Producing hydrocarbons and non-hydrocarbon containing materials when treating a hydrocarbon containing formation

• US 7,100,994 B2
• Filed: 10/24/2002
• Issued: 09/05/2006
• Est. Priority Date: 10/24/2001
• Status: Expired due to Fees

• Current Assignee: Shell Oil Company (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: de Rouffignac, Eric Pierre, Vinegar, Harold J., Schoeling, Lanny Gene, Wellington, Scott Lee, Maher, Kevin Albert
• Primary Examiner(s): SUCHFIELD, GEORGE A
• Application Number:
  US10/279,229
• Publication Number:
  US 20030196788A1
• Time in Patent Office: 1,412 Days
• Field of Search: 166/52, 166/57, 166/59, 166/60, 166/75.12, 166/245, 166/258, 166/266, 166/267, 166/268, 166/272.1, 166/272.3, 166/302, 166/303, 166/308, 299/2, 299/3, 299/4, 299/5, 299/7, 299/10, 299/13, 299/14, 405/52, 423/131, 423/132, 423/208, 423/658.5
• US Class Current: 299/7
• CPC Class Codes: B09C 1/02 Extraction using liquids, e.g. washing, leaching , flotation
• CPC Class Codes: B09C 1/06 thermally
• CPC Class Codes: B09C 2101/00 In situ
• CPC Class Codes: C10G 45/00 Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
• CPC Class Codes: C10G 9/24 by heating with electrical means
• CPC Class Codes: E21B 17/0285 characterised by electrically insulating elements
• CPC Class Codes: E21B 43/168 Injecting a gaseous medium
• 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 43/305 comprising at least one inclined or horizontal well
• CPC Class Codes: E21B 47/0224 using seismic or acoustic means
• CPC Class Codes: G01V 3/26 operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device with electromagnetic waves G01V3/30
• CPC Class Codes: Y02P 30/00 Technologies relating to oil refining and petrochemical industry
• CPC Class Codes: Y02P 30/40 Ethylene production
• CPC Class Codes: Y10S 210/901 Specified land fill feature, e.g. prevention of ground water fouling
• CPC Class Codes: Y10T 137/0391 Affecting flow by the addition of material or energy

Abstract

A method for treating a hydrocarbon containing formation is provided. In one embodiment, heat from one or more heaters may be provided to at least a portion of the formation. Heat may be allowed to transfer from the one or more heaters to at least a part of the formation. In certain embodiments, the heat from the one or more heaters may pyrolyze at least some hydrocarbons within the formation. In an embodiment, a first fluid may be introduced into at least a portion of the formation. The portion may have previously undergone an in situ conversion process. A mixture of the first fluid and a second fluid (or a second compound) may be produced from the formation. In some embodiments, a first fluid may be provided to the formation prior to pyrolyzing hydrocarbons in the formation, and a second fluid (or a second compound) may be produced prior to pyrolyzing hydrocarbons in the formation. In some embodiments the second fluid or second compound include minerals, metals, salts, or other compounds that may be recovered.

Claims

1. A method of treating a hydrocarbon containing formation in situ, comprising:

providing heat from one or more heaters substantially by conduction to a portion of the formation;

allowing the heat to transfer from 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.

2. The method of claim 1, wherein conducting the in situ conversion process comprises producing a mixture, and wherein the mixture is produced from the formation when a partial pressure of hydrogen in the portion of the formation is at least about 0.5 bars.

3. The method of claim 1, wherein the in situ conversion process comprises:

providing additional heat to the portion of the formation;

pyrolyzing at least some hydrocarbons in the selected section; and

producing a mixture from the formation.

4. The method of claim 1, wherein the selected section comprises nahcolite.

5. The method of claim 1, wherein the selected section comprises dawsonite.

6. The method of claim 1, wherein the selected section comprises trona.

7. The method of claim 1, wherein the selected section comprises gaylussite.

8. The method of claim 1, wherein the selected section comprises carbonates.

9. The method of claim 1, wherein the selected section comprises carbonate phosphates.

10. The method of claim 1, wherein the selected section comprises carbonate chlorides.

11. The method of claim 1, wherein the selected section comprises silicates.

12. The method of claim 1, wherein the selected section comprises borosilicates.

13. The method of claim 1, wherein the selected section comprises halides.

14. The method of claim 1, wherein the first fluid comprises a pH greater than about 7.

15. The method of claim 1, wherein the first fluid comprises a temperature less than about 110°

C.

16. The method of claim 1, wherein the portion has previously undergone an in situ conversion process prior to the injection of the first fluid into the selected section.

17. The method of claim 1, wherein the second fluid comprises hydrocarbons.

18. The method of claim 1, wherein the second fluid comprises hydrocarbons, and further comprising:

fragmenting at least some of the portion prior to providing the first fluid to the selected section;

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.

19. The method of claim 1, further comprising removing mass from the selected section of the formation with the second fluid.

20. The method of claim 1, further comprising removing mass from the selected section of the formation with the second fluid such that a permeability of the selected section increases.

21. The method of claim 1, further comprising removing mass from the selected section of the formation with the second fluid and decreasing a heat transfer time in the selected section.

22. The method of claim 1, further comprising controlling the amount of heat provided such that the selected section has a temperature of above about 120°

C.

23. The method of claim 1, 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.

24. The method of claim 1, wherein the second fluid comprises soda ash, and further comprising removing a portion of the soda ash from the second fluid as sodium carbonate.

25. The method of claim 1, wherein the in situ conversion process comprises pyrolyzing hydrocarbon containing material in the selected section.

26. The method of claim 1, wherein the second fluid includes 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 nalicolite 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 including alumina from the formation.

27. The method of claim 1, further comprising providing a barrier to the portion of the formation to inhibit migration of fluids into or out of the portion.

28. The method of claim 1, further comprising controlling the amount of heat provided such that a temperature in the selected section of the formation is less than about 100°

C.

29. The method of claim 1, wherein the first fluid comprises steam.

30. The method of claim 1, wherein the second fluid includes a metal.

31. The method of claim 1, wherein the second fluid includes a mineral.

32. The method of claim 1, wherein the second fluid includes aluminum.

33. The method of claim 1, wherein the second fluid includes a metal, and further comprising separating the metal from the second fluid.

34. The method of claim 1, further comprising producing a non-hydrocarbon containing material from the second fluid.

35. The method of claim 1, wherein greater than about 10% by weight of the selected section comprises nalicolite.

36. The method of claim 1, wherein greater than about 2% by weight of the selected section comprises dawsonite.

37. The method of claim 1, 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.

38. The method of claim 1, wherein a temperature in the selected section is less than about 90°

C. prior to injecting the first fluid into the selected section.

39. The method of claim 1, wherein the hydrocarbon containing formation comprises oil shale.

40. The method of claim 1, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits a flow of water into the selected section.

41. A method of treating a hydrocarbon containing formation in situ, compnsing:

providing heat to a portion of the formation;

allowing the heat to transfer from 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;

conducting an in situ conversion process in the selected section;

producing a second fluid from the formation, wherein the second fluid includes nahcolite;

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 including alumina from the formation.

42. The method of claim 41, wherein conducting the in situ conversion process comprises producing a mixture, and wherein the mixture is produced from the formation when a partial pressure of hydrogen in the portion of the formation is at least about 0.5 bars.

43. The method of claim 41, wherein the in situ conversion process comprises:

providing additional heat to the portion of the formation;

pyrolyzing at least some hydrocarbons in the selected section; and

producing a mixture from the formation.

44. The method of claim 41, wherein the first fluid comprises a pH greater than about 7.

45. The method of claim 41, wherein the first fluid comprises a temperature less than about 110°

C.

46. The method of claim 41, further comprising removing mass from the selected section of the formation with the second fluid.

47. The method of claim 41, further comprising controlling the heat provided to the portion of the formation such that the selected section has a temperature above about 120°

C.

48. The method of claim 41, wherein the in situ conversion process comprises pyrolyzing hydrocarbon containing material in the selected section.

49. The method of claim 41, wherein the provided heat comprises waste heat from another portion of the formation.

50. The method of claim 41, wherein the first fluid provides heat to the selected section.

51. The method of claim 41, further comprising providing a barrier substantially surrounding the selected section such that the barrier inhibits flow of water into the formation.

52. A method of treating a hydrocarbon containing formation in situ, comprising:

providing heat to a portion of the formation;

allowing the heat to transfer from the portion to a selected section of the formation such that dissociation of carbonate minerals is inhibited;

controlling the heat provided to the formation such that a temperature in the selected section of the formation is less than about 100°

C.;

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.

53. The method of claim 52, wherein the selected section comprises nahcolite.

54. The method of claim 52, wherein the selected section comprises dawsonite.

55. The method of claim 52, wherein the selected section compnses trona.

56. The method of claim 52, wherein the selected section comprises gaylussite.

57. The method of claim 52, wherein the selected section comprises carbonates.

58. The method of claim 52, wherein the selected section comprises carbonate phosphates.

59. The method of claim 52, wherein the selected section comprises carbonate chlorides.

60. The method of claim 52, wherein the selected section comprises silicates.

61. The method of claim 52, wherein the selected section comprises borosilicates.

62. The method of claim 52, wherein the selected section comprises halides.

63. A method of treating a hydrocarbon containing formation in situ, comprising:

providing heat from one or more heaters to a portion of the formation;

allowing the heat to transfer from 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;

conducting an in situ conversion process in the selected section;

pyrolyzing at least some hydrocarbons in 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.

64. The method of claim 63, wherein the third fluid comprises water.

65. The method of claim 63, wherein the third fluid comprises steam.

66. The method of claim 63, wherein the fourth fluid includes a metal.

67. The method of claim 63, wherein the fourth fluid includes a mineral.

68. The method of claim 63, wherein the fourth fluid includes aluminum.

69. The method of claim 63, wherein the fourth fluid includes a metal, and producing the metal from the second fluid.

70. The method of claim 63, further comprising producing a non-hydrocarbon containing material from the fourth fluid.

71. The method of claim 63, wherein the second fluid comprises hydrocarbons.

72. A method of treating a hydrocarbon containing formation in situ, comprising:

providing heat to a portion of the formation;

allowing the heat to transfer from 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, wherein a temperature in the selected section is less than about 90°

C.;

producing a second fluid from the formation; and

conducting an in situ conversion process in the selected section.

73. The method of claim 72, wherein the portion has previously undergone an in situ conversion process prior to injection of the first fluid into the selected section.

74. The method of claim 72, 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.

75. The method of claim 72, further comprising removing mass from the selected section of the formation with the second fluid such that a permeability of the selected section increases.

76. The method of claim 72, further comprising removing mass from the selected section of the formation with the second fluid and decreasing a heat transfer time in the selected section.

77. The method of claim 72, wherein the selected section comprises nahcolite, and controlling the heat such that the selected section has a temperature less than about a dissociation temperature of nahcolite.

78. The method of claim 72, wherein the second fluid comprises soda ash, and removing a portion of the soda ash from the second fluid as sodium carbonate.

79. The method of claim 72, further comprising providing a barrier to the portion of the formation to inhibit migration of fluids into or out of the portion.

80. The method of claim 72, wherein the first fluid is at a temperature above about 90°

C., and wherein the first fluid provides heat to the selected section.

81. The method of claim 72, 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.

82. The method of claim 72, wherein the first fluid comprises steam, and providing heat to the formation by injecting the steam into the formation.