 15, wherein a tube is disposed in at least one of the open wellbores proximate to the heater, the method further comprising flowing a substantially constant amount of fluid into at least one of the open wellbores through critical flow orifices in the tube.

23. The method of claim 15, wherein a perforated tube is disposed in at least one of the open wellbores proximate to the heater, the method further comprising flowing a corrosion inhibiting fluid into at least one of the open wellbores through the perforated tube.

24. The method of claim 15, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation.

25. The method of claim 15, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel.

26. The method of claim 15, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement.

27. The method of claim 15, further comprising coupling an overburden casing to at least one of the 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 open wellbores.

28. The method of claim 15, further comprising coupling an overburden casing to at least one of the 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 open wellbores and the overburden casing with a packing material.

29. The method of claim 15, further comprising heating at least the portion of the formation to substantially pyrolyze at least some hydrocarbons within the formation.

30. The method of claim 15, further comprising controlling a pressure and a temperature within at least a majority of the part of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

31. The method of claim 15, further comprising controlling a pressure with the wellbore.

32. The method of claim 15, further comprising controlling a pressure within at least a majority of the part of the formation with a valve coupled to a production well located in the formation.

33. The method of claim 15, further comprising controlling the heat such that an average heating rate of the part of the formation is less than about 1°

C. per day in a pyrolysis temperature range of about 270°

C. to about 400°

C.

34. The method of claim 15, wherein providing heat from the heaters to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the heaters, 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 (Pwr) provided to the selected volume is equal to or less than h*V*C_v*ρ

_B, wherein ρ

_B is formation bulk density, and wherein an average heating rate (h) of the selected volume is about 10°

C./day.

35. The method of claim 15, wherein allowing the heat to transfer from the heaters to the part of the formation comprises transferring heat substantially by conduction.

36. The method of claim 15, wherein providing heat from the heaters comprises heating the part of the formation such that a thermal conductivity of at least a portion of the part of the formation is greater than about 0.5 W/(m °

C.).

37. The method of claim 15, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°

.

38. The method of claim 15, 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.

39. The method of claim 15, 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.

40. The method of claim 15, 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.

41. The method of claim 15, 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.

42. The method of claim 15, 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.

43. The method of claim 15, 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.

44. The method of claim 15, 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.

45. The method of claim 15, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

46. The method of claim 15, 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.

47. The method of claim 15, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

48. The method of claim 15, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

49. The method of claim 15, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises molecular hydrogen, and wherein the molecular hydrogen is greater than about 10% by volume of the non-condensable component and wherein the molecular hydrogen is less than about 80% by volume of the non-condensable component.

50. The method of claim 15, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

51. The method of claim 15, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

52. The method of claim 15, further comprising controlling a pressure within at least a majority of the part of the formation.

53. The method of claim 15, further comprising controlling a pressure within at least a majority of the part of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

54. The method of claim 15, 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.

55. The method of claim 15, wherein the partial pressure of H₂ is measured when the mixture is at a production well.

56. The method of claim 15, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

57. The method of claim 15, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

58. The method of claim 15, 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.

59. The method of claim 15, 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.

60. The method of claim 15, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the part of the formation to greater than about 100 millidarcy.

61. The method of claim 15, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the part of the formation.

62. The method of claim 15, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

63. The method of claim 15, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heaters are disposed in the formation for the production well.

64. The method of claim 15, wherein at least about 20 heaters are disposed in the formation for each production well.

65. The method of claim 15, further comprising providing heat from three or more heaters to at least a portion of the formation, wherein three or more of the heaters are located in the formation in a unit of heaters, and wherein the unit of heaters comprises a triangular pattern.

66. The method of claim 15, further comprising providing heat from three or more heaters to at least a portion of the formation, wherein three or more of the heaters are located in the formation in a unit of heaters, wherein the unit of heaters 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.

67. The method of claim 15, further comprising separating the produced mixture into a gas stream and a liquid stream.

68. The method of claim 15, 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.

69. The method of claim 15, wherein the produced mixture comprises H₂S, the method further comprising separating a portion of the H₂S from non-condensable hydrocarbons.

70. The method of claim 15, wherein the produced mixture comprises CO₂, the method further comprising separating a portion of the CO₂ from non-condensable hydrocarbons.

71. The method of claim 15, 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.

72. The method of claim 15, 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.

73. The method of claim 15, 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.

74. The method of claim 15, wherein the part of the formation is heated to a minimum pyrolysis temperature of about 270°

C.

75. The method of claim 15, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

76. The method of claim 15, 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.

77. The method of claim 15, 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 increase the API gravity.