CA2445415A1 - In situ recovery from a oil shale formation - Google Patents

In situ recovery from a oil shale formation Download PDF

Info

Publication number
CA2445415A1
CA2445415A1 CA002445415A CA2445415A CA2445415A1 CA 2445415 A1 CA2445415 A1 CA 2445415A1 CA 002445415 A CA002445415 A CA 002445415A CA 2445415 A CA2445415 A CA 2445415A CA 2445415 A1 CA2445415 A1 CA 2445415A1
Authority
CA
Canada
Prior art keywords
formation
condensable hydrocarbons
heat
heat sources
weight
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Granted
Application number
CA002445415A
Other languages
French (fr)
Other versions
CA2445415C (en
Inventor
Harold J. Vinegar
Scott L. Wellington
John M. Karanikas
Kevin A. Maher
Robert C. Ryan
Gordon T. Shahin
Charlie R. Keedy
Ajay M. Madgavkar
James L. Menotti
Martijn Van Hardeveld
John M. Ward
Meliha D. Sumnu-Dindoruk
Bruce Roberts
Peter Veenstra
Wade Watkins
Steve Crane
Eric De Rouffignac
George L. Stegemeier
Ilya E. Berchenko
Etuan Zhang
Thomas D. Fowler
John M. Coles
Lanny Schoeling
Fred G. Carl
Bruce G. Hunsucker
Philip T. Baxley
Lawrence J. Bielamowicz
Margaret Messier
Kip Pratt
Bruce Lepper
Ronald Bass
Tom Mikus
Carlos Glandt
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell Canada Ltd
Original Assignee
Harold J. Vinegar
Scott L. Wellington
John M. Karanikas
Kevin A. Maher
Robert C. Ryan
Gordon T. Shahin
Charlie R. Keedy
Ajay M. Madgavkar
James L. Menotti
Martijn Van Hardeveld
John M. Ward
Meliha D. Sumnu-Dindoruk
Bruce Roberts
Peter Veenstra
Wade Watkins
Steve Crane
Eric De Rouffignac
George L. Stegemeier
Ilya E. Berchenko
Etuan Zhang
Thomas D. Fowler
John M. Coles
Lanny Schoeling
Fred G. Carl
Bruce G. Hunsucker
Philip T. Baxley
Lawrence J. Bielamowicz
Margaret Messier
Kip Pratt
Bruce Lepper
Ronald Bass
Tom Mikus
Carlos Glandt
Shell Canada Limited
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Harold J. Vinegar, Scott L. Wellington, John M. Karanikas, Kevin A. Maher, Robert C. Ryan, Gordon T. Shahin, Charlie R. Keedy, Ajay M. Madgavkar, James L. Menotti, Martijn Van Hardeveld, John M. Ward, Meliha D. Sumnu-Dindoruk, Bruce Roberts, Peter Veenstra, Wade Watkins, Steve Crane, Eric De Rouffignac, George L. Stegemeier, Ilya E. Berchenko, Etuan Zhang, Thomas D. Fowler, John M. Coles, Lanny Schoeling, Fred G. Carl, Bruce G. Hunsucker, Philip T. Baxley, Lawrence J. Bielamowicz, Margaret Messier, Kip Pratt, Bruce Lepper, Ronald Bass, Tom Mikus, Carlos Glandt, Shell Canada Limited filed Critical Harold J. Vinegar
Publication of CA2445415A1 publication Critical patent/CA2445415A1/en
Application granted granted Critical
Publication of CA2445415C publication Critical patent/CA2445415C/en
Anticipated expiration legal-status Critical
Expired - Lifetime legal-status Critical Current

Links

Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/243Combustion in situ
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2401Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection by means of electricity
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/243Combustion in situ
    • E21B43/247Combustion in situ in association with fracturing processes or crevice forming processes
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/30Specific pattern of wells, e.g. optimizing 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 a heat source 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

WHAT IS CLAIMED IS:

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 heating 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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 % 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.

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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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 mufti-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*.rho.B

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

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.

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.

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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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 (Hz) 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*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 mufti-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 HZ within the mixture is greater than about 0.5 bars.

209. The method of claim 208, wherein the partial pressure of HZ 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 (east 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) ofthe 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*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 (Cv), 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*Cv*pB
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.

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 (Cv), 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*Cv*pB
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 are 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.B 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 (.NU.) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C .NU.), 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*.NU.*C .NU.*.rho. .beta.
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho. .beta. 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 (.NU.) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (C .NU.), 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 .NU. *.rho. .beta.
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p .beta. 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 Maim 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 [-44000/T + 67]
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:
p = e[-31000/T + 51]

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:
p = e [-22000/T + 38]

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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 [(-A/T)+B-2.6744];
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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 [-57000/T + 83]

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:

p = e [-16000/T + 28].

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:

p = e [-12000/T + 22].

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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 [-14000/T + 25]
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:
p = e [-16000/T + 28].

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:

p = e[-18000/T + 32].

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,*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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[-38000/T + 61]

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:

p = e[-13000/T + 24].

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:

p = e[-8000/T + 18]

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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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 mufti-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*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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 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*.rho. B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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).

WHAT IS CLAIMED IS:

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 heating 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:

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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B

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

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.

1129. 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.

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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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.
411~

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 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.
1153. The method of claim 1122, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05 % by weight of the produced mixture is ammonia.
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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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 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.

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*pB
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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*pB
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.
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*pB
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 H2within the mixture is greater than about 0.5 bars.

1323. The method of claim 1322, wherein the partial pressure of H2within 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*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 (~) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (~~), 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~*p~

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.

1380. The method of claim 13?2, 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*p B

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

14$3. 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 (~) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (~~), 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*~*~~*pB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p~ 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p8 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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 (Cv), 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*Cv*Pb 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.

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 cycloallcanes.

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 (Cv), 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*Cv*pB
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.

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 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.
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 fonnation, 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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 mufti-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 volmne 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p$ 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*.rho.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B

wherein Pwr is the heating energy/day, la is an average heating rate of the formation, .RHO.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 Hz 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 and 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.B is formation bulls 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 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.
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 flameless 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.B is formation bulls 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*pB
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.

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 mufti-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 HZ 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*pB
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p$ is formation bulls 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.

203 8. 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*pB

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.

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*pB

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.

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.

2124. The method of claim 2124, wherein at least about 20 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.

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"*p B

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

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 first 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 *Y*C v*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p B is formation bulls 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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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*p B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p B is formation bulls 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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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*.RHO.B

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .RHO.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 % 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"*pB
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p B is formation bulls 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.

244. 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*pB
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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*p.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*.rho.B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, .rho.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*pB
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.

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 heaters.

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*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p B is formation bulls 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"*p B
wherein Pwr is the heating energy/day, h is an average heating rate of the formation, p 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 mufti-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*.rho.B
wherein Pwr is the heating energy/day, ~is an average heating rate of the formation, .rho.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 25°.
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 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.
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 at 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 product 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 he 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 clean 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, farther 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 centralizes, wherein the support member is configured to support the insulated conductor, and wherein the centralizes 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.
CA2445415A 2001-04-24 2002-04-24 In situ recovery from a oil shale formation Expired - Lifetime CA2445415C (en)

Applications Claiming Priority (5)

Application Number Priority Date Filing Date Title
US28606201P 2001-04-24 2001-04-24
US60/286,062 2001-04-24
US33724901P 2001-10-24 2001-10-24
US60/337,249 2001-10-24
PCT/US2002/013311 WO2002086018A2 (en) 2001-04-24 2002-04-24 In situ recovery from a oil shale formation

Publications (2)

Publication Number Publication Date
CA2445415A1 true CA2445415A1 (en) 2002-10-31
CA2445415C CA2445415C (en) 2011-08-30

Family

ID=26963559

Family Applications (1)

Application Number Title Priority Date Filing Date
CA2445415A Expired - Lifetime CA2445415C (en) 2001-04-24 2002-04-24 In situ recovery from a oil shale formation

Country Status (4)

Country Link
US (24) US6991033B2 (en)
AU (2) AU2002257221B2 (en)
CA (1) CA2445415C (en)
WO (1) WO2002086018A2 (en)

Families Citing this family (398)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO1998052704A1 (en) * 1997-05-20 1998-11-26 Shell Internationale Research Maatschappij B.V. Remediation method
US8682589B2 (en) * 1998-12-21 2014-03-25 Baker Hughes Incorporated Apparatus and method for managing supply of additive at wellsites
US8760657B2 (en) * 2001-04-11 2014-06-24 Gas Sensing Technology Corp In-situ detection and analysis of methane in coal bed methane formations with spectrometers
WO2001081239A2 (en) 2000-04-24 2001-11-01 Shell Internationale Research Maatschappij B.V. In situ recovery from a hydrocarbon containing formation
AU2002257221B2 (en) 2001-04-24 2008-12-18 Shell Internationale Research Maatschappij B.V. In situ recovery from a oil shale formation
US7040400B2 (en) 2001-04-24 2006-05-09 Shell Oil Company In situ thermal processing of a relatively impermeable formation using an open wellbore
US8764978B2 (en) 2001-07-16 2014-07-01 Foret Plasma Labs, Llc System for treating a substance with wave energy from an electrical arc and a second source
US7622693B2 (en) 2001-07-16 2009-11-24 Foret Plasma Labs, Llc Plasma whirl reactor apparatus and methods of use
US7165615B2 (en) * 2001-10-24 2007-01-23 Shell Oil Company In situ recovery from a hydrocarbon containing formation using conductor-in-conduit heat sources with an electrically conductive material in the overburden
EP1467826B8 (en) * 2001-10-24 2005-09-14 Shell Internationale Researchmaatschappij B.V. Thermally enhanced soil decontamination method
KR100925130B1 (en) * 2001-10-24 2009-11-05 쉘 인터내셔날 리써취 마트샤피지 비.브이. Remediation of mercury contaminated soil
NZ532089A (en) * 2001-10-24 2005-09-30 Shell Int Research Installation and use of removable heaters in a hydrocarbon containing formation
BR0213513B8 (en) * 2001-10-24 2013-02-19 Method for soil contamination remediation, and soil remediation system.
US6774148B2 (en) * 2002-06-25 2004-08-10 Chevron U.S.A. Inc. Process for conversion of LPG and CH4 to syngas and higher valued products
UA80556C2 (en) * 2002-07-17 2007-10-10 Шелл Інтернаціонале Рісерч Маатшаппідж Б.В. Method for forge welding tubulars
US8224163B2 (en) 2002-10-24 2012-07-17 Shell Oil Company Variable frequency temperature limited heaters
US7344622B2 (en) * 2003-04-08 2008-03-18 Grispin Charles W Pyrolytic process and apparatus for producing enhanced amounts of aromatic compounds
NZ567052A (en) 2003-04-24 2009-11-27 Shell Int Research Thermal process for subsurface formations
US7835893B2 (en) * 2003-04-30 2010-11-16 Landmark Graphics Corporation Method and system for scenario and case decision management
US7534926B2 (en) * 2003-05-15 2009-05-19 Board Of Regents, The University Of Texas System Soil remediation using heated vapors
US6881009B2 (en) * 2003-05-15 2005-04-19 Board Of Regents , The University Of Texas System Remediation of soil piles using central equipment
US7004678B2 (en) * 2003-05-15 2006-02-28 Board Of Regents, The University Of Texas System Soil remediation with heated soil
US8296968B2 (en) * 2003-06-13 2012-10-30 Charles Hensley Surface drying apparatus and method
US7631691B2 (en) * 2003-06-24 2009-12-15 Exxonmobil Upstream Research Company Methods of treating a subterranean formation to convert organic matter into producible hydrocarbons
WO2005010320A1 (en) * 2003-06-24 2005-02-03 Exxonmobil Upstream Research Company Methods of treating a subterranean formation to convert organic matter into producible hydrocarbons
US20060230760A1 (en) * 2003-07-14 2006-10-19 Hendershot William B Self-sustaining on-site production of electricity utilizing oil shale and/or oil sands deposits
US7410002B2 (en) 2003-08-05 2008-08-12 Stream-Flo Industries, Ltd. Method and apparatus to provide electrical connection in a wellhead for a downhole electrical device
US7552762B2 (en) * 2003-08-05 2009-06-30 Stream-Flo Industries Ltd. Method and apparatus to provide electrical connection in a wellhead for a downhole electrical device
DE10345342A1 (en) * 2003-09-19 2005-04-28 Engelhard Arzneimittel Gmbh Producing an ivy leaf extract containing hederacoside C and alpha-hederin, useful for treating respiratory diseases comprises steaming comminuted ivy leaves before extraction
AU2004288130B2 (en) * 2003-11-03 2009-12-17 Exxonmobil Upstream Research Company Hydrocarbon recovery from impermeable oil shales
US7152675B2 (en) * 2003-11-26 2006-12-26 The Curators Of The University Of Missouri Subterranean hydrogen storage process
US7226895B2 (en) * 2004-04-06 2007-06-05 Baker Hughes Incorporated Drilling fluid systems for reducing circulation losses
US7320364B2 (en) 2004-04-23 2008-01-22 Shell Oil Company Inhibiting reflux in a heated well of an in situ conversion system
US8028438B2 (en) * 2004-07-02 2011-10-04 Aqualizer, Llc Moisture condensation control system
US7685737B2 (en) * 2004-07-19 2010-03-30 Earthrenew, Inc. Process and system for drying and heat treating materials
US20060042794A1 (en) * 2004-09-01 2006-03-02 Pfefferle William C Method for high temperature steam
EP1809721B1 (en) * 2004-10-13 2012-12-05 Charlie Holding Intellectual Property, Inc. Pyrolytic process for producing enhanced amounts of aromatic compounds
DE102005000782A1 (en) * 2005-01-05 2006-07-20 Voith Paper Patent Gmbh Drying cylinder for use in the production or finishing of fibrous webs, e.g. paper, comprises heating fluid channels between a supporting structure and a thin outer casing
US7398823B2 (en) * 2005-01-10 2008-07-15 Conocophillips Company Selective electromagnetic production tool
US7538275B2 (en) 2005-02-07 2009-05-26 Rockbestos Surprenant Cable Corp. Fire resistant cable
US7185702B2 (en) * 2005-02-25 2007-03-06 Halliburton Energy Services, Inc. Methods and compositions for the in-situ thermal stimulation of hydrocarbons using peroxide-generating compounds
US7565779B2 (en) 2005-02-25 2009-07-28 W. R. Grace & Co.-Conn. Device for in-situ barrier
US7584581B2 (en) * 2005-02-25 2009-09-08 Brian Iske Device for post-installation in-situ barrier creation and method of use thereof
BRPI0608286A2 (en) * 2005-03-08 2009-12-22 Authentix Inc system, method and device for identifying and quantifying markers for authenticating a material and method for identifying, authenticating, and quantifying latent markers in a material
RU2007137495A (en) * 2005-03-10 2009-04-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. (NL) HEAT TRANSMISSION SYSTEM FOR COMBUSTION OF FUEL AND HEATING OF TECHNOLOGICAL FLUID AND METHOD OF ITS USE
EP1856444B1 (en) * 2005-03-10 2012-10-10 Shell Oil Company Method of starting up a direct heating system for the flameless combustion of fuel and direct heating of a process fluid
US8224165B2 (en) 2005-04-22 2012-07-17 Shell Oil Company Temperature limited heater utilizing non-ferromagnetic conductor
AU2006239999B2 (en) 2005-04-22 2010-06-17 Shell Internationale Research Maatschappij B.V. In situ conversion process systems utilizing wellbores in at least two regions of a formation
US8209202B2 (en) 2005-04-29 2012-06-26 Landmark Graphics Corporation Analysis of multiple assets in view of uncertainties
US8287050B2 (en) * 2005-07-18 2012-10-16 Osum Oil Sands Corp. Method of increasing reservoir permeability
JP3921226B2 (en) * 2005-07-29 2007-05-30 シャープ株式会社 Cooker
WO2007028238A1 (en) * 2005-09-06 2007-03-15 14007 Mining Inc. Method of breaking brittle solids
US20070056726A1 (en) * 2005-09-14 2007-03-15 Shurtleff James K Apparatus, system, and method for in-situ extraction of oil from oil shale
EP1941003B1 (en) * 2005-10-24 2011-02-23 Shell Internationale Research Maatschappij B.V. Methods of filtering a liquid stream produced from an in situ heat treatment process
US7809538B2 (en) 2006-01-13 2010-10-05 Halliburton Energy Services, Inc. Real time monitoring and control of thermal recovery operations for heavy oil reservoirs
CA2637984C (en) 2006-01-19 2015-04-07 Pyrophase, Inc. Radio frequency technology heater for unconventional resources
US7743826B2 (en) 2006-01-20 2010-06-29 American Shale Oil, Llc In situ method and system for extraction of oil from shale
US7445041B2 (en) * 2006-02-06 2008-11-04 Shale And Sands Oil Recovery Llc Method and system for extraction of hydrocarbons from oil shale
DE602007011124D1 (en) * 2006-02-07 2011-01-27 Colt Engineering Corp Carbon dioxide enriched flue gas injection for hydrocarbon recovery
US7892597B2 (en) * 2006-02-09 2011-02-22 Composite Technology Development, Inc. In situ processing of high-temperature electrical insulation
RU2418158C2 (en) * 2006-02-16 2011-05-10 ШЕВРОН Ю. Эс. Эй. ИНК. Extraction method of kerogenes from underground shale formation and explosion method of underground shale formation
US7484561B2 (en) * 2006-02-21 2009-02-03 Pyrophase, Inc. Electro thermal in situ energy storage for intermittent energy sources to recover fuel from hydro carbonaceous earth formations
FR2897692B1 (en) * 2006-02-22 2008-04-04 Oxand Sa METHOD AND SYSTEM FOR IDENTIFYING AND EVALUATING FAILURE RISK OF A GEOLOGICAL CONTAINMENT SYSTEM
US7931080B2 (en) * 2006-02-24 2011-04-26 Shale And Sands Oil Recovery Llc Method and system for extraction of hydrocarbons from oil sands
WO2008063239A1 (en) * 2006-11-17 2008-05-29 Shale And Sands Oil Recovery Llc Method for extraction of hydrocarbons from limestone formations
US20090173491A1 (en) * 2006-02-24 2009-07-09 O'brien Thomas B Method and system for extraction of hydrocarbons from oil shale and limestone formations
US7448447B2 (en) * 2006-02-27 2008-11-11 Schlumberger Technology Corporation Real-time production-side monitoring and control for heat assisted fluid recovery applications
US9605522B2 (en) * 2006-03-29 2017-03-28 Pioneer Energy, Inc. Apparatus and method for extracting petroleum from underground sites using reformed gases
US7506685B2 (en) * 2006-03-29 2009-03-24 Pioneer Energy, Inc. Apparatus and method for extracting petroleum from underground sites using reformed gases
US7543638B2 (en) * 2006-04-10 2009-06-09 Schlumberger Technology Corporation Low temperature oxidation for enhanced oil recovery
US7644993B2 (en) 2006-04-21 2010-01-12 Exxonmobil Upstream Research Company In situ co-development of oil shale with mineral recovery
US7533719B2 (en) 2006-04-21 2009-05-19 Shell Oil Company Wellhead with non-ferromagnetic materials
US8127865B2 (en) * 2006-04-21 2012-03-06 Osum Oil Sands Corp. Method of drilling from a shaft for underground recovery of hydrocarbons
US7609585B2 (en) * 2006-05-15 2009-10-27 Pgs Geophysical As Method for sub-salt migration velocity analysis
WO2007137088A2 (en) * 2006-05-17 2007-11-29 Composite Technology Development, Inc. Field application of polymer-based electrical insulation
US8205674B2 (en) 2006-07-25 2012-06-26 Mountain West Energy Inc. Apparatus, system, and method for in-situ extraction of hydrocarbons
GB0616330D0 (en) * 2006-08-17 2006-09-27 Schlumberger Holdings A method of deriving reservoir layer pressures and measuring gravel pack effectiveness in a flowing well using permanently installed distributed temperature
US7772160B2 (en) * 2006-09-06 2010-08-10 Baker Hughes Incorporated Method for controlled placement of additives in oil and gas production
US7677673B2 (en) * 2006-09-26 2010-03-16 Hw Advanced Technologies, Inc. Stimulation and recovery of heavy hydrocarbon fluids
US7665524B2 (en) * 2006-09-29 2010-02-23 Ut-Battelle, Llc Liquid metal heat exchanger for efficient heating of soils and geologic formations
US20080078552A1 (en) * 2006-09-29 2008-04-03 Osum Oil Sands Corp. Method of heating hydrocarbons
US7770643B2 (en) 2006-10-10 2010-08-10 Halliburton Energy Services, Inc. Hydrocarbon recovery using fluids
US7832482B2 (en) 2006-10-10 2010-11-16 Halliburton Energy Services, Inc. Producing resources using steam injection
JO2670B1 (en) 2006-10-13 2012-06-17 ايكسون موبيل ابستريم ريسيرتش Enhanced shale oil production by in situ heating using hydraulically fractured producing wells
AU2013206722B2 (en) * 2006-10-13 2015-04-09 Exxonmobil Upstream Research Company Optimized well spacing for in situ shale oil development
CA2664321C (en) * 2006-10-13 2014-03-18 Exxonmobil Upstream Research Company Combined development of oil shale by in situ heating with a deeper hydrocarbon resource
AU2007313388B2 (en) * 2006-10-13 2013-01-31 Exxonmobil Upstream Research Company Heating an organic-rich rock formation in situ to produce products with improved properties
WO2008048456A2 (en) * 2006-10-13 2008-04-24 Exxonmobil Upstream Research Company Optimized well spacing for in situ shale oil development
CA2663650A1 (en) * 2006-10-13 2008-04-24 Exxonmobil Upstream Research Company Improved method of developing a subsurface freeze zone using formation fractures
US7644769B2 (en) * 2006-10-16 2010-01-12 Osum Oil Sands Corp. Method of collecting hydrocarbons using a barrier tunnel
GB2455947B (en) 2006-10-20 2011-05-11 Shell Int Research Heating hydrocarbon containing formations in a checkerboard pattern staged process
CA2668774A1 (en) 2006-11-22 2008-05-29 Osum Oil Sands Corp. Recovery of bitumen by hydraulic excavation
JO2601B1 (en) * 2007-02-09 2011-11-01 ريد لييف ريسورسيز ، انك. Methods Of Recovering Hydrocarbons From Hydrocarbonaceous Material Using A Constructed Infrastructure And Associated Systems
RU2450042C2 (en) * 2007-02-09 2012-05-10 Ред Лиф Рисорсис, Инк. Methods of producing hydrocarbons from hydrocarbon-containing material using built infrastructure and related systems
US7862706B2 (en) * 2007-02-09 2011-01-04 Red Leaf Resources, Inc. Methods of recovering hydrocarbons from water-containing hydrocarbonaceous material using a constructed infrastructure and associated systems
CA2891016C (en) * 2007-02-10 2019-05-07 Vast Power Portfolio, Llc Hot fluid recovery of heavy oil with steam and carbon dioxide
US8394180B2 (en) * 2007-02-16 2013-03-12 Shell Oil Company Systems and methods for absorbing gases into a liquid
US7712327B2 (en) * 2007-03-19 2010-05-11 Colmac Coil Manufacturing, Inc. Heat exchanger and method for defrosting a heat exchanger
CA2675780C (en) 2007-03-22 2015-05-26 Exxonmobil Upstream Research Company Granular electrical connections for in situ formation heating
BRPI0808508A2 (en) 2007-03-22 2014-08-19 Exxonmobil Upstream Res Co METHODS FOR HEATING SUB-SURFACE FORMATION AND ROCK FORMATION RICH IN ORGANIC COMPOUNDS, AND METHOD FOR PRODUCING A HYDROCARBON FLUID
US20100276139A1 (en) * 2007-03-29 2010-11-04 Texyn Hydrocarbon, Llc System and method for generation of synthesis gas from subterranean coal deposits via thermal decomposition of water by an electric torch
US7735554B2 (en) * 2007-03-29 2010-06-15 Texyn Hydrocarbon, Llc System and method for recovery of fuel products from subterranean carbonaceous deposits via an electric device
US20080257552A1 (en) * 2007-04-17 2008-10-23 Shurtleff J Kevin Apparatus, system, and method for in-situ extraction of hydrocarbons
GB2460980B (en) * 2007-04-20 2011-11-02 Shell Int Research Controlling and assessing pressure conditions during treatment of tar sands formations
JP6105190B2 (en) * 2007-05-07 2017-03-29 ルムス テクノロジー インコーポレイテッド Decoking method for ethylene furnace radiation coil
BRPI0810761A2 (en) 2007-05-15 2014-10-21 Exxonmobil Upstream Res Co METHOD FOR HEATING IN SITU OF A SELECTED PORTION OF A ROCK FORMATION RICH IN ORGANIC COMPOUND, AND TO PRODUCE A HYDROCARBON FLUID, AND, WELL HEATER.
BRPI0810752A2 (en) 2007-05-15 2014-10-21 Exxonmobil Upstream Res Co METHODS FOR IN SITU HEATING OF A RICH ROCK FORMATION IN ORGANIC COMPOUND, IN SITU HEATING OF A TARGETED XISTO TRAINING AND TO PRODUCE A FLUID OF HYDROCARBON, SQUARE FOR A RACHOSETUS ORGANIC BUILDING , AND FIELD TO PRODUCE A HYDROCARBON FLUID FROM A TRAINING RICH IN A TARGET ORGANIC COMPOUND.
US7579833B2 (en) * 2007-05-18 2009-08-25 Baker Hughes Incorporated Water mapping using surface NMR
US8616294B2 (en) * 2007-05-20 2013-12-31 Pioneer Energy, Inc. Systems and methods for generating in-situ carbon dioxide driver gas for use in enhanced oil recovery
US7650939B2 (en) * 2007-05-20 2010-01-26 Pioneer Energy, Inc. Portable and modular system for extracting petroleum and generating power
AU2008262537B2 (en) * 2007-05-25 2014-07-17 Exxonmobil Upstream Research Company A process for producing hydrocarbon fluids combining in situ heating, a power plant and a gas plant
US8146664B2 (en) 2007-05-25 2012-04-03 Exxonmobil Upstream Research Company Utilization of low BTU gas generated during in situ heating of organic-rich rock
CA2591395A1 (en) * 2007-06-01 2008-12-01 Noralta Controls Ltd. Method of automated oil well pump control and an automated well pump control system
US9376635B2 (en) 2007-06-11 2016-06-28 Hsm Systems, Inc. Carbonaceous material upgrading using supercritical fluids
US8691084B2 (en) * 2007-06-11 2014-04-08 University Of New Brunswick Bitumen upgrading using supercritical fluids
US7731421B2 (en) * 2007-06-25 2010-06-08 Schlumberger Technology Corporation Fluid level indication system and technique
US7909094B2 (en) * 2007-07-06 2011-03-22 Halliburton Energy Services, Inc. Oscillating fluid flow in a wellbore
US7748137B2 (en) * 2007-07-15 2010-07-06 Yin Wang Wood-drying solar greenhouse
KR101495377B1 (en) * 2007-07-20 2015-02-24 셀 인터나쵸나아레 레사아치 마아츠샤피 비이부이 A flameless combustion heater
BRPI0814798A2 (en) * 2007-07-20 2019-09-24 Shell Int Research flameless combustion heater
US20090028000A1 (en) * 2007-07-26 2009-01-29 O'brien Thomas B Method and process for the systematic exploration of uranium in the athabasca basin
US7620498B2 (en) * 2007-08-23 2009-11-17 Chevron U.S.A. Inc. Automated borehole image interpretation
US8768672B2 (en) * 2007-08-24 2014-07-01 ExxonMobil. Upstream Research Company Method for predicting time-lapse seismic timeshifts by computer simulation
US8548782B2 (en) 2007-08-24 2013-10-01 Exxonmobil Upstream Research Company Method for modeling deformation in subsurface strata
DE102007040607B3 (en) * 2007-08-27 2008-10-30 Siemens Ag Method for in-situ conveyance of bitumen or heavy oil from upper surface areas of oil sands
US20090084707A1 (en) * 2007-09-28 2009-04-02 Osum Oil Sands Corp. Method of upgrading bitumen and heavy oil
WO2009043055A2 (en) * 2007-09-28 2009-04-02 Bhom Llc System and method for extraction of hydrocarbons by in-situ radio frequency heating of carbon bearing geological formations
US7902955B2 (en) * 2007-10-02 2011-03-08 Schlumberger Technology Corporation Providing an inductive coupler assembly having discrete ferromagnetic segments
US11806686B2 (en) 2007-10-16 2023-11-07 Foret Plasma Labs, Llc System, method and apparatus for creating an electrical glow discharge
US9230777B2 (en) 2007-10-16 2016-01-05 Foret Plasma Labs, Llc Water/wastewater recycle and reuse with plasma, activated carbon and energy system
US8278810B2 (en) 2007-10-16 2012-10-02 Foret Plasma Labs, Llc Solid oxide high temperature electrolysis glow discharge cell
US9051820B2 (en) * 2007-10-16 2015-06-09 Foret Plasma Labs, Llc System, method and apparatus for creating an electrical glow discharge
US9516736B2 (en) 2007-10-16 2016-12-06 Foret Plasma Labs, Llc System, method and apparatus for recovering mining fluids from mining byproducts
US9761413B2 (en) 2007-10-16 2017-09-12 Foret Plasma Labs, Llc High temperature electrolysis glow discharge device
US9560731B2 (en) 2007-10-16 2017-01-31 Foret Plasma Labs, Llc System, method and apparatus for an inductively coupled plasma Arc Whirl filter press
US10267106B2 (en) 2007-10-16 2019-04-23 Foret Plasma Labs, Llc System, method and apparatus for treating mining byproducts
US8810122B2 (en) 2007-10-16 2014-08-19 Foret Plasma Labs, Llc Plasma arc torch having multiple operating modes
US9185787B2 (en) 2007-10-16 2015-11-10 Foret Plasma Labs, Llc High temperature electrolysis glow discharge device
US9445488B2 (en) 2007-10-16 2016-09-13 Foret Plasma Labs, Llc Plasma whirl reactor apparatus and methods of use
US8146661B2 (en) 2007-10-19 2012-04-03 Shell Oil Company Cryogenic treatment of gas
US8167960B2 (en) 2007-10-22 2012-05-01 Osum Oil Sands Corp. Method of removing carbon dioxide emissions from in-situ recovery of bitumen and heavy oil
CA2705198A1 (en) * 2007-11-19 2009-05-28 Shell Internationale Research Maatschappij B.V. Systems and methods for producing oil and/or gas
CN101836072B (en) * 2007-11-19 2013-04-17 株式会社尼康 Interferometer
CN101861445B (en) * 2007-11-19 2014-06-25 国际壳牌研究有限公司 Systems and methods for producing oil and/or gas
US7905288B2 (en) * 2007-11-27 2011-03-15 Los Alamos National Security, Llc Olefin metathesis for kerogen upgrading
US20090139716A1 (en) * 2007-12-03 2009-06-04 Osum Oil Sands Corp. Method of recovering bitumen from a tunnel or shaft with heating elements and recovery wells
US8082995B2 (en) 2007-12-10 2011-12-27 Exxonmobil Upstream Research Company Optimization of untreated oil shale geometry to control subsidence
US8006407B2 (en) * 2007-12-12 2011-08-30 Richard Anderson Drying system and method of using same
US7832483B2 (en) * 2008-01-23 2010-11-16 New Era Petroleum, Llc. Methods of recovering hydrocarbons from oil shale and sub-surface oil shale recovery arrangements for recovering hydrocarbons from oil shale
WO2009098597A2 (en) 2008-02-06 2009-08-13 Osum Oil Sands Corp. Method of controlling a recovery and upgrading operation in a reservor
US8003844B2 (en) * 2008-02-08 2011-08-23 Red Leaf Resources, Inc. Methods of transporting heavy hydrocarbons
US8904749B2 (en) 2008-02-12 2014-12-09 Foret Plasma Labs, Llc Inductively coupled plasma arc device
US10244614B2 (en) 2008-02-12 2019-03-26 Foret Plasma Labs, Llc System, method and apparatus for plasma arc welding ceramics and sapphire
MX2010008819A (en) 2008-02-12 2010-11-05 Foret Plasma Labs Llc System, method and apparatus for lean combustion with plasma from an electrical arc.
US20090207302A1 (en) * 2008-02-14 2009-08-20 Chris Neffendorf Method and apparatus to measure features in a conduit
US8272216B2 (en) * 2008-02-22 2012-09-25 Toyota Jidosha Kabushiki Kaisha Method for converting solar thermal energy
US20100003184A1 (en) * 2008-02-22 2010-01-07 Toyota Jidosha Kabushiki Kaisha Method for storing solar thermal energy
US7938183B2 (en) * 2008-02-28 2011-05-10 Baker Hughes Incorporated Method for enhancing heavy hydrocarbon recovery
EP2098683A1 (en) 2008-03-04 2009-09-09 ExxonMobil Upstream Research Company Optimization of untreated oil shale geometry to control subsidence
JP5365037B2 (en) 2008-03-18 2013-12-11 トヨタ自動車株式会社 Hydrogen generator, ammonia burning internal combustion engine, and fuel cell
US7898903B2 (en) * 2008-03-28 2011-03-01 Silvano Marchetti Combined probe and corresponding seismic module for the measurement of static and dynamic properties of the soil
US20090260810A1 (en) * 2008-04-18 2009-10-22 Michael Anthony Reynolds Method for treating a hydrocarbon containing formation
WO2009129143A1 (en) 2008-04-18 2009-10-22 Shell Oil Company Systems, methods, and processes utilized for treating hydrocarbon containing subsurface formations
CA2718885C (en) 2008-05-20 2014-05-06 Osum Oil Sands Corp. Method of managing carbon reduction for hydrocarbon producers
WO2009142803A1 (en) * 2008-05-23 2009-11-26 Exxonmobil Upstream Research Company Field management for substantially constant composition gas generation
US8071037B2 (en) * 2008-06-25 2011-12-06 Cummins Filtration Ip, Inc. Catalytic devices for converting urea to ammonia
MX2011000563A (en) * 2008-07-14 2011-03-30 Shell Int Research Systems and methods for producing oil and/or gas.
US8450536B2 (en) 2008-07-17 2013-05-28 Pioneer Energy, Inc. Methods of higher alcohol synthesis
US8485257B2 (en) * 2008-08-06 2013-07-16 Chevron U.S.A. Inc. Supercritical pentane as an extractant for oil shale
CA2734188C (en) 2008-08-19 2016-11-08 Quick Connectors, Inc. High-pressure, high-temperature standoff for electrical connector in an underground well
US8278928B2 (en) * 2008-08-25 2012-10-02 Baker Hughes Incorporated Apparatus and method for detection of position of a component in an earth formation
AU2009298555B2 (en) * 2008-10-02 2016-09-22 American Shale Oil, Llc Carbon sequestration in depleted oil shale deposits
WO2010045115A2 (en) * 2008-10-13 2010-04-22 Shell Oil Company Treating subsurface hydrocarbon containing formations and the systems, methods, and processes utilized
US20100101793A1 (en) * 2008-10-29 2010-04-29 Symington William A Electrically Conductive Methods For Heating A Subsurface Formation To Convert Organic Matter Into Hydrocarbon Fluids
CA2780335A1 (en) * 2008-11-03 2010-05-03 Laricina Energy Ltd. Passive heating assisted recovery methods
CN102209835B (en) * 2008-11-06 2014-04-16 美国页岩油公司 Heater and method for recovering hydrocarbons from underground deposits
US8151482B2 (en) * 2008-11-25 2012-04-10 William H Moss Two-stage static dryer for converting organic waste to solid fuel
US8333239B2 (en) * 2009-01-16 2012-12-18 Resource Innovations Inc. Apparatus and method for downhole steam generation and enhanced oil recovery
CA2651527C (en) * 2009-01-29 2012-12-04 Imperial Oil Resources Limited Method and system for enhancing a recovery process employing one or more horizontal wellbores
WO2010088632A2 (en) 2009-02-02 2010-08-05 Glasspoint Solar, Inc. Concentrating solar power with glasshouses
US8366917B2 (en) * 2009-02-12 2013-02-05 Red Leaf Resources, Inc Methods of recovering minerals from hydrocarbonaceous material using a constructed infrastructure and associated systems
US8323481B2 (en) * 2009-02-12 2012-12-04 Red Leaf Resources, Inc. Carbon management and sequestration from encapsulated control infrastructures
BRPI1008442A2 (en) * 2009-02-12 2019-09-24 Red Leaf Resources Inc vapor barrier and collection system for encapsulated control infrastructures
BRPI1008448A2 (en) * 2009-02-12 2016-02-23 Red Leaf Resources Inc articulated plumbing connection system
US8365478B2 (en) 2009-02-12 2013-02-05 Red Leaf Resources, Inc. Intermediate vapor collection within encapsulated control infrastructures
US9758881B2 (en) * 2009-02-12 2017-09-12 The George Washington University Process for electrosynthesis of energetic molecules
EA026039B1 (en) * 2009-02-12 2017-02-28 Ред Лиф Рисорсиз, Инк. Method of recovering hydrocarbons from hydrocarbonaceous materials
US8490703B2 (en) * 2009-02-12 2013-07-23 Red Leaf Resources, Inc Corrugated heating conduit and method of using in thermal expansion and subsidence mitigation
US8349171B2 (en) 2009-02-12 2013-01-08 Red Leaf Resources, Inc. Methods of recovering hydrocarbons from hydrocarbonaceous material using a constructed infrastructure and associated systems maintained under positive pressure
CA2692885C (en) * 2009-02-19 2016-04-12 Conocophillips Company In situ combustion processes and configurations using injection and production wells
CN102325959B (en) 2009-02-23 2014-10-29 埃克森美孚上游研究公司 Water treatment following shale oil production by in situ heating
US20100236987A1 (en) * 2009-03-19 2010-09-23 Leslie Wayne Kreis Method for the integrated production and utilization of synthesis gas for production of mixed alcohols, for hydrocarbon recovery, and for gasoline/diesel refinery
CA2758192A1 (en) 2009-04-10 2010-10-14 Shell Internationale Research Maatschappij B.V. Treatment methodologies for subsurface hydrocarbon containing formations
BRPI1015966A2 (en) 2009-05-05 2016-05-31 Exxonmobil Upstream Company "method for treating an underground formation, and, computer readable storage medium."
WO2010132704A2 (en) * 2009-05-15 2010-11-18 American Shale Oil, Llc In situ method and system for extraction of oil from shale
US8025445B2 (en) * 2009-05-29 2011-09-27 Baker Hughes Incorporated Method of deployment for real time casing imaging
WO2011002557A1 (en) 2009-07-02 2011-01-06 Exxonmobil Upstream Research Company System and method for enhancing the production of hydrocarbons
KR101034722B1 (en) * 2009-07-07 2011-05-17 경희대학교 산학협력단 Measurement method for a granular compaction pile using crosshole seismic testing
CA2709241C (en) * 2009-07-17 2015-11-10 Conocophillips Company In situ combustion with multiple staged producers
US20110033238A1 (en) * 2009-08-06 2011-02-10 Bp Corporation North America Inc. Greenhouse Gas Reservoir Systems and Processes of Sequestering Greenhouse Gases
US8443888B2 (en) * 2009-08-13 2013-05-21 Baker Hughes Incorporated Apparatus and method for passive fluid control in a wellbore
US8534124B2 (en) * 2009-09-17 2013-09-17 Raytheon Company Sensor housing apparatus
US7937948B2 (en) * 2009-09-23 2011-05-10 Pioneer Energy, Inc. Systems and methods for generating electricity from carbonaceous material with substantially no carbon dioxide emissions
US8816203B2 (en) 2009-10-09 2014-08-26 Shell Oil Company Compacted coupling joint for coupling insulated conductors
US8356935B2 (en) 2009-10-09 2013-01-22 Shell Oil Company Methods for assessing a temperature in a subsurface formation
US9466896B2 (en) 2009-10-09 2016-10-11 Shell Oil Company Parallelogram coupling joint for coupling insulated conductors
US8335650B2 (en) * 2009-10-20 2012-12-18 Schlumberger Technology Corporation Methods and apparatus to determine phase-change pressures
WO2011055158A1 (en) * 2009-11-03 2011-05-12 City University Of Hong Kong A passive lc ballast and method of manufacturing a passive lc ballast
US8886502B2 (en) * 2009-11-25 2014-11-11 Halliburton Energy Services, Inc. Simulating injection treatments from multiple wells
US9176245B2 (en) * 2009-11-25 2015-11-03 Halliburton Energy Services, Inc. Refining information on subterranean fractures
US8898044B2 (en) * 2009-11-25 2014-11-25 Halliburton Energy Services, Inc. Simulating subterranean fracture propagation
AP3601A (en) 2009-12-03 2016-02-24 Red Leaf Resources Inc Methods and systems for removing fines from hydrocarbon-containing fluids
US8613312B2 (en) * 2009-12-11 2013-12-24 Technological Research Ltd Method and apparatus for stimulating wells
WO2011084497A1 (en) * 2009-12-15 2011-07-14 Chevron U.S.A. Inc. System, method and assembly for wellbore maintenance operations
CN102781548B (en) 2009-12-16 2015-04-15 红叶资源公司 Method for the removal and condensation of vapors
US8863839B2 (en) * 2009-12-17 2014-10-21 Exxonmobil Upstream Research Company Enhanced convection for in situ pyrolysis of organic-rich rock formations
JP2011145125A (en) * 2010-01-13 2011-07-28 Sumitomo Chemical Co Ltd Method for detecting abnormality in heat-exchange process
US20110174694A1 (en) * 2010-01-15 2011-07-21 Schlumberger Technology Corporation Producing hydrocarbons from oil shale based on conditions under which production of oil and bitumen are optimized
US8210773B2 (en) 2010-02-16 2012-07-03 Specialty Earth Sciences Process for insitu treatment of soil and groundwater
DE102010023542B4 (en) * 2010-02-22 2012-05-24 Siemens Aktiengesellschaft Apparatus and method for recovering, in particular recovering, a carbonaceous substance from a subterranean deposit
US9057249B2 (en) 2010-03-05 2015-06-16 Exxonmobil Upstream Research Company CO2 storage in organic-rich rock formation with hydrocarbon recovery
EP2547973B1 (en) * 2010-03-15 2014-03-19 Solaronics S.A. Drying installation
US9033042B2 (en) 2010-04-09 2015-05-19 Shell Oil Company Forming bitumen barriers in subsurface hydrocarbon formations
US8502120B2 (en) 2010-04-09 2013-08-06 Shell Oil Company Insulating blocks and methods for installation in insulated conductor heaters
US8631866B2 (en) 2010-04-09 2014-01-21 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
US8833453B2 (en) 2010-04-09 2014-09-16 Shell Oil Company Electrodes for electrical current flow heating of subsurface formations with tapered copper thickness
US9127538B2 (en) 2010-04-09 2015-09-08 Shell Oil Company Methodologies for treatment of hydrocarbon formations using staged pyrolyzation
US8939207B2 (en) 2010-04-09 2015-01-27 Shell Oil Company Insulated conductor heaters with semiconductor layers
US10041342B2 (en) * 2010-04-12 2018-08-07 Schlumberger Technology Corporation Automatic stage design of hydraulic fracture treatments using fracture height and in-situ stress
US8464792B2 (en) * 2010-04-27 2013-06-18 American Shale Oil, Llc Conduction convection reflux retorting process
AT511789B1 (en) 2010-05-13 2015-08-15 Baker Hughes Inc Prevention or mitigation of combustion gas induced steel corrosion
US8532968B2 (en) * 2010-06-16 2013-09-10 Foroil Method of improving the production of a mature gas or oil field
WO2012128877A2 (en) 2011-02-22 2012-09-27 Glasspoint Solar, Inc. Concentrating solar power with glasshouses
WO2012006288A2 (en) 2010-07-05 2012-01-12 Glasspoint Solar, Inc. Subsurface thermal energy storage of heat generated by concentrating solar power
WO2012006350A1 (en) 2010-07-07 2012-01-12 Composite Technology Development, Inc. Coiled umbilical tubing
US8755945B2 (en) * 2010-08-04 2014-06-17 Powerquest Llc Efficient computer cooling methods and apparatus
US8616280B2 (en) 2010-08-30 2013-12-31 Exxonmobil Upstream Research Company Wellbore mechanical integrity for in situ pyrolysis
WO2012030426A1 (en) 2010-08-30 2012-03-08 Exxonmobil Upstream Research Company Olefin reduction for in situ pyrolysis oil generation
US8772683B2 (en) * 2010-09-09 2014-07-08 Harris Corporation Apparatus and method for heating of hydrocarbon deposits by RF driven coaxial sleeve
US8463549B1 (en) * 2010-09-10 2013-06-11 Selman and Associates, Ltd. Method for geosteering directional drilling apparatus
US8463550B1 (en) * 2010-09-10 2013-06-11 Selman and Associates, Ltd. System for geosteering directional drilling apparatus
US8692170B2 (en) * 2010-09-15 2014-04-08 Harris Corporation Litz heating antenna
US8732946B2 (en) 2010-10-08 2014-05-27 Shell Oil Company Mechanical compaction of insulator for insulated conductor splices
US8943686B2 (en) 2010-10-08 2015-02-03 Shell Oil Company Compaction of electrical insulation for joining insulated conductors
US8857051B2 (en) 2010-10-08 2014-10-14 Shell Oil Company System and method for coupling lead-in conductor to insulated conductor
US20120089335A1 (en) * 2010-10-11 2012-04-12 Baker Hughes Incorporated Fluid pressure-viscosity analyzer for downhole fluid sampling pressure drop rate setting
US9008884B2 (en) 2010-12-15 2015-04-14 Symbotic Llc Bot position sensing
US9033033B2 (en) 2010-12-21 2015-05-19 Chevron U.S.A. Inc. Electrokinetic enhanced hydrocarbon recovery from oil shale
US8936089B2 (en) 2010-12-22 2015-01-20 Chevron U.S.A. Inc. In-situ kerogen conversion and recovery
US8615082B1 (en) * 2011-01-27 2013-12-24 Selman and Associates, Ltd. System for real-time streaming of well logging data with self-aligning satellites
US8615660B1 (en) * 2011-01-27 2013-12-24 Selman and Associates, Ltd. Cloud computing system for real-time streaming of well logging data with self-aligning satellites
US20120193092A1 (en) * 2011-01-31 2012-08-02 Baker Hughes Incorporated Apparatus and methods for tracking the location of fracturing fluid in a subterranean formation
WO2012106028A1 (en) * 2011-02-03 2012-08-09 Exxonmobill Upstream Research Company Systems and methods for managing pressure in casing annuli of subterranean wells
US9016370B2 (en) 2011-04-08 2015-04-28 Shell Oil Company Partial solution mining of hydrocarbon containing layers prior to in situ heat treatment
RU2587459C2 (en) 2011-04-08 2016-06-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Systems for joining insulated conductors
US8522881B2 (en) 2011-05-19 2013-09-03 Composite Technology Development, Inc. Thermal hydrate preventer
US9279316B2 (en) 2011-06-17 2016-03-08 Athabasca Oil Corporation Thermally assisted gravity drainage (TAGD)
US9051828B2 (en) * 2011-06-17 2015-06-09 Athabasca Oil Sands Corp. Thermally assisted gravity drainage (TAGD)
WO2013016685A1 (en) * 2011-07-27 2013-01-31 World Energy Systems Incorporated Apparatus and methods for recovery of hydrocarbons
TWI622540B (en) 2011-09-09 2018-05-01 辛波提克有限責任公司 Automated storage and retrieval system
ES2570568T5 (en) * 2011-09-09 2022-04-12 Siemens Gamesa Renewable Energy Deutschland Gmbh Wind turbine with tower air conditioning system that uses outside air
US9376901B2 (en) * 2011-09-20 2016-06-28 John Pantano Increased resource recovery by inorganic and organic reactions and subsequent physical actions that modify properties of the subterranean formation which reduces produced water waste and increases resource utilization via stimulation of biogenic methane generation
JO3139B1 (en) 2011-10-07 2017-09-20 Shell Int Research Forming insulated conductors using a final reduction step after heat treating
JO3141B1 (en) 2011-10-07 2017-09-20 Shell Int Research Integral splice for insulated conductors
WO2013052566A1 (en) 2011-10-07 2013-04-11 Shell Oil Company Using dielectric properties of an insulated conductor in a subsurface formation to assess properties of the insulated conductor
US9309755B2 (en) 2011-10-07 2016-04-12 Shell Oil Company Thermal expansion accommodation for circulated fluid systems used to heat subsurface formations
CA2845012A1 (en) 2011-11-04 2013-05-10 Exxonmobil Upstream Research Company Multiple electrical connections to optimize heating for in situ pyrolysis
WO2013106156A1 (en) * 2011-12-14 2013-07-18 Shell Oil Company System and method for producing oil
US8851177B2 (en) 2011-12-22 2014-10-07 Chevron U.S.A. Inc. In-situ kerogen conversion and oxidant regeneration
US8701788B2 (en) 2011-12-22 2014-04-22 Chevron U.S.A. Inc. Preconditioning a subsurface shale formation by removing extractible organics
US9181467B2 (en) 2011-12-22 2015-11-10 Uchicago Argonne, Llc Preparation and use of nano-catalysts for in-situ reaction with kerogen
CA2898956A1 (en) 2012-01-23 2013-08-01 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
AU2012367347A1 (en) 2012-01-23 2014-08-28 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
WO2013120260A1 (en) * 2012-02-15 2013-08-22 四川宏华石油设备有限公司 Shale gas production method
CA2811666C (en) 2012-04-05 2021-06-29 Shell Internationale Research Maatschappij B.V. Compaction of electrical insulation for joining insulated conductors
US8770284B2 (en) 2012-05-04 2014-07-08 Exxonmobil Upstream Research Company Systems and methods of detecting an intersection between a wellbore and a subterranean structure that includes a marker material
US8992771B2 (en) 2012-05-25 2015-03-31 Chevron U.S.A. Inc. Isolating lubricating oils from subsurface shale formations
WO2013180909A1 (en) * 2012-05-29 2013-12-05 Exxonmobil Upstream Research Company Systems and methods for hydrotreating a shale oil stream using hydrogen gas that is concentrated from the shale oil stream
US20140014327A1 (en) * 2012-07-13 2014-01-16 Schlumberger Technology Corporation Methodology and system for producing fluids from a condensate gas reservoir
US9175558B2 (en) 2012-07-31 2015-11-03 Raytheon Company Seismic navigation
US9945181B2 (en) * 2012-08-31 2018-04-17 Halliburton Energy Services, Inc. System and method for detecting drilling events using an opto-analytical device
EP3348783B1 (en) 2012-09-20 2020-07-15 nVent Services GmbH Downhole wellbore heating system
US11796225B2 (en) 2012-10-18 2023-10-24 American Piledriving Equipment, Inc. Geoexchange systems including ground source heat exchangers and related methods
US8978756B2 (en) * 2012-10-19 2015-03-17 Harris Corporation Hydrocarbon processing apparatus including resonant frequency tracking and related methods
DE102012220237A1 (en) * 2012-11-07 2014-05-08 Siemens Aktiengesellschaft Shielded multipair arrangement as a supply line to an inductive heating loop in heavy oil deposit applications
US20150292309A1 (en) * 2012-11-25 2015-10-15 Harold Vinegar Heater pattern including heaters powered by wind-electricity for in situ thermal processing of a subsurface hydrocarbon-containing formation
US9194199B2 (en) * 2012-12-10 2015-11-24 John Pantano Methods and systems of down-hole reagent processing and deployment
CA2894535C (en) 2012-12-11 2018-05-29 Foret Plasma Labs, Llc High temperature countercurrent vortex reactor system, method and apparatus
CA2891081A1 (en) 2012-12-27 2014-07-03 Halliburton Energy Services, Inc. Systems and methods for estimation of intra-kerogen porosity from core pyrolysis and basin modeling data
US9200799B2 (en) 2013-01-07 2015-12-01 Glasspoint Solar, Inc. Systems and methods for selectively producing steam from solar collectors and heaters for processes including enhanced oil recovery
US9309757B2 (en) * 2013-02-21 2016-04-12 Harris Corporation Radio frequency antenna assembly for hydrocarbon resource recovery including adjustable shorting plug and related methods
CN105189919B (en) 2013-03-12 2017-12-01 弗雷特等离子实验室公司 For sintering the apparatus and method of proppant
US20140262278A1 (en) * 2013-03-15 2014-09-18 Otis R. Walton Method and Apparatus for Extracting Frozen Volatiles from Subsurface Regolith
US9284826B2 (en) * 2013-03-15 2016-03-15 Chevron U.S.A. Inc. Oil extraction using radio frequency heating
US10316644B2 (en) 2013-04-04 2019-06-11 Shell Oil Company Temperature assessment using dielectric properties of an insulated conductor heater with selected electrical insulation
CA2910486C (en) * 2013-04-30 2020-04-28 Statoil Canada Limited Method of recovering thermal energy
US9476108B2 (en) * 2013-07-26 2016-10-25 Ecolab Usa Inc. Utilization of temperature heat adsorption skin temperature as scale control reagent driver
GB201414850D0 (en) * 2013-08-21 2014-10-01 Genie Ip Bv Method and system for heating a bed of rocks containing sulfur-rich type iis kerogen
US20150083411A1 (en) * 2013-09-24 2015-03-26 Oborn Environmental Solutions, LLC Automated systems and methods for production of gas from groundwater aquifers
US9417357B2 (en) 2013-09-26 2016-08-16 Harris Corporation Method for hydrocarbon recovery with change detection and related apparatus
US10006271B2 (en) 2013-09-26 2018-06-26 Harris Corporation Method for hydrocarbon recovery with a fractal pattern and related apparatus
US9976409B2 (en) 2013-10-08 2018-05-22 Halliburton Energy Services, Inc. Assembly for measuring temperature of materials flowing through tubing in a well system
WO2015053749A1 (en) 2013-10-08 2015-04-16 Halliburton Energy Services, Inc. Assembly for measuring temperature of materials flowing through tubing in a well system
CA2923681A1 (en) 2013-10-22 2015-04-30 Exxonmobil Upstream Research Company Systems and methods for regulating an in situ pyrolysis process
EP3060347B1 (en) * 2013-10-25 2017-11-01 Selfrag AG Method for fragmenting and/or pre-weakening material by means of high-voltage discharges
US10041341B2 (en) 2013-11-06 2018-08-07 Nexen Energy Ulc Processes for producing hydrocarbons from a reservoir
US9394772B2 (en) 2013-11-07 2016-07-19 Exxonmobil Upstream Research Company Systems and methods for in situ resistive heating of organic matter in a subterranean formation
US9399907B2 (en) * 2013-11-20 2016-07-26 Shell Oil Company Steam-injecting mineral insulated heater design
US9328596B2 (en) * 2014-01-21 2016-05-03 Delphi Technologies, Inc. Heater and method of operating
MX2016009971A (en) 2014-01-31 2017-06-29 Bailey Curlett Harry Method and system for subsurface resource production.
CA3176275A1 (en) 2014-02-18 2015-08-18 Athabasca Oil Corporation Cable-based well heater
GB2523567B (en) * 2014-02-27 2017-12-06 Statoil Petroleum As Producing hydrocarbons from a subsurface formation
RU2686564C2 (en) 2014-04-04 2019-04-29 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Insulated conductors, formed using the stage of final decrease dimension after thermal treatment
BG66879B1 (en) * 2014-04-30 2019-05-15 Атанасов Ковачки Христо Method and device for direction of gases at single-borehole subterranean gasification of fuels
US9864092B2 (en) * 2014-06-26 2018-01-09 Board Of Regents, The University Of Texas System Tracers for formation analysis
US9970916B2 (en) * 2014-07-29 2018-05-15 Wellntel, Inc. Wellhead water quality detector
US9451792B1 (en) * 2014-09-05 2016-09-27 Atmos Nation, LLC Systems and methods for vaporizing assembly
US10288322B2 (en) 2014-10-23 2019-05-14 Glasspoint Solar, Inc. Heat storage devices for solar steam generation, and associated systems and methods
CA2967325C (en) 2014-11-21 2019-06-18 Exxonmobil Upstream Research Company Method of recovering hydrocarbons within a subsurface formation
US10400563B2 (en) 2014-11-25 2019-09-03 Salamander Solutions, LLC Pyrolysis to pressurise oil formations
GB201421261D0 (en) * 2014-12-01 2015-01-14 Lindberg Erkki J Improvements in and relating to the processing of matrices and/or the contents of matrices
JP6448085B2 (en) * 2014-12-19 2019-01-09 ケミカルグラウト株式会社 Ground freezing method and ground freezing system
AU2015202948B2 (en) * 2014-12-22 2016-10-13 Future Energy Innovations Pty Ltd Oil and Gas Well and Field Integrity Protection System
CA2975611C (en) 2015-02-07 2019-09-17 World Energy Systems Incorporated Stimulation of light tight shale oil formations
JP7085838B2 (en) 2015-02-26 2022-06-17 シーツーシーエヌティー エルエルシー Methods and systems for manufacturing carbon nanofibers
US10030484B2 (en) 2015-04-22 2018-07-24 King Fahd University Of Petroleum And Minerals Method for estimating inflow performance relationship (IPR) of snaky oil horizontal wells
US10728956B2 (en) * 2015-05-29 2020-07-28 Watlow Electric Manufacturing Company Resistive heater with temperature sensing power pins
US10563499B2 (en) * 2015-06-26 2020-02-18 University Of Louisiana At Lafayette Method for determining pore pressure in oil and gas wells using basin thermal characteristics
US10132130B2 (en) 2015-08-18 2018-11-20 Joy Global Surface Mining Inc Combustor for heating of airflow on a drill rig
UA121420C2 (en) 2015-09-30 2020-05-25 Ред Ліф Рісорсіз, Інк. Staged zone heating of hydrocarbons bearing materials
WO2017066295A1 (en) 2015-10-13 2017-04-20 Clarion Energy Llc Methods and systems for carbon nanofiber production
WO2017091688A1 (en) * 2015-11-23 2017-06-01 Gtherm Energy, Inc. Reservoir modeling system for enhanced oil recovery
US10983246B2 (en) * 2015-12-21 2021-04-20 Schlumberger Technology Corporation Thermal maturity estimation via logs
AU2017216399A1 (en) 2016-02-01 2018-08-09 Glasspoint Solar, Inc. Separators and mixers for delivering controlled-quality solar-generated steam over long distances for enhanced oil recovery, and associated systems and methods
DK3414425T3 (en) * 2016-02-08 2022-10-24 Proton Tech Inc IN-SITU METHOD FOR PRODUCING HYDROGEN FROM UNDERGROUND HYDROCARBON RESERVOIRS
US10577973B2 (en) 2016-02-18 2020-03-03 General Electric Company Service tube for a turbine engine
US10677626B2 (en) * 2016-03-01 2020-06-09 Besst, Inc. Flowmeter profiling system for use in groundwater production wells and boreholes
CN105840183B (en) * 2016-05-05 2022-05-24 中国石油天然气集团有限公司 Underground temperature and pressure parameter measuring circuit and measuring method thereof
FR3053034A1 (en) * 2016-06-22 2017-12-29 Gauchi Georges Martino PROCESS FOR PRODUCING SHALE HYDROGEN
US10202733B2 (en) 2016-08-05 2019-02-12 Csi Technologies Llc Method of using low-density, freezable fluid to create a flow barrier in a well
RU2637490C1 (en) * 2016-10-28 2017-12-05 Акционерное общество "Ордена Трудового Красного Знамени и ордена труда ЧССР опытное конструкторское бюро "ГИДРОПРЕСС" Device for electric heating of bath for deactivation
US10647045B1 (en) 2016-11-03 2020-05-12 Specialty Earth Sciences, Llc Shaped or sized encapsulated reactant and method of making
US10253608B2 (en) 2017-03-14 2019-04-09 Saudi Arabian Oil Company Downhole heat orientation and controlled fracture initiation using electromagnetic assisted ceramic materials
RU2018139429A (en) * 2017-04-18 2021-05-18 Интеллиджент Уэллхэд Системс Инк. DEVICE AND METHOD FOR CONTROL OF FLEXIBLE PIPE COLUMN
CN107100663B (en) * 2017-05-02 2019-08-06 中国矿业大学 A kind of accurate pumping method of coal mine gas
AU2018265269A1 (en) 2017-05-10 2019-12-12 Gcp Applied Technologies Inc. In-situ barrier device with internal injection conduit
WO2018226991A1 (en) 2017-06-07 2018-12-13 Shifamed Holdings, Llc Intravascular fluid movement devices, systems, and methods of use
US10378299B2 (en) 2017-06-08 2019-08-13 Csi Technologies Llc Method of producing resin composite with required thermal and mechanical properties to form a durable well seal in applications
US10428261B2 (en) 2017-06-08 2019-10-01 Csi Technologies Llc Resin composite with overloaded solids for well sealing applications
CA2972203C (en) 2017-06-29 2018-07-17 Exxonmobil Upstream Research Company Chasing solvent for enhanced recovery processes
CN109285137A (en) * 2017-07-21 2019-01-29 中国石油大学(北京) The acquisition methods and device of shale hole contribution degree
CA2974712C (en) 2017-07-27 2018-09-25 Imperial Oil Resources Limited Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes
CA2978157C (en) 2017-08-31 2018-10-16 Exxonmobil Upstream Research Company Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation
CN109594969A (en) * 2017-09-28 2019-04-09 中国石油天然气股份有限公司 The analytic method of vapor chamber
US20190122785A1 (en) * 2017-10-19 2019-04-25 Shell Oil Company Mineral insulated power cables for electric motor driven integral compressors
CA2983541C (en) 2017-10-24 2019-01-22 Exxonmobil Upstream Research Company Systems and methods for dynamic liquid level monitoring and control
WO2019094963A1 (en) 2017-11-13 2019-05-16 Shifamed Holdings, Llc Intravascular fluid movement devices, systems, and methods of use
CN109838230B (en) * 2017-11-28 2022-06-03 中国石油天然气股份有限公司 Quantitative evaluation method for oil reservoir water flooded layer
CN109989746A (en) * 2017-12-29 2019-07-09 中国石油天然气股份有限公司 The method and apparatus of Evaluation of Carbonate Reservoir
CN112004563A (en) 2018-02-01 2020-11-27 施菲姆德控股有限责任公司 Intravascular blood pump and methods of use and manufacture
WO2019168520A1 (en) * 2018-02-28 2019-09-06 Trs Group, Inc. Thermal conduction heater well and electrical resistance heating electrode
US11126762B2 (en) * 2018-02-28 2021-09-21 Saudi Arabian Oil Company Locating new hydrocarbon fields and predicting reservoir performance from hydrocarbon migration
TN2020000184A1 (en) * 2018-03-06 2022-04-04 Proton Tech Canada Inc In-situ process to produce synthesis gas from underground hydrocarbon reservoirs
US10669829B2 (en) * 2018-03-20 2020-06-02 Saudi Arabian Oil Company Using electromagnetic waves to remove near wellbore damages in a hydrocarbon reservoir
US10739607B2 (en) * 2018-03-22 2020-08-11 Industrial Technology Research Institute Light source module, sensing device and method for generating superposition structured patterns
CN108629505A (en) * 2018-05-02 2018-10-09 长安大学 A kind of Construction of Asphalt Pavement carbon emission method for quantitatively evaluating
CN108798648A (en) * 2018-06-07 2018-11-13 西南石油大学 A kind of hypotonic tight gas reservoir improvement positive sequence modified isochronal test method
CN108868756B (en) * 2018-06-22 2021-11-02 西南石油大学 Coal reservoir rock structure complexity evaluation method based on logging information
CN109033012B (en) * 2018-06-28 2023-01-06 中国石油天然气股份有限公司 Method and device for determining temperature field of hollow sucker rod hot water injection circulation shaft
CN109339775A (en) * 2018-10-25 2019-02-15 西南石油大学 A kind of method of determining water drive gas reservoir Living space
US11053775B2 (en) * 2018-11-16 2021-07-06 Leonid Kovalev Downhole induction heater
CN109536151B (en) * 2019-01-08 2021-11-02 中国石油天然气股份有限公司 Solution type combustion-supporting channeling sealing agent for fireflooding oil reservoir
CN109852360B (en) * 2019-01-08 2021-11-02 中国石油天然气股份有限公司 Turbid liquid type fire flooding oil reservoir combustion-supporting channeling-sealing agent
US10788547B2 (en) 2019-01-17 2020-09-29 Sandisk Technologies Llc Voltage-controlled interlayer exchange coupling magnetoresistive memory device and method of operating thereof
US11049538B2 (en) 2019-01-17 2021-06-29 Western Digital Technologies, Inc. Voltage-controlled interlayer exchange coupling magnetoresistive memory device and method of operating thereof
CN109736763A (en) * 2019-02-02 2019-05-10 吉林大学 A kind of high-temperature gas auxiliary eddy current heating device and eddy heating for heating method
US11654275B2 (en) 2019-07-22 2023-05-23 Shifamed Holdings, Llc Intravascular blood pumps with struts and methods of use and manufacture
CN110376666B (en) * 2019-07-25 2022-07-26 江西师范大学 Ultra-wideband perfect absorber of mid-infrared band and preparation method thereof
CN112624549A (en) * 2019-09-24 2021-04-09 王其成 High-liquid-content oil sludge cracking treatment device and process
EP4034192A4 (en) 2019-09-25 2023-11-29 Shifamed Holdings, LLC Intravascular blood pump systems and methods of use and control thereof
CN110965999B (en) * 2019-12-24 2022-04-12 中国石油集团渤海钻探工程有限公司 Shale oil dominant lithology fine identification method
US11506050B2 (en) 2019-12-27 2022-11-22 Adams Testing Service, Inc. Hydraulic pressure testing system, and method of testing tubular products
CN111353227B (en) * 2020-02-28 2023-03-14 西安石油大学 CO based on cross-scale multi-flow space gas transmission mechanism 2 Dynamic simulation method for strengthening shale gas reservoir development
AR123020A1 (en) 2020-07-21 2022-10-26 Red Leaf Resources Inc METHODS FOR PROCESSING OIL SHALE IN STAGES
CN112084718B (en) * 2020-09-16 2021-05-04 西南石油大学 Shale gas reservoir single-phase gas three-hole three-permeation model construction method based on seepage difference
CN112160738B (en) * 2020-09-18 2021-12-28 西安交通大学 Well arrangement structure for underground in-situ pyrolysis of coal and construction method thereof
US11125069B1 (en) 2021-01-19 2021-09-21 Ergo Exergy Technologies Inc. Underground coal gasification and associated systems and methods
US11642709B1 (en) 2021-03-04 2023-05-09 Trs Group, Inc. Optimized flux ERH electrode
WO2022226292A1 (en) 2021-04-22 2022-10-27 Brown Charles J Laser-based gasification of carbonaceous materials, and related systems and methods
CN113075027B (en) * 2021-04-27 2022-05-31 长沙理工大学 Test device and method for measuring dynamic elastic modulus of soil body model
CN113216918B (en) * 2021-05-08 2022-09-13 西南石油大学 Method for improving shale oil reservoir recovery ratio by catalytic oxidation combustion fracturing reservoir
WO2022241194A1 (en) 2021-05-14 2022-11-17 Brown Charles J Depositing materials in a gaseous state using a laser-based applicator, and related methods, apparatuses, and systems
CN113027403B (en) * 2021-05-27 2021-08-06 中国煤炭地质总局勘查研究总院 Method for injecting hot steam into coal seam and electronic equipment
CN113514886B (en) * 2021-07-22 2021-12-10 核工业北京地质研究院 Geological-seismic three-dimensional prediction method for beneficial part of sandstone-type uranium deposit mineralization
WO2023102046A1 (en) * 2021-11-30 2023-06-08 Schlumberger Technology Corporation Hydrate operations system
CN115095306A (en) * 2022-06-14 2022-09-23 中国石油大学(华东) Oil shale air/CO 2 Alternate injection in-situ combustion method and application
CN115559695B (en) * 2022-11-09 2023-03-14 中国矿业大学 Mining area multi-source industrial flue gas collaborative flooding coalbed methane sealing method and system
CN117345161B (en) * 2023-11-30 2024-02-06 河北华运鸿业化工有限公司 Self-adaptive compound determination method, system and actuator for emulsified asphalt plugging agent

Family Cites Families (909)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2734579A (en) * 1956-02-14 Production from bituminous sands
SE123138C1 (en) 1948-01-01
US345586A (en) * 1886-07-13 Oil from wells
US48994A (en) 1865-07-25 Improvement in devices for oil-wells
SE126674C1 (en) 1949-01-01
US326439A (en) 1885-09-15 Protecting wells
US94813A (en) 1869-09-14 Improvement in torpedoes for oil-wells
US2732195A (en) 1956-01-24 Ljungstrom
CA899987A (en) 1972-05-09 Chisso Corporation Method for controlling heat generation locally in a heat-generating pipe utilizing skin effect current
SE123136C1 (en) 1948-01-01
US760304A (en) * 1903-10-24 1904-05-17 Frank S Gilbert Heater for oil-wells.
US1342741A (en) 1918-01-17 1920-06-08 David T Day Process for extracting oils and hydrocarbon material from shale and similar bituminous rocks
US1269747A (en) 1918-04-06 1918-06-18 Lebbeus H Rogers Method of and apparatus for treating oil-shale.
GB156396A (en) 1919-12-10 1921-01-13 Wilson Woods Hoover An improved method of treating shale and recovering oil therefrom
US1457479A (en) * 1920-01-12 1923-06-05 Edson R Wolcott Method of increasing the yield of oil wells
US1510655A (en) * 1922-11-21 1924-10-07 Clark Cornelius Process of subterranean distillation of volatile mineral substances
US1634236A (en) * 1925-03-10 1927-06-28 Standard Dev Co Method of and apparatus for recovering oil
US1646599A (en) 1925-04-30 1927-10-25 George A Schaefer Apparatus for removing fluid from wells
US1811560A (en) * 1926-04-08 1931-06-23 Standard Oil Dev Co Method of and apparatus for recovering oil
US1666488A (en) 1927-02-05 1928-04-17 Crawshaw Richard Apparatus for extracting oil from shale
US1681523A (en) 1927-03-26 1928-08-21 Patrick V Downey Apparatus for heating oil wells
US1913395A (en) 1929-11-14 1933-06-13 Lewis C Karrick Underground gasification of carbonaceous material-bearing substances
US2244255A (en) * 1939-01-18 1941-06-03 Electrical Treating Company Well clearing system
US2244256A (en) 1939-12-16 1941-06-03 Electrical Treating Company Apparatus for clearing wells
US2319702A (en) * 1941-04-04 1943-05-18 Socony Vacuum Oil Co Inc Method and apparatus for producing oil wells
US2365591A (en) 1942-08-15 1944-12-19 Ranney Leo Method for producing oil from viscous deposits
US2423674A (en) * 1942-08-24 1947-07-08 Johnson & Co A Process of catalytic cracking of petroleum hydrocarbons
US2381256A (en) * 1942-10-06 1945-08-07 Texas Co Process for treating hydrocarbon fractions
US2390770A (en) 1942-10-10 1945-12-11 Sun Oil Co Method of producing petroleum
US2484063A (en) 1944-08-19 1949-10-11 Thermactor Corp Electric heater for subsurface materials
US2472445A (en) 1945-02-02 1949-06-07 Thermactor Company Apparatus for treating oil and gas bearing strata
US2481051A (en) * 1945-12-15 1949-09-06 Texaco Development Corp Process and apparatus for the recovery of volatilizable constituents from underground carbonaceous formations
US2444755A (en) * 1946-01-04 1948-07-06 Ralph M Steffen Apparatus for oil sand heating
US2634961A (en) 1946-01-07 1953-04-14 Svensk Skifferolje Aktiebolage Method of electrothermal production of shale oil
US2466945A (en) 1946-02-21 1949-04-12 In Situ Gases Inc Generation of synthesis gas
US2484806A (en) 1946-02-23 1949-10-18 Carl B Albert Garment blocker
US2497868A (en) * 1946-10-10 1950-02-21 Dalin David Underground exploitation of fuel deposits
US2939689A (en) * 1947-06-24 1960-06-07 Svenska Skifferolje Ab Electrical heater for treating oilshale and the like
US2786660A (en) 1948-01-05 1957-03-26 Phillips Petroleum Co Apparatus for gasifying coal
US2548360A (en) * 1948-03-29 1951-04-10 Stanley A Germain Electric oil well heater
US2584605A (en) 1948-04-14 1952-02-05 Edmund S Merriam Thermal drive method for recovery of oil
US2685930A (en) * 1948-08-12 1954-08-10 Union Oil Co Oil well production process
US2630307A (en) * 1948-12-09 1953-03-03 Carbonic Products Inc Method of recovering oil from oil shale
US2595979A (en) * 1949-01-25 1952-05-06 Texas Co Underground liquefaction of coal
US2642943A (en) * 1949-05-20 1953-06-23 Sinclair Oil & Gas Co Oil recovery process
US2593477A (en) 1949-06-10 1952-04-22 Us Interior Process of underground gasification of coal
GB674082A (en) 1949-06-15 1952-06-18 Nat Res Dev Improvements in or relating to the underground gasification of coal
US2670802A (en) * 1949-12-16 1954-03-02 Thermactor Company Reviving or increasing the production of clogged or congested oil wells
US2623596A (en) 1950-05-16 1952-12-30 Atlantic Refining Co Method for producing oil by means of carbon dioxide
US2714930A (en) 1950-12-08 1955-08-09 Union Oil Co Apparatus for preventing paraffin deposition
US2695163A (en) 1950-12-09 1954-11-23 Stanolind Oil & Gas Co Method for gasification of subterranean carbonaceous deposits
GB697189A (en) 1951-04-09 1953-09-16 Nat Res Dev Improvements relating to the underground gasification of coal
US2630306A (en) 1952-01-03 1953-03-03 Socony Vacuum Oil Co Inc Subterranean retorting of shales
US2757739A (en) 1952-01-07 1956-08-07 Parelex Corp Heating apparatus
US2780450A (en) * 1952-03-07 1957-02-05 Svenska Skifferolje Ab Method of recovering oil and gases from non-consolidated bituminous geological formations by a heating treatment in situ
US2777679A (en) 1952-03-07 1957-01-15 Svenska Skifferolje Ab Recovering sub-surface bituminous deposits by creating a frozen barrier and heating in situ
US2789805A (en) * 1952-05-27 1957-04-23 Svenska Skifferolje Ab Device for recovering fuel from subterraneous fuel-carrying deposits by heating in their natural location using a chain heat transfer member
US2761663A (en) * 1952-09-05 1956-09-04 Louis F Gerdetz Process of underground gasification of coal
US2780449A (en) 1952-12-26 1957-02-05 Sinclair Oil & Gas Co Thermal process for in-situ decomposition of oil shale
US2825408A (en) 1953-03-09 1958-03-04 Sinclair Oil & Gas Company Oil recovery by subsurface thermal processing
US2783971A (en) 1953-03-11 1957-03-05 Engineering Lab Inc Apparatus for earth boring with pressurized air
US2771954A (en) 1953-04-29 1956-11-27 Exxon Research Engineering Co Treatment of petroleum production wells
US2703621A (en) * 1953-05-04 1955-03-08 George W Ford Oil well bottom hole flow increasing unit
US2743906A (en) 1953-05-08 1956-05-01 William E Coyle Hydraulic underreamer
US2803305A (en) * 1953-05-14 1957-08-20 Pan American Petroleum Corp Oil recovery by underground combustion
US2914309A (en) * 1953-05-25 1959-11-24 Svenska Skifferolje Ab Oil and gas recovery from tar sands
US2902270A (en) 1953-07-17 1959-09-01 Svenska Skifferolje Ab Method of and means in heating of subsurface fuel-containing deposits "in situ"
US2890754A (en) * 1953-10-30 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2890755A (en) 1953-12-19 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2841375A (en) * 1954-03-03 1958-07-01 Svenska Skifferolje Ab Method for in-situ utilization of fuels by combustion
US2794504A (en) * 1954-05-10 1957-06-04 Union Oil Co Well heater
US2793696A (en) 1954-07-22 1957-05-28 Pan American Petroleum Corp Oil recovery by underground combustion
US2923535A (en) * 1955-02-11 1960-02-02 Svenska Skifferolje Ab Situ recovery from carbonaceous deposits
US2799341A (en) 1955-03-04 1957-07-16 Union Oil Co Selective plugging in oil wells
US2801089A (en) * 1955-03-14 1957-07-30 California Research Corp Underground shale retorting process
US2862558A (en) 1955-12-28 1958-12-02 Phillips Petroleum Co Recovering oils from formations
US2819761A (en) * 1956-01-19 1958-01-14 Continental Oil Co Process of removing viscous oil from a well bore
US2857002A (en) 1956-03-19 1958-10-21 Texas Co Recovery of viscous crude oil
US2906340A (en) * 1956-04-05 1959-09-29 Texaco Inc Method of treating a petroleum producing formation
US2991046A (en) * 1956-04-16 1961-07-04 Parsons Lional Ashley Combined winch and bollard device
US2889882A (en) * 1956-06-06 1959-06-09 Phillips Petroleum Co Oil recovery by in situ combustion
US3120264A (en) * 1956-07-09 1964-02-04 Texaco Development Corp Recovery of oil by in situ combustion
US3016053A (en) 1956-08-02 1962-01-09 George J Medovick Underwater breathing apparatus
US2997105A (en) 1956-10-08 1961-08-22 Pan American Petroleum Corp Burner apparatus
US2932352A (en) 1956-10-25 1960-04-12 Union Oil Co Liquid filled well heater
US2804149A (en) 1956-12-12 1957-08-27 John R Donaldson Oil well heater and reviver
US2952449A (en) 1957-02-01 1960-09-13 Fmc Corp Method of forming underground communication between boreholes
US3127936A (en) * 1957-07-26 1964-04-07 Svenska Skifferolje Ab Method of in situ heating of subsurface preferably fuel containing deposits
US2942223A (en) 1957-08-09 1960-06-21 Gen Electric Electrical resistance heater
US2906337A (en) * 1957-08-16 1959-09-29 Pure Oil Co Method of recovering bitumen
US3007521A (en) * 1957-10-28 1961-11-07 Phillips Petroleum Co Recovery of oil by in situ combustion
US3010516A (en) * 1957-11-18 1961-11-28 Phillips Petroleum Co Burner and process for in situ combustion
US2954826A (en) 1957-12-02 1960-10-04 William E Sievers Heated well production string
US2994376A (en) * 1957-12-27 1961-08-01 Phillips Petroleum Co In situ combustion process
US3061009A (en) * 1958-01-17 1962-10-30 Svenska Skifferolje Ab Method of recovery from fossil fuel bearing strata
US3062282A (en) * 1958-01-24 1962-11-06 Phillips Petroleum Co Initiation of in situ combustion in a carbonaceous stratum
US3051235A (en) 1958-02-24 1962-08-28 Jersey Prod Res Co Recovery of petroleum crude oil, by in situ combustion and in situ hydrogenation
US3004603A (en) 1958-03-07 1961-10-17 Phillips Petroleum Co Heater
US3032102A (en) 1958-03-17 1962-05-01 Phillips Petroleum Co In situ combustion method
US3004596A (en) * 1958-03-28 1961-10-17 Phillips Petroleum Co Process for recovery of hydrocarbons by in situ combustion
US3004601A (en) 1958-05-09 1961-10-17 Albert G Bodine Method and apparatus for augmenting oil recovery from wells by refrigeration
US3048221A (en) 1958-05-12 1962-08-07 Phillips Petroleum Co Hydrocarbon recovery by thermal drive
US3026940A (en) 1958-05-19 1962-03-27 Electronic Oil Well Heater Inc Oil well temperature indicator and control
US3010513A (en) * 1958-06-12 1961-11-28 Phillips Petroleum Co Initiation of in situ combustion in carbonaceous stratum
US2958519A (en) 1958-06-23 1960-11-01 Phillips Petroleum Co In situ combustion process
US3044545A (en) * 1958-10-02 1962-07-17 Phillips Petroleum Co In situ combustion process
US3050123A (en) * 1958-10-07 1962-08-21 Cities Service Res & Dev Co Gas fired oil-well burner
US2950240A (en) * 1958-10-10 1960-08-23 Socony Mobil Oil Co Inc Selective cracking of aliphatic hydrocarbons
US2974937A (en) * 1958-11-03 1961-03-14 Jersey Prod Res Co Petroleum recovery from carbonaceous formations
US2998457A (en) * 1958-11-19 1961-08-29 Ashland Oil Inc Production of phenols
US2970826A (en) 1958-11-21 1961-02-07 Texaco Inc Recovery of oil from oil shale
US3036632A (en) * 1958-12-24 1962-05-29 Socony Mobil Oil Co Inc Recovery of hydrocarbon materials from earth formations by application of heat
US3097690A (en) 1958-12-24 1963-07-16 Gulf Research Development Co Process for heating a subsurface formation
US2969226A (en) 1959-01-19 1961-01-24 Pyrochem Corp Pendant parting petro pyrolysis process
US3017168A (en) * 1959-01-26 1962-01-16 Phillips Petroleum Co In situ retorting of oil shale
US3110345A (en) * 1959-02-26 1963-11-12 Gulf Research Development Co Low temperature reverse combustion process
US3113619A (en) * 1959-03-30 1963-12-10 Phillips Petroleum Co Line drive counterflow in situ combustion process
US3113620A (en) 1959-07-06 1963-12-10 Exxon Research Engineering Co Process for producing viscous oil
US3113623A (en) 1959-07-20 1963-12-10 Union Oil Co Apparatus for underground retorting
US3181613A (en) 1959-07-20 1965-05-04 Union Oil Co Method and apparatus for subterranean heating
US3132692A (en) * 1959-07-27 1964-05-12 Phillips Petroleum Co Use of formation heat from in situ combustion
US3116792A (en) 1959-07-27 1964-01-07 Phillips Petroleum Co In situ combustion process
US3150715A (en) 1959-09-30 1964-09-29 Shell Oil Co Oil recovery by in situ combustion with water injection
US3079085A (en) 1959-10-21 1963-02-26 Clark Apparatus for analyzing the production and drainage of petroleum reservoirs, and the like
US3095031A (en) 1959-12-09 1963-06-25 Eurenius Malte Oscar Burners for use in bore holes in the ground
US3131763A (en) * 1959-12-30 1964-05-05 Texaco Inc Electrical borehole heater
US3163745A (en) 1960-02-29 1964-12-29 Socony Mobil Oil Co Inc Heating of an earth formation penetrated by a well borehole
US3127935A (en) 1960-04-08 1964-04-07 Marathon Oil Co In situ combustion for oil recovery in tar sands, oil shales and conventional petroleum reservoirs
US3137347A (en) 1960-05-09 1964-06-16 Phillips Petroleum Co In situ electrolinking of oil shale
US3139928A (en) 1960-05-24 1964-07-07 Shell Oil Co Thermal process for in situ decomposition of oil shale
US3058730A (en) 1960-06-03 1962-10-16 Fmc Corp Method of forming underground communication between boreholes
US3106244A (en) * 1960-06-20 1963-10-08 Phillips Petroleum Co Process for producing oil shale in situ by electrocarbonization
US3142336A (en) 1960-07-18 1964-07-28 Shell Oil Co Method and apparatus for injecting steam into subsurface formations
US3084919A (en) * 1960-08-03 1963-04-09 Texaco Inc Recovery of oil from oil shale by underground hydrogenation
US3165152A (en) 1960-08-11 1965-01-12 Int Harvester Co Counter flow heat exchanger
US3105545A (en) * 1960-11-21 1963-10-01 Shell Oil Co Method of heating underground formations
US3164207A (en) * 1961-01-17 1965-01-05 Wayne H Thessen Method for recovering oil
US3191679A (en) 1961-04-13 1965-06-29 Wendell S Miller Melting process for recovering bitumens from the earth
US3207220A (en) 1961-06-26 1965-09-21 Chester I Williams Electric well heater
US3114417A (en) 1961-08-14 1963-12-17 Ernest T Saftig Electric oil well heater apparatus
US3246695A (en) 1961-08-21 1966-04-19 Charles L Robinson Method for heating minerals in situ with radioactive materials
US3057404A (en) 1961-09-29 1962-10-09 Socony Mobil Oil Co Inc Method and system for producing oil tenaciously held in porous formations
US3183675A (en) 1961-11-02 1965-05-18 Conch Int Methane Ltd Method of freezing an earth formation
US3170842A (en) 1961-11-06 1965-02-23 Phillips Petroleum Co Subcritical borehole nuclear reactor and process
US3209825A (en) 1962-02-14 1965-10-05 Continental Oil Co Low temperature in-situ combustion
US3205946A (en) 1962-03-12 1965-09-14 Shell Oil Co Consolidation by silica coalescence
US3165154A (en) 1962-03-23 1965-01-12 Phillips Petroleum Co Oil recovery by in situ combustion
US3149670A (en) 1962-03-27 1964-09-22 Smclair Res Inc In-situ heating process
US3149672A (en) * 1962-05-04 1964-09-22 Jersey Prod Res Co Method and apparatus for electrical heating of oil-bearing formations
US3208531A (en) 1962-08-21 1965-09-28 Otis Eng Co Inserting tool for locating and anchoring a device in tubing
US3182721A (en) 1962-11-02 1965-05-11 Sun Oil Co Method of petroleum production by forward in situ combustion
US3288648A (en) * 1963-02-04 1966-11-29 Pan American Petroleum Corp Process for producing electrical energy from geological liquid hydrocarbon formation
US3205942A (en) 1963-02-07 1965-09-14 Socony Mobil Oil Co Inc Method for recovery of hydrocarbons by in situ heating of oil shale
US3221811A (en) 1963-03-11 1965-12-07 Shell Oil Co Mobile in-situ heating of formations
US3250327A (en) 1963-04-02 1966-05-10 Socony Mobil Oil Co Inc Recovering nonflowing hydrocarbons
US3244231A (en) * 1963-04-09 1966-04-05 Pan American Petroleum Corp Method for catalytically heating oil bearing formations
US3241611A (en) 1963-04-10 1966-03-22 Equity Oil Company Recovery of petroleum products from oil shale
GB959945A (en) 1963-04-18 1964-06-03 Conch Int Methane Ltd Constructing a frozen wall within the ground
US3237689A (en) * 1963-04-29 1966-03-01 Clarence I Justheim Distillation of underground deposits of solid carbonaceous materials in situ
US3223166A (en) * 1963-05-27 1965-12-14 Pan American Petroleum Corp Method of controlled catalytic heating of a subsurface formation
US3205944A (en) 1963-06-14 1965-09-14 Socony Mobil Oil Co Inc Recovery of hydrocarbons from a subterranean reservoir by heating
US3244213A (en) * 1963-10-09 1966-04-05 Goodyear Tire & Rubber Pneumatic tire
US3233668A (en) 1963-11-15 1966-02-08 Exxon Production Research Co Recovery of shale oil
US3285335A (en) * 1963-12-11 1966-11-15 Exxon Research Engineering Co In situ pyrolysis of oil shale formations
US3273640A (en) * 1963-12-13 1966-09-20 Pyrochem Corp Pressure pulsing perpendicular permeability process for winning stabilized primary volatiles from oil shale in situ
US3303883A (en) 1964-01-06 1967-02-14 Mobil Oil Corp Thermal notching technique
US3275076A (en) 1964-01-13 1966-09-27 Mobil Oil Corp Recovery of asphaltic-type petroleum from a subterranean reservoir
US3342258A (en) 1964-03-06 1967-09-19 Shell Oil Co Underground oil recovery from solid oil-bearing deposits
US3294167A (en) 1964-04-13 1966-12-27 Shell Oil Co Thermal oil recovery
US3284281A (en) 1964-08-31 1966-11-08 Phillips Petroleum Co Production of oil from oil shale through fractures
US3302707A (en) 1964-09-30 1967-02-07 Mobil Oil Corp Method for improving fluid recoveries from earthen formations
US3310109A (en) 1964-11-06 1967-03-21 Phillips Petroleum Co Process and apparatus for combination upgrading of oil in situ and refining thereof
US3380913A (en) * 1964-12-28 1968-04-30 Phillips Petroleum Co Refining of effluent from in situ combustion operation
US3332480A (en) 1965-03-04 1967-07-25 Pan American Petroleum Corp Recovery of hydrocarbons by thermal methods
US3338306A (en) 1965-03-09 1967-08-29 Mobil Oil Corp Recovery of heavy oil from oil sands
US3358756A (en) 1965-03-12 1967-12-19 Shell Oil Co Method for in situ recovery of solid or semi-solid petroleum deposits
US3262741A (en) 1965-04-01 1966-07-26 Pittsburgh Plate Glass Co Solution mining of potassium chloride
DE1242535B (en) 1965-04-13 1967-06-22 Deutsche Erdoel Ag Process for the removal of residual oil from oil deposits
US3316344A (en) 1965-04-26 1967-04-25 Central Electr Generat Board Prevention of icing of electrical conductors
US3342267A (en) 1965-04-29 1967-09-19 Gerald S Cotter Turbo-generator heater for oil and gas wells and pipe lines
US3278234A (en) 1965-05-17 1966-10-11 Pittsburgh Plate Glass Co Solution mining of potassium chloride
US3352355A (en) * 1965-06-23 1967-11-14 Dow Chemical Co Method of recovery of hydrocarbons from solid hydrocarbonaceous formations
US3346044A (en) 1965-09-08 1967-10-10 Mobil Oil Corp Method and structure for retorting oil shale in situ by cycling fluid flows
US3349845A (en) 1965-10-22 1967-10-31 Sinclair Oil & Gas Company Method of establishing communication between wells
US3379248A (en) 1965-12-10 1968-04-23 Mobil Oil Corp In situ combustion process utilizing waste heat
US3424254A (en) 1965-12-29 1969-01-28 Major Walter Huff Cryogenic method and apparatus for drilling hot geothermal zones
US3454365A (en) * 1966-02-18 1969-07-08 Phillips Petroleum Co Analysis and control of in situ combustion of underground carbonaceous deposit
US3386508A (en) * 1966-02-21 1968-06-04 Exxon Production Research Co Process and system for the recovery of viscous oil
US3362751A (en) 1966-02-28 1968-01-09 Tinlin William Method and system for recovering shale oil and gas
US3595082A (en) 1966-03-04 1971-07-27 Gulf Oil Corp Temperature measuring apparatus
US3410977A (en) 1966-03-28 1968-11-12 Ando Masao Method of and apparatus for heating the surface part of various construction materials
DE1615192B1 (en) 1966-04-01 1970-08-20 Chisso Corp Inductively heated heating pipe
US3513913A (en) 1966-04-19 1970-05-26 Shell Oil Co Oil recovery from oil shales by transverse combustion
US3372754A (en) 1966-05-31 1968-03-12 Mobil Oil Corp Well assembly for heating a subterranean formation
US3399623A (en) 1966-07-14 1968-09-03 James R. Creed Apparatus for and method of producing viscid oil
US3412011A (en) 1966-09-02 1968-11-19 Phillips Petroleum Co Catalytic cracking and in situ combustion process for producing hydrocarbons
NL153755C (en) 1966-10-20 1977-11-15 Stichting Reactor Centrum METHOD FOR MANUFACTURING AN ELECTRIC HEATING ELEMENT, AS WELL AS HEATING ELEMENT MANUFACTURED USING THIS METHOD.
US3465819A (en) 1967-02-13 1969-09-09 American Oil Shale Corp Use of nuclear detonations in producing hydrocarbons from an underground formation
US3389975A (en) 1967-03-10 1968-06-25 Sinclair Research Inc Process for the recovery of aluminum values from retorted shale and conversion of sodium aluminate to sodium aluminum carbonate hydroxide
NL6803827A (en) 1967-03-22 1968-09-23
US3438439A (en) 1967-05-29 1969-04-15 Pan American Petroleum Corp Method for plugging formations by production of sulfur therein
US3622071A (en) 1967-06-08 1971-11-23 Combustion Eng Crude petroleum transmission system
US3474863A (en) 1967-07-28 1969-10-28 Shell Oil Co Shale oil extraction process
US3528501A (en) 1967-08-04 1970-09-15 Phillips Petroleum Co Recovery of oil from oil shale
US3480082A (en) 1967-09-25 1969-11-25 Continental Oil Co In situ retorting of oil shale using co2 as heat carrier
US3434541A (en) * 1967-10-11 1969-03-25 Mobil Oil Corp In situ combustion process
US3485300A (en) 1967-12-20 1969-12-23 Phillips Petroleum Co Method and apparatus for defoaming crude oil down hole
US3477058A (en) 1968-02-01 1969-11-04 Gen Electric Magnesia insulated heating elements and methods of production
US3580987A (en) 1968-03-26 1971-05-25 Pirelli Electric cable
US3455383A (en) * 1968-04-24 1969-07-15 Shell Oil Co Method of producing fluidized material from a subterranean formation
US3578080A (en) 1968-06-10 1971-05-11 Shell Oil Co Method of producing shale oil from an oil shale formation
US3497000A (en) * 1968-08-19 1970-02-24 Pan American Petroleum Corp Bottom hole catalytic heater
US3529682A (en) * 1968-10-03 1970-09-22 Bell Telephone Labor Inc Location detection and guidance systems for burrowing device
US3537528A (en) 1968-10-14 1970-11-03 Shell Oil Co Method for producing shale oil from an exfoliated oil shale formation
US3593789A (en) 1968-10-18 1971-07-20 Shell Oil Co Method for producing shale oil from an oil shale formation
US3565171A (en) 1968-10-23 1971-02-23 Shell Oil Co Method for producing shale oil from a subterranean oil shale formation
US3502372A (en) * 1968-10-23 1970-03-24 Shell Oil Co Process of recovering oil and dawsonite from oil shale
US3554285A (en) 1968-10-24 1971-01-12 Phillips Petroleum Co Production and upgrading of heavy viscous oils
US3629551A (en) 1968-10-29 1971-12-21 Chisso Corp Controlling heat generation locally in a heat-generating pipe utilizing skin-effect current
US3501201A (en) * 1968-10-30 1970-03-17 Shell Oil Co Method of producing shale oil from a subterranean oil shale formation
US3617471A (en) 1968-12-26 1971-11-02 Texaco Inc Hydrotorting of shale to produce shale oil
US3593790A (en) * 1969-01-02 1971-07-20 Shell Oil Co Method for producing shale oil from an oil shale formation
US3614986A (en) 1969-03-03 1971-10-26 Electrothermic Co Method for injecting heated fluids into mineral bearing formations
US3562401A (en) * 1969-03-03 1971-02-09 Union Carbide Corp Low temperature electric transmission systems
US3542131A (en) 1969-04-01 1970-11-24 Mobil Oil Corp Method of recovering hydrocarbons from oil shale
US3547192A (en) 1969-04-04 1970-12-15 Shell Oil Co Method of metal coating and electrically heating a subterranean earth formation
US3618663A (en) * 1969-05-01 1971-11-09 Phillips Petroleum Co Shale oil production
US3605890A (en) 1969-06-04 1971-09-20 Chevron Res Hydrogen production from a kerogen-depleted shale formation
US3572838A (en) 1969-07-07 1971-03-30 Shell Oil Co Recovery of aluminum compounds and oil from oil shale formations
US3526095A (en) 1969-07-24 1970-09-01 Ralph E Peck Liquid gas storage system
US3599714A (en) * 1969-09-08 1971-08-17 Roger L Messman Method of recovering hydrocarbons by in situ combustion
US3614387A (en) 1969-09-22 1971-10-19 Watlow Electric Mfg Co Electrical heater with an internal thermocouple
US3547193A (en) 1969-10-08 1970-12-15 Electrothermic Co Method and apparatus for recovery of minerals from sub-surface formations using electricity
US3702886A (en) 1969-10-10 1972-11-14 Mobil Oil Corp Crystalline zeolite zsm-5 and method of preparing the same
US3661423A (en) 1970-02-12 1972-05-09 Occidental Petroleum Corp In situ process for recovery of carbonaceous materials from subterranean deposits
US3943160A (en) 1970-03-09 1976-03-09 Shell Oil Company Heat-stable calcium-compatible waterflood surfactant
US3709979A (en) 1970-04-23 1973-01-09 Mobil Oil Corp Crystalline zeolite zsm-11
USRE27309E (en) * 1970-05-07 1972-03-14 Gas in
US3759574A (en) * 1970-09-24 1973-09-18 Shell Oil Co Method of producing hydrocarbons from an oil shale formation
US4305463A (en) * 1979-10-31 1981-12-15 Oil Trieval Corporation Oil recovery method and apparatus
US3679812A (en) 1970-11-13 1972-07-25 Schlumberger Technology Corp Electrical suspension cable for well tools
US3680633A (en) 1970-12-28 1972-08-01 Sun Oil Co Delaware Situ combustion initiation process
US3675715A (en) 1970-12-30 1972-07-11 Forrester A Clark Processes for secondarily recovering oil
US3775185A (en) 1971-01-13 1973-11-27 United Aircraft Corp Fuel cell utilizing fused thallium oxide electrolyte
US3770614A (en) 1971-01-15 1973-11-06 Mobil Oil Corp Split feed reforming and n-paraffin elimination from low boiling reformate
US3832449A (en) 1971-03-18 1974-08-27 Mobil Oil Corp Crystalline zeolite zsm{14 12
US3691291A (en) 1971-04-19 1972-09-12 Gen Electric Splice for joining high voltage cables
US3700280A (en) 1971-04-28 1972-10-24 Shell Oil Co Method of producing oil from an oil shale formation containing nahcolite and dawsonite
US3774701A (en) 1971-05-07 1973-11-27 C Weaver Method and apparatus for drilling
US3870063A (en) * 1971-06-11 1975-03-11 John T Hayward Means of transporting crude oil through a pipeline
US3770398A (en) 1971-09-17 1973-11-06 Cities Service Oil Co In situ coal gasification process
US3812913A (en) 1971-10-18 1974-05-28 Sun Oil Co Method of formation consolidation
US3893918A (en) 1971-11-22 1975-07-08 Engineering Specialties Inc Method for separating material leaving a well
US3766982A (en) 1971-12-27 1973-10-23 Justheim Petrol Co Method for the in-situ treatment of hydrocarbonaceous materials
US3759328A (en) * 1972-05-11 1973-09-18 Shell Oil Co Laterally expanding oil shale permeabilization
US3794116A (en) * 1972-05-30 1974-02-26 Atomic Energy Commission Situ coal bed gasification
US3757860A (en) 1972-08-07 1973-09-11 Atlantic Richfield Co Well heating
US3779602A (en) * 1972-08-07 1973-12-18 Shell Oil Co Process for solution mining nahcolite
CA983704A (en) 1972-08-31 1976-02-17 Joseph D. Robinson Method for determining distance and direction to a cased well bore
US3809159A (en) 1972-10-02 1974-05-07 Continental Oil Co Process for simultaneously increasing recovery and upgrading oil in a reservoir
US3804172A (en) * 1972-10-11 1974-04-16 Shell Oil Co Method for the recovery of oil from oil shale
US3794113A (en) 1972-11-13 1974-02-26 Mobil Oil Corp Combination in situ combustion displacement and steam stimulation of producing wells
US3804169A (en) 1973-02-07 1974-04-16 Shell Oil Co Spreading-fluid recovery of subterranean oil
US3947683A (en) * 1973-06-05 1976-03-30 Texaco Inc. Combination of epithermal and inelastic neutron scattering methods to locate coal and oil shale zones
US4076761A (en) * 1973-08-09 1978-02-28 Mobil Oil Corporation Process for the manufacture of gasoline
US4016245A (en) 1973-09-04 1977-04-05 Mobil Oil Corporation Crystalline zeolite and method of preparing same
US3881551A (en) 1973-10-12 1975-05-06 Ruel C Terry Method of extracting immobile hydrocarbons
US3853185A (en) 1973-11-30 1974-12-10 Continental Oil Co Guidance system for a horizontal drilling apparatus
US3907045A (en) * 1973-11-30 1975-09-23 Continental Oil Co Guidance system for a horizontal drilling apparatus
US3882941A (en) 1973-12-17 1975-05-13 Cities Service Res & Dev Co In situ production of bitumen from oil shale
GB1445941A (en) 1974-02-26 1976-08-11 Apv Co Ltd Heat treatment of particulate solid materials
US4037655A (en) 1974-04-19 1977-07-26 Electroflood Company Method for secondary recovery of oil
US4199025A (en) 1974-04-19 1980-04-22 Electroflood Company Method and apparatus for tertiary recovery of oil
US3922148A (en) 1974-05-16 1975-11-25 Texaco Development Corp Production of methane-rich gas
US3948755A (en) 1974-05-31 1976-04-06 Standard Oil Company Process for recovering and upgrading hydrocarbons from oil shale and tar sands
ZA753184B (en) 1974-05-31 1976-04-28 Standard Oil Co Process for recovering upgraded hydrocarbon products
US3894769A (en) 1974-06-06 1975-07-15 Shell Oil Co Recovering oil from a subterranean carbonaceous formation
US3892270A (en) * 1974-06-06 1975-07-01 Chevron Res Production of hydrocarbons from underground formations
US3948758A (en) 1974-06-17 1976-04-06 Mobil Oil Corporation Production of alkyl aromatic hydrocarbons
US4006778A (en) 1974-06-21 1977-02-08 Texaco Exploration Canada Ltd. Thermal recovery of hydrocarbon from tar sands
US4026357A (en) 1974-06-26 1977-05-31 Texaco Exploration Canada Ltd. In situ gasification of solid hydrocarbon materials in a subterranean formation
US4029360A (en) 1974-07-26 1977-06-14 Occidental Oil Shale, Inc. Method of recovering oil and water from in situ oil shale retort flue gas
US4005752A (en) * 1974-07-26 1977-02-01 Occidental Petroleum Corporation Method of igniting in situ oil shale retort with fuel rich flue gas
US3941421A (en) 1974-08-13 1976-03-02 Occidental Petroleum Corporation Apparatus for obtaining uniform gas flow through an in situ oil shale retort
GB1454324A (en) 1974-08-14 1976-11-03 Iniex Recovering combustible gases from underground deposits of coal or bituminous shale
US3947656A (en) * 1974-08-26 1976-03-30 Fast Heat Element Manufacturing Co., Inc. Temperature controlled cartridge heater
US3948319A (en) 1974-10-16 1976-04-06 Atlantic Richfield Company Method and apparatus for producing fluid by varying current flow through subterranean source formation
AR205595A1 (en) 1974-11-06 1976-05-14 Haldor Topsoe As PROCEDURE FOR PREPARING GASES RICH IN METHANE
US4138442A (en) * 1974-12-05 1979-02-06 Mobil Oil Corporation Process for the manufacture of gasoline
US3952802A (en) * 1974-12-11 1976-04-27 In Situ Technology, Inc. Method and apparatus for in situ gasification of coal and the commercial products derived therefrom
US3982591A (en) 1974-12-20 1976-09-28 World Energy Systems Downhole recovery system
US3982592A (en) * 1974-12-20 1976-09-28 World Energy Systems In situ hydrogenation of hydrocarbons in underground formations
US3986556A (en) * 1975-01-06 1976-10-19 Haynes Charles A Hydrocarbon recovery from earth strata
US3958636A (en) 1975-01-23 1976-05-25 Atlantic Richfield Company Production of bitumen from a tar sand formation
US4042026A (en) 1975-02-08 1977-08-16 Deutsche Texaco Aktiengesellschaft Method for initiating an in-situ recovery process by the introduction of oxygen
US3972372A (en) 1975-03-10 1976-08-03 Fisher Sidney T Exraction of hydrocarbons in situ from underground hydrocarbon deposits
US4096163A (en) 1975-04-08 1978-06-20 Mobil Oil Corporation Conversion of synthesis gas to hydrocarbon mixtures
US3924680A (en) 1975-04-23 1975-12-09 In Situ Technology Inc Method of pyrolysis of coal in situ
US3973628A (en) 1975-04-30 1976-08-10 New Mexico Tech Research Foundation In situ solution mining of coal
US3989108A (en) 1975-05-16 1976-11-02 Texaco Inc. Water exclusion method for hydrocarbon production wells using freezing technique
US4016239A (en) 1975-05-22 1977-04-05 Union Oil Company Of California Recarbonation of spent oil shale
US3987851A (en) 1975-06-02 1976-10-26 Shell Oil Company Serially burning and pyrolyzing to produce shale oil from a subterranean oil shale
US3986557A (en) * 1975-06-06 1976-10-19 Atlantic Richfield Company Production of bitumen from tar sands
CA1064890A (en) 1975-06-10 1979-10-23 Mae K. Rubin Crystalline zeolite, synthesis and use thereof
US3950029A (en) 1975-06-12 1976-04-13 Mobil Oil Corporation In situ retorting of oil shale
US3993132A (en) 1975-06-18 1976-11-23 Texaco Exploration Canada Ltd. Thermal recovery of hydrocarbons from tar sands
FR2314791A1 (en) * 1975-06-18 1977-01-14 Pont A Mousson MACHINE, ESPECIALLY CENTRIFUGAL CASTING, WITH AXIAL SUPPORT DEVICE
US4069868A (en) 1975-07-14 1978-01-24 In Situ Technology, Inc. Methods of fluidized production of coal in situ
BE832017A (en) 1975-07-31 1975-11-17 NEW PROCESS FOR EXPLOITATION OF A COAL OR LIGNITE DEPOSIT BY UNDERGROUND GASING UNDER HIGH PRESSURE
US4199024A (en) 1975-08-07 1980-04-22 World Energy Systems Multistage gas generator
US3954140A (en) * 1975-08-13 1976-05-04 Hendrick Robert P Recovery of hydrocarbons by in situ thermal extraction
US3986349A (en) 1975-09-15 1976-10-19 Chevron Research Company Method of power generation via coal gasification and liquid hydrocarbon synthesis
US3994340A (en) 1975-10-30 1976-11-30 Chevron Research Company Method of recovering viscous petroleum from tar sand
US3994341A (en) * 1975-10-30 1976-11-30 Chevron Research Company Recovering viscous petroleum from thick tar sand
US4087130A (en) 1975-11-03 1978-05-02 Occidental Petroleum Corporation Process for the gasification of coal in situ
US4018280A (en) * 1975-12-10 1977-04-19 Mobil Oil Corporation Process for in situ retorting of oil shale
US3992474A (en) 1975-12-15 1976-11-16 Uop Inc. Motor fuel production with fluid catalytic cracking of high-boiling alkylate
US4019575A (en) 1975-12-22 1977-04-26 Chevron Research Company System for recovering viscous petroleum from thick tar sand
US4017319A (en) 1976-01-06 1977-04-12 General Electric Company Si3 N4 formed by nitridation of sintered silicon compact containing boron
US3999607A (en) 1976-01-22 1976-12-28 Exxon Research And Engineering Company Recovery of hydrocarbons from coal
US4031956A (en) * 1976-02-12 1977-06-28 In Situ Technology, Inc. Method of recovering energy from subsurface petroleum reservoirs
US4008762A (en) * 1976-02-26 1977-02-22 Fisher Sidney T Extraction of hydrocarbons in situ from underground hydrocarbon deposits
US4010800A (en) * 1976-03-08 1977-03-08 In Situ Technology, Inc. Producing thin seams of coal in situ
US4048637A (en) 1976-03-23 1977-09-13 Westinghouse Electric Corporation Radar system for detecting slowly moving targets
DE2615874B2 (en) * 1976-04-10 1978-10-19 Deutsche Texaco Ag, 2000 Hamburg Application of a method for extracting crude oil and bitumen from underground deposits by means of a combustion front in deposits of any content of intermediate hydrocarbons in the crude oil or bitumen
GB1544245A (en) * 1976-05-21 1979-04-19 British Gas Corp Production of substitute natural gas
US4049053A (en) 1976-06-10 1977-09-20 Fisher Sidney T Recovery of hydrocarbons from partially exhausted oil wells by mechanical wave heating
US4193451A (en) * 1976-06-17 1980-03-18 The Badger Company, Inc. Method for production of organic products from kerogen
US4067390A (en) * 1976-07-06 1978-01-10 Technology Application Services Corporation Apparatus and method for the recovery of fuel products from subterranean deposits of carbonaceous matter using a plasma arc
US4057293A (en) 1976-07-12 1977-11-08 Garrett Donald E Process for in situ conversion of coal or the like into oil and gas
US4043393A (en) 1976-07-29 1977-08-23 Fisher Sidney T Extraction from underground coal deposits
US4091869A (en) 1976-09-07 1978-05-30 Exxon Production Research Company In situ process for recovery of carbonaceous materials from subterranean deposits
US4059308A (en) 1976-11-15 1977-11-22 Trw Inc. Pressure swing recovery system for oil shale deposits
US4083604A (en) 1976-11-15 1978-04-11 Trw Inc. Thermomechanical fracture for recovery system in oil shale deposits
US4065183A (en) * 1976-11-15 1977-12-27 Trw Inc. Recovery system for oil shale deposits
US4077471A (en) 1976-12-01 1978-03-07 Texaco Inc. Surfactant oil recovery process usable in high temperature, high salinity formations
US4064943A (en) 1976-12-06 1977-12-27 Shell Oil Co Plugging permeable earth formation with wax
US4089374A (en) 1976-12-16 1978-05-16 In Situ Technology, Inc. Producing methane from coal in situ
US4084637A (en) 1976-12-16 1978-04-18 Petro Canada Exploration Inc. Method of producing viscous materials from subterranean formations
US4093026A (en) 1977-01-17 1978-06-06 Occidental Oil Shale, Inc. Removal of sulfur dioxide from process gas using treated oil shale and water
DE2705129C3 (en) 1977-02-08 1979-11-15 Deutsche Texaco Ag, 2000 Hamburg Seismic procedure to control underground processes
US4277416A (en) 1977-02-17 1981-07-07 Aminoil, Usa, Inc. Process for producing methanol
US4085803A (en) 1977-03-14 1978-04-25 Exxon Production Research Company Method for oil recovery using a horizontal well with indirect heating
US4151877A (en) * 1977-05-13 1979-05-01 Occidental Oil Shale, Inc. Determining the locus of a processing zone in a retort through channels
US4099567A (en) 1977-05-27 1978-07-11 In Situ Technology, Inc. Generating medium BTU gas from coal in situ
US4144935A (en) * 1977-08-29 1979-03-20 Iit Research Institute Apparatus and method for in situ heat processing of hydrocarbonaceous formations
US4140180A (en) * 1977-08-29 1979-02-20 Iit Research Institute Method for in situ heat processing of hydrocarbonaceous formations
NL181941C (en) * 1977-09-16 1987-12-01 Ir Arnold Willem Josephus Grup METHOD FOR UNDERGROUND GASULATION OF COAL OR BROWN.
US4125159A (en) 1977-10-17 1978-11-14 Vann Roy Randell Method and apparatus for isolating and treating subsurface stratas
SU915451A1 (en) * 1977-10-21 1988-08-23 Vnii Ispolzovania Method of underground gasification of fuel
US4119349A (en) 1977-10-25 1978-10-10 Gulf Oil Corporation Method and apparatus for recovery of fluids produced in in-situ retorting of oil shale
US4114688A (en) 1977-12-05 1978-09-19 In Situ Technology Inc. Minimizing environmental effects in production and use of coal
US4158467A (en) 1977-12-30 1979-06-19 Gulf Oil Corporation Process for recovering shale oil
US4148359A (en) 1978-01-30 1979-04-10 Shell Oil Company Pressure-balanced oil recovery process for water productive oil shale
DE2812490A1 (en) 1978-03-22 1979-09-27 Texaco Ag PROCEDURE FOR DETERMINING THE SPATIAL EXTENSION OF SUBSEQUENT REACTIONS
US4160479A (en) * 1978-04-24 1979-07-10 Richardson Reginald D Heavy oil recovery process
US4197911A (en) 1978-05-09 1980-04-15 Ramcor, Inc. Process for in situ coal gasification
US4228853A (en) 1978-06-21 1980-10-21 Harvey A Herbert Petroleum production method
US4186801A (en) * 1978-12-18 1980-02-05 Gulf Research And Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4185692A (en) 1978-07-14 1980-01-29 In Situ Technology, Inc. Underground linkage of wells for production of coal in situ
US4167213A (en) 1978-07-17 1979-09-11 Standard Oil Company (Indiana) Method for determining the position and inclination of a flame front during in situ combustion of a rubbled oil shale retort
US4184548A (en) 1978-07-17 1980-01-22 Standard Oil Company (Indiana) Method for determining the position and inclination of a flame front during in situ combustion of an oil shale retort
US4183405A (en) * 1978-10-02 1980-01-15 Magnie Robert L Enhanced recoveries of petroleum and hydrogen from underground reservoirs
US4446917A (en) 1978-10-04 1984-05-08 Todd John C Method and apparatus for producing viscous or waxy crude oils
JPS5571984A (en) * 1978-11-25 1980-05-30 Casio Comput Co Ltd Electronic watch
US4311340A (en) 1978-11-27 1982-01-19 Lyons William C Uranium leeching process and insitu mining
NL7811732A (en) 1978-11-30 1980-06-03 Stamicarbon METHOD FOR CONVERSION OF DIMETHYL ETHER
JPS5576586A (en) 1978-12-01 1980-06-09 Tokyo Shibaura Electric Co Heater
US4457365A (en) 1978-12-07 1984-07-03 Raytheon Company In situ radio frequency selective heating system
US4299086A (en) 1978-12-07 1981-11-10 Gulf Research & Development Company Utilization of energy obtained by substoichiometric combustion of low heating value gases
US4265307A (en) 1978-12-20 1981-05-05 Standard Oil Company Shale oil recovery
US4194562A (en) 1978-12-21 1980-03-25 Texaco Inc. Method for preconditioning a subterranean oil-bearing formation prior to in-situ combustion
US4258955A (en) 1978-12-26 1981-03-31 Mobil Oil Corporation Process for in-situ leaching of uranium
US4274487A (en) 1979-01-11 1981-06-23 Standard Oil Company (Indiana) Indirect thermal stimulation of production wells
US4232902A (en) 1979-02-09 1980-11-11 Ppg Industries, Inc. Solution mining water soluble salts at high temperatures
US4324292A (en) 1979-02-21 1982-04-13 University Of Utah Process for recovering products from oil shale
US4260192A (en) * 1979-02-21 1981-04-07 Occidental Research Corporation Recovery of magnesia from oil shale
US4289354A (en) 1979-02-23 1981-09-15 Edwin G. Higgins, Jr. Borehole mining of solid mineral resources
US4243511A (en) * 1979-03-26 1981-01-06 Marathon Oil Company Process for suppressing carbonate decomposition in vapor phase water retorting
US4248306A (en) 1979-04-02 1981-02-03 Huisen Allan T Van Geothermal petroleum refining
US4282587A (en) 1979-05-21 1981-08-04 Daniel Silverman Method for monitoring the recovery of minerals from shallow geological formations
US4216079A (en) 1979-07-09 1980-08-05 Cities Service Company Emulsion breaking with surfactant recovery
US4234230A (en) 1979-07-11 1980-11-18 The Superior Oil Company In situ processing of mined oil shale
US4290650A (en) 1979-08-03 1981-09-22 Ppg Industries Canada Ltd. Subterranean cavity chimney development for connecting solution mined cavities
US4228854A (en) 1979-08-13 1980-10-21 Alberta Research Council Enhanced oil recovery using electrical means
US4701587A (en) 1979-08-31 1987-10-20 Metcal, Inc. Shielded heating element having intrinsic temperature control
US4256945A (en) 1979-08-31 1981-03-17 Iris Associates Alternating current electrically resistive heating element having intrinsic temperature control
US4327805A (en) 1979-09-18 1982-05-04 Carmel Energy, Inc. Method for producing viscous hydrocarbons
US4549396A (en) 1979-10-01 1985-10-29 Mobil Oil Corporation Conversion of coal to electricity
US4368114A (en) 1979-12-05 1983-01-11 Mobil Oil Corporation Octane and total yield improvement in catalytic cracking
US4250230A (en) * 1979-12-10 1981-02-10 In Situ Technology, Inc. Generating electricity from coal in situ
US4250962A (en) * 1979-12-14 1981-02-17 Gulf Research & Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4260018A (en) * 1979-12-19 1981-04-07 Texaco Inc. Method for steam injection in steeply dipping formations
US4359687A (en) 1980-01-25 1982-11-16 Shell Oil Company Method and apparatus for determining shaliness and oil saturations in earth formations using induced polarization in the frequency domain
US4398151A (en) 1980-01-25 1983-08-09 Shell Oil Company Method for correcting an electrical log for the presence of shale in a formation
US4285547A (en) * 1980-02-01 1981-08-25 Multi Mineral Corporation Integrated in situ shale oil and mineral recovery process
USRE30738E (en) 1980-02-06 1981-09-08 Iit Research Institute Apparatus and method for in situ heat processing of hydrocarbonaceous formations
US4303126A (en) * 1980-02-27 1981-12-01 Chevron Research Company Arrangement of wells for producing subsurface viscous petroleum
US4319635A (en) * 1980-02-29 1982-03-16 P. H. Jones Hydrogeology, Inc. Method for enhanced oil recovery by geopressured waterflood
US4375302A (en) * 1980-03-03 1983-03-01 Nicholas Kalmar Process for the in situ recovery of both petroleum and inorganic mineral content of an oil shale deposit
US4445574A (en) * 1980-03-24 1984-05-01 Geo Vann, Inc. Continuous borehole formed horizontally through a hydrocarbon producing formation
US4417782A (en) 1980-03-31 1983-11-29 Raychem Corporation Fiber optic temperature sensing
CA1168283A (en) 1980-04-14 1984-05-29 Hiroshi Teratani Electrode device for electrically heating underground deposits of hydrocarbons
US4273188A (en) 1980-04-30 1981-06-16 Gulf Research & Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4306621A (en) 1980-05-23 1981-12-22 Boyd R Michael Method for in situ coal gasification operations
US4287957A (en) 1980-05-27 1981-09-08 Evans Robert F Cooling a drilling tool component with a separate flow stream of reduced-temperature gaseous drilling fluid
US4409090A (en) 1980-06-02 1983-10-11 University Of Utah Process for recovering products from tar sand
CA1165361A (en) 1980-06-03 1984-04-10 Toshiyuki Kobayashi Electrode unit for electrically heating underground hydrocarbon deposits
US4381641A (en) 1980-06-23 1983-05-03 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4310440A (en) 1980-07-07 1982-01-12 Union Carbide Corporation Crystalline metallophosphate compositions
US4401099A (en) 1980-07-11 1983-08-30 W.B. Combustion, Inc. Single-ended recuperative radiant tube assembly and method
US4299285A (en) 1980-07-21 1981-11-10 Gulf Research & Development Company Underground gasification of bituminous coal
US4396062A (en) 1980-10-06 1983-08-02 University Of Utah Research Foundation Apparatus and method for time-domain tracking of high-speed chemical reactions
FR2491945B1 (en) 1980-10-13 1985-08-23 Ledent Pierre PROCESS FOR PRODUCING A HIGH HYDROGEN GAS BY SUBTERRANEAN COAL GASIFICATION
US4353418A (en) 1980-10-20 1982-10-12 Standard Oil Company (Indiana) In situ retorting of oil shale
US4384613A (en) 1980-10-24 1983-05-24 Terra Tek, Inc. Method of in-situ retorting of carbonaceous material for recovery of organic liquids and gases
US4366864A (en) 1980-11-24 1983-01-04 Exxon Research And Engineering Co. Method for recovery of hydrocarbons from oil-bearing limestone or dolomite
US4401163A (en) * 1980-12-29 1983-08-30 The Standard Oil Company Modified in situ retorting of oil shale
US4385661A (en) 1981-01-07 1983-05-31 The United States Of America As Represented By The United States Department Of Energy Downhole steam generator with improved preheating, combustion and protection features
US4423311A (en) 1981-01-19 1983-12-27 Varney Sr Paul Electric heating apparatus for de-icing pipes
US4366668A (en) * 1981-02-25 1983-01-04 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4382469A (en) 1981-03-10 1983-05-10 Electro-Petroleum, Inc. Method of in situ gasification
US4363361A (en) 1981-03-19 1982-12-14 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4390067A (en) 1981-04-06 1983-06-28 Exxon Production Research Co. Method of treating reservoirs containing very viscous crude oil or bitumen
US4399866A (en) * 1981-04-10 1983-08-23 Atlantic Richfield Company Method for controlling the flow of subterranean water into a selected zone in a permeable subterranean carbonaceous deposit
US4444255A (en) 1981-04-20 1984-04-24 Lloyd Geoffrey Apparatus and process for the recovery of oil
US4380930A (en) 1981-05-01 1983-04-26 Mobil Oil Corporation System for transmitting ultrasonic energy through core samples
US4429745A (en) * 1981-05-08 1984-02-07 Mobil Oil Corporation Oil recovery method
US4378048A (en) 1981-05-08 1983-03-29 Gulf Research & Development Company Substoichiometric combustion of low heating value gases using different platinum catalysts
US4384614A (en) * 1981-05-11 1983-05-24 Justheim Pertroleum Company Method of retorting oil shale by velocity flow of super-heated air
US4384948A (en) * 1981-05-13 1983-05-24 Ashland Oil, Inc. Single unit RCC
US4437519A (en) * 1981-06-03 1984-03-20 Occidental Oil Shale, Inc. Reduction of shale oil pour point
US4463807A (en) 1981-06-15 1984-08-07 In Situ Technology, Inc. Minimizing subsidence effects during production of coal in situ
US4428700A (en) * 1981-08-03 1984-01-31 E. R. Johnson Associates, Inc. Method for disposing of waste materials
US4456065A (en) 1981-08-20 1984-06-26 Elektra Energie A.G. Heavy oil recovering
US4344483A (en) 1981-09-08 1982-08-17 Fisher Charles B Multiple-site underground magnetic heating of hydrocarbons
US4452491A (en) 1981-09-25 1984-06-05 Intercontinental Econergy Associates, Inc. Recovery of hydrocarbons from deep underground deposits of tar sands
US4425967A (en) 1981-10-07 1984-01-17 Standard Oil Company (Indiana) Ignition procedure and process for in situ retorting of oil shale
US4401162A (en) 1981-10-13 1983-08-30 Synfuel (An Indiana Limited Partnership) In situ oil shale process
US4605680A (en) 1981-10-13 1986-08-12 Chevron Research Company Conversion of synthesis gas to diesel fuel and gasoline
US4410042A (en) 1981-11-02 1983-10-18 Mobil Oil Corporation In-situ combustion method for recovery of heavy oil utilizing oxygen and carbon dioxide as initial oxidant
US4444258A (en) 1981-11-10 1984-04-24 Nicholas Kalmar In situ recovery of oil from oil shale
US4418752A (en) * 1982-01-07 1983-12-06 Conoco Inc. Thermal oil recovery with solvent recirculation
FR2519688A1 (en) 1982-01-08 1983-07-18 Elf Aquitaine SEALING SYSTEM FOR DRILLING WELLS IN WHICH CIRCULATES A HOT FLUID
DE3202492C2 (en) 1982-01-27 1983-12-01 Veba Oel Entwicklungsgesellschaft mbH, 4660 Gelsenkirchen-Buer Process for increasing the yield of hydrocarbons from a subterranean formation
US4397732A (en) 1982-02-11 1983-08-09 International Coal Refining Company Process for coal liquefaction employing selective coal feed
US4551226A (en) 1982-02-26 1985-11-05 Chevron Research Company Heat exchanger antifoulant
GB2117030B (en) 1982-03-17 1985-09-11 Cameron Iron Works Inc Method and apparatus for remote installations of dual tubing strings in a subsea well
US4530401A (en) 1982-04-05 1985-07-23 Mobil Oil Corporation Method for maximum in-situ visbreaking of heavy oil
CA1196594A (en) 1982-04-08 1985-11-12 Guy Savard Recovery of oil from tar sands
US4537252A (en) 1982-04-23 1985-08-27 Standard Oil Company (Indiana) Method of underground conversion of coal
US4491179A (en) 1982-04-26 1985-01-01 Pirson Sylvain J Method for oil recovery by in situ exfoliation drive
US4455215A (en) 1982-04-29 1984-06-19 Jarrott David M Process for the geoconversion of coal into oil
US4412585A (en) * 1982-05-03 1983-11-01 Cities Service Company Electrothermal process for recovering hydrocarbons
US4415034A (en) * 1982-05-03 1983-11-15 Cities Service Company Electrode well completion
US4524826A (en) 1982-06-14 1985-06-25 Texaco Inc. Method of heating an oil shale formation
US4457374A (en) 1982-06-29 1984-07-03 Standard Oil Company Transient response process for detecting in situ retorting conditions
US4442896A (en) * 1982-07-21 1984-04-17 Reale Lucio V Treatment of underground beds
US4440871A (en) 1982-07-26 1984-04-03 Union Carbide Corporation Crystalline silicoaluminophosphates
US4407973A (en) 1982-07-28 1983-10-04 The M. W. Kellogg Company Methanol from coal and natural gas
US4931171A (en) * 1982-08-03 1990-06-05 Phillips Petroleum Company Pyrolysis of carbonaceous materials
US4479541A (en) 1982-08-23 1984-10-30 Wang Fun Den Method and apparatus for recovery of oil, gas and mineral deposits by panel opening
US4460044A (en) 1982-08-31 1984-07-17 Chevron Research Company Advancing heated annulus steam drive
US4544478A (en) * 1982-09-03 1985-10-01 Chevron Research Company Process for pyrolyzing hydrocarbonaceous solids to recover volatile hydrocarbons
US4458767A (en) 1982-09-28 1984-07-10 Mobil Oil Corporation Method for directionally drilling a first well to intersect a second well
US4485868A (en) 1982-09-29 1984-12-04 Iit Research Institute Method for recovery of viscous hydrocarbons by electromagnetic heating in situ
US4695713A (en) 1982-09-30 1987-09-22 Metcal, Inc. Autoregulating, electrically shielded heater
US4927857A (en) 1982-09-30 1990-05-22 Engelhard Corporation Method of methanol production
CA1214815A (en) 1982-09-30 1986-12-02 John F. Krumme Autoregulating electrically shielded heater
US4498531A (en) 1982-10-01 1985-02-12 Rockwell International Corporation Emission controller for indirect fired downhole steam generators
US4485869A (en) 1982-10-22 1984-12-04 Iit Research Institute Recovery of liquid hydrocarbons from oil shale by electromagnetic heating in situ
DE3365337D1 (en) * 1982-11-22 1986-09-18 Shell Int Research Process for the preparation of a fischer-tropsch catalyst, a catalyst so prepared and use of this catalyst in the preparation of hydrocarbons
US4498535A (en) * 1982-11-30 1985-02-12 Iit Research Institute Apparatus and method for in situ controlled heat processing of hydrocarbonaceous formations with a controlled parameter line
US4474238A (en) * 1982-11-30 1984-10-02 Phillips Petroleum Company Method and apparatus for treatment of subsurface formations
US4752673A (en) 1982-12-01 1988-06-21 Metcal, Inc. Autoregulating heater
US4483398A (en) 1983-01-14 1984-11-20 Exxon Production Research Co. In-situ retorting of oil shale
US4501326A (en) * 1983-01-17 1985-02-26 Gulf Canada Limited In-situ recovery of viscous hydrocarbonaceous crude oil
US4609041A (en) 1983-02-10 1986-09-02 Magda Richard M Well hot oil system
US4526615A (en) 1983-03-01 1985-07-02 Johnson Paul H Cellular heap leach process and apparatus
US4886118A (en) 1983-03-21 1989-12-12 Shell Oil Company Conductively heating a subterranean oil shale to create permeability and subsequently produce oil
US4640352A (en) * 1983-03-21 1987-02-03 Shell Oil Company In-situ steam drive oil recovery process
US4500651A (en) 1983-03-31 1985-02-19 Union Carbide Corporation Titanium-containing molecular sieves
US4458757A (en) * 1983-04-25 1984-07-10 Exxon Research And Engineering Co. In situ shale-oil recovery process
US4524827A (en) * 1983-04-29 1985-06-25 Iit Research Institute Single well stimulation for the recovery of liquid hydrocarbons from subsurface formations
US4545435A (en) 1983-04-29 1985-10-08 Iit Research Institute Conduction heating of hydrocarbonaceous formations
US4518548A (en) 1983-05-02 1985-05-21 Sulcon, Inc. Method of overlaying sulphur concrete on horizontal and vertical surfaces
US5073625A (en) 1983-05-26 1991-12-17 Metcal, Inc. Self-regulating porous heating device
US4794226A (en) 1983-05-26 1988-12-27 Metcal, Inc. Self-regulating porous heater device
DE3319732A1 (en) 1983-05-31 1984-12-06 Kraftwerk Union AG, 4330 Mülheim MEDIUM-POWER PLANT WITH INTEGRATED COAL GASIFICATION SYSTEM FOR GENERATING ELECTRICITY AND METHANOL
US4658215A (en) 1983-06-20 1987-04-14 Shell Oil Company Method for induced polarization logging
US4583046A (en) 1983-06-20 1986-04-15 Shell Oil Company Apparatus for focused electrode induced polarization logging
US4717814A (en) 1983-06-27 1988-01-05 Metcal, Inc. Slotted autoregulating heater
US4439307A (en) * 1983-07-01 1984-03-27 Dravo Corporation Heating process gas for indirect shale oil retorting through the combustion of residual carbon in oil depleted shale
US4524113A (en) 1983-07-05 1985-06-18 United Technologies Corporation Direct use of methanol fuel in a molten carbonate fuel cell
US5209987A (en) 1983-07-08 1993-05-11 Raychem Limited Wire and cable
US4985313A (en) 1985-01-14 1991-01-15 Raychem Limited Wire and cable
US4598392A (en) 1983-07-26 1986-07-01 Mobil Oil Corporation Vibratory signal sweep seismic prospecting method and apparatus
US4501445A (en) * 1983-08-01 1985-02-26 Cities Service Company Method of in-situ hydrogenation of carbonaceous material
US4538682A (en) 1983-09-08 1985-09-03 Mcmanus James W Method and apparatus for removing oil well paraffin
IN161735B (en) 1983-09-12 1988-01-30 Shell Int Research
US4698149A (en) * 1983-11-07 1987-10-06 Mobil Oil Corporation Enhanced recovery of hydrocarbonaceous fluids oil shale
US4573530A (en) * 1983-11-07 1986-03-04 Mobil Oil Corporation In-situ gasification of tar sands utilizing a combustible gas
US4489782A (en) 1983-12-12 1984-12-25 Atlantic Richfield Company Viscous oil production using electrical current heating and lateral drain holes
US4598772A (en) * 1983-12-28 1986-07-08 Mobil Oil Corporation Method for operating a production well in an oxygen driven in-situ combustion oil recovery process
US4540882A (en) 1983-12-29 1985-09-10 Shell Oil Company Method of determining drilling fluid invasion
US4583242A (en) 1983-12-29 1986-04-15 Shell Oil Company Apparatus for positioning a sample in a computerized axial tomographic scanner
US4635197A (en) * 1983-12-29 1987-01-06 Shell Oil Company High resolution tomographic imaging method
US4613754A (en) 1983-12-29 1986-09-23 Shell Oil Company Tomographic calibration apparatus
US4571491A (en) * 1983-12-29 1986-02-18 Shell Oil Company Method of imaging the atomic number of a sample
US4542648A (en) 1983-12-29 1985-09-24 Shell Oil Company Method of correlating a core sample with its original position in a borehole
US4662439A (en) 1984-01-20 1987-05-05 Amoco Corporation Method of underground conversion of coal
US4572229A (en) 1984-02-02 1986-02-25 Thomas D. Mueller Variable proportioner
US4623401A (en) 1984-03-06 1986-11-18 Metcal, Inc. Heat treatment with an autoregulating heater
US4644283A (en) 1984-03-19 1987-02-17 Shell Oil Company In-situ method for determining pore size distribution, capillary pressure and permeability
US4637464A (en) * 1984-03-22 1987-01-20 Amoco Corporation In situ retorting of oil shale with pulsed water purge
US4552214A (en) * 1984-03-22 1985-11-12 Standard Oil Company (Indiana) Pulsed in situ retorting in an array of oil shale retorts
US4570715A (en) * 1984-04-06 1986-02-18 Shell Oil Company Formation-tailored method and apparatus for uniformly heating long subterranean intervals at high temperature
US4577690A (en) 1984-04-18 1986-03-25 Mobil Oil Corporation Method of using seismic data to monitor firefloods
US5055180A (en) * 1984-04-20 1991-10-08 Electromagnetic Energy Corporation Method and apparatus for recovering fractions from hydrocarbon materials, facilitating the removal and cleansing of hydrocarbon fluids, insulating storage vessels, and cleansing storage vessels and pipelines
US4592423A (en) 1984-05-14 1986-06-03 Texaco Inc. Hydrocarbon stratum retorting means and method
US4597441A (en) 1984-05-25 1986-07-01 World Energy Systems, Inc. Recovery of oil by in situ hydrogenation
US4663711A (en) 1984-06-22 1987-05-05 Shell Oil Company Method of analyzing fluid saturation using computerized axial tomography
US4577503A (en) 1984-09-04 1986-03-25 International Business Machines Corporation Method and device for detecting a specific acoustic spectral feature
US4577691A (en) 1984-09-10 1986-03-25 Texaco Inc. Method and apparatus for producing viscous hydrocarbons from a subterranean formation
US4576231A (en) * 1984-09-13 1986-03-18 Texaco Inc. Method and apparatus for combating encroachment by in situ treated formations
US4597444A (en) * 1984-09-21 1986-07-01 Atlantic Richfield Company Method for excavating a large diameter shaft into the earth and at least partially through an oil-bearing formation
US4691771A (en) 1984-09-25 1987-09-08 Worldenergy Systems, Inc. Recovery of oil by in-situ combustion followed by in-situ hydrogenation
US4616705A (en) 1984-10-05 1986-10-14 Shell Oil Company Mini-well temperature profiling process
US4598770A (en) 1984-10-25 1986-07-08 Mobil Oil Corporation Thermal recovery method for viscous oil
JPS61104582A (en) 1984-10-25 1986-05-22 株式会社デンソー Sheathed heater
US4572299A (en) * 1984-10-30 1986-02-25 Shell Oil Company Heater cable installation
US4669542A (en) 1984-11-21 1987-06-02 Mobil Oil Corporation Simultaneous recovery of crude from multiple zones in a reservoir
US4585066A (en) * 1984-11-30 1986-04-29 Shell Oil Company Well treating process for installing a cable bundle containing strands of changing diameter
US4704514A (en) 1985-01-11 1987-11-03 Egmond Cor F Van Heating rate variant elongated electrical resistance heater
US4645906A (en) 1985-03-04 1987-02-24 Thermon Manufacturing Company Reduced resistance skin effect heat generating system
US4785163A (en) 1985-03-26 1988-11-15 Raychem Corporation Method for monitoring a heater
US4698583A (en) 1985-03-26 1987-10-06 Raychem Corporation Method of monitoring a heater for faults
NO861531L (en) 1985-04-19 1986-10-20 Raychem Gmbh HOT BODY.
US4671102A (en) 1985-06-18 1987-06-09 Shell Oil Company Method and apparatus for determining distribution of fluids
US4626665A (en) 1985-06-24 1986-12-02 Shell Oil Company Metal oversheathed electrical resistance heater
US4623444A (en) * 1985-06-27 1986-11-18 Occidental Oil Shale, Inc. Upgrading shale oil by a combination process
US4605489A (en) * 1985-06-27 1986-08-12 Occidental Oil Shale, Inc. Upgrading shale oil by a combination process
US4662438A (en) 1985-07-19 1987-05-05 Uentech Corporation Method and apparatus for enhancing liquid hydrocarbon production from a single borehole in a slowly producing formation by non-uniform heating through optimized electrode arrays surrounding the borehole
US4719423A (en) * 1985-08-13 1988-01-12 Shell Oil Company NMR imaging of materials for transport properties
US4728892A (en) 1985-08-13 1988-03-01 Shell Oil Company NMR imaging of materials
US4778586A (en) 1985-08-30 1988-10-18 Resource Technology Associates Viscosity reduction processing at elevated pressure
US4683947A (en) * 1985-09-05 1987-08-04 Air Products And Chemicals Inc. Process and apparatus for monitoring and controlling the flammability of gas from an in-situ combustion oil recovery project
US4662437A (en) 1985-11-14 1987-05-05 Atlantic Richfield Company Electrically stimulated well production system with flexible tubing conductor
CA1253555A (en) 1985-11-21 1989-05-02 Cornelis F.H. Van Egmond Heating rate variant elongated electrical resistance heater
US4662443A (en) 1985-12-05 1987-05-05 Amoco Corporation Combination air-blown and oxygen-blown underground coal gasification process
US4686029A (en) 1985-12-06 1987-08-11 Union Carbide Corporation Dewaxing catalysts and processes employing titanoaluminosilicate molecular sieves
US4849611A (en) 1985-12-16 1989-07-18 Raychem Corporation Self-regulating heater employing reactive components
US4730162A (en) 1985-12-31 1988-03-08 Shell Oil Company Time-domain induced polarization logging method and apparatus with gated amplification level
US4706751A (en) * 1986-01-31 1987-11-17 S-Cal Research Corp. Heavy oil recovery process
US4694907A (en) 1986-02-21 1987-09-22 Carbotek, Inc. Thermally-enhanced oil recovery method and apparatus
US4640353A (en) * 1986-03-21 1987-02-03 Atlantic Richfield Company Electrode well and method of completion
US4734115A (en) * 1986-03-24 1988-03-29 Air Products And Chemicals, Inc. Low pressure process for C3+ liquids recovery from process product gas
US4651825A (en) * 1986-05-09 1987-03-24 Atlantic Richfield Company Enhanced well production
US4702758A (en) 1986-05-29 1987-10-27 Shell Western E&P Inc. Turbine cooling waxy oil
US4814587A (en) 1986-06-10 1989-03-21 Metcal, Inc. High power self-regulating heater
US4682652A (en) 1986-06-30 1987-07-28 Texaco Inc. Producing hydrocarbons through successively perforated intervals of a horizontal well between two vertical wells
US4769602A (en) 1986-07-02 1988-09-06 Shell Oil Company Determining multiphase saturations by NMR imaging of multiple nuclides
US4893504A (en) * 1986-07-02 1990-01-16 Shell Oil Company Method for determining capillary pressure and relative permeability by imaging
US4716960A (en) * 1986-07-14 1988-01-05 Production Technologies International, Inc. Method and system for introducing electric current into a well
US4818370A (en) 1986-07-23 1989-04-04 Cities Service Oil And Gas Corporation Process for converting heavy crudes, tars, and bitumens to lighter products in the presence of brine at supercritical conditions
US4772634A (en) 1986-07-31 1988-09-20 Energy Research Corporation Apparatus and method for methanol production using a fuel cell to regulate the gas composition entering the methanol synthesizer
US4744245A (en) 1986-08-12 1988-05-17 Atlantic Richfield Company Acoustic measurements in rock formations for determining fracture orientation
US4696345A (en) * 1986-08-21 1987-09-29 Chevron Research Company Hasdrive with multiple offset producers
US4728412A (en) * 1986-09-19 1988-03-01 Amoco Corporation Pour-point depression of crude oils by addition of tar sand bitumen
US4769606A (en) 1986-09-30 1988-09-06 Shell Oil Company Induced polarization method and apparatus for distinguishing dispersed and laminated clay in earth formations
US4737267A (en) * 1986-11-12 1988-04-12 Duo-Ex Coproration Oil shale processing apparatus and method
US5340467A (en) 1986-11-24 1994-08-23 Canadian Occidental Petroleum Ltd. Process for recovery of hydrocarbons and rejection of sand
US4983319A (en) * 1986-11-24 1991-01-08 Canadian Occidental Petroleum Ltd. Preparation of low-viscosity improved stable crude oil transport emulsions
CA1288043C (en) 1986-12-15 1991-08-27 Peter Van Meurs Conductively heating a subterranean oil shale to create permeabilityand subsequently produce oil
US4766958A (en) * 1987-01-12 1988-08-30 Mobil Oil Corporation Method of recovering viscous oil from reservoirs with multiple horizontal zones
US4793656A (en) 1987-02-12 1988-12-27 Shell Mining Company In-situ coal drying
US4756367A (en) 1987-04-28 1988-07-12 Amoco Corporation Method for producing natural gas from a coal seam
US4817711A (en) 1987-05-27 1989-04-04 Jeambey Calhoun G System for recovery of petroleum from petroleum impregnated media
US4818371A (en) * 1987-06-05 1989-04-04 Resource Technology Associates Viscosity reduction by direct oxidative heating
US4787452A (en) 1987-06-08 1988-11-29 Mobil Oil Corporation Disposal of produced formation fines during oil recovery
US4821798A (en) 1987-06-09 1989-04-18 Ors Development Corporation Heating system for rathole oil well
US4793409A (en) 1987-06-18 1988-12-27 Ors Development Corporation Method and apparatus for forming an insulated oil well casing
US4884455A (en) 1987-06-25 1989-12-05 Shell Oil Company Method for analysis of failure of material employing imaging
US4856341A (en) 1987-06-25 1989-08-15 Shell Oil Company Apparatus for analysis of failure of material
US4827761A (en) 1987-06-25 1989-05-09 Shell Oil Company Sample holder
US4776638A (en) * 1987-07-13 1988-10-11 University Of Kentucky Research Foundation Method and apparatus for conversion of coal in situ
US4848924A (en) 1987-08-19 1989-07-18 The Babcock & Wilcox Company Acoustic pyrometer
CA1254505A (en) * 1987-10-02 1989-05-23 Ion I. Adamache Exploitation method for reservoirs containing hydrogen sulphide
US4828031A (en) * 1987-10-13 1989-05-09 Chevron Research Company In situ chemical stimulation of diatomite formations
US4762425A (en) 1987-10-15 1988-08-09 Parthasarathy Shakkottai System for temperature profile measurement in large furnances and kilns and method therefor
US5306640A (en) 1987-10-28 1994-04-26 Shell Oil Company Method for determining preselected properties of a crude oil
US4987368A (en) * 1987-11-05 1991-01-22 Shell Oil Company Nuclear magnetism logging tool using high-temperature superconducting squid detectors
US4842448A (en) 1987-11-12 1989-06-27 Drexel University Method of removing contaminants from contaminated soil in situ
US4808925A (en) 1987-11-19 1989-02-28 Halliburton Company Three magnet casing collar locator
US4852648A (en) 1987-12-04 1989-08-01 Ava International Corporation Well installation in which electrical current is supplied for a source at the wellhead to an electrically responsive device located a substantial distance below the wellhead
US4823890A (en) 1988-02-23 1989-04-25 Longyear Company Reverse circulation bit apparatus
US4883582A (en) * 1988-03-07 1989-11-28 Mccants Malcolm T Vis-breaking heavy crude oils for pumpability
US4866983A (en) 1988-04-14 1989-09-19 Shell Oil Company Analytical methods and apparatus for measuring the oil content of sponge core
US4815790A (en) * 1988-05-13 1989-03-28 Natec, Ltd. Nahcolite solution mining process
US4885080A (en) * 1988-05-25 1989-12-05 Phillips Petroleum Company Process for demetallizing and desulfurizing heavy crude oil
US4884635A (en) 1988-08-24 1989-12-05 Texaco Canada Resources Enhanced oil recovery with a mixture of water and aromatic hydrocarbons
US4840720A (en) 1988-09-02 1989-06-20 Betz Laboratories, Inc. Process for minimizing fouling of processing equipment
US4928765A (en) * 1988-09-27 1990-05-29 Ramex Syn-Fuels International Method and apparatus for shale gas recovery
US4856587A (en) * 1988-10-27 1989-08-15 Nielson Jay P Recovery of oil from oil-bearing formation by continually flowing pressurized heated gas through channel alongside matrix
US4848460A (en) 1988-11-04 1989-07-18 Western Research Institute Contained recovery of oily waste
US5065501A (en) 1988-11-29 1991-11-19 Amp Incorporated Generating electromagnetic fields in a self regulating temperature heater by positioning of a current return bus
US4974425A (en) 1988-12-08 1990-12-04 Concept Rkk, Limited Closed cryogenic barrier for containment of hazardous material migration in the earth
US4860544A (en) 1988-12-08 1989-08-29 Concept R.K.K. Limited Closed cryogenic barrier for containment of hazardous material migration in the earth
US4940095A (en) 1989-01-27 1990-07-10 Dowell Schlumberger Incorporated Deployment/retrieval method and apparatus for well tools used with coiled tubing
US5103920A (en) 1989-03-01 1992-04-14 Patton Consulting Inc. Surveying system and method for locating target subterranean bodies
CA2015318C (en) * 1990-04-24 1994-02-08 Jack E. Bridges Power sources for downhole electrical heating
US4895206A (en) * 1989-03-16 1990-01-23 Price Ernest H Pulsed in situ exothermic shock wave and retorting process for hydrocarbon recovery and detoxification of selected wastes
US4913065A (en) 1989-03-27 1990-04-03 Indugas, Inc. In situ thermal waste disposal system
US5150118A (en) 1989-05-08 1992-09-22 Hewlett-Packard Company Interchangeable coded key pad assemblies alternately attachable to a user definable keyboard to enable programmable keyboard functions
US5084637A (en) * 1989-05-30 1992-01-28 International Business Machines Corp. Bidirectional level shifting interface circuit
DE3918265A1 (en) 1989-06-05 1991-01-03 Henkel Kgaa PROCESS FOR THE PREPARATION OF ETHANE SULPHONATE BASE TENSID MIXTURES AND THEIR USE
US5059303A (en) * 1989-06-16 1991-10-22 Amoco Corporation Oil stabilization
US5041210A (en) * 1989-06-30 1991-08-20 Marathon Oil Company Oil shale retorting with steam and produced gas
DE3922612C2 (en) * 1989-07-10 1998-07-02 Krupp Koppers Gmbh Process for the production of methanol synthesis gas
US4982786A (en) * 1989-07-14 1991-01-08 Mobil Oil Corporation Use of CO2 /steam to enhance floods in horizontal wellbores
US5050386A (en) 1989-08-16 1991-09-24 Rkk, Limited Method and apparatus for containment of hazardous material migration in the earth
US5097903A (en) * 1989-09-22 1992-03-24 Jack C. Sloan Method for recovering intractable petroleum from subterranean formations
US5305239A (en) 1989-10-04 1994-04-19 The Texas A&M University System Ultrasonic non-destructive evaluation of thin specimens
US4926941A (en) * 1989-10-10 1990-05-22 Shell Oil Company Method of producing tar sand deposits containing conductive layers
US5656239A (en) 1989-10-27 1997-08-12 Shell Oil Company Method for recovering contaminants from soil utilizing electrical heating
US4984594A (en) * 1989-10-27 1991-01-15 Shell Oil Company Vacuum method for removing soil contamination utilizing surface electrical heating
US5020596A (en) 1990-01-24 1991-06-04 Indugas, Inc. Enhanced oil recovery system with a radiant tube heater
US5082055A (en) * 1990-01-24 1992-01-21 Indugas, Inc. Gas fired radiant tube heater
US5011329A (en) 1990-02-05 1991-04-30 Hrubetz Exploration Company In situ soil decontamination method and apparatus
CA2009782A1 (en) * 1990-02-12 1991-08-12 Anoosh I. Kiamanesh In-situ tuned microwave oil extraction process
US5152341A (en) 1990-03-09 1992-10-06 Raymond S. Kasevich Electromagnetic method and apparatus for the decontamination of hazardous material-containing volumes
US5027896A (en) * 1990-03-21 1991-07-02 Anderson Leonard M Method for in-situ recovery of energy raw material by the introduction of a water/oxygen slurry
GB9007147D0 (en) * 1990-03-30 1990-05-30 Framo Dev Ltd Thermal mineral extraction system
US5014788A (en) 1990-04-20 1991-05-14 Amoco Corporation Method of increasing the permeability of a coal seam
CA2015460C (en) 1990-04-26 1993-12-14 Kenneth Edwin Kisman Process for confining steam injected into a heavy oil reservoir
US5126037A (en) 1990-05-04 1992-06-30 Union Oil Company Of California Geopreater heating method and apparatus
US5032042A (en) 1990-06-26 1991-07-16 New Jersey Institute Of Technology Method and apparatus for eliminating non-naturally occurring subsurface, liquid toxic contaminants from soil
US5201219A (en) 1990-06-29 1993-04-13 Amoco Corporation Method and apparatus for measuring free hydrocarbons and hydrocarbons potential from whole core
US5054551A (en) 1990-08-03 1991-10-08 Chevron Research And Technology Company In-situ heated annulus refining process
US5109928A (en) 1990-08-17 1992-05-05 Mccants Malcolm T Method for production of hydrocarbon diluent from heavy crude oil
US5042579A (en) 1990-08-23 1991-08-27 Shell Oil Company Method and apparatus for producing tar sand deposits containing conductive layers
US5060726A (en) 1990-08-23 1991-10-29 Shell Oil Company Method and apparatus for producing tar sand deposits containing conductive layers having little or no vertical communication
US5046559A (en) 1990-08-23 1991-09-10 Shell Oil Company Method and apparatus for producing hydrocarbon bearing deposits in formations having shale layers
BR9004240A (en) * 1990-08-28 1992-03-24 Petroleo Brasileiro Sa ELECTRIC PIPE HEATING PROCESS
US5085276A (en) * 1990-08-29 1992-02-04 Chevron Research And Technology Company Production of oil from low permeability formations by sequential steam fracturing
US5066852A (en) 1990-09-17 1991-11-19 Teledyne Ind. Inc. Thermoplastic end seal for electric heating elements
US5207273A (en) 1990-09-17 1993-05-04 Production Technologies International Inc. Method and apparatus for pumping wells
JPH04272680A (en) 1990-09-20 1992-09-29 Thermon Mfg Co Switch-controlled-zone type heating cable and assembling method thereof
US5182427A (en) 1990-09-20 1993-01-26 Metcal, Inc. Self-regulating heater utilizing ferrite-type body
US5400430A (en) * 1990-10-01 1995-03-21 Nenniger; John E. Method for injection well stimulation
US5247994A (en) 1990-10-01 1993-09-28 Nenniger John E Method of stimulating oil wells
US5517593A (en) * 1990-10-01 1996-05-14 John Nenniger Control system for well stimulation apparatus with response time temperature rise used in determining heater control temperature setpoint
FR2669077B2 (en) 1990-11-09 1995-02-03 Institut Francais Petrole METHOD AND DEVICE FOR PERFORMING INTERVENTIONS IN WELLS OR HIGH TEMPERATURES.
US5060287A (en) 1990-12-04 1991-10-22 Shell Oil Company Heater utilizing copper-nickel alloy core
US5065818A (en) 1991-01-07 1991-11-19 Shell Oil Company Subterranean heaters
US5190405A (en) * 1990-12-14 1993-03-02 Shell Oil Company Vacuum method for removing soil contaminants utilizing thermal conduction heating
SU1836876A3 (en) 1990-12-29 1994-12-30 Смешанное научно-техническое товарищество по разработке техники и технологии для подземной электроэнергетики Process of development of coal seams and complex of equipment for its implementation
US5626190A (en) 1991-02-06 1997-05-06 Moore; Boyd B. Apparatus for protecting electrical connection from moisture in a hazardous area adjacent a wellhead barrier for an underground well
US5289882A (en) * 1991-02-06 1994-03-01 Boyd B. Moore Sealed electrical conductor method and arrangement for use with a well bore in hazardous areas
US5103909A (en) 1991-02-19 1992-04-14 Shell Oil Company Profile control in enhanced oil recovery
US5102551A (en) 1991-04-29 1992-04-07 Texaco Inc. Membrane process for treating a mixture containing dewaxed oil and dewaxing solvent
US5093002A (en) 1991-04-29 1992-03-03 Texaco Inc. Membrane process for treating a mixture containing dewaxed oil and dewaxing solvent
US5246273A (en) 1991-05-13 1993-09-21 Rosar Edward C Method and apparatus for solution mining
ATE147135T1 (en) * 1991-06-17 1997-01-15 Electric Power Res Inst ENERGY SYSTEM WITH COMPRESSED AIR STORAGE
DK0519573T3 (en) * 1991-06-21 1995-07-03 Shell Int Research Hydrogenation catalyst and process
IT1248535B (en) 1991-06-24 1995-01-19 Cise Spa SYSTEM TO MEASURE THE TRANSFER TIME OF A SOUND WAVE
US5215954A (en) 1991-07-30 1993-06-01 Cri International, Inc. Method of presulfurizing a hydrotreating, hydrocracking or tail gas treating catalyst
US5189283A (en) * 1991-08-28 1993-02-23 Shell Oil Company Current to power crossover heater control
US5168927A (en) 1991-09-10 1992-12-08 Shell Oil Company Method utilizing spot tracer injection and production induced transport for measurement of residual oil saturation
US5173213A (en) 1991-11-08 1992-12-22 Baker Hughes Incorporated Corrosion and anti-foulant composition and method of use
US5347070A (en) 1991-11-13 1994-09-13 Battelle Pacific Northwest Labs Treating of solid earthen material and a method for measuring moisture content and resistivity of solid earthen material
US5349859A (en) 1991-11-15 1994-09-27 Scientific Engineering Instruments, Inc. Method and apparatus for measuring acoustic wave velocity using impulse response
US5199490A (en) 1991-11-18 1993-04-06 Texaco Inc. Formation treating
DE69209466T2 (en) 1991-12-16 1996-08-14 Inst Francais Du Petrole Active or passive monitoring arrangement for underground deposit by means of fixed stations
CA2058255C (en) 1991-12-20 1997-02-11 Roland P. Leaute Recovery and upgrading of hydrocarbons utilizing in situ combustion and horizontal wells
DK0555060T3 (en) * 1992-02-04 1996-08-19 Air Prod & Chem Methanol production in liquid phase with CO-rich feedback
US5420402A (en) 1992-02-05 1995-05-30 Iit Research Institute Methods and apparatus to confine earth currents for recovery of subsurface volatiles and semi-volatiles
US5211230A (en) 1992-02-21 1993-05-18 Mobil Oil Corporation Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion
GB9207174D0 (en) 1992-04-01 1992-05-13 Raychem Sa Nv Method of forming an electrical connection
US5255740A (en) 1992-04-13 1993-10-26 Rrkt Company Secondary recovery process
US5332036A (en) 1992-05-15 1994-07-26 The Boc Group, Inc. Method of recovery of natural gases from underground coal formations
US5392854A (en) * 1992-06-12 1995-02-28 Shell Oil Company Oil recovery process
US5255742A (en) 1992-06-12 1993-10-26 Shell Oil Company Heat injection process
US5297626A (en) * 1992-06-12 1994-03-29 Shell Oil Company Oil recovery process
US5226961A (en) 1992-06-12 1993-07-13 Shell Oil Company High temperature wellbore cement slurry
US5236039A (en) 1992-06-17 1993-08-17 General Electric Company Balanced-line RF electrode system for use in RF ground heating to recover oil from oil shale
US5295763A (en) * 1992-06-30 1994-03-22 Chambers Development Co., Inc. Method for controlling gas migration from a landfill
US5275726A (en) 1992-07-29 1994-01-04 Exxon Research & Engineering Co. Spiral wound element for separation
US5282957A (en) 1992-08-19 1994-02-01 Betz Laboratories, Inc. Methods for inhibiting polymerization of hydrocarbons utilizing a hydroxyalkylhydroxylamine
US5305829A (en) * 1992-09-25 1994-04-26 Chevron Research And Technology Company Oil production from diatomite formations by fracture steamdrive
US5229583A (en) 1992-09-28 1993-07-20 Shell Oil Company Surface heating blanket for soil remediation
US5339904A (en) 1992-12-10 1994-08-23 Mobil Oil Corporation Oil recovery optimization using a well having both horizontal and vertical sections
CA2096034C (en) * 1993-05-07 1996-07-02 Kenneth Edwin Kisman Horizontal well gravity drainage combustion process for oil recovery
US5360067A (en) 1993-05-17 1994-11-01 Meo Iii Dominic Vapor-extraction system for removing hydrocarbons from soil
US5325918A (en) * 1993-08-02 1994-07-05 The United States Of America As Represented By The United States Department Of Energy Optimal joule heating of the subsurface
US5377756A (en) * 1993-10-28 1995-01-03 Mobil Oil Corporation Method for producing low permeability reservoirs using a single well
US5388642A (en) * 1993-11-03 1995-02-14 Amoco Corporation Coalbed methane recovery using membrane separation of oxygen from air
US5388640A (en) * 1993-11-03 1995-02-14 Amoco Corporation Method for producing methane-containing gaseous mixtures
US5388643A (en) * 1993-11-03 1995-02-14 Amoco Corporation Coalbed methane recovery using pressure swing adsorption separation
US5388641A (en) * 1993-11-03 1995-02-14 Amoco Corporation Method for reducing the inert gas fraction in methane-containing gaseous mixtures obtained from underground formations
US5566755A (en) 1993-11-03 1996-10-22 Amoco Corporation Method for recovering methane from a solid carbonaceous subterranean formation
US5388645A (en) * 1993-11-03 1995-02-14 Amoco Corporation Method for producing methane-containing gaseous mixtures
US5411086A (en) * 1993-12-09 1995-05-02 Mobil Oil Corporation Oil recovery by enhanced imbitition in low permeability reservoirs
US5435666A (en) 1993-12-14 1995-07-25 Environmental Resources Management, Inc. Methods for isolating a water table and for soil remediation
US5433271A (en) 1993-12-20 1995-07-18 Shell Oil Company Heat injection process
US5411089A (en) 1993-12-20 1995-05-02 Shell Oil Company Heat injection process
US5404952A (en) 1993-12-20 1995-04-11 Shell Oil Company Heat injection process and apparatus
US5634984A (en) 1993-12-22 1997-06-03 Union Oil Company Of California Method for cleaning an oil-coated substrate
CA2144597C (en) 1994-03-18 1999-08-10 Paul J. Latimer Improved emat probe and technique for weld inspection
US5415231A (en) 1994-03-21 1995-05-16 Mobil Oil Corporation Method for producing low permeability reservoirs using steam
US5439054A (en) 1994-04-01 1995-08-08 Amoco Corporation Method for treating a mixture of gaseous fluids within a solid carbonaceous subterranean formation
US5431224A (en) 1994-04-19 1995-07-11 Mobil Oil Corporation Method of thermal stimulation for recovery of hydrocarbons
US5409071A (en) 1994-05-23 1995-04-25 Shell Oil Company Method to cement a wellbore
ZA954204B (en) 1994-06-01 1996-01-22 Ashland Chemical Inc A process for improving the effectiveness of a process catalyst
US5503226A (en) 1994-06-22 1996-04-02 Wadleigh; Eugene E. Process for recovering hydrocarbons by thermally assisted gravity segregation
AU2241695A (en) 1994-07-18 1996-02-16 Babcock & Wilcox Co., The Sensor transport system for flash butt welder
US5402847A (en) 1994-07-22 1995-04-04 Conoco Inc. Coal bed methane recovery
US5458774A (en) 1994-07-25 1995-10-17 Mannapperuma; Jatal D. Corrugated spiral membrane module
US5632336A (en) 1994-07-28 1997-05-27 Texaco Inc. Method for improving injectivity of fluids in oil reservoirs
US5539853A (en) * 1994-08-01 1996-07-23 Noranda, Inc. Downhole heating system with separate wiring cooling and heating chambers and gas flow therethrough
US5525322A (en) 1994-10-12 1996-06-11 The Regents Of The University Of California Method for simultaneous recovery of hydrogen from water and from hydrocarbons
US5553189A (en) 1994-10-18 1996-09-03 Shell Oil Company Radiant plate heater for treatment of contaminated surfaces
US5497087A (en) * 1994-10-20 1996-03-05 Shell Oil Company NMR logging of natural gas reservoirs
US5624188A (en) 1994-10-20 1997-04-29 West; David A. Acoustic thermometer
US5498960A (en) * 1994-10-20 1996-03-12 Shell Oil Company NMR logging of natural gas in reservoirs
US5559263A (en) 1994-11-16 1996-09-24 Tiorco, Inc. Aluminum citrate preparations and methods
US5554453A (en) 1995-01-04 1996-09-10 Energy Research Corporation Carbonate fuel cell system with thermally integrated gasification
US6088294A (en) 1995-01-12 2000-07-11 Baker Hughes Incorporated Drilling system with an acoustic measurement-while-driving system for determining parameters of interest and controlling the drilling direction
WO1996021871A1 (en) 1995-01-12 1996-07-18 Baker Hughes Incorporated A measurement-while-drilling acoustic system employing multiple, segmented transmitters and receivers
DE19505517A1 (en) * 1995-02-10 1996-08-14 Siegfried Schwert Procedure for extracting a pipe laid in the ground
US5621844A (en) 1995-03-01 1997-04-15 Uentech Corporation Electrical heating of mineral well deposits using downhole impedance transformation networks
CA2152521C (en) * 1995-03-01 2000-06-20 Jack E. Bridges Low flux leakage cables and cable terminations for a.c. electrical heating of oil deposits
US5935421A (en) 1995-05-02 1999-08-10 Exxon Research And Engineering Company Continuous in-situ combination process for upgrading heavy oil
US5911898A (en) 1995-05-25 1999-06-15 Electric Power Research Institute Method and apparatus for providing multiple autoregulated temperatures
US5571403A (en) 1995-06-06 1996-11-05 Texaco Inc. Process for extracting hydrocarbons from diatomite
US6170264B1 (en) 1997-09-22 2001-01-09 Clean Energy Systems, Inc. Hydrocarbon combustion power generation system with CO2 sequestration
US6165154A (en) * 1995-06-07 2000-12-26 Deka Products Limited Partnership Cassette for intravenous-line flow-control system
US6015015A (en) * 1995-06-20 2000-01-18 Bj Services Company U.S.A. Insulated and/or concentric coiled tubing
US5626191A (en) * 1995-06-23 1997-05-06 Petroleum Recovery Institute Oilfield in-situ combustion process
US5899958A (en) 1995-09-11 1999-05-04 Halliburton Energy Services, Inc. Logging while drilling borehole imaging and dipmeter device
US5759022A (en) 1995-10-16 1998-06-02 Gas Research Institute Method and system for reducing NOx and fuel emissions in a furnace
DE59510855D1 (en) * 1995-11-08 2004-03-18 Ct Pulse Orthopedics Ltd Intervertebral prosthesis
US5767584A (en) 1995-11-14 1998-06-16 Grow International Corp. Method for generating electrical power from fuel cell powered cars parked in a conventional parking lot
US5890840A (en) 1995-12-08 1999-04-06 Carter, Jr.; Ernest E. In situ construction of containment vault under a radioactive or hazardous waste site
PT870100E (en) * 1995-12-27 2000-09-29 Shell Int Research CHAMBER OF COMBUSTION WITHOUT FLAME AND RESPECTIVE IGNITION PROCESS
IE960011A1 (en) 1996-01-10 1997-07-16 Padraig Mcalister Structural ice composites, processes for their construction¹and their use as artificial islands and other fixed and¹floating structures
US5751895A (en) * 1996-02-13 1998-05-12 Eor International, Inc. Selective excitation of heating electrodes for oil wells
US5676212A (en) 1996-04-17 1997-10-14 Vector Magnetics, Inc. Downhole electrode for well guidance system
US5826655A (en) 1996-04-25 1998-10-27 Texaco Inc Method for enhanced recovery of viscous oil deposits
US5652389A (en) 1996-05-22 1997-07-29 The United States Of America As Represented By The Secretary Of Commerce Non-contact method and apparatus for inspection of inertia welds
US6022834A (en) 1996-05-24 2000-02-08 Oil Chem Technologies, Inc. Alkaline surfactant polymer flooding composition and process
CA2177726C (en) 1996-05-29 2000-06-27 Theodore Wildi Low-voltage and low flux density heating system
US5769569A (en) 1996-06-18 1998-06-23 Southern California Gas Company In-situ thermal desorption of heavy hydrocarbons in vadose zone
US5828797A (en) 1996-06-19 1998-10-27 Meggitt Avionics, Inc. Fiber optic linked flame sensor
WO1997048639A1 (en) 1996-06-21 1997-12-24 Syntroleum Corporation Synthesis gas production system and method
PE17599A1 (en) * 1996-07-09 1999-02-22 Syntroleum Corp PROCEDURE TO CONVERT GASES TO LIQUIDS
US5826653A (en) 1996-08-02 1998-10-27 Scientific Applications & Research Associates, Inc. Phased array approach to retrieve gases, liquids, or solids from subaqueous geologic or man-made formations
US5782301A (en) 1996-10-09 1998-07-21 Baker Hughes Incorporated Oil well heater cable
US6056057A (en) 1996-10-15 2000-05-02 Shell Oil Company Heater well method and apparatus
US6079499A (en) 1996-10-15 2000-06-27 Shell Oil Company Heater well method and apparatus
US5861137A (en) * 1996-10-30 1999-01-19 Edlund; David J. Steam reformer with internal hydrogen purification
US5955039A (en) 1996-12-19 1999-09-21 Siemens Westinghouse Power Corporation Coal gasification and hydrogen production system and method
US5862858A (en) * 1996-12-26 1999-01-26 Shell Oil Company Flameless combustor
US6427124B1 (en) 1997-01-24 2002-07-30 Baker Hughes Incorporated Semblance processing for an acoustic measurement-while-drilling system for imaging of formation boundaries
US6039121A (en) 1997-02-20 2000-03-21 Rangewest Technologies Ltd. Enhanced lift method and apparatus for the production of hydrocarbons
US5744025A (en) 1997-02-28 1998-04-28 Shell Oil Company Process for hydrotreating metal-contaminated hydrocarbonaceous feedstock
GB9704181D0 (en) * 1997-02-28 1997-04-16 Thompson James Apparatus and method for installation of ducts
US5926437A (en) 1997-04-08 1999-07-20 Halliburton Energy Services, Inc. Method and apparatus for seismic exploration
US5984578A (en) 1997-04-11 1999-11-16 New Jersey Institute Of Technology Apparatus and method for in situ removal of contaminants using sonic energy
US5802870A (en) 1997-05-02 1998-09-08 Uop Llc Sorption cooling process and system
GB2364381B (en) 1997-05-02 2002-03-06 Baker Hughes Inc Downhole injection evaluation system
WO1998050179A1 (en) 1997-05-07 1998-11-12 Shell Internationale Research Maatschappij B.V. Remediation method
US6023554A (en) * 1997-05-20 2000-02-08 Shell Oil Company Electrical heater
AU720947B2 (en) 1997-06-05 2000-06-15 Shell Internationale Research Maatschappij B.V. Remediation method
US6102122A (en) 1997-06-11 2000-08-15 Shell Oil Company Control of heat injection based on temperature and in-situ stress measurement
US6112808A (en) * 1997-09-19 2000-09-05 Isted; Robert Edward Method and apparatus for subterranean thermal conditioning
US5984010A (en) 1997-06-23 1999-11-16 Elias; Ramon Hydrocarbon recovery systems and methods
CA2208767A1 (en) 1997-06-26 1998-12-26 Reginald D. Humphreys Tar sands extraction process
US5891829A (en) * 1997-08-12 1999-04-06 Intevep, S.A. Process for the downhole upgrading of extra heavy crude oil
US5868202A (en) * 1997-09-22 1999-02-09 Tarim Associates For Scientific Mineral And Oil Exploration Ag Hydrologic cells for recovery of hydrocarbons or thermal energy from coal, oil-shale, tar-sands and oil-bearing formations
US6149344A (en) 1997-10-04 2000-11-21 Master Corporation Acid gas disposal
US6187465B1 (en) * 1997-11-07 2001-02-13 Terry R. Galloway Process and system for converting carbonaceous feedstocks into energy without greenhouse gas emissions
US6354373B1 (en) 1997-11-26 2002-03-12 Schlumberger Technology Corporation Expandable tubing for a well bore hole and method of expanding
ATE236343T1 (en) 1997-12-11 2003-04-15 Alberta Res Council PETROLEUM PROCESSING PROCESS IN SITU
US6152987A (en) 1997-12-15 2000-11-28 Worcester Polytechnic Institute Hydrogen gas-extraction module and method of fabrication
US6094048A (en) 1997-12-18 2000-07-25 Shell Oil Company NMR logging of natural gas reservoirs
NO305720B1 (en) * 1997-12-22 1999-07-12 Eureka Oil Asa Procedure for increasing oil production from an oil reservoir
US6026914A (en) 1998-01-28 2000-02-22 Alberta Oil Sands Technology And Research Authority Wellbore profiling system
US6035949A (en) 1998-02-03 2000-03-14 Altschuler; Sidney J. Methods for installing a well in a subterranean formation
US6540018B1 (en) 1998-03-06 2003-04-01 Shell Oil Company Method and apparatus for heating a wellbore
US6269876B1 (en) * 1998-03-06 2001-08-07 Shell Oil Company Electrical heater
MA24902A1 (en) 1998-03-06 2000-04-01 Shell Int Research ELECTRIC HEATER
CA2327744C (en) 1998-04-06 2004-07-13 Da Qing Petroleum Administration Bureau A foam drive method
US6035701A (en) * 1998-04-15 2000-03-14 Lowry; William E. Method and system to locate leaks in subsurface containment structures using tracer gases
AU3978399A (en) * 1998-05-12 1999-11-29 Lockheed Martin Corporation System and process for secondary hydrocarbon recovery
US6173778B1 (en) * 1998-05-27 2001-01-16 Bj Services Company Storable liquid systems for use in cementing oil and gas wells
US6244338B1 (en) 1998-06-23 2001-06-12 The University Of Wyoming Research Corp., System for improving coalbed gas production
US6016868A (en) * 1998-06-24 2000-01-25 World Energy Systems, Incorporated Production of synthetic crude oil from heavy hydrocarbons recovered by in situ hydrovisbreaking
US6016867A (en) 1998-06-24 2000-01-25 World Energy Systems, Incorporated Upgrading and recovery of heavy crude oils and natural bitumens by in situ hydrovisbreaking
US6130398A (en) 1998-07-09 2000-10-10 Illinois Tool Works Inc. Plasma cutter for auxiliary power output of a power source
US6388947B1 (en) 1998-09-14 2002-05-14 Tomoseis, Inc. Multi-crosswell profile 3D imaging and method
NO984235L (en) 1998-09-14 2000-03-15 Cit Alcatel Heating system for metal pipes for crude oil transport
US6192748B1 (en) * 1998-10-30 2001-02-27 Computalog Limited Dynamic orienting reference system for directional drilling
US5968349A (en) 1998-11-16 1999-10-19 Bhp Minerals International Inc. Extraction of bitumen from bitumen froth and biotreatment of bitumen froth tailings generated from tar sands
US20040035582A1 (en) 2002-08-22 2004-02-26 Zupanick Joseph A. System and method for subterranean access
US6269881B1 (en) 1998-12-22 2001-08-07 Chevron U.S.A. Inc Oil recovery method for waxy crude oil using alkylaryl sulfonate surfactants derived from alpha-olefins and the alpha-olefin compositions
US6609761B1 (en) 1999-01-08 2003-08-26 American Soda, Llp Sodium carbonate and sodium bicarbonate production from nahcolitic oil shale
US6078868A (en) 1999-01-21 2000-06-20 Baker Hughes Incorporated Reference signal encoding for seismic while drilling measurement
US6218333B1 (en) 1999-02-15 2001-04-17 Shell Oil Company Preparation of a hydrotreating catalyst
US6283230B1 (en) 1999-03-01 2001-09-04 Jasper N. Peters Method and apparatus for lateral well drilling utilizing a rotating nozzle
US6155117A (en) 1999-03-18 2000-12-05 Mcdermott Technology, Inc. Edge detection and seam tracking with EMATs
US6561269B1 (en) 1999-04-30 2003-05-13 The Regents Of The University Of California Canister, sealing method and composition for sealing a borehole
US6110358A (en) * 1999-05-21 2000-08-29 Exxon Research And Engineering Company Process for manufacturing improved process oils using extraction of hydrotreated distillates
US6257334B1 (en) 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process
US6269310B1 (en) 1999-08-25 2001-07-31 Tomoseis Corporation System for eliminating headwaves in a tomographic process
US6193010B1 (en) 1999-10-06 2001-02-27 Tomoseis Corporation System for generating a seismic signal in a borehole
US6196350B1 (en) 1999-10-06 2001-03-06 Tomoseis Corporation Apparatus and method for attenuating tube waves in a borehole
US6288372B1 (en) 1999-11-03 2001-09-11 Tyco Electronics Corporation Electric cable having braidless polymeric ground plane providing fault detection
US6353706B1 (en) * 1999-11-18 2002-03-05 Uentech International Corporation Optimum oil-well casing heating
US6417268B1 (en) 1999-12-06 2002-07-09 Hercules Incorporated Method for making hydrophobically associative polymers, methods of use and compositions
US6318468B1 (en) 1999-12-16 2001-11-20 Consolidated Seven Rocks Mining, Ltd. Recovery and reforming of crudes at the heads of multifunctional wells and oil mining system with flue gas stimulation
US6422318B1 (en) * 1999-12-17 2002-07-23 Scioto County Regional Water District #1 Horizontal well system
US6715550B2 (en) 2000-01-24 2004-04-06 Shell Oil Company Controllable gas-lift well and valve
US6633236B2 (en) 2000-01-24 2003-10-14 Shell Oil Company Permanent downhole, wireless, two-way telemetry backbone using redundant repeaters
US6679332B2 (en) * 2000-01-24 2004-01-20 Shell Oil Company Petroleum well having downhole sensors, communication and power
US7259688B2 (en) 2000-01-24 2007-08-21 Shell Oil Company Wireless reservoir production control
WO2001056922A1 (en) * 2000-02-01 2001-08-09 Texaco Development Corporation Integration of shift reactors and hydrotreaters
AU4341301A (en) * 2000-03-02 2001-09-12 Shell Oil Co Controlled downhole chemical injection
MY128294A (en) 2000-03-02 2007-01-31 Shell Int Research Use of downhole high pressure gas in a gas-lift well
US7170424B2 (en) 2000-03-02 2007-01-30 Shell Oil Company Oil well casting electrical power pick-off points
US6357526B1 (en) 2000-03-16 2002-03-19 Kellogg Brown & Root, Inc. Field upgrading of heavy oil and bitumen
US6485232B1 (en) 2000-04-14 2002-11-26 Board Of Regents, The University Of Texas System Low cost, self regulating heater for use in an in situ thermal desorption soil remediation system
US6632047B2 (en) * 2000-04-14 2003-10-14 Board Of Regents, The University Of Texas System Heater element for use in an in situ thermal desorption soil remediation system
US6918444B2 (en) 2000-04-19 2005-07-19 Exxonmobil Upstream Research Company Method for production of hydrocarbons from organic-rich rock
GB0009662D0 (en) 2000-04-20 2000-06-07 Scotoil Group Plc Gas and oil production
US6698515B2 (en) 2000-04-24 2004-03-02 Shell Oil Company In situ thermal processing of a coal formation using a relatively slow heating rate
WO2001081239A2 (en) 2000-04-24 2001-11-01 Shell Internationale Research Maatschappij B.V. In situ recovery from a hydrocarbon containing formation
US7011154B2 (en) 2000-04-24 2006-03-14 Shell Oil Company In situ recovery from a kerogen and liquid hydrocarbon containing formation
US6715546B2 (en) 2000-04-24 2004-04-06 Shell Oil Company In situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore
US6715548B2 (en) 2000-04-24 2004-04-06 Shell Oil Company In situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids
US7096953B2 (en) * 2000-04-24 2006-08-29 Shell Oil Company In situ thermal processing of a coal formation using a movable heating element
US20030085034A1 (en) 2000-04-24 2003-05-08 Wellington Scott Lee In situ thermal processing of a coal formation to produce pyrolsis products
US6588504B2 (en) * 2000-04-24 2003-07-08 Shell Oil Company In situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids
US6584406B1 (en) 2000-06-15 2003-06-24 Geo-X Systems, Ltd. Downhole process control method utilizing seismic communication
GB2383633A (en) 2000-06-29 2003-07-02 Paulo S Tubel Method and system for monitoring smart structures utilizing distributed optical sensors
US6585046B2 (en) 2000-08-28 2003-07-01 Baker Hughes Incorporated Live well heater cable
US6412559B1 (en) 2000-11-24 2002-07-02 Alberta Research Council Inc. Process for recovering methane and/or sequestering fluids
US20020110476A1 (en) 2000-12-14 2002-08-15 Maziasz Philip J. Heat and corrosion resistant cast stainless steels with improved high temperature strength and ductility
US20020112987A1 (en) * 2000-12-15 2002-08-22 Zhiguo Hou Slurry hydroprocessing for heavy oil upgrading using supported slurry catalysts
US20020112890A1 (en) * 2001-01-22 2002-08-22 Wentworth Steven W. Conduit pulling apparatus and method for use in horizontal drilling
US6516891B1 (en) 2001-02-08 2003-02-11 L. Murray Dallas Dual string coil tubing injector assembly
US6821501B2 (en) 2001-03-05 2004-11-23 Shell Oil Company Integrated flameless distributed combustion/steam reforming membrane reactor for hydrogen production and use thereof in zero emissions hybrid power system
US20020153141A1 (en) 2001-04-19 2002-10-24 Hartman Michael G. Method for pumping fluids
AU2002257221B2 (en) 2001-04-24 2008-12-18 Shell Internationale Research Maatschappij B.V. In situ recovery from a oil shale formation
CA2668387C (en) 2001-04-24 2012-05-22 Shell Canada Limited In situ recovery from a tar sands formation
US6948562B2 (en) 2001-04-24 2005-09-27 Shell Oil Company Production of a blending agent using an in situ thermal process in a relatively permeable formation
US7040400B2 (en) 2001-04-24 2006-05-09 Shell Oil Company In situ thermal processing of a relatively impermeable formation using an open wellbore
US20030029617A1 (en) * 2001-08-09 2003-02-13 Anadarko Petroleum Company Apparatus, method and system for single well solution-mining
US6591908B2 (en) 2001-08-22 2003-07-15 Alberta Science And Research Authority Hydrocarbon production process with decreasing steam and/or water/solvent ratio
MY129091A (en) 2001-09-07 2007-03-30 Exxonmobil Upstream Res Co Acid gas disposal method
US6755251B2 (en) 2001-09-07 2004-06-29 Exxonmobil Upstream Research Company Downhole gas separation method and system
NZ532089A (en) 2001-10-24 2005-09-30 Shell Int Research Installation and use of removable heaters in a hydrocarbon containing formation
US7077199B2 (en) 2001-10-24 2006-07-18 Shell Oil Company In situ thermal processing of an oil reservoir formation
US6969123B2 (en) 2001-10-24 2005-11-29 Shell Oil Company Upgrading and mining of coal
US7104319B2 (en) 2001-10-24 2006-09-12 Shell Oil Company In situ thermal processing of a heavy oil diatomite formation
US7165615B2 (en) * 2001-10-24 2007-01-23 Shell Oil Company In situ recovery from a hydrocarbon containing formation using conductor-in-conduit heat sources with an electrically conductive material in the overburden
BR0213513B8 (en) 2001-10-24 2013-02-19 Method for soil contamination remediation, and soil remediation system.
US7090013B2 (en) 2001-10-24 2006-08-15 Shell Oil Company In situ thermal processing of a hydrocarbon containing formation to produce heated fluids
US6759364B2 (en) 2001-12-17 2004-07-06 Shell Oil Company Arsenic removal catalyst and method for making same
US6684948B1 (en) * 2002-01-15 2004-02-03 Marshall T. Savage Apparatus and method for heating subterranean formations using fuel cells
US6679326B2 (en) 2002-01-15 2004-01-20 Bohdan Zakiewicz Pro-ecological mining system
US7032809B1 (en) 2002-01-18 2006-04-25 Steel Ventures, L.L.C. Seam-welded metal pipe and method of making the same without seam anneal
CA2473372C (en) 2002-01-22 2012-11-20 Presssol Ltd. Two string drilling system using coil tubing
US6958195B2 (en) 2002-02-19 2005-10-25 Utc Fuel Cells, Llc Steam generator for a PEM fuel cell power plant
US6818333B2 (en) 2002-06-03 2004-11-16 Institut Francais Du Petrole Thin zeolite membrane, its preparation and its use in separation
AU2003260210A1 (en) 2002-08-21 2004-03-11 Presssol Ltd. Reverse circulation directional and horizontal drilling using concentric coil tubing
US8224163B2 (en) 2002-10-24 2012-07-17 Shell Oil Company Variable frequency temperature limited heaters
US7055602B2 (en) 2003-03-11 2006-06-06 Shell Oil Company Method and composition for enhanced hydrocarbons recovery
US7258752B2 (en) 2003-03-26 2007-08-21 Ut-Battelle Llc Wrought stainless steel compositions having engineered microstructures for improved heat resistance
NZ567052A (en) 2003-04-24 2009-11-27 Shell Int Research Thermal process for subsurface formations
US6951250B2 (en) 2003-05-13 2005-10-04 Halliburton Energy Services, Inc. Sealant compositions and methods of using the same to isolate a subterranean zone from a disposal well
US7114880B2 (en) 2003-09-26 2006-10-03 Carter Jr Ernest E Process for the excavation of buried waste
US7147057B2 (en) 2003-10-06 2006-12-12 Halliburton Energy Services, Inc. Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore
US7416653B2 (en) 2003-12-19 2008-08-26 Shell Oil Company Systems and methods of producing a crude product
US20050167331A1 (en) 2003-12-19 2005-08-04 Bhan Opinder K. Systems, methods, and catalysts for producing a crude product
US20070000810A1 (en) 2003-12-19 2007-01-04 Bhan Opinder K Method for producing a crude product with reduced tan
US20060289340A1 (en) 2003-12-19 2006-12-28 Brownscombe Thomas F Methods for producing a total product in the presence of sulfur
US7320364B2 (en) 2004-04-23 2008-01-22 Shell Oil Company Inhibiting reflux in a heated well of an in situ conversion system
RU2399648C2 (en) 2004-08-10 2010-09-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Method for obtaining middle-distillate product and low molecular weight olefins from hydrocarbon raw material and device for its implementation
US7582203B2 (en) 2004-08-10 2009-09-01 Shell Oil Company Hydrocarbon cracking process for converting gas oil preferentially to middle distillate and lower olefins
EP1874897A1 (en) 2005-04-11 2008-01-09 Shell Internationale Research Maatschappij B.V. Method and catalyst for producing a crude product having a reduced mcr content
US7426959B2 (en) 2005-04-21 2008-09-23 Shell Oil Company Systems and methods for producing oil and/or gas
US8224165B2 (en) 2005-04-22 2012-07-17 Shell Oil Company Temperature limited heater utilizing non-ferromagnetic conductor
AU2006239999B2 (en) 2005-04-22 2010-06-17 Shell Internationale Research Maatschappij B.V. In situ conversion process systems utilizing wellbores in at least two regions of a formation
WO2007002111A1 (en) 2005-06-20 2007-01-04 Ksn Energies, Llc Method and apparatus for in-situ radiofrequency assisted gravity drainage of oil (ragd)
US20060175061A1 (en) 2005-08-30 2006-08-10 Crichlow Henry B Method for Recovering Hydrocarbons from Subterranean Formations
EP1941003B1 (en) 2005-10-24 2011-02-23 Shell Internationale Research Maatschappij B.V. Methods of filtering a liquid stream produced from an in situ heat treatment process
RU2418158C2 (en) 2006-02-16 2011-05-10 ШЕВРОН Ю. Эс. Эй. ИНК. Extraction method of kerogenes from underground shale formation and explosion method of underground shale formation
US7533719B2 (en) 2006-04-21 2009-05-19 Shell Oil Company Wellhead with non-ferromagnetic materials
GB2455947B (en) 2006-10-20 2011-05-11 Shell Int Research Heating hydrocarbon containing formations in a checkerboard pattern staged process
GB2460980B (en) 2007-04-20 2011-11-02 Shell Int Research Controlling and assessing pressure conditions during treatment of tar sands formations
BRPI0810752A2 (en) 2007-05-15 2014-10-21 Exxonmobil Upstream Res Co METHODS FOR IN SITU HEATING OF A RICH ROCK FORMATION IN ORGANIC COMPOUND, IN SITU HEATING OF A TARGETED XISTO TRAINING AND TO PRODUCE A FLUID OF HYDROCARBON, SQUARE FOR A RACHOSETUS ORGANIC BUILDING , AND FIELD TO PRODUCE A HYDROCARBON FLUID FROM A TRAINING RICH IN A TARGET ORGANIC COMPOUND.
US8146661B2 (en) 2007-10-19 2012-04-03 Shell Oil Company Cryogenic treatment of gas
WO2009129143A1 (en) 2008-04-18 2009-10-22 Shell Oil Company Systems, methods, and processes utilized for treating hydrocarbon containing subsurface formations
US8277642B2 (en) 2008-06-02 2012-10-02 Korea Technology Industries, Co., Ltd. System for separating bitumen from oil sands
WO2010045115A2 (en) 2008-10-13 2010-04-22 Shell Oil Company Treating subsurface hydrocarbon containing formations and the systems, methods, and processes utilized
CA2758192A1 (en) 2009-04-10 2010-10-14 Shell Internationale Research Maatschappij B.V. Treatment methodologies for subsurface hydrocarbon containing formations
US9127538B2 (en) 2010-04-09 2015-09-08 Shell Oil Company Methodologies for treatment of hydrocarbon formations using staged pyrolyzation
US9033042B2 (en) 2010-04-09 2015-05-19 Shell Oil Company Forming bitumen barriers in subsurface hydrocarbon formations

Also Published As

Publication number Publication date
US20030131993A1 (en) 2003-07-17
US7735935B2 (en) 2010-06-15
US7032660B2 (en) 2006-04-25
WO2002086018A3 (en) 2004-01-15
US7004251B2 (en) 2006-02-28
US6951247B2 (en) 2005-10-04
US20030111223A1 (en) 2003-06-19
US20030131996A1 (en) 2003-07-17
US6997518B2 (en) 2006-02-14
US6915850B2 (en) 2005-07-12
US20030173078A1 (en) 2003-09-18
US20030148894A1 (en) 2003-08-07
US6991032B2 (en) 2006-01-31
US20040211557A1 (en) 2004-10-28
US7040399B2 (en) 2006-05-09
US6880633B2 (en) 2005-04-19
US7004247B2 (en) 2006-02-28
US20030141067A1 (en) 2003-07-31
US20030131994A1 (en) 2003-07-17
US20040211554A1 (en) 2004-10-28
US20030146002A1 (en) 2003-08-07
US7051811B2 (en) 2006-05-30
US7013972B2 (en) 2006-03-21
US6994169B2 (en) 2006-02-07
WO2002086018A2 (en) 2002-10-31
US20100270015A1 (en) 2010-10-28
US6991033B2 (en) 2006-01-31
US8608249B2 (en) 2013-12-17
US6877555B2 (en) 2005-04-12
US6929067B2 (en) 2005-08-16
US20030141066A1 (en) 2003-07-31
US20030136559A1 (en) 2003-07-24
US6918442B2 (en) 2005-07-19
US7040397B2 (en) 2006-05-09
US7225866B2 (en) 2007-06-05
US6923257B2 (en) 2005-08-02
US20030080604A1 (en) 2003-05-01
US20030142964A1 (en) 2003-07-31
AU2009200992A1 (en) 2009-04-02
CA2445415C (en) 2011-08-30
US20060213657A1 (en) 2006-09-28
US6918443B2 (en) 2005-07-19
US20140305640A1 (en) 2014-10-16
US20030137181A1 (en) 2003-07-24
US20030141068A1 (en) 2003-07-31
AU2002257221B2 (en) 2008-12-18
US20030209348A1 (en) 2003-11-13
US20030136558A1 (en) 2003-07-24
US20080314593A1 (en) 2008-12-25
US20030173080A1 (en) 2003-09-18
US20030164239A1 (en) 2003-09-04

Similar Documents

Publication Publication Date Title
CA2445415A1 (en) In situ recovery from a oil shale formation
CA2407022A1 (en) In situ recovery from a hydrocarbon containing formation
AU2009303604B2 (en) Circulated heated transfer fluid heating of subsurface hydrocarbon formations
CA2462794C (en) Method and system for in situ heating a hydrocarbon containing formation by a u-shaped opening
CA2665864C (en) Heating hydrocarbon containing formations in a checkerboard pattern staged process
US9022109B2 (en) Leak detection in circulated fluid systems for heating subsurface formations
AU2003285008B2 (en) Inhibiting wellbore deformation during in situ thermal processing of a hydrocarbon containing formation
EA011905B1 (en) In situ conversion process utilizing a closed loop heating system
WO2008131175A1 (en) Molten salt as a heat transfer fluid for heating a subsurface formation
AU2002359315A1 (en) In situ thermal processing of a hydrocarbon containing formation via backproducing through a heater well
CN1717531B (en) Method for processing hydrocarbon-containing stratum
AU2011237624B2 (en) Leak detection in circulated fluid systems for heating subsurface formations
WO2018067713A1 (en) Subsurface electrical connections for high voltage, low current mineral insulated cable heaters

Legal Events

Date Code Title Description
EEER Examination request