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Publication numberCA2667274 A1
Publication typeApplication
Application numberCA 2667274
PCT numberPCT/US2007/022376
Publication date2 May 2008
Filing date19 Oct 2007
Priority date20 Oct 2006
Also published asCA2665862A1, CA2665862C, CA2665864A1, CA2665864C, CA2665865A1, CA2665865C, CA2665869A1, CA2665869C, CA2666206A1, CA2666947A1, CA2666947C, CA2666956A1, CA2666956C, CA2666959A1, CA2666959C, EP2074279A2, EP2074281A2, EP2074281A4, EP2074282A2, EP2074283A2, EP2074284A2, EP2074284A4, US7540324, US7562707, US7631690, US7635024, US7644765, US7673681, US7677310, US7677314, US7681647, US7703513, US7717171, US7730945, US7730946, US7730947, US7841401, US7845411, US8191630, US8555971, US20080128134, US20080135244, US20080135253, US20080135254, US20080142216, US20080142217, US20080185147, US20080217003, US20080217004, US20080217015, US20080217016, US20080236831, US20080277113, US20080283246, US20090014180, US20090014181, US20100276141, US20130056210, WO2008051495A2, WO2008051495A3, WO2008051495A8, WO2008051822A2, WO2008051822A3, WO2008051825A1, WO2008051827A2, WO2008051827A3, WO2008051830A2, WO2008051830A3, WO2008051831A2, WO2008051831A3, WO2008051833A2, WO2008051833A3, WO2008051834A2, WO2008051834A3, WO2008051836A2, WO2008051836A3, WO2008051837A2, WO2008051837A3
Publication numberCA 2667274, CA 2667274 A1, CA 2667274A1, CA-A1-2667274, CA2667274 A1, CA2667274A1, PCT/2007/22376, PCT/US/2007/022376, PCT/US/2007/22376, PCT/US/7/022376, PCT/US/7/22376, PCT/US2007/022376, PCT/US2007/22376, PCT/US2007022376, PCT/US200722376, PCT/US7/022376, PCT/US7/22376, PCT/US7022376, PCT/US722376
InventorsHarold J. Vinegar, Ronald M. Bass, Wim Bond, Michael Patrick Brady, Joseph P. Brignac, Jr., David Burns, Frederick Gordon Carl, Jr., Ralph Anthony Cherrillo, Del Scott Christensen, William George Coit, Michael Costello, Thomas D. Fowler, Bernard Goldberg, Charles R. Goodwin, Arthur Herman Hale, Christopher Kelvin Harris, Richard A. Hinson, Joseph Arno Horton, Jr., Randy Carl John, John Michael Karanikas, Dong-Sub Kim, Gene Richard Lambirth, Stanley Leroy Mason, Philip James Maziasz, James Louis Menotti, Vijay Nair, James Richard, Jr., Augustinus Wilhelmus Maria Roes, Michael Leonard Santella, Joachim Hugo Schneibel, John Paul Shingledecker, Vinod Kumar Sikka, Frances Marion Stone, Jr., John Michael Vitek, Kenneth Michael Cowan, Charles D'angelo, Ian Alexander Davidson, Wolfgang Deeg, Paggio Alan Anthony Del, Boestert Johannes Leendert Willem Cornelis Den, Rouffignac Eric Pierre De, Zaida Diaz, Michael David Fairbanks, Walter Farmayan, Steven Paul Giles, Jean-Charles Ginestra, Peter Terry Griffin, Paul Taylor Hamilton, Naval Goel, Peringandoor Raman Hariharan, Gorem Heron, Stephen Palmer Hirshblond, Chia-Fu Hsu, Thomas J. Keltner, Myron Ira Kuhlman, Robert Lenke, Ruijian Li, Remco Hugo Mandema, Albert J. Mansure, Billy John Ii Mckinzie, Johannes Kornelis Minderhoud, Weijian Mo, Abdul Wahid Munshi, Michel Serge Marie Muylle, Richard Gene Nelson, Scott Vinh Nguyen, Monica M. Pingo-Almada, Robert Charles Ryan, Allan James Samuel, Chester Ledlie Sandberg, Willem Jan Antoon Henri Schoeber, Lanny Gene Schoeling, Mark Alan Siddoway, George Leo Stegemeier, Ronnie Wade Watkins, Sau-Wai Wong, Xueying Xie, Etuan Zhang, Gary Lee Beer, Duncan Macdonald, David Scott Miller, Ernest E. Carter, Jr., Jaime Santos Son, Taixu Bai, Mahamad Khodaverdian, Tulio Rafael Colmenares, Marian Marino, Ralph Sterman Baker, Faraz Abbasi, Robert James Dombrowski, Ramesh Raju Mudunuri, Namit Jaiswal, Deniz Sumnu Dinoruk
ApplicantShell Internationale Research Maatschappij B.V., Harold J. Vinegar, Ronald M. Bass, Wim Bond, Michael Patrick Brady, Joseph P. Brignac, Jr., David Burns, Frederick Gordon Carl, Jr., Ralph Anthony Cherrillo, Del Scott Christensen, William George Coit, Michael Costello, Thomas D. Fowler, Bernard Goldberg, Charles R. Goodwin, Arthur Herman Hale, Christopher Kelvin Harris, Richard A. Hinson, Joseph Arno Horton, Jr., Randy Carl John, John Michael Karanikas, Dong-Sub Kim, Gene Richard Lambirth, Stanley Leroy Mason, Philip James Maziasz, James Louis Menotti, David Scott Miller, Vijay Nair, James Richard, Jr., Augustinus Wilhelmus Maria Roes, Michael Leonard Santella, Joachim Hugo Schneibel, John Paul Shingledecker, Vinod Kumar Sikka, Frances Marion Stone, Jr., John Michael Vitek, Kenneth Michael Cowan, Charles D'angelo, Ian Alexander Davidson, Wolfgang Deeg, Paggio Alan Anthony Del, Boestert Johannes Leendert Willem Cornelis Den, Rouffignac Eric Pierre De, Zaida Diaz, Michael David Fairbanks, Walter Farmayan, Steven Paul Giles, Jean-Charles Ginestra, Peter Terry Griffin, Paul Taylor Hamilton, Naval Goel, Peringandoor Raman Hariharan, Gorem Heron, Stephen Palmer Hirshblond, Chia-Fu Hsu, Thomas J. Keltner, Myron Ira Kuhlman, Robert Lenke, Ruijian Li, Remco Hugo Mandema, Albert J. Mansure, Billy John Ii Mckinzie, Johannes Kornelis Minderhoud, Weijian Mo, Abdul Wahid Munshi, Michel Serge Marie Muylle, Richard Gene Nelson, Scott Vinh Nguyen, Monica M. Pingo-Almada, Robert Charles Ryan, Allan James Samuel, Chester Ledlie Sandberg, Willem Jan Antoon Henri Schoeber, Lanny Gene Schoeling, Mark Alan Siddoway, George Leo Stegemeier, Ronnie Wade Watkins, Sau-Wai Wong, Xueying Xie, Etuan Zhang, Gary Lee Beer, Duncan Macdonald, Ernest E. Carter, Jr., Jaime Santos Son, Taixu Bai, Mahamad Khodaverdian, Tulio Rafael Colmenares, Marian Marino, Ralph Sterman Baker, Faraz Abbasi, Robert James Dombrowski, Ramesh Raju Mudunuri, Namit Jaiswal, Deniz Sumnu Dinoruk
Export CitationBiBTeX, EndNote, RefMan
External Links: CIPO, Espacenet
Systems and processes for use in treating subsurface formations
CA 2667274 A1
Abstract
Methods for treating a tar sands formation are described herein. Methods for treating a tar sands may include heating a portion of a hydrocarbon layer in the formation from one or more heaters located in the portion. The heat may be controlled to increase the permeability of at least part of the portion to create an injection zone in the portion with an average permeability sufficient to allow injection of a fluid through the injection zone. A drive fluid and/or an oxidizing fluid may be provided into the injection zone. At least some hydrocarbons are produced from the portion.
Claims(1685)
1. A method for treating a tar sands formation, comprising:
heating a portion of a hydrocarbon layer in the formation from one or more heaters located in the portion;
controlling the heating to increase the permeability of at least part of the portion to create an injection zone in the portion with an average permeability sufficient to allow injection of a fluid through the injection zone;
providing a drive fluid and/or an oxidizing fluid into the injection zone; and producing at least some hydrocarbons from the portion.
2. The method of claim 1, wherein the drive fluid and/or the oxidizing fluid moves from the injection zone to mobilize at least some hydrocarbons in the portion.
3. The method of any of claims 1 or 2, further comprising providing at least some heat to the portion using the drive fluid and/or the oxidizing fluid.
4. The method of any of claims 1-3, further comprising providing at least some heat outside the injection zone with the drive fluid and/or the oxidizing fluid.
5. The method of any of claims 1-4, further comprising increasing the permeability of at least part of the portion outside the injection zone with the drive fluid and/or the oxidizing fluid.
6. The method of any of claims 1-5, wherein at least some of the heaters are turned down and/or off after increasing the permeability in the injection zone.
7. The method of any of claims 1-6, wherein the drive fluid and/or the oxidizing fluid comprises steam, water, carbon dioxide, carbon monoxide, methane, pyrolyzed hydrocarbons, and/or air.
8. The method of any of claims 1-7, wherein the injection zone has little or no initial injectivity.
9. The method of any of claims 1-8, wherein increasing the permeability of the injection zone creates a fluid production network between at least one of the heaters and a production well in the injection zone.
10. The method of any of claims 1-9, further comprising providing the drive fluid and/or the oxidizing fluid to a part of the injection zone behind a heat front generated by the heaters.
11. The method of claim 10, further comprising producing hydrocarbons from the part behind the heat front.
12. The method of any of claims 1-11, further comprising controlling the temperature and the pressure in the portion such that (a) at least a majority of the hydrocarbons in the portion are mobilized, (b) the pressure is below the fracture pressure of the portion, and (c) at least some hydrocarbons in the portion form a fluid comprising mobilized hydrocarbons that can be produced through a production well.
13. The method of any of claims 1-12, further comprising controlling the heating so that the injection zone has a substantially uniform porosity and/or a substantially uniform injectivity.
14. The method of any of claims 1-13, wherein the drive fluid and/or the oxidizing fluid is provided from a well having a well length adapted to emit the drive fluid and/or the oxidizing fluid from the well to the injection zone, wherein the provided heat increases injectivity from the well from at most about 10 kg/m/day of steam to at least about 100 kg/m/day of steam, and wherein injectivity is the mass of steam that can be injected per unit well length that is adapted to emit the drive fluid from the well, per day.
15. The method of any of claims 1-14, wherein the provided heat decreases a viscosity of liquid hydrocarbons in the injection zone to less than about 500 cp (wherein the viscosity is measured at 1 atm and 5C) for a distance of about 2 m from at least one of the heaters.
16. The method of any of claims 1-15, wherein the provided heat decreases a viscosity of liquid hydrocarbons in the injection zone with an initial viscosity of above about 10000 cp (wherein the viscosity is measured at 1 atm and 5C).
17. The method of any of claims 1-16, wherein the injection zone is above a portion of the formation from which the hydrocarbons are produced.
18. The method of any of claims 1-17, further comprising:
allowing at least some of the hydrocarbons to flow into a second portion of the formation;
providing heat to the second portion of the formation from one or more heaters located in the formation; and producing at least some hydrocarbons from the second portion of the formation.
19. A method for treating a hydrocarbon containing formation, comprising:
providing heat from one or more heaters located in a first section of the formation;
allowing some of the heat to transfer from the first section to a second section of the formation, the second section being adjacent to the first section;
producing at least some fluids from the second section of the formation, wherein at least some of the fluids produced in the second section comprise fluids initially in the first section;
and providing heat from one or more heaters located in the second section of the formation after at least some fluids have been produced from the second section.
20. The method of claim 19, wherein at least some of the produced fluids comprise hydrocarbons.
21. The method of claim 19, wherein at least some of the produced fluids comprise hydrocarbons initially in the first section.
22. The method of claim 19, further comprising allowing at least some fluids to flow from the first section to the second section.
23. The method of claim 19, further comprising allowing at least some fluids to flow from the first section to the second section to transfer heat from the first section to the second section.
24. The method of claim 19, wherein the provided heat increases the permeability of the first section and/or the second section.
25. The method of claim 19, wherein the provided heat mobilizes at least some hydrocarbons in the first section and/or the second section.
26. The method of claim 19, wherein the provided heat pyrolyzes at least some hydrocarbons in the first section and/or the second section.
27. The method of claim 19, further comprising dewatering the first section and/or the second section prior to providing heat to the formation.
28. The method of claim 19, wherein the first section and the second section are substantially equal sized sections.
29. The method of claim 19, further comprising injecting a fluid into the first section.
30. The method of claim 19, further comprising:
allowing some of the heat to transfer from the second section to a third section of the formation the third section being adjacent to the second section and separated from the first section by the second section;
producing at least some fluids from the third section of the formation, wherein at least some of the fluids produced in the third section comprise fluids initially in the first section and/or the second section.
31. The method of claim 30, further comprising providing heat from one or more heaters located in the second section of the formation after at least some fluids have been produced from the second section.
32. The method of claim 30, further comprising shutting down production in the second section after production in the third section is started.
33. A method for treating a hydrocarbon containing formation, comprising:
providing heat from one or more heaters located in two or more first sections of the formation;

allowing some of the heat to transfer from the first sections to two or more second sections of the formation;
wherein the first sections and the second sections are arranged in a checkerboard pattern, the checkerboard pattern having each first section substantially surrounded by one or more of the second sections and each second section substantially surrounded by one or more of the first sections;
producing at least some fluids from the second sections of the formation, wherein at least some of the fluids produced in the second sections comprise fluids initially in the first sections;
and providing heat from one or more heaters located in the second sections of the formation after at least some fluids have been produced from the second sections.
34. The method of claim 33, wherein at least some of the produced fluids comprise hydrocarbons.
35. The method of claim 33, wherein at least some of the produced fluids comprise hydrocarbons initially in the first sections.
36. The method of claim 33, further comprising allowing at least some fluids to flow from the first sections to the second sections.
37. The method of claim 33, further comprising allowing at least some fluids to flow from the first sections to the second sections to transfer heat from the first sections to the second sections.
38. The method of claim 33, wherein the provided heat increases the permeability of at least one of the first sections and/or at least one of the second sections.
39. The method of claim 33, wherein the provided heat mobilizes at least some hydrocarbons in the first sections and/or the second sections.
40. The method of claim 33, wherein the provided heat pyrolyzes at least some hydrocarbons in the first sections and/or the second sections.
41. The method of claim 33, further comprising dewatering at least one of the first sections and/or at least one of the second sections prior to providing heat to the formation.
42. The method of claim 33, wherein the first sections and the second sections are substantially equal sized sections.
43. The method of claim 33, further comprising injecting a fluid into at least one of the first sections.
44. A method for treating a hydrocarbon containing formation, comprising:
treating a first zone of the formation at or near a center of a treatment area;

beginning treatment of a plurality of zones of the formation at selected times after the treatment of the first zone begins, the treatment of each successively treated zone beginning at a selected time after treatment of the previous zone begins;
wherein each successively treated zone is adjacent to the zone treated previously;
wherein the successive treatment of the zones proceeds in an outward spiral sequence from the first zone so that the treatment of the zones moves outwards towards the boundary of the treatment area;
wherein treatment of each of the zones comprises:
providing heat from one or more heaters located in two or more first sections of the zone;
allowing some of the heat to transfer from the first sections to two or more second sections of the zone;
wherein the first sections and the second sections are arranged in a checkerboard pattern within the zone, the checkerboard pattern having each first section substantially surrounded by one or more of the second sections and each second section substantially surrounded by one or more of the first sections;
producing at least some fluids from the second sections, wherein at least some of the fluids produced in the second sections comprise fluids initially in the first sections;
and providing heat from one or more heaters located in the second sections after at least some fluids have been produced from the second sections.
45. The method of claim 44, further comprising providing a barrier around at least a portion of the treatment area.
46. The method of claim 44, further comprising allowing outer zones of the formation to expand inwards into pore spaces in previously treated zones to minimize shearing in the formation.
47. The method of claim 44,wherein the outward spiral sequence minimizes and/or inhibits expansion stresses in the formation.
48. The method of claim 44, further comprising providing one or more support portions in the formation between one or more of the zones.
49. The method of claim 48, wherein the support portions provide support against geomechanical shifting, shearing, and/or expansion stress in the formation.
50. The method of claim 44, wherein at least some of the produced fluids comprise hydrocarbons.
51. The method of claim 44, wherein at least some of the produced fluids comprise hydrocarbons initially in the first sections.
52. The method of claim 44, further comprising allowing at least some fluids to flow from the first sections to the second sections.
53. The method of claim 44, further comprising allowing at least some fluids to flow from the first sections to the second sections to transfer heat from the first sections to the second sections.
54. The method of claim 44, wherein the provided heat increases the permeability of at least one of the first sections and/or at least one of the second sections.
55. The method of claim 44, wherein the provided heat mobilizes at least some hydrocarbons in the first sections and/or the second sections.
56. The method of claim 44, wherein the provided heat pyrolyzes at least some hydrocarbons in the first sections and/or the second sections.
57. The method of claim 44, further comprising dewatering at least one of the first sections and/or at least one of the second sections prior to providing heat to the formation.
58. The method of claim 44, wherein the first sections and the second sections are substantially equal sized sections.
59. The method of claim 44, further comprising injecting a fluid into at least one of the first sections.
60. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters so that at least a portion of the formation reaches a visbreaking temperature;
maintaining a pressure in the formation below a fracture pressure of the formation; and producing at least some visbroken fluids from the formation.
61. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters so that at least a portion of the formation reaches a visbreaking temperature;
maintaining a pressure in the formation below a fracture pressure of the formation while allowing the portion of the formation to heat to the visbreaking temperature;
reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the visbreaking temperature; and producing fluids from the formation.
62. The method of claim 61, wherein the visbreaking temperature is between about 200 C and about 240 C.
63. The method of claim 61, further comprising operating the heaters at full power until the portion of the formation reaches the visbreaking temperature.
64. The method of claim 61, further comprising maintaining the pressure in the formation below the fracture pressure of the formation by removing at least some fluids from the formation.
65. The method of claim 61, wherein the fracture pressure of the formation is between about 2000 kPa and about 10000 kPa.
66. The method of claim 61, wherein the selected pressure is at most about 1000 kPa.
67. The method of claim 61, wherein the selected pressure is a pressure at which coke formation is inhibited in the formation.
68. The method of claim 61, further comprising increasing the temperature of the portion of the formation to pyrolysis temperatures after reducing the pressure to the selected pressure.
69. The method of claim 61, further comprising producing at least some mobilized hydrocarbons from the formation.
70. The method of claim 61, further comprising producing at least some visbroken hydrocarbons from the formation.
71. The method of claim 61, further comprising producing at least some pyrolyzed hydrocarbons from the formation.
72. The method of claim 61, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and pyrolyzed hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation.
73. The method of claim 61, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and pyrolyzed hydrocarbons produced from the formation to vary the total recovery of hydrocarbons from the formation.
74. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
controlling conditions in the formation so that water is recondensed in the formation in situ; and producing fluids from the formation.
75. A method for treating a tar sands formation, comprising:

providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation;
creating an injection zone in the formation with the provided heat, the injection zone having a permeability sufficient enough to allow injection of a drive fluid into the zone;
providing the drive fluid into the injection zone; and producing fluids from the formation.
76. The method of claim 75, wherein the heaters are turned off after creating the injection zone.
77. The method of claim 75, wherein the drive fluid mobilizes at least some hydrocarbons in the formation.
78. The method of claim 75, further comprising providing at least some heat to the formation using the drive fluid.
79. The method of claim 75, wherein the drive fluid comprises pressurized steam.
80. The method of claim 75, wherein the formation has little or no initial injectivity.
81. The method of claim 75, wherein the injection zone comprises a fluid production network between at least one of the heaters and a production well.
82. The method of claim 75, wherein the formation comprises a karsted formation.
83. A method for treating a tar sands formation, comprising:
providing heat to a portion of a hydrocarbon layer in the formation from one or more heaters located in the formation;
providing a drive fluid to a part of the portion of the formation behind a heat front generated by the heaters; and producing fluids from the part of the formation behind the heat front.
84. A method for treating a tar sands formation, comprising:
providing a drive fluid to a first portion of the formation to mobilize at least some hydrocarbons in the first portion;
allowing at least some of the mobilized hydrocarbons to flow into a second portion of the formation;
providing heat to the second portion the formation from one or more heaters located in the formation; and producing at least some hydrocarbons from the second portion of the formation.
85. A method for treating a tar sands formation, comprising:
providing heat from one or more heaters to one or more karsted zones of the tar sands formation;
mobilizing hydrocarbon fluids in the formation; and producing hydrocarbon fluids from the formation.
86. The method of claim 85, wherein one or more karsted zones are selectively heated.
87. The method of claim 85, further comprising flowing the mobilized hydrocarbon fluids in an interconnected pore network of the formation.
88. The method of claim 85, further comprising flowing the mobilized hydrocarbons fluids in an interconnected pore network of the formation, wherein the interconnected pore network comprises a plurality of vugs.
89. The method of claim 85, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
90. The method of claim 85, further comprising pyrolyzing at least some hydrocarbons in the formation.
91. The method of claim 85, wherein the formation includes vugs having a porosity of at least 20 porosity units in a formation with a porosity of at most about 15 porosity units, and wherein the vugs include unmobilized hydrocarbons prior to heating.
92. The method of claim 85, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
93. The method of claim 85, wherein the formation is a karsted carbonate formation containing viscous hydrocarbons.
94. The method of claim 85, further comprising injecting steam into the formation.
95. The method of claim 85, further comprising heating the formation with the one or more heaters to increase steam injectivity, and then injecting steam in the formation.
96. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing the provided heat to reduce the viscosity of at least some hydrocarbons in the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
97. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing the provided heat to reduce the viscosity of at least some hydrocarbons in the karsted layers to get an injectivity in at least one of the karsted layers sufficient to allow a drive fluid to flow in the karsted layers;

providing the drive fluid into at least one of the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
98. A method for treating a formation containing dolomite and hydrocarbons, comprising:
providing heat at less than the decomposition temperature of dolomite from one or more heaters to at least a portion of the formation;
mobilizing hydrocarbon fluids in the formation; and producing hydrocarbon fluids from the formation.
99. The method of claim 98, further comprising providing heat at or higher than the decomposition temperature of dolomite to produce carbon dioxide.
100. The method of claim 98, further comprising providing heat at or higher than the decomposition temperature of dolomite to produce carbon dioxide, the heating being conducted such that carbon dioxide provides a gas cap on the formation.
101. The method of claim 98, further comprising providing heat at or higher than the decomposition temperature of dolomite to produce carbon dioxide, the heating being provided such that the carbon dioxide mixes with hydrocarbons in the formation and reduces the viscosity of such hydrocarbons.
102. The method of claim 98, wherein the heat is less than about 407 C.
103. The method of claim 98, further comprising flowing the mobilized hydrocarbon fluids in an interconnected pore network of the formation.
104. The method of claim 98, further comprising flowing the mobilized hydrocarbons fluids in an interconnected pore network of the formation, wherein the interconnected pore network comprises a plurality of vugs.
105. The method of claim 98, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
106. The method of claim 98, further comprising pyrolyzing at least some hydrocarbons in the formation.
107. The method of claim 98, wherein the formation includes vugs having a porosity of at least 20 porosity units in a formation with a porosity of at most about 15 porosity units, and wherein the vugs include unmobilized hydrocarbons prior to heating.
108. The method of claim 98, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
109. The method of claim 98, further comprising injecting steam into the formation.
110. The method of claim 98, further comprising heating the formation with the one or more heaters to increase steam injectivity, and then injecting steam in the formation.
111. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing a temperature in at least one of the karsted layers to reach a decomposition temperature of dolomite in the formation;
allowing the dolomite to decompose; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
112. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the pressure to increase in an upper portion of the formation to provide a gas cap in the upper portion; and producing at least some hydrocarbons from a lower portion of the formation.
113. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing a temperature in at least one of the karsted layers to reach a decomposition temperature of dolomite in the formation;
allowing the dolomite to decompose and produce carbon dioxide;
maintaining the carbon dioxide in the formation to provide a gas cap in an upper portion of at least one of the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
114. A method for treating a tar sands formation, the method comprising the steps of:
providing heat to a portion of a hydrocarbon layer in the formation from one or more heaters located in the formation;
providing a drive fluid to a part of the formation; and producing fluids from the formation.
115. The method of claim 114, wherein the drive fluid is provided from a well having a well length adapted to emit the drive fluid from the well to the formation, and the provided heat increases injectivity of drive fluid from the well from at most about 10 kg/m/day of steam to at least about 100 kg/m/day of steam, and where injectivity is the mass of steam that can be injected per unit well length that is adapted to emit the drive fluid from the well to the formation, per day.
116. The method of claim 114, wherein the provided heat decreases a viscosity of fluids in the formation to less than about 500 cp for a distance of about 2 m from at least one of the heaters.
117. The method of claim 114, wherein the provided heat decreases a viscosity of fluids in the formation with an initial viscosity of above about 10000 cp.
118. The method of claim 114, wherein the drive fluid is steam.
119. The method of claim 114, wherein the drive fluid is provided to a part of the formation to which heat has been provided.
120. The method of claim 114, wherein the fluid is produced from a portion of the formation to which heat has been provided.
121. The method of claim 120, wherein the portion of the formation to which drive fluid is provided is above the portion of the formation from which fluids are produced.
122. The method of claim 114, wherein the drive fluid is provided to a part of the formation to which heat has been provided and the fluid is produced from a portion of the formation to which heat has been provided, and there is at least one path from the portion of the formation to which the drive fluid is provided to the portion of the formation from which fluids are produced, and wherein the viscosity of fluids in the path has been reduced to below about 500 cp by the provided heat.
123. The method of claim 122, wherein the viscosity of the fluids in the formation in the path from the portion of the formation to which drive fluid is provided and the portion of the formation from which fluids are produced is reduced from an initial viscosity of above about 10000 cp by the provided heat.
124. The method of claim 123, wherein fluids in the at least one path from the portion of the formation to which the drive fluid is provided to the portion of the formation from which fluids are produced have a viscosity which has been reduced to below about 100 cp by the provided heat.
125. The method of claim 124, wherein the drive fluid is steam.
126. The method of claim 125, wherein the portion of the formation to which drive fluid is provided is above the portion of the formation from which fluids are produced.
127. A composition comprising:
from about percent 18 to about 22 percent by weight chromium;
from about percent 12 to about 13 percent by weight nickel;

between about 3 percent by weight and about 10 percent by weight copper;
from about 1 percent to about 10 percent by weight manganese;
from about 0.3 percent to about 1 percent by weight silicon;
from about 0.5 percent to about 1.5 percent by weight niobium; and from about 38 percent to about 63.5 percent by weight iron.
128. The composition of claim 127, further comprising from about 0.2 percent to 0.5 percent by weight nitrogen.
129. The composition of claim 127, further comprising from about 0.3 percent to 1 percent by weight molybdenum.
130. The composition of claim 127, further comprising from about 0.08 percent to 0.2 percent by weight carbon.
131. The composition of claim 127, further comprising from about 0.01 percent to 2 percent by weight tungsten.
132. The composition of claim 127, wherein the composition comprises nanonitride precipitates.
133. The composition of claim 132, wherein the nanonitride precipitates comprise particles having maximum dimensions in the range of about five to one hundred nanometers.
134. The composition of claim 132, wherein the composition further comprise nanocarbide precipitates.
135. The composition of claim 134, wherein the nanocarbide precipitates comprise particles having maximum dimensions in the range of about five to two hundred nanometers.
136. The composition of claim 127, wherein the composition, when at 800C, has at least 3.25 percent by weight of precipitates.
137. The composition of claim 136, wherein at least two percent by weight of the precipitates present at 800C are Cu, M(C,N), M2(C,N) or M23C6 phases.
138. The composition of claim 136, wherein the composition has been annealed at an annealing temperature, and the composition comprises at least 1.5 percent by weight more Cu, M(C,N), M2(C,N) or M23C6 phases at 800C than at the annealing temperature.
139. The composition of claim 138, wherein the annealing temperature is at least 1250C.
140. The composition of claim 138, wherein the annealing temperature is at between 1300C
and the melting temperature of the composition.
141. The composition of claim 127, wherein the composition, when at 800C, has at least 4 percent by weight of precipitates.
142. The composition of claim 127, wherein the composition, when at 800C, has at least 8 percent by weight of precipitates.
143. A composition comprising:
from about 18 percent to 22 percent by weight chromium;
from about 10 percent to 14 percent by weight nickel;
from about 1 percent to 10 percent by weight copper;
from about 0.5 percent to 1.5 percent by weight niobium;
from about 36 percent to 70.5 percent by weight iron; and precipitates of nanonitrides.
144. The composition of claim 143, wherein the nanonitride precipitates comprise particles having a maximum dimension of between five and one hundred nanometers.
145. The composition of claim 144, wherein the composition, when at 800 C, has at least 3.25 percent by weight of precipitates.
146. The composition of claim 144, wherein the composition, when at 800C, has at least 4 percent by weight of precipitates.
147. The composition of claim 143, wherein at least 2 percent by weight of the precipitates present at 800C are Cu, M(C,N), M2(C,N) or M23C6 phases.
148. The composition of claim 143, wherein the composition has been subjected to cold work.
149. The composition of claim 143, wherein the composition has been subjected to hot work.
150. The composition of claim 143, wherein the composition has been subjected to hot aging.
151. A heater system comprising:
a heat generating element; and a canister surrounding the heat generating element, wherein the canister is at least partially made of a material comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 10 percent to about 14 percent by weight nickel;
from about 1 percent to 10 percent by weight copper;
from about 0.5 percent to 1.5 percent by weight niobium;
from about 36 percent to 70.5 percent by weight iron; and precipitates of nanonitrides.
152. The heater system of claim 151, wherein the heat generating element is an electrical powered heat generating element.
153. The heater system of claim 151, wherein the heat generating element is a hydrocarbon fuel burning element.
154. A system for heating a subterranean formation comprising a tubular, the tubular at least partially made from a material comprising:
from about 18 percent to 22 percent by weight chromium;
from about 10 percent to 14 percent by weight nickel;
from about 1 percent to 10 percent by weight copper;
from about 0.5 percent to 1.5 percent by weight niobium;
from about 36 percent to 70.5 percent by weight iron; and precipitates of nanonitrides.
155. The system of claim 154, wherein a heating medium is circulated through the tubular to heat the subterranean formation.
156. The system of claim 154, wherein the heating medium comprises steam.
157. The system of claim 154, wherein the heating medium comprises carbon dioxide.
158. The system of claim 154, wherein the heating medium is heated at the surface by exchanging heat with helium.
159. The system of claim 158, wherein the helium is heated in a nuclear reactor.
160. The system of claim 154, wherein the system further comprises an electrically powered heating element as a source of heat.
161. The system of claim 154, wherein the tubular is fabricated by welding a rolled plate of material to form a tubular.
162. The system of claim 161, wherein the welding comprises laser welding.
163. The system of claim 161, wherein the welding comprises gas tungsten arc-welding.
164. A composition comprising:
about 11 percent to about 14 percent by weight Cr;
about 6 percent to about 12 percent by weight Co;
about 0.01 percent to about 0.15 percent by weight C;
about 0.1 percent to about 1.0 percent by weight Si; and about 65 percent to about 82 percent by weight Fe.
165. The composition of claim 164, further comprising about 0.01 percent to about 1 percent by weight Mn.
166. The composition of claim 164, further comprising about 0.1 percent to about 0.75 percent by weight Ni.
167. The composition of claim 164, wherein the composition comprises about 8 percent to about 10 percent Co.
168. The composition of claim 164, wherein the composition comprises less than about 0.75 % by weight Ni.
169. The composition of claim 164, wherein the composition comprises more than about 76 percent by weight Fe.
170. A heater comprising a metal section comprising:
iron, cobalt, and carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 800 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
171. The heater of claim 170, wherein the metal section further comprises one or more metals capable of forming carbides.
172. The heater of claim 170, wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
173. The heater of claim 170, wherein metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
174. The heater of claim 170,wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium and/or titanium.
175. The heater of claim 170, wherein the metal section further comprises manganese.
176. The heater of claim 170, wherein the metal section further comprises nickel.
177. The heater of claim 170, wherein the metal section further comprises silicon.
178. The heater of claim 170, wherein the metal section further comprises chromium.
179. The heater of claim 170, wherein the metal section further comprises manganese, silicon, chromium, or combinations thereof.
180. The heater of claim 170, wherein the content of iron in the metal section is at least 50%
by weight.
181. The heater of claim 170, wherein the content of cobalt in the metal section is at least 2%
by weight.
182. The heater of claim 170, wherein the metal section has at most 1% by weight of manganese.
183. The heater of claim 170, wherein the metal section has at most 1% by weight of nickel.
184. The heater of claim 170, wherein the metal section has at most 1% by weight of silicon.
185. The heater of claim 170, wherein the metal section has at most 1% by weight of vanadium.
186. The heater of claim 170, wherein the metal section has at most 1% by weight of titanium.
187. The heater of claim 170, wherein the metal section has at most 1% by weight of manganese.
188. A method of heating a formation containing hydrocarbons, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a metal section comprising iron, cobalt, and carbon, wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T
c is at least 800 C;
and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
189. A heater comprising a metal section, comprising:
iron, cobalt, chromium and carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
190. The heater of claim 189, wherein the metal section further comprises one or more metals capable of forming carbides.
191. The heater of claim 189, wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
192. The heater of claim 189, wherein metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
193. The heater of claim 189, wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium and/or titanium.
194. The heater of claim 189, wherein the metal section further comprises manganese.
195. The heater of claim 189, wherein the metal section further comprises nickel.
196. The heater of claim 189, wherein the metal section further comprises silicon.
197. The heater of claim 189, wherein the metal section further comprises manganese, silicon, chromium, or combinations thereof.
198. The heater of claim 189, wherein the content of iron in the metal section is at least 50%
by weight.
199. The heater of claim 189, wherein the content of chromium in the metal section is at least 9% by weight.
200. The heater of claim 189, wherein the content of chromium in the metal section is at least 11% by weight.
201. The heater of claim 189, wherein the content of cobalt in the metal section is at least 6%
by weight.
202. The heater of claim 189, wherein the metal section has at most 1% by weight of manganese.
203. The heater of claim 189, wherein the metal section has at most 1% by weight of nickel.
204. The heater of claim 189, wherein the metal section has at most 1% by weight of silicon.
205. The heater of claim 189, wherein the metal section has at most 1% by weight of vanadium.
206. The heater of claim 189, wherein the metal section has at most 1% by weight of titanium.
207. The heater of claim 189, wherein the metal section has at most 1% by weight of manganese.
208. A method of heating a formation containing hydrocarbons, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a metal section comprising iron, cobalt, chromium and carbon, wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740 C; and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
209. A heater comprising:
a metal section having at least 50% by weight iron, at least 6% by weight cobalt, at least 9% by weight chromium, and at least 0.5% by weight vanadium;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
210. The heater of claim 209, wherein the metal section further comprises carbon.
211. The heater of claim 209, wherein metal section further comprises titanium.
212. The heater of claim 209,wherein the metal section further comprises manganese.
213. The heater of claim 209, wherein the metal section further comprises nickel.
214. The heater of claim 209,wherein the metal section further comprises silicon.
215. The heater of claim 209, wherein the metal section further comprises manganese, silicon, nickel, or combinations thereof.
216. The heater of claim 209,wherein the content of chromium in the metal section is at least 11% by weight.
217. The heater of claim 209, wherein the metal section has at most 1% by weight of manganese.
218. The heater of claim 209, wherein the metal section has at most 1% by weight of nickel.
219. The heater of claim 209, wherein the metal section has at most 1% by weight of silicon.
220. The heater of claim 209, wherein the metal section has at most 1% by weight of vanadium.
221. The heater of claim 209, wherein the metal section has at most 1% by weight of titanium.
222. The heater of claim 209, wherein the metal section has at most 1% by weight of manganese.
223. A method of heating a formation containing hydrocarbons, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a metal section having at least 50% by weight iron, at least 6% by weight cobalt, at least 9% by weight chromium, and at least 0.5% by weight vanadium; wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T
c is at least 740 C;
and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
224. A heater comprising:
a metal section having at least 50% by weight iron, at least 9% by weight chromium and at least 0.1 % by weight carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 800 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
225. The heater of claim 224, wherein the metal section further comprises one or more metals capable of forming carbides.
226. The heater of claim 224, wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
227. The heater of claim 224, wherein metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
228. The heater of claim 224, wherein the metal section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium and/or titanium.
229. The heater of claim 224, wherein the metal section further comprises manganese.
230. The heater of claim 224, wherein the metal section further comprises nickel.
231. The heater of claim 224, wherein the metal section further comprises silicon.
232. The heater of claim 224, wherein the metal section further comprises manganese, silicon, or combinations thereof.
233. The heater of claim 224, wherein the content of iron in the metal section is at least 50%
by weight.
234. The heater of claim 224, wherein the content of chromium in the metal section is at least 11% by weight.
235. The heater of claim 224, wherein the metal section has at least 6% by weight of cobalt.
236. The heater of claim 224, wherein the metal section has at most 1% by weight of manganese.
237. The heater of claim 224, wherein the metal section has at most 1% by weight of nickel.
238. The heater of claim 224, wherein the metal section has at most 1% by weight of silicon.
239. The heater of claim 224, wherein the metal section has at most 1% by weight of vanadium.
240. The heater of claim 224, wherein the metal section has at most 1% by weight of titanium.
241. The heater of claim 224, wherein the metal section has at most 1% by weight of manganese.
242. A method of heating a formation containing hydrocarbons, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a metal section having at least 50% by weight iron, at least 9% by weight chromium and at least 0.1 % by weight carbon. wherein the heater section has a Curie temperature (T
c) less than a phase transformation temperature, wherein the T c is at least 800 C; and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
243. A method of providing at least a partial barrier for a subsurface formation, comprising:
providing an opening in the formation;
providing liquefied wax to the opening, the wax having a solidification temperature that is greater than the temperature of the portion of the formation in which the barrier to desired to be formed;
pressurizing the liquefied wax such that at least a portion of the liquefied wax flows into the formation; and allowing the wax to solidify to form at least a partial barrier in the formation.
244. The method of claim 243, wherein the wax comprises a surfactant.
245. The method of claim 243,wherein the wax comprises a surfactant selected to increase the miscibility of the wax in the formation.
246. The method of claim 243, wherein the wax viscosity increases quickly as the wax solidifies.
247. The method of claim 243, wherein the wax is selected to resist biological degradation.
248. The method of claim 243, wherein at least 50 weight percent of the wax is a hydrocarbon with branched chains.
249. The method of claim 243, wherein the wax, when flowing in a conduit, solidifies on the inner wall of the conduit, and the solidified wax provides insulation to inhibit further solidification of the wax in the conduit.
250. The method of claim 243, further comprising dewatering at least a portion of the formation.
251. The method of claim 243, further comprising cooling at least a portion of the wax in the formation.
252. The method of claim 243, further comprising providing wax to at least two openings such that the wax from at least two openings mixes and solidifies to form a barrier.
253. The method of claim 243, further comprising heating wax in the opening with a heater.
254. The method of claim 243, further comprising heating wax in the opening with a temperature limited heater.
255. The method of claim 243, further comprising heating wax in the opening with a temperature limited heater such that the wax is not heated above its flash point.
256. The method of claim 243, further comprising providing heat from one or more heaters to a section of the formation to mobilize fluids in the section of the formation, wherein the barrier inhibits flow of fluids into and/or out of the section of the formation.
257. The method of claim 243, further comprising providing heat from one or more heaters to a section of the formation to mobilize fluids in the section of the formation, wherein the barrier inhibits flow of fluids into and/or out of the section of the formation, and producing fluids from the section of the formation.
258. The method of claim 243, further comprising forming a frozen barrier by circulating cooling fluid in the opening.
259. The method of claim 243, further comprising injecting grout into the opening.
260. The method of claim 243, further comprising providing heated water to the opening.
261. The method of claim 243, further comprising providing heated water to the opening, and pressurizing the water.
262. The method of claim 243, further comprising providing water to opening, and heating the water.
263. The method of claim 243, further comprising providing water to the opening, and the pressurizing the water, prior to providing the wax to the opening.
264. The method of claim 243, further comprising inserting a conduit in the opening, and providing pressurized water to a space between the opening and the conduit to at least partially flush wax from the opening.
265. The method of claim 243, further comprising inserting a conduit in the opening, and providing pressurized water to the conduit to at least partially flush wax from the opening.
266. The method of claim 243, wherein the wax is sufficiently pressurized such that wax travels at least about 1 meter into the formation.
267. The method of claim 243, wherein as the wax is provided such that it travels further into the hotter sections of the formation.
268. A method of providing at least a partial barrier for a subsurface formation, comprising:
providing an opening in the formation;
providing a composition including cross-linkable polymer to the opening, the composition being configured to solidify after a selected time in the formation;
pressurizing the composition such that at least a portion of the composition flows into the formation; and allowing the composition to solidify to form at least a partial barrier in the formation.
269. The method of claim 268, wherein the composition comprises a cross-linking inhibitor.
270. The method of claim 268, wherein the composition comprises a cross-linking initiator and a cross-linking inhibitor.
271. The method of claim 268, wherein the composition comprises a cross-linking inhibitor that is configured to degrade after a selected time in the formation.
272. A method of containing liquid hydrocarbon contaminants in a fracture system of a subsurface formation, comprising:
raising a temperature of the formation near at least one injection well adjacent to a portion of the formation that contains the liquid hydrocarbon contaminants above a melting temperature of a material including wax;

introducing molten material into the formation through the injection well, wherein the molten material enters the fracture system and mixes with the contaminants in the fracture system; and allowing the molten material to cool in the formation and congeal to form a containment barrier.
273. A method of forming a wellbore in a formation through at least two permeable zones, comprising:
drilling a first portion of the wellbore to a depth between a first permeable zone and a second permeable zone;
heating a portion of the wellbore adjacent to the first permeable zone;
introducing a wax into the wellbore, wherein a portion of the wax enters the first permeable zone and congeals in the first permeable zone to form a barrier; and drilling a second portion of the wellbore through a second permeable zone to a desired depth.
274. A method for heating a subsurface treatment area, comprising:
producing hot fluid from at least one subsurface layer; and transferring heat from at least a portion of the hot fluid to the treatment area.
275. The method of claim 274, wherein the hot fluid is produced from a geothermally pressurized geyser.
276. The method of claim 274, wherein the hot fluid is pumped from the subsurface layer.
277. The method of claim 274, wherein transferring heat from the hot fluid to the treatment area comprises circulating hot fluid through wells in the treatment area.
278. The method of claim 274, wherein transferring heat from the hot fluid to the treatment area comprises introducing at least a portion of the hot fluid directly into the treatment area.
279. The method of claim 274, further comprising using the hot fluid to provide heat to the formation for solution mining.
280. The method of claim 274, further introducing the hot fluid as a first fluid in a solution mining process and producing a second fluid from the formation, wherein the second fluid contains at least some minerals dissolved in the first fluid.
281. The method of claim 274, using the hot fluid to preheat at least a section of the treatment area and using heat sources to provide additional heat to the section above a pyrolysis temperature of hydrocarbons in the treatment area.
282. The method of claim 274, further comprising directing the hot fluid to the treatment area without first producing the hot fluid to the surface.
283. A method for heating at least a portion of a subsurface treatment area, comprising:
introducing a fluid into a hot subsurface layer to transfer heat from the hot layer to the fluid;
producing at least a portion of the fluid introduced into the hot layer, wherein the produced fluid is hot fluid at a temperature higher than the temperature of the fluid introduced into the hot layer; and transferring heat from at least a portion of the hot fluid to the treatment area.
284. The method of claim 283, wherein transferring heat from the hot fluid to the treatment area comprises circulating hot fluid through wells in the treatment area.
285. The method of claim 283, wherein transferring heat from the hot fluid to the treatment area comprises introducing at least a portion of the hot fluid directly into the treatment area.
286. The method of claim 283, further comprising using the hot fluid to provide heat to the formation for solution mining.
287. The method of claim 283, further introducing the hot fluid as a first fluid in a solution mining process and producing a second fluid from the formation, wherein the second fluid contains at least some minerals dissolved in the first fluid.
288. The method of claim 283, using the hot fluid to preheat at least a section of the treatment area and using heat sources to provide additional heat to the section above a pyrolysis temperature of hydrocarbons in the treatment area.
289. The method of claim 283, further comprising directing the hot fluid to the treatment area without first producing the hot fluid to the surface.
290. The method of claim 283, further comprising introducing at least a portion of the hot fluid after the hot fluid has transferred heat to the treatment area back to the hot subsurface layer.
291. A method of treating a subsurface treatment area in a formation, comprising:
heating a treatment area to mobilize formation fluid in the treatment area;
and introducing a fluid into the formation to inhibit migration of formation fluid from the treatment area.
292. The method of claim 291, wherein the fluid comprises carbon dioxide.
293. The method of claim 291, wherein the fluid is introduced into the formation in an area between a barrier and the treatment area.
294. A method for treating a subsurface treatment area in a formation, comprising:
heating a subsurface treatment area with a plurality of heat sources; and introducing a fluid into the formation from a plurality of wells offset from the heat sources to inhibit outward migration of formation fluid from the treatment area.
295. The method of claim 294, wherein a barrier is offset from the plurality of wells used to introduce the fluid into the formation.
296. The method of claim 294, wherein the fluid comprises carbon dioxide.
297. The method of claim 294, further comprising providing heat to at least a portion the formation adjacent to at least one of the plurality of wells from a heater coupled to the well.
298. The method of claim 294, further comprising providing heat to at least a portion the formation adjacent to at least one of the plurality of wells from a heater coupled to the well, wherein the heater is configured to provide heat without raising the formation above a pyrolysis temperature or a dissociation temperature of minerals in the formation.
299. The method of claim 294, further comprising providing heat to at least a portion of the formation adjacent to at least one of the plurality of wells from a heater well in the formation that is offset from the well.
300. The method of claim 294, further comprising providing heat to at least a portion of the formation adjacent to at least one of the plurality of wells from a heater well in the formation that is offset from the well, wherein the heater is configured to provide heat without raising the formation above a pyrolysis temperature or a dissociation temperature of minerals in the formation.
301. An in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising:
a plurality of wellbores in the formation;
piping positioned in at least two of the wellbores;
a fluid circulation system coupled to the piping; and a nuclear reactor configured to heat a heat transfer fluid circulated by the circulation system through the piping to heat the temperature of the formation to temperatures that allow for hydrocarbon production from the formation.
302. The system of claim 301, wherein the heat transter fluid comprises carbon dioxide.
303. The system of claim 301, wherein the nuclear reactor comprises a pebble bed reactor.
304. A method of heating a subsurface formation, comprising:
heating a heat transfer fluid using heat exchange with helium heated by a nuclear reactor;
circulating the heat transfer fluid through piping in the formation to heat a portion of the formation to allow hydrocarbons to be produced from the formation; and producing hydrocarbons from the formation.
305. The system of claim 304, wherein the heat transfer fluid comprises carbon dioxide.
306. The system of claim 304, wherein the nuclear reactor comprises a pebble bed reactor.
307. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant line;
a fuel line positioned in the oxidant line; and a plurality of oxidizers coupled to the fuel line, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel line with an oxidant;
an igniter;
a nozzle and flame holder; and a heat shield, wherein the heat shield comprises a plurality of openings in communication with the oxidant line.
308. The assembly of claim 307, further comprising a water line positioned in the oxidant line, the water line configured to deliver water that inhibits coking of fuel to the fuel line before a first oxidizer in the gas burner assembly.
309. The assembly of claim 307, wherein the heat shield comprises at least one flame stabilizer.
310. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant line;
a fuel line positioned in the oxidant line; and a plurality of oxidizers coupled to the fuel line, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel line with an oxidant;
an catalyst chamber configured to produce hot reaction products to ignite fuel and oxidant;
a nozzle and flame holder; and a heat shield, wherein the heat shield comprises a plurality of openings in communication with the oxidant line.
311. The assembly of claim 310, further comprising a water line positioned in the oxidant line, the water line configured to deliver water that inhibits coking of fuel to the fuel line before a first oxidizer in the gas burner assembly.
312. The assembly of claim 310, wherein the heat shield comprises at least one flame stabilizer.
313. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant line;
a fuel line positioned in the oxidant line; and a plurality of oxidizers coupled to the fuel line, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel line with an oxidant;
an igniter in the mix chamber configured to ignite fuel and oxidant to preheat fuel and oxidant;
an catalyst chamber configured to react preheated fuel and oxidant,from the mix chamber to produce hot reaction products to ignite fuel and oxidant;
a nozzle and flame holder; and a heat shield, wherein the heat shield comprises a plurality of openings in communication with the oxidant line.
314. The assembly of claim 313, further comprising a water line positioned in the oxidant line, the water line configured to deliver water that inhibits coking of fuel to the fuel line before a first oxidizer in the gas burner assembly.
315. The assembly of claim 313, wherein the heat shield comprises at least one flame stabilizer.
316. A heater, comprising:
a heater section comprising iron, cobalt, and carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, and the T c is at least 800 C; and wherein the heater section is configured to provide, when time varying current is applied to the heater section, an electrical resistance.
317. The heater of claim 316, wherein the heater section further comprises one or more metals capable of forming carbides.
318. The heater of claim 316, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
319. The heater of claim 316, wherein heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
320. The heater of claim 316,wherein the heater section further comprises one or more metals capable of forming carbides, and wherein at least one of the metals is vanadium and/or titanium.
321. The heater of claim 316, wherein the heater section further comprises manganese.
322. The heater of claim 316, wherein the heater section further comprises nickel.
323. The heater of claim 316, wherein the heater section further comprises silicon.
324. The heater of claim 316, wherein the heater section further comprises chromium.
325. The heater of claim 316, wherein the heater section further comprises manganese, silicon, chromium, or combinations thereof.
326. The heater of claim 316, wherein the content of iron in the heater section is at least 50% by weight.
327. The heater of claim 316, wherein the content of cobalt in the heater section is at least 2%
by weight.
328. The heater of claim 316, wherein the heater section has at most 1% by weight of manganese.
329. The heater of claim 316, wherein the heater section has at most 1% by weight of nickel.
330. The heater of claim 316, wherein the heater section has at most 1% by weight of silicon.
331. The heater of claim 3 16, wherein the heater section has at most 1% by weight of vanadium.
332. The heater of claim 316, wherein the heater section has at most 1% by weight of titanium.
333. The heater of claim 316, wherein the heater section has at most 1% by weight of manganese.
334. The heater of claim 316, wherein the heater section is configured to provide a reduced amount of heat at or near, and above, the Curie temperature.
335. The heater of claim 316, wherein the heater is located in a subsurface formation.
336. The heater of claim 316, wherein the heater is configured to provide heat to a subsurface formation.
337. The heater of claim 316, wherein the heater is configured to provide heat to a hydrocarbon containing formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
338. A method of heating a hydrocarbon containing formation, comprising:
providing a temperature limited heater to the formation, wherein the heater comprises a heater section comprising iron, cobalt, and carbon, wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T
c is at least 800 C;
and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
339. The method of claim 338, wherein the heater section provides a reduced amount of heat at or near, and above, the Curie temperature.
340. The method of claim 338, further comprising providing heat to the formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
341. A heater, comprising:
a heater section comprising iron, cobalt, chromium and carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
342. The heater of claim 341, wherein the heater section further comprises one or more metals capable of forming carbides.
343. The heater of claim 341, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
344. The heater of claim 341, wherein heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
345. The heater of claim 341, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium and/or titanium.
346. The heater of claim 341, wherein the heater section further comprises manganese.
347. The heater of claim 341, wherein the heater section further comprises nickel.
348. The heater of claim 341, wherein the heater section further comprises silicon.
349. The heater of claim 341, wherein the heater section further comprises manganese, silicon, chromium, or combinations thereof.
350. The heater of claim 341, wherein the content of iron in the heater section is at least 50%
by weight.
351. The heater of claim 341, wherein the content of chromium in the heater section is at least 9% by weight.
352. The heater of claim 341, wherein the content of chromium in the heater section is at least 11% by weight.
353. The heater of claim 341, wherein the content of cobalt in the heater section is at least 6%
by weight.
354. The heater of claim 341, wherein the heater section has at most 1% by weight of manganese.
355. The heater of claim 341, wherein the heater section has at most 1% by weight of nickel.
356. The heater of claim 341, wherein the heater section has at most 1% by weight of silicon.
357. The heater of claim 341, wherein the heater section has at most 1% by weight of vanadium.
358. The heater of claim 341, wherein the heater section has at most 1% by weight of titanium.
359. The heater of claim 341, wherein the heater section has at most 1% by weight of manganese.
360. The heater of claim 341, wherein the heater section is configured to provide a reduced amount of heat at or near, and above, the Curie temperature.
361. The heater of claim 341, wherein the heater is located in a subsurface formation.
362. The heater of claim 341, wherein the heater is configured to provide heat to a subsurface formation.
363. The heater of claim 341, wherein the heater is configured to provide heat to a hydrocarbon containing formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
364. A method of heating a hydrocarbon containing formation, comprising:
providing a temperature limited heater to the formation, wherein the heater comprises a heater section comprising iron, cobalt, chromium and carbon, wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740C; and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
365. The method of claim 364, wherein the heater section provides a reduced amount of heat at or near, and above, the Curie temperature.
366. The method of claim 364, further comprising providing heat to the formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
367. A heater, comprising:
a heater section having at least 50% by weight iron, at least 6% by weight cobalt, at least 9% by weight chromium, and at least 0.5% by weight vanadium;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 740 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
368. The heater of claim 367, wherein the heater section further comprises carbon.
369. The heater of claim 367, wherein the heater section further comprises titanium.
370. The heater of claim 367, wherein the heater section further comprises manganese.
371. The heater of claim 367, wherein the heater section further comprises nickel.
372. The heater of claim 367, wherein the heater section further comprises silicon.
373. The heater of claim 367, wherein the heater section further comprises manganese, silicon, nickel, or combinations thereof.
374. The heater of claim 367,wherein the content of chromium in the heater section is at least 11% by weight.
375. The heater of claim 367, wherein the heater section has at most 1% by weight of manganese.
376. The heater of claim 367, wherein the heater section has at most 1% by weight of nickel.
377. The heater of claim 367, wherein the heater section has at most 1% by weight of silicon.
378. The heater of claim 367, wherein the heater section has at most 1% by weight of vanadium.
379. The heater of claim 367, wherein the heater section has at most 1% by weight of titanium.
380. The heater of claim 367, wherein the heater section has at most 1% by weight of manganese.
381. The heater of claim 367, wherein the heater section is configured to provide a reduced amount of heat at or near, and above, the Curie temperature.
382. The heater of claim 367, wherein the heater is located in a subsurface formation.
383. The heater of claim 367, wherein the heater is configured to provide heat to a subsurface formation.
384. The heater of claim 367, wherein the heater is configured to provide heat to a hydrocarbon containing formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
385. A method of heating a hydrocarbon containing formation, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a heater section having at least 50% by weight iron, at least 6% by weight cobalt, at least 9% by weight chromium, and at least 0.5% by weight vanadium; wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T
c is at least 740 C;
and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
386. The method of claim 385, wherein the heater section provides a reduced amount of heat at or near, and above, the Curie temperature.
387. The method of claim 385, further comprising providing heat to the formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
388. A heater, comprising:
a heater section having at least 50% by weight iron, at least 9% by weight chromium and at least 0.1% by weight carbon;
wherein the heater section has a Curie temperature (T c) less than a phase transformation temperature, wherein the T c is at least 800 C; and wherein the heater section is configured to provide, when time varying current is applied, an electrical resistance.
389. The heater of claim 388, wherein the heater section further comprises one or more metals capable of forming carbides.
390. The heater of claim 388, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium.
391. The heater of claim 388, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is titanium.
392. The heater of claim 388, wherein the heater section further comprises one or more metals capable of forming carbides, wherein at least one of the metals is vanadium and/or titanium.
393. The heater of claim 388, wherein the heater section further comprises manganese.
394. The heater of claim 388, wherein the heater section further comprises nickel.
395. The heater of claim 388, wherein the heater section further comprises silicon.
396. The heater of claim 388, wherein the heater section further comprises manganese, silicon, or combinations thereof.
397. The heater of claim 388, wherein the content of iron in the heater section is at least 50%
by weight.
398. The heater of claim 388, wherein the content of chromium in the heater section is at least 11% by weight.
399. The heater of claim 388, wherein the heater section has at least 6% by weight of cobalt.
400. The heater of claim 388, wherein the heater section has at most 1% by weight of manganese.
401. The heater of claim 388, wherein the heater section has at most 1% by weight of nickel.
402. The heater of claim 388, wherein the heater section has at most 1% by weight of silicon.
403. The heater of claim 388, wherein the heater section has at most 1% by weight of vanadium.
404. The heater of claim 388, wherein the heater section has at most 1% by weight of titanium.
405. The heater of claim 388, wherein the heater section has at most 1% by weight of manganese.
406. The heater of claim 388, wherein the heater section is configured to provide a reduced amount of heat at or near, and above, the Curie temperature.
407. The heater of claim 388, wherein the heater is located in a subsurface formation.
408. The heater of claim 388, wherein the heater is configured to provide heat to a subsurface formation.
409. The heater of claim 388, wherein the heater is configured to provide heat to a hydrocarbon containing formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
410. A method of heating a formation containing hydrocarbons, comprising:
providing a temperature limited heater to a formation, wherein the heater comprises a metal section having at least 50% by weight iron, at least 9% by weight chromium and at least 0.1% by weight carbon. wherein the heater section has a Curie temperature (T
c) less than a phase transformation temperature, wherein the T c is at least 800 C; and providing current to the temperature limited heater such that the temperature limited heater provides electrical resistance heating to at least a portion of the formation.
411. The method of claim 410, wherein the heater section provides a reduced amount of heat at or near, and above, the Curie temperature.
412. The method of claim 410, further comprising providing heat to the formation such that at least some hydrocarbons in the formation are mobilized and/or pyrolyzed.
413. A system for coupling ends of elongated heaters, comprising:
two elongated heaters with an end portion of one heater abutted or near to an end portion of the other heater, the elongated heaters comprising cores and one or more conductors substantially concentrically surrounding the cores, the cores having a lower melting point than the conductors, at least one end portion of at least one conductor having a beveled edge, and at least one end portion of at least one core having a recessed opening;
a core coupling material at least partially inside the recessed opening, the core coupling material extending between the two elongated heaters; and wherein the gap formed by the beveled edge is configured to be filled with a coupling material for coupling the one or more conductors.
414. The system of claim 413, wherein the end portions of both conductors have beveled edges.
415. The system of claim 413, wherein the end portions of both cores have recessed openings.
416. The system of claim 413, wherein the core comprises copper.
417. The system of claim 413, wherein the core coupling material comprises copper.
418. The system of claim 413, wherein at least one conductor comprises ferromagnetic material.
419. The system of claim 413, wherein the outermost conductor comprises stainless steel.
420. The system of claim 413, wherein the coupling material comprises a non-ferromagnetic material.
421. The system of claim 413, wherein the core coupling material comprises material that thermally expands radially more than the coupling material.
422. The system of claim 413, wherein the elongated heaters comprise cores substantially concentrically surrounded by ferromagnetic conductors, the ferromagnetic conductors substantially concentrically surrounded by an outer electrical conductor.
423. The system of claim 413, wherein the elongated heaters are configured to be coupled by welding together the conductors with the coupling material in the gap formed by the beveled edges.
424. The system of claim 413, wherein electrical current is configured to flow primarily through the core coupling material when an electrical current is applied to the elongated heaters.
425. The system of claim 413, wherein the heaters are configured to be used to heat a subsurface formation.
426. A method for coupling two elongated heaters, comprising:
placing a core coupling material in recesses in the end portions of cores of the two elongated heaters, the cores of the heaters substantially concentrically surrounded by one or more conductors, the cores having a lower melting point than the one or more conductors; and coupling the end portions of the two heaters by filling gaps between beveled edges of the end portions of the one or more conductors with a coupling material.
427. The method of claim 426, further comprising coupling the end portions of the two heaters by welding together the end portions.
428. The method of claim 426, wherein the coupling material comprises non-ferromagnetic material.
429. The method of claim 426, wherein the core coupling material comprises copper.
430. The method of claim 426, wherein during coupling of the end portions of the two heaters, electricity primarily flows through the core coupling material.
431. The method of claim 426, wherein the two heaters are coupled without welding the cores of the heaters together.
432. The method of claim 426, further comprising installing the heaters in a subsurface formation.
433. The method of claim 426, further comprising applying electrical current to the heaters, and providing heat from the heaters to at least a portion of a subsurface formation.
434. A system for coupling end portions of two elongated heater portions, comprising:
a holding system configured to hold end portions of the two elongated heater portions so that the end portions are abutted together or located near each other;
a shield for enclosing the end portions, the shield configured to inhibit oxidation during welding that joins the end portions together, the shield comprising a hinged door that, when closed, is configured to at least partially isolate the interior of the shield from the atmosphere, and the hinged door, when open, is configured to allow access to the interior of the shield; and one or more inert gas inlets configured to provide at least one inert gas to flush the system with inert gas during welding of the end portions.
435. The system of claim 434, further comprising at least one source of inert gas.
436. The system of claim 434, wherein the inert gas comprises argon.
437. The system of claim 434, wherein the shield comprises a window configured to allow an operator of the system to view the welding of the end portions.
438. The system of claim 434, wherein the shield, when closed, form a substantially airtight seal to seal off the interior of the shield from the atmosphere.
439. The system of claim 434, wherein the shield is configured to allow a positive pressure of inert gas to be provided during welding of the end portions.
440. The system of claim 434, wherein the shield comprises one or more clamps to secure the end portions of the heaters to the shield.
441. The system of claim 434, wherein the end portions are configured to be orbital welded to join the end portions together.
442. The system of claim 434, wherein the shield is configured to allow the heater portions to be moved through the shield so that a non-welded end portion of one of the heater portions can be positioned for welding to an end portion of a third elongated heater portion.
443. The system of claim 434, further comprising a control circuit configured to monitor hydrocarbon gas concentration in the shield, wherein the control circuit is configured to shut off welding of the end portions when the hydrocarbon gas concentration exceeds a minimum value.
444. The system of claim 434, wherein the heater portions are configured to be used to heat a subsurface formation.
445. A method for coupling end portions of two elongated heater portions, comprising:

holding end portions of two elongated heater portions so that the end portions are abutted together or located near each other;
enclosing the end portions of the heaters in a shield, the shield comprising a hinged door that is configured to at least partially isolate the interior of the shield from the atmosphere when closed, and the hinged door when open is configured to allow access to the interior of the shield when open;
welding the end portions together, the shield inhibiting oxidation during the welding; and providing an inert gas to flush the system during welding of the end portions of the heaters.
446. The method of claim 445, wherein the shield forms an airtight seal to seal off the interior of the shield from the atmosphere when closed.
447. The method of claim 445, wherein the inert gas comprises argon.
448. The method of claim 445, further comprising providing a positive pressure of inert gas into the shield.
449. The method of claim 445, further comprising pulling a vacuum on the interior of the shield prior to welding the end portions together and before providing the inert gas.
450. The method of claim 445, further comprising viewing the welding of the end portions through a window.
451. The method of claim 445, further comprising orbital welding the end portions together.
452. The method of claim 445, further comprising securing the end portions to the shield by clamping the end portions to the shield.
453. The method of claim 445, further comprising moving the elongated heater portions through the shield so that a non-welded end portion of one of the heater portions is positioned for welding to an end portion of a third elongated heater portion.
454. The method of claim 445, further comprising coupling a plurality of additional elongated heater portions to the two elongated heater portions by repeating the method to weld the end portions of each of the additional elongated heater portions to previously welded heater portions, thereby forming an elongated heater.
455. The method of claim 445, further comprising monitoring hydrocarbon gas concentration in the shield, and shutting off welding of the end portions when the hydrocarbon gas concentration exceeds a minimum value.
456. The method of claim 454, further comprising installing the elongated heater in a subsurface formation.
457. The method of claim 454, further comprising applying electrical current to the elongated heater, and providing heat from the heater to at least a portion of a subsurface formation.
458. A heater, comprising:
a ferromagnetic conductor; and an electrical conductor electrically coupled to the ferromagnetic conductor;
wherein the heater is configured to provide a first amount of heat at a lower temperature and, the heater is configured to provide a second reduced amount of heat when the heater reaches a selected temperature, or enters a selected temperature range, at which the ferromagnetic conductor undergoes a phase transformation.
459. The heater of claim 458, wherein the ferromagnetic conductor is positioned relative to the outer electrical conductor such that an electromagnetic field produced by time-varying current flow in the ferromagnetic conductor confines a majority of the flow of the electrical current to the outer electrical conductor at temperatures below or near the selected temperature.
460. The heater of claim 458, wherein the electrical conductor provides a majority of a resistive heat output of the heater at temperatures up to approximately the selected temperature, or the selected temperature range, of the phase transformation of the ferromagnetic conductor.
461. The heater of claim 458, wherein the phase transformation comprises a crystalline phase transformation.
462. The heater of claim 458, wherein the phase transformation comprises a change in the crystal structure of the ferromagnetic material.
463. The heater of claim 458, wherein the phase transformation comprises the transformation of the ferromagnetic conductor from ferrite to austenite.
464. The heater of claim 458, wherein the heater self-limits at a temperature near the phase transformation temperature or temperature range.
465. The heater of claim 458, wherein the phase transformation is reversible.
466. The heater of claim 458, wherein the Curie temperature of the ferromagnetic material is within the temperature range of the phase transformation of the ferromagnetic material.
467. The heater of claim 458, wherein the ferromagnetic conductor comprises additional material configured to adjust the selected temperature, or the selected temperature range, of the ferromagnetic conductor.
468. The heater of claim 467, wherein the additional material is configured to adjust the width of the temperature range of the phase transformation.
469. The heater of claim 458, wherein the heater has a turndown ratio of at least 2 to 1.
470. The heater of claim 458, wherein the heater is configured to provide heat to a hydrocarbon containing layer in a hydrocarbon containing formation such that heat transfers from the heater to hydrocarbons in the hydrocarbon containing layer to at least mobilize some hydrocarbons in the layer.
471. A heater, comprising:
a ferromagnetic conductor;
an electrical conductor electrically coupled to the ferromagnetic conductor;
wherein the electrical conductor provides a majority of a resistive heat output of the heater at temperatures up to approximately the selected temperature, or the selected temperature range, of the phase transformation of the ferromagnetic conductor; and the heater is configured to provide a first amount of heat at a lower temperature and, the heater is configured to provide a second reduced amount of heat when the heater reaches a selected temperature, or enters a selected temperature range, at which the ferromagnetic conductor undergoes a phase transformation.
472. A method of heating a subsurface formation, comprising:
providing electrical current to a ferromagnetic conductor and an electrical conductor electrically coupled to the ferromagnetic conductor to provide heat to at least a portion of the subsurface formation;
wherein a first amount of heat is provided at a lower temperature and, a second reduced amount of heat is provided when the ferromagnetic conductor reaches a selected temperature, or enters a selected temperature range, at which the ferromagnetic conductor undergoes a phase transformation.
473. The method of claim 472, wherein the ferromagnetic conductor is positioned relative to the outer electrical conductor such that an electromagnetic field produced by time-varying current flow in the ferromagnetic conductor confines a majority of the flow of the electrical current to the outer electrical conductor at temperatures below or near the selected temperature.
474. The method of claim 472, wherein the electrical conductor provides a majority of a resistive heat output at temperatures up to approximately the selected temperature, or the selected temperature range, of the phase transformation of the ferromagnetic conductor.
475. The method of claim 472, wherein the phase transformation comprises a crystalline phase transformation.
476. The method of claim 472, wherein the phase transformation comprises a change in the crystal structure of the ferromagnetic material.
477. The method of claim 472, wherein the phase transformation comprises the transformation of the ferromagnetic conductor from ferrite to austenite.
478. The method of claim 472, wherein the phase transformation is reversible.
479. The method of claim 472, wherein the ferromagnetic conductor comprises additional material configured to adjust the selected temperature, or the selected temperature range, of the ferromagnetic conductor.
480. The method of claim 479, wherein the material addition is configured to adjust the width of the temperature range of the phase transformation.
481. The method of claim 472, wherein the heater has a turndown ratio of at least 2 to 1.
482. The method of claim 472, wherein the subsurface formation comprises hydrocarbons, the method further comprising allowing the heat to transfer to the formation such that at least some hydrocarbons are pyrolyzed in the formation.
483. The method of claim 472, further comprising producing a fluid from the formation.
484. The method of claim 472, further comprising producing a composition comprising hydrocarbons from the subsurface formation.
485. The method of claim 472, further comprising producing a transportation fuel from hydrocarbons produced from the subsurface formation.
486. A method for treating a hydrocarbon containing formation, comprising:
providing heat for a first amount of time to a first hydrocarbon layer in the formation from a first heater located in an opening in the formation, the opening and the first heater having a substantially horizontal or inclined portion located in the first hydrocarbon layer in the formation and at least one connecting portion extending between the substantially horizontal or inclined portion and the surface;
removing at least one connecting portion of the first heater from the opening;

placing an isolation material in the opening such that the isolation material at least partially isolates the layer in which the substantially horizontal or inclined portion of the first heater is located;
forming an additional substantially horizontal or inclined opening portion in a second hydrocarbon layer, the additional portion extending from at least one of the connecting portions of the opening;
placing a second heater in the additional substantially horizontal opening portion; and providing heat from the second heater to the second hydrocarbon layer.
487. The method of claim 486, further comprising producing fluids from the formation.
488. The method of claim 486, wherein the first amount of time is sufficient time to produce a selected amount of hydrocarbons from the first hydrocarbon layer.
489. The method of claim 486, wherein at least one of the connecting portions is coupled to an end portion of the substantially horizontal or inclined portion.
490. The method of claim 486, wherein the second hydrocarbon layer is separated from the first hydrocarbon layer by an at least partially impermeable layer.
491. The method of claim 486, further comprising placing the isolation material in at least one of the connecting portions.
492. The method of claim 486, wherein the isolation material at least partially isolates the opening above the first hydrocarbon layer or, alternatively, below the first hydrocarbon layer.
493. The method of claim 486, further comprising uncoupling at least one connecting portion of the first heater from the substantially horizontal portion of the first heater.
494. The method of claim 486, further comprising abandoning the first hydrocarbon layer after treating the formation by leaving the packing in place in the opening.
495. The method of claim 486, wherein the connecting portion of the first heater is uncoupled from the substantially horizontal portion of the first heater by breaking one or more links on the first heater.
496. The method of claim 495, wherein the breaking is performed by pulling one or more of the connecting portions with a sufficient amount of force.
497. The method of claim 486, wherein the formation comprises an oil shale formation.
498. The method of claim 486, wherein the first hydrocarbon layer has a higher richness than the second hydrocarbon layer.
499. The method of claim 486, wherein the first hydrocarbon layer is at a greater depth than the second hydrocarbon layer.
500. The method of claim 486, wherein the impermeable material provides an impermeable layer between the first hydrocarbon layer and the second hydrocarbon layer.
501. The method of claim 486, wherein the opening has a first end portion at a first location on the surface of the formation and a second end portion at a second location on the surface of the formation.
502. The method of claim 486, wherein the opening comprises a u-shaped opening.
503. The method of claim 486, wherein the connecting portions of the opening comprise relatively vertical portions.
504. The method of claim 486, wherein the substantially horizontal portion of the opening extends between at least two relatively vertical connecting portions of the opening in the first hydrocarbon layer.
505. The method of claim 486, wherein the additional substantially horizontal portion of the opening extends between at least two relatively vertical connecting portions of the opening in the second hydrocarbon layer.
506. The method of claim 486, wherein the substantially horizontal portion of the first heater is left in the substantially horizontal portion of the opening after removing the connecting portions of the first heater from the opening.
507. The method of claim 486, further comprising producing a composition comprising hydrocarbons from the first hydrocarbon layer and/or the second hydrocarbon layer.
508. The method of claim 486, further comprising producing a transportation fuel made from hydrocarbons produced from the first hydrocarbon layer and/or the second hydrocarbon layer.
509. A method for treating a hydrocarbon containing formation, comprising:
providing heat for a first amount of time to a first hydrocarbon layer in the formation from a first heater located in an opening in the formation, the opening and the first heater having a substantially horizontal or inclined portion located in the first hydrocarbon layer in the formation and two connecting portions extending between the substantially horizontal or inclined portion and the surface, each connecting portion being coupled to one of the end portions of the substantially horizontal or inclined portion;
removing at least one connecting portion of the first heater from the opening;

placing an isolation material in the opening such that the isolation material at least partially isolates the layer in which the substantially horizontal or inclined portion of the first heater is located;
forming an additional substantially horizontal or inclined opening portion in a second hydrocarbon layer, the additional portion extending between the connecting portions of the opening;
placing a second heater in the additional substantially horizontal opening portion; and providing heat from the second heater to the second hydrocarbon layer.
510. A method for treating a hydrocarbon containing formation, comprising:
providing heat for a first amount of time to a first hydrocarbon layer in the formation from a first heater located in an opening in the formation, the opening and the first heater having a substantially horizontal or inclined portion located in the first hydrocarbon layer in the formation and a connecting portion extending between the substantially horizontal or inclined portion and the surface, the connecting portion being coupled to an end portion of the substantially horizontal or inclined portion;
removing at least the connecting portion of the first heater from the opening;

placing an isolation material in the opening such that the isolation material at least partially isolates the layer in which the substantially horizontal or inclined portion of the first heater is located;
forming an additional substantially horizontal or inclined opening portion in a second hydrocarbon layer, the additional portion extending from the connecting portion of the opening;
placing a second heater in the additional substantially horizontal opening portion; and providing heat from the second heater to the second hydrocarbon layer.
511. A method for producing hydrocarbons from a subsurface formation, comprising:
providing heat to the subsurface formation using an in situ heat treatment process;
forming one or more formation particles, wherein the formation particles are formed during heating of the subsurface formation; and producing a fluid comprising hydrocarbons and the formation particles from the subsurface formation, wherein the formation particles in the produced fluid comprise cenospheres and have an average particle size of at least 0.5 micrometers.
512. The method of claim 511, wherein a majority of the formation particles have an average diameter ranging between 0.5 microns and 200 microns.
513. The method of claim 511, wherein the formation particles have an average diameter between 5 microns and 100 microns.
514. The method of claim 511, wherein one or more of the formation particles comprises one or more organic compounds.
515. The method of claim 511, wherein one or more of the formation particles comprises a mixture of organic and inorganic compounds.
516. The method of claim 511, wherein one or more of the formation particles comprises asphaltenes.
517. The method of claim 511, wherein one or more of the formation particles comprises clay.
518. The method of claim 511, wherein one or more of the formation particles comprises quartz.
519. The method of claim 511, wherein one or more of the formation particles comprises one or more zeolites.
520. The method of claim 511, wherein forming one or more formation particles produces a bimodal distribution of formation particles.
521. The method of claim 511, wherein forming one or more formation particles produces a trimodal distribution of formation particles.
522. The method of claim 511, further comprising removing formation particles from the produced fluid.
523. The method of claim 511, further comprising filtering the produced fluid to remove selected formation particles.
524. The method of claim 511, further comprising centrifuging the produced fluid to remove selected formation particles.
525. The method of claim 511, further comprising treating the produced fluid to agglomerate selected formation particles, and then removing the agglomerated formation particles from the produced fluid.
526. A formation fluid composition, comprising:
hydrocarbons having a boiling range distribution between -5 C and 600 C; and one or more formation particles, wherein one or more of the formation particles comprises cenospheres and wherein one or more of the formation particles have an average particle size of at least 0.5 micrometers.
527. The formation fluid composition of claim 526, wherein a majority of the formation particles have an average diameter ranging between 0.5 microns and 200 microns.
528. The formation fluid composition of claim 526, wherein the formation particles have an average diameter between 5 microns and 100 microns.
529. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises one or more organic compounds.
530. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises organic and/or inorganic compounds.
531. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises asphaltenes.
532. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises clay.
533. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises quartz.
534. The formation fluid composition of claim 526, wherein one or more of the formation particles further comprises one or more zeolites.
535. The formation fluid composition of claim 526, wherein a distribution of the formation particles in the formation fluid is bimodal.
536. The formation fluid composition of claim 526, wherein a distribution of the formation particles in the formation fluid is trimodal.
537. A method of producing transportation fuel, comprising:
providing formation fluid from a subsurface in situ heat treatment process, wherein the formation fluid has a boiling range distribution between -5 C and 350 C as determined by ASTM D5307;
separating a liquid stream from the formation fluid;
hydrotreating the separated liquid stream;
distilling the hydrotreated liquid stream to produce a distilled stream, wherein the distilled stream has a boiling range distribution between 150 C and 350 C as determined by ASTM D5307; and combining the distilled liquid stream with one or more additives to produce transportation fuel.
538. The method of claim 537, wherein the transportation fuel is suitable for use in aircraft.
539. The method of claim 537, wherein the transportation fuel is suitable for use in diesel fuel consuming vehicles and equipment.
540. The method of claim 537, wherein the transportation fuel is suitable for use aircraft and in diesel fuel consuming vehicles and equipment.
541. The method of claim 537, wherein the transportation fuel is suitable for use military aircraft and in military diesel fuel consuming vehicles and equipment.
542. The method of claim 537, wherein separating a liquid stream comprises removing lower boiling hydrocarbons from the formation fluid to obtain the separated liquid stream, wherein the separated liquid stream has a boiling range distribution between 50 C
and 350 C as determined by ASTM D5307.
543. The method of claim 537, wherein the distilled liquid stream has a boiling range distribution between 180 C and 330 C as determined by ASTM
D5307.
544. The method of claim 537, wherein at least 50 percent by weight of hydrocarbons in the separated liquid stream have a carbon number from 4 to 12 as determined by ASTM D6730.
545. The method of claim 537, wherein from 60 to 95 percent by weight of hydrocarbons in the separated liquid stream have a carbon number from 8 to 13 as determined by ASTM D6730.
546. The method of claim 537, wherein separated liquid stream has at most 15 percent by weight naphthenes, at least 70 percent by weight total paraffins, at most 5 percent by weight olefins, and at most 30% by weight aromatics as determined by ASTM D6730.
547. The method of claim 537, wherein the separated liquid stream has a nitrogen content of at least 0.01% by weight as determined by ASTM D5762.
548. The method of claim 537, wherein the separated liquid stream has a sulfur content of at least 0.01% by weight as determined by ASTM D4294.
549. The method of claim 537, wherein the separated liquid stream has a total aromatic content of at most 30% by weight as determined by ASTM D6730.
550. The method of claim 537, wherein the separated liquid stream has a total paraffinic content of at least 70% by weight as determined by ASTM D6730.
551. The method of claim 537, wherein the distilled liquid stream has a sulfur content of at most 0.001% by weight as determined by ASTM D4294.
552. The method of claim 537, wherein the distilled liquid stream has a total aromatics content of at most 25% by volume as determined by ASTM D1319.
553. The method of claim 537, wherein the transportation fuel has a boiling range distribution between 140 C and 330 C as determined by ASTM D2887, an API
gravity between 37 and 51 as determined by ASTM D1298, a freezing point of at most -47 C as determined by ASTM
D5901; a viscosity of at most 8.0 mm 2/s at -20 C as determined by ASTM D445, a hydrogen content of at least 23.4% by weight as determined by ASTM D3343, an aromatics content of at most 25% by volume as determined by ASTM D1319, sulfur content of at most 0.3%
by weight as determined by ASTM D4294, a net heat of combustion of at least 42.8 MJ/kg as determined by ASTM D3338; and thermal oxidation stability properties of: a heat tube deposit of at most 3 and a change in pressure drop of at most 25 mm Hg as determined by ASTM D3241.
554. The method of claim 537, wherein at least one of the additives comprises corrosion inhibitor, lubricity improver, static dissipate additive, fuel system icing inhibitor, antioxidant, detergents, surfactants, friction modifiers, or mixtures thereof.
555. A hydrocarbon composition, comprising:
hydrocarbons having a boiling range distribution from about 165 C to about 260 C as determined by ASTM Method D5307, wherein the hydrocarbons have been obtained from an in situ heat treatment process;
a sulfur compound content of at most 30 ppm by weight as measured by ASTM
Method D4294; and a wear scar diameter of at most 0.85, as determined by ASTM Method D5001.
556. The method of claim 555, wherein the hydrocarbon composition is suitable use as transportation fuel.
557. The method of claim 555, wherein the hydrocarbon composition is suitable use as jet fuel.
558. A hydrocarbon composition produced by a method, comprising:
providing formation fluid from a subsurface in situ heat treatment process, wherein the formation fluid has a boiling range distribution between -5 C and 350 C as determined by ASTM Method D5307;
separating a liquid stream from the formation fluid;
hydrotreating the separated liquid stream; and distilling the hydrotreated liquid stream to produce a hydrocarbon composition stream, wherein the hydrocarbon composition has a boiling range distribution between 165 C and 260 C as determined by ASTM Method D5307, a wear scar diameter of at most 0.85 mm as determined by ASTM Method D5001, and a sulfur compound content of at most 30 ppm by weight as determined by ASTM Method 4294.
559. A method of producing a hydrocarbon composition, comprising:
providing formation fluid from a subsurface in situ heat treatment process, wherein the formation fluid has a boiling range distribution between -5 C and 350 C as determined by ASTM Method D5307;
separating a liquid stream from the formation fluid;
hydrotreating the separated liquid stream; and distilling the hydrotreated liquid stream to produce a distilled stream, wherein the distilled stream has a boiling range distribution between 165 C and 260 C as determined by ASTM Method D5307, a wear scar diameter of at most 0.85 mm as determined by ASTM
Method D5001, and a sulfur compound content of at most 30 ppm by weight as determined by ASTM Method 4294.
560. A method for treating a hydrocarbon containing formation, comprising:
providing heat to the formation;
producing heated fluid from the formation; and generating electricity from at least a portion of the heated fluid using a Kalina cycle.
561. The method of claim 560, wherein providing heat to the formation comprises heating the formation using a fireflood.
562. The method of claim 560, wherein providing heat to the formation comprises transferring heat to the formation from electrical resistance heaters.
563. The method of claim 560, wherein providing heat to the formation comprises transferring heat to the formation from subsurface gas burners.
564. The method of claim 560, wherein providing heat to the formation comprises transferring heat to the formation from fluid flowing through conduits positioned in the formation.
565. The method of claim 560, wherein the Kalina cycle comprises passing a rich working fluid stream from a separator to a turbine to generate electricity.
566. The method of claim 560, wherein the Kalina cycle comprises passing the heated fluid through a first heat exchanger to transfer heat to a first portion of a working fluid; passing a second portion of the working fluid to a second heat exchanger to transfer heat to a lean working fluid stream exiting a separator; and passing the first working fluid stream and the second working fluid stream to the separator.
567. The method of claim 560, wherein the Kalina cycle comprises passing the heated fluid through a heat exchanger to transfer heat to a working fluid; and then passing the working fluid to a separator.
568. The method of claim 560, wherein the heated fluid comprises fluid produced during an in situ heat treatment process.
569. The method of claim 560, wherein the heated fluid comprises fluid produced during a solution mining process.
570. The method of claim 560, further comprising using at least a portion of the electricity to power electrical resistance heaters in the formation, or in another formation.
571. The method of claim 560, further comprising using a least a portion of the electricity to power a refrigeration system for a barrier around a treatment area.
572. The method of claim 560, further comprising using a least a portion of the electricity to power one or more compressors that supply compressed gas to the formation.
573. The method of claim 560, wherein a working fluid of the Kalina cycle comprises aqueous ammonia.
574. The method of claim 560, wherein a working fluid of the Kalina cycle comprises alkanes.
575. The method of claim 560, wherein a working fluid of the Kalina cycle comprises hydrofluorocarbons.
576. The method of claim 560, wherein a working fluid of the Kalina cycle comprises alkanes and hydrofluorocarbons.
577. The method of claim 560, wherein at least a portion of heat transfer to a working fluid of the Kalina cycle takes place in the heated formation.
578. A system for generating electricity, comprising:

a plurality of heaters in the formation, the heaters configured to heat a portion of the portion;
a plurality of production wells, the production wells configured to remove heated formation fluid from the heated portion of the formation;
a Kalina cycle system coupled to one or more of the production wells, wherein heat from the heated formation fluid is used by the Kalina cycle system to generate electricity.
579. The system of claim 578, wherein at least a portion of a working fluid of the Kalina cycle is directed through a heated portion of the formation to result in the transfer of heat from the heated portion of the formation to the working fluid.
580. The system of claim 578, wherein the formation fluid comprises fluid produced during a solution mining process.
581. The system of claim 578, wherein the formation fluid comprises fluid produced during an in situ heat treatment process.
582. A method for forming a barrier around at least a portion of a treatment area in a subsurface formation, comprising:
introducing sulfur into one or more wellbores located inside a perimeter of a treatment area in the formation, wherein the treatment area has a permeability of at least 0.1 darcy; and allowing at least some of the sulfur to move towards portions of the formation cooler than the melting point of sulfur to solidify the sulfur in the formation to form a barrier.
583. The method of claim 582, wherein the treatment area has a permeability of at least I
darcy.
584. The method of claim 582, wherein the treatment area has a permeability of at least 10 darcy.
585. The method of claim 582, wherein the treatment area has a permeability of at least 100 darcy.
586. The method of claim 582, wherein the permeability of the treatment has been increased by a solution mining process.
587. The method of claim 582, wherein the permeability of the treatment has been increased by an in situ heat treatment process.
588. The method of claim 582, wherein the sulfur is provided as a liquid into the formation.
589. The method of claim 588, wherein the heat of the formation adjacent to the wellbore vaporizes the sulfur.
590. The method of claim 582, wherein the sulfur is provided as a vapor into the formation.
591. The method of claim 582, wherein the flow of sulfur is directed towards the perimeter of the treatment area.
592. The method of claim 582, wherein the wellbores through which sulfur is introduced into the formation are located near the perimeter of the treatment area.
593. The method of claim 582, wherein a low temperature barrier at least partially surrounding the treatment area enhances the solidification of the sulfur to form the barrier.
594. The method of claim 582, further comprising storing carbon dioxide in the treatment area.
595. A method of forming a barrier in a formation, comprising:
heating a portion of a formation adjacent to a plurality of wellbores to raise a temperature of the formation adjacent to the wellbores above a melting temperature of sulfur and below a pyrolysis temperature of hydrocarbons in the formation;
introducing molten sulfur into at least some of the wellbores; and allowing the sulfur to move outwards from the wellbores towards portions of the formation cooler than the melting temperature of sulfur so that the sulfur solidifies in the formation to form a barrier.
596. The method of claim 595, wherein at least one heater used to heat the portion of the formation adjacent the wellbores comprises a temperature limited heater.
597. The method of claim 595, further comprising solution mining a treatment area inside the barrier.
598. The method of claim 595, further comprising using an in situ heat treatment process on a treatment area inside the barrier.
599. The method of claim 595, further comprising storing carbon dioxide inside the barrier.
600. The method of claim 595, further comprising forming the barrier between a first barrier and a treatment area used to produce formation fluid from the formation.
601. The method of claim 595, wherein a temperature of the molten sulfur introduced into the formation is near the melting temperature of sulfur.
602. A method for providing acidic gas to a subsurface formation, comprising:
providing heat from one or more heaters to a portion of a subsurface formation;
producing fluids from the formation using a heat treatment process, wherein the produced fluids comprise one or more acidic gases; and introducing at least a portion of one of the acidic gases into the formation, or into another formation, through one or more wellbores at a pressure below a lithostatic pressure of the formation in which the acidic gas is introduced.
603. The method of claim 602, wherein at least a portion of the acidic gas comprises hydrogen sulfide and/or carbon dioxide.
604. The method of claim 602, wherein at least a portion of the introduced acidic gas comprises hydrogen sulfide and the hydrogen sulfide forms a sulfide layer on the surface of the walls of the wellbores.
605. The method of claim 604, wherein at least one of the acidic gases comprises carbon dioxide, and the method further comprising introducing the carbon dioxide into the sulfided wellbore.
606. The method of claim 602, wherein at least a portion of the acidic gas reacts in the formation.
607. The method of claim 602, wherein at least a portion of the acidic gas is sequestered in the formation.
608. The method of claim 602, wherein at least a portion of the acidic gas is introduced near the bottom of the saline aquifer.
609. The method of claim 602, wherein at least one of the heaters is a temperature limited heater.
610. The method of claim 602, wherein at least one of the heaters is an electrical heater.
611. A method for providing acidic gas to a subsurface formation, comprising:
providing heat from one or more heaters to a portion of a subsurface formation;
producing fluids from the formation using a heat treatment process, wherein the produced fluids comprise one or more acidic gases;
removing at least a portion of carbon dioxide from the acidic gases;
introducing at least a portion of the carbon dioxide into the formation, or into another formation, through one or more wellbores; and introducing a fluid in the wellbores used for carbon dioxide introduction to inhibit corrosion in the wellbores.
612. The method of claim 611, wherein at least a portion of the carbon dioxide reacts in the formation.
613. The method of claim 611, wherein at least a portion of the carbon dioxide is sequestered in the formation.
614. The method of claim 611, wherein the fluid comprises one or more corrosion inhibitors.
615. The method of claim 611, wherein the fluid comprises one or more polymers.
616. The method of claim 611, wherein the fluid comprises one or more surfactants.
617. The method of claim 611, wherein the fluid comprises one or more hydrocarbons.
618. The method of claim 611, wherein the fluid comprises one or more corrosion inhibitors, one or more surfactants, one or more hydrocarbons, one or more polymers or mixtures thereof.
619. A composition comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 5 percent to about 13 percent by weight nickel;
between about 3 percent and about 10 percent by weight copper;
from about 1 percent to about 10 percent by weight manganese;
from about 0.3 percent to about 1 percent by weight silicon;
from about 0.5 percent to about 1.5 percent by weight niobium;
from about 0.5 to about 2 percent by weight tungsten; and from about 38 percent to about 63 percent by weight iron.
620. The composition of claim 619, wherein the composition has a yield strength of greater than 35 ksi at about 800C.
621. The composition of claim 619, wherein the composition, after being annealed, has a yield strength at about 800 C that changes less than 20 percent as a result of being cold worked by twenty percent.
622. The composition of claim 619, further comprising from about 0.2 percent to about 0.5 percent by weight nitrogen.
623. The composition of claim 619, further comprising about 0.3 percent to about 1 percent by weight molybdenum.
624. The composition of claim 619, further comprising from about 0.08 percent to about 0.2 percent by weight carbon.
625. The composition of claim 619, wherein the composition comprises nanonitride precipitates.
626. The composition of claim 625, wherein the nanonitride precipitates comprise a majority of particles having maximum dimensions in the range of five to one hundred nanometers.
627. The composition of claim 625, wherein the composition further comprises nanocarbide precipitates.
628. The composition of claim 625, wherein the nanocarbide precipitates comprise particles having maximum dimensions in the range of five to two hundred nanometers.
629. The composition of claim 619, wherein the composition, when at about 800 C, has at least 3.25 percent by weight of precipitates.
630. The composition of claim 629, wherein at least two percent by weight of the precipitates present at about 800 C are Cu, M(C,N), M2(C,N) or M23C6 phases.
631. The composition of claim 629, wherein the composition has been annealed at an annealing temperature, and the composition comprises at least 1.5 percent by weight more Cu, M(C,N), M2(C,N) or M23C6 phases at 800C than at the annealing temperature.
632. The composition of claim 631, wherein the annealing temperature is at least 1250 C.
633. The composition of claim 631, wherein the annealing temperature is at between about 1300 C and the melting temperature of the composition.
634. The composition of claim 619, wherein the composition, when at about 800 C, has at least 4 percent by weight of precipitates.
635. The composition of claim 619, wherein the composition, when at about 800 C, has at least 8 percent by weight of precipitates.
636. A composition comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 5 percent to about 9 percent by weight nickel;
from about 1 percent to about 6 percent by weight copper;
from about 0.5 percent to about 1.5 percent by weight niobium;
from about 1 to about 10 percent by weight manganese;
from about 0.5 to about 1.5 percent by weight of tungsten;
from about 36 percent to about 74 percent by weight iron; and precipitates of nanonitrides, wherein the ratio of tungsten to copper is between about 1/10 and 10/1.
637. The composition of claim 636, wherein the ratio of copper to manganese is between about 1/5 and 5/1.
638. The composition of claim 636, wherein the nanonitride precipitates comprise a majority of particles having a maximum dimension of between five and one hundred nanometers.
639. The composition of claim 638, wherein the composition, when at about 800 C, has at least 3.25 percent by weight of precipitates.
640. The composition of claim 638, wherein the composition, when at about 800 C, has at least 4 percent by weight of precipitates.
641. The composition of claim 636, wherein at least 2 percent by weight of the precipitates present at 800C are Cu, M(C,N), M2(C,N) or M23C6 phases.
642. The composition of claim 636, wherein the composition has been subjected to cold work to an extent of at least about 10 percent.
643. The composition of claim 636, wherein the composition has been subjected to hot work to an extent of at least about ten percent.
644. The composition of claim 636, wherein the composition has been subjected to hot aging.
645. A heater system comprising:
a heat generating element; and a canister surrounding the heat generating element, wherein the canister is at least partially made of a material comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 5 percent to about 14 percent by weight nickel;
from about 1 percent to about 10 percent by weight copper;
from about 0.5 percent to about 1.5 percent by weight niobium;
from about 36 percent to about 70.5 percent by weight iron; and precipitates of nanonitrides.
646. The heater system of claim 645, wherein the heat generating element is an electrical powered heat generating element.
647. The heater system of claim 645, wherein the heat generating element is a hydrocarbon fuel burning element.
648. A method of heating a subterranean formation comprising:
positioning one or more heater systems in a subterranean formation, wherein at least one of the heater systems comprises:
a heat generating element; and a canister surrounding the heat generating element, wherein the canister is at least partially made of a material comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 5 percent to about 14 percent by weight nickel;
from about 1 percent to about 10 percent by weight copper;
from about 0.5 percent to about 1.5 percent by weight niobium; and from about 36 percent to about 70.5 percent by weight iron; and allowing heat from the heater system to heat at least a portion of the subterranean formation.
649. A system for heating a subterranean formation comprising a tubular, the tubular at least partially made from a material comprising:
from about 18 percent to about 22 percent by weight chromium;
from about 10 percent to about 14 percent by weight nickel;
from about 1 percent to about 10 percent by weight copper;
from about 0.5 percent to about 1.5 percent by weight niobium;

from about 36 percent to about 70.5 percent by weight iron; and precipitates of nanonitrides.
650. The system of claim 649, wherein a heating medium is circulated through the tubular to heat the subterranean formation.
651. The system of claim 650, wherein the heating medium comprises steam.
652. The system of claim 650, wherein the heating medium comprises carbon dioxide.
653. The system of claim 650, wherein the heating medium is heated at the surface by exchanging heat with helium.
654. The system of claim 653, wherein the helium is heated in a nuclear reactor.
655. The system of claim 649, wherein the system further comprises an electrically powered heating element as a source of heat.
656. The system of claim 649, wherein the tubular is fabricated by welding a rolled plate of material to form a tubular.
657. The system of claim 656, wherein the welding comprises laser welding.
658. The system of claim 656, wherein the welding comprises gas tungsten arc-welding.
659. A method of heating a subterranean formation, comprising:
positioning one or more heater systems in a subterranean formation, wherein at least one of the heater systems comprises a tubular and at least a portion of the tubular is made from a material comprising :
from about 18 percent to about 22 percent by weight chromium;
from about 5 percent to about 14 percent by weight nickel;
from about 1 percent to about 10 percent by weight copper;
from about 0.5 percent to about 1.5 percent by weight niobium; and from about 36 percent to about 70.5 percent by weight iron; and allowing heat from the heater system to heat at least a portion of the subterranean formation.
660. A composition, comprising:
from 18 percent to 22 percent by weight chromium;
from 11 percent to 14 percent by weight nickel;
at most 3 percent by weight copper;
from 1 percent to 10 percent by weight manganese;
at most 0.75 percent by weight silicon;
from 0.5 percent to 1.5 percent by weight niobium;
from 0.5 to 1.5 percent by weight tungsten; and wherein the material is capable of being cold-worked to form a wrought material.
661. The composition of claim 660, wherein the material is capable of being hot-worked.
662. The composition of claim 660, further comprising from 0.07 percent to 0.15 percent by weight carbon.
663. The composition of claim 660, further comprising from 0.2 percent to 0.5 percent by weight nitrogen.
664. The composition of claim 660, further comprising iron.
665. A system for electrically insulating an overburden portion of a heater wellbore, comprising:
the heater wellbore located in a subsurface formation; and an electrically insulating casing located in the overburden portion of the heater wellbore, the casing comprising at least one non-ferromagnetic material such that ferromagnetic effects are inhibited in the casing.
666. The system of claim 665, wherein the non-ferromagnetic material comprises non-metallic material.
667. The system of claim 665, wherein the non-ferromagnetic material comprises fiberglass.
668. The system of claim 665, wherein the non-ferromagnetic material comprises high-density polyethylene (HDPE).
669. The system of claim 665, wherein the casing consists of non-ferromagnetic material.
670. The system of claim 665, wherein the casing comprises a ferromagnetic metal coupled to the inside diameter of a non-ferromagnetic metal such that ferromagnetic effects are inhibited in the casing.
671. The system of claim 670, wherein the ferromagnetic metal comprises carbon steel and the non-ferromagnetic metal comprises copper.
672. The system of claim 665, further comprising a heater located in the heater wellbore, wherein the heater is configured to provide heat to at least a portion of the subsurface formation.
673. A method for electrically insulating an overburden portion of a heater wellbore, comprising:
locating an electrically casing in the overburden portion of the heater wellbore in a subsurface formation, wherein the casing comprises at least one non-ferromagnetic material that inhibits ferromagnetic effects in the overburden portion of the heater wellbore.
674. The method of claim 673, wherein the non-ferromagnetic material comprises non-metallic material.
675. The method of claim 673, wherein the non-ferromagnetic material comprises fiberglass.
676. The method of claim 673, wherein the non-ferromagnetic material comprises high-density polyethylene (HDPE).
677. The method of claim 673, wherein the casing consists of non-ferromagnetic material.
678. The method of claim 673, wherein the casing comprises a ferromagnetic metal coupled to the inside diameter of a non-ferromagnetic metal such that ferromagnetic effects are inhibited in the casing.
679. The method of claim 678, wherein the ferromagnetic metal comprises carbon steel and the non-ferromagnetic metal comprises copper.
680. The method of claim 673, further comprising installing a heater in the heater wellbore.
681. The method of claim 673, further comprising providing heat to at least a portion of the subsurface formation with a heater located in the heater wellbore.
682. The method of claim 673, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with a heater located in the heater wellbore such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation.
683. The method of claim 673, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with a heater located in the heater wellbore such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, and producing a fluid from the formation.
684. The method of claim 673, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with a heater located in the heater wellbore such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, and producing a composition comprising hydrocarbons from the formation.
685. The method of claim 673, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with a heater located in the heater wellbore such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, producing hydrocarbons from the formation, and producing a transportation fuel from hydrocarbons produced from the formation.
686. A wellhead for coupling to a heater located in a wellbore in a subsurface formation, comprising:
the heater located in the wellbore in the subsurface formation; and a wellhead coupled to the heater, the wellhead being configured to electrically couple the heater to one or more surface electrical components, and wherein the wellhead comprises at least one non-ferromagnetic material such that ferromagnetic effects are inhibited in the wellhead.
687. The wellhead of claim 686, wherein the non-ferromagnetic material comprises non-metallic material.
688. The wellhead of claim 686, wherein the non-ferromagnetic material comprises fiberglass.
689. The wellhead of claim 686, wherein the non-ferromagnetic material comprises high-density polyethylene (HDPE).
690. The wellhead of claim 686, wherein the wellhead consists of non-ferromagnetic material.
691. The wellhead of claim 686, wherein the wellhead comprises a ferromagnetic metal coupled to a non-ferromagnetic metal such that ferromagnetic effects are inhibited in the wellhead.
692. The wellhead of claim 691, wherein the ferromagnetic metal comprises carbon steel and the non-ferromagnetic metal comprises copper.
693. The wellhead of claim 686, further comprising a heater located in the heater wellbore, wherein the heater is configured to provide heat to at least a portion of the subsurface formation.
694. A method for coupling to a heater in a subsurface wellbore, comprising:
coupling a wellhead to the heater in the wellbore, wherein the wellhead comprises at least one non-ferromagnetic material so that ferromagnetic effects are inhibited in the wellhead.
695. The method of claim 694, wherein the non-ferromagnetic material comprises non-metallic material.
696. The method of claim 694, wherein the non-ferromagnetic material comprises fiberglass.
697. The method of claim 694, wherein the non-ferromagnetic material comprises high-density polyethylene (HDPE).
698. The method of claim 694, wherein the wellhead consists of non-ferromagnetic material.
699. The method of claim 694, wherein the wellhead comprises a ferromagnetic metal coupled to the inside diameter of a non-ferromagnetic metal such that ferromagnetic effects are inhibited in the casing.
700. The method of claim 699, wherein the ferromagnetic metal comprises carbon steel and the non-ferromagnetic metal comprises copper.
701. The method of claim 694, further comprising installing the heater in the heater wellbore and coupling the heater to the wellhead.
702. The method of claim 694, further comprising electrically coupling one or more surface electrical components to the heater through the wellhead.
703. The method of claim 694, further comprising providing heat to at least a portion of the subsurface formation with the heater.
704. The method of claim 694, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with the heater such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation.
705. The method of claim 694, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with the heater such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, and producing a fluid from the formation.
706. The method of claim 694, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with the heater such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, and producing a composition comprising hydrocarbons from the formation.
707. The method of claim 694, wherein the subsurface formation comprises a hydrocarbon containing formation, the method further comprising providing heat to at least a portion of the formation with the heater such that at least some hydrocarbons are pyrolyzed and/or mobilized in the formation, producing hydrocarbons from the formation, and producing a transportation fuel from hydrocarbons produced from the formation.
708. A system for providing power to one or more subsurface heaters, comprising:
an intermittent power source;
a transformer coupled to the intermittent power source, the transformer being configured to transform power from the intermittent power source to power with appropriate operating parameters for the heaters; and a tap controller coupled to the transformer, the tap controller being configured to monitor and control the transformer so that a constant voltage is provided to the heaters from the transformer regardless of the load of the heaters and the power output provided by the intermittent power source.
709. The system of claim 708, further comprising a control system coupled to the tap controller, the control system being configured to operate the tap controller.
710. The system of claim 708, further comprising a control system coupled to the tap controller, the control system being configured to operate the tap controller using at least one predictive algorithm.
711. The system of claim 708, further comprising one or more sensors coupled to the system, the sensors being configured to monitor one or more operating parameters of the heaters, the intermittent power source, and/or the transformer.
712. The system of claim 708, further comprising:
a control system coupled to the tap controller; and one or more sensors coupled to the system configured to monitor one or more operating parameters of the heaters, the intermittent power source, and/or the transformer;
wherein the control system is configured to operate the tap controller based on operating parameter data collected from the sensors.
713. The system of claim 708, wherein the tap controller is configured to store, for future use, load provided by the transformer that is in excess of the load required by the heaters.
714. The system of claim 708, wherein the intermittent power source comprises a windmill.
715. The system of claim 708, wherein the intermittent power source comprises a gas turbine.
716. The system of claim 708, wherein the tap controller is configured to control power output in a range between about 5 megavolt amps (MVA) and about 500 MVA.
717. The system of claim 708, wherein the tap controller is configured to automatically control the power provided to the heaters.
718. The system of claim 708, wherein the tap controller is configured to automatically control the power provided to the heaters to within about 20% of the power required by the heaters.
719. A method for controlling power provided to one or more subsurface heaters from an intermittent power source, comprising:
monitoring one or more operating parameters of the heaters, the intermittent power source, and a transformer coupled to the intermittent power source that transforms power from the intermittent power source to power with appropriate operating parameters for the heaters;
and controlling the power output of the transformer so that a constant voltage is provided to the heaters regardless of the load of the heaters and the power output provided by the intermittent power source.
720. The method of claim 719, further comprising controlling the power output of the transformer using a tap controller coupled to the transformer and the heaters.
721. The method of claim 719, further comprising controlling the power output of the transformer using at least one predictive algorithm.
722. The method of claim 719, further comprising controlling the power output of the transformer using at least one predictive algorithm that assesses the monitored operating parameters of the heaters, the intermittent power source, and the transformer.
723. The method of claim 719, further comprising monitoring the operating parameters of the heaters, the intermittent power source, and the transformer using one or more sensors coupled to the heaters, the intermittent power source, and the transformer.
724. The method of claim 719, further comprising storing, for future use, load provided by the transformer that is in excess of the load required by the heaters.
725. The method of claim 719, wherein the intermittent power source comprises a windmill.
726. The method of claim 719, wherein the intermittent power source comprises a gas turbine.
727. The method of claim 719, further comprising controlling the power output of the transformer in a range between about 5 megavolt amps (MVA) and about 500 MVA.
728. The method of claim 719, further comprising automatically controlling the power provided to the heaters.
729. The method of claim 719, further comprising automatically controlling the power provided to the heaters to within about 20% of the power required by the heaters.
730. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation overburden while allowing the portion of the formation to heat to a selected average temperature of at least about 280 C and at most about 300 C; and reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the selected average temperature.
731. The method of claim 730, wherein the fracture pressure is about 15000 kPa.
732. The method of claim 730, wherein the selected pressure is a pressure below which substantial hydrocarbon coking in the formation occurs when the average temperature in the formation is less than 300 C.
733. The method of claim 730, wherein the selected pressure is between about 100 kPa and about 1000 kPa.
734. The method of claim 730, wherein the selected pressure is between about 200 kPa and about 800 kPa.
735. The method of claim 730, further comprising producing fluids from the formation.
736. The method of claim 730, further comprising producing fluids from the formation to maintain the pressure below the fracture pressure.
737. The method of claim 730, wherein the selected average temperature is between about 285 C and about 295 C.
738. The method of claim 730, further comprising providing a drive fluid to the formation.
739. The method of claim 730, further comprising providing steam to the formation.
740. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation overburden while allowing the portion of the formation to heat to a selected average temperature range;
producing at least some fluids from the formation to maintain the pressure below the fracture pressure; and assessing the average temperature in the portion by analyzing at least some of the produced fluids.
741. The method of claim 740, further reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the selected average temperature range.
742. The method of claim 740, wherein the selected average temperature range comprises a temperature range from about 280 C to about 300 C.
743. The method of claim 740, wherein the selected average temperature range is below the temperature at which substantial coking of hydrocarbons occurs in the formation.
744. The method of claim 740, further comprising providing steam to the formation.
745. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation overburden by producing at least some fluid from the formation;
assessing the hydrocarbon isomer shift of at least a portion of the fluid produced from the formation; and reducing the pressure in the formation to a selected pressure when the assessed hydrocarbon isomer shift reaches a selected value.
746. The method of claim 745, wherein the average temperature in the portion is based on, at least in part, the hydrocarbon isomer shift.
747. The method of claim 745, wherein the hydrocarbon isomer shift comprises n-butane-.delta.13C4 percentage versus propane- .delta.13C3 percentage.
748. The method of claim 745, wherein the hydrocarbon isomer shift comprises n-pentane-.delta.13C5 percentage versus propane- .delta.13C3 percentage.
749. The method of claim 745, wherein the hydrocarbon isomer shift comprises n-pentane-.delta.13C5 percentage (.gamma.-axis) versus n-butane- .delta.13C4 percentage.
750. The method of claim 745, wherein the hydrocarbon isomer shift comprises i-pentane-.delta.13C5 percentage (.gamma.-axis) versus i-butane- .delta.13C4 percentage.
751. The method of claim 745, wherein the selected value of the hydrocarbon isomer shift corresponds to an average temperature between about 280 C and about 300 C.
752. The method of claim 745, further comprising heating the formation after reducing the pressure.
753. The method of claim 745, further comprising producing fluids from the formation after reducing the pressure.
754. The method of claim 745, wherein the selected pressure is a pressure below which substantial hydrocarbon coking in the formation occurs when the average temperature in the formation is less than 300 C.
755. The method of claim 745, further comprising providing steam to the formation.
756. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation overburden by producing at least some fluid from the formation;
assessing the weight percentage of saturates in at least a portion of the fluid produced from the formation; and reducing the pressure in the formation to a selected pressure when the assessed weight percentage of saturates reaches a selected value.
757. The method of claim 756, wherein the average temperature in the portion is assessed base on, at least in part, the weight percentage of saturates.
758. The method of claim 756, wherein the selected value of the weight percentage of saturates corresponds to an average temperature between about 280 C
and about 300 C.
759. The method of claim 756, wherein the selected value of the weight percentage of saturates is about 30%.
760. The method of claim 756, further comprising heating the formation after reducing the pressure.
761. The method of claim 756, further comprising producing fluids from the formation after reducing the pressure.
762. The method of claim 756, wherein the selected pressure is a pressure below which substantial hydrocarbon coking in the formation occurs when the average temperature in the formation is less than 300 C.
763. The method of claim 756, further comprising providing steam to the formation.
764. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation overburden by producing at least some fluid from the formation;
assessing the weight percentage of n-C7 in at least a portion of the fluid produced from the formation; and reducing the pressure in the formation to a selected pressure when the assessed n-C7 reaches a selected value.
765. The method of claim 764, wherein the average temperature in the portion is assessed based on, at least in part, the weight percentage of n-C7.
766. The method of claim 764, wherein the selected value of the weight percentage of n-C7 corresponds to an average temperature between 280 C and 300 C.
767. The method of claim 764, wherein the selected value of the weight percentage of n-C7 is about 60%.
768. The method of claim 764, further comprising heating the formation after reducing the pressure.
769. The method of claim 764, further comprising producing fluids from the formation after reducing the pressure.
770. The method of claim 764, wherein the selected pressure is a pressure below which substantial hydrocarbon coking in the formation occurs when the average temperature in the formation is less than 300 C.
771. The method of claim 764, further comprising providing steam to the formation.
772. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
assessing a viscosity of one or more zones of the hydrocarbon layer;
varying a number of production wells in the zones based on the assessed viscosities, wherein the number of production wells in a first zone of the formation is less than the number of production wells in a second zone of the formation if the viscosity in the first zone is greater than the viscosity in the second zone; and producing fluids from the formation through the production wells.
773. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
assessing a viscosity of one or more zones of the hydrocarbon layer;
varying the heating rates in the zones based on the assessed viscosities, wherein the heating rate in a first zone of the formation is less than the heating rate in a second zone of the formation if the viscosity in the first zone is greater than the viscosity in the second zone; and producing fluids from the formation.
774. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
assessing a viscosity of one or more zones of the hydrocarbon layer;
varying the heater spacing in the zones based on the assessed viscosities, wherein the heater spacing in a first zone of the formation is denser than the heater spacing in a second zone of the formation if the viscosity in the first zone is greater than the viscosity in the second zone;
allowing the heat to transfer from the heaters to the zones in the formation;
and producing fluids from one or more openings located in at least one selected zone to maintain a pressure in the selected zone below a selected pressure.
775. The method of claim 774, wherein the selected zone is the first zone of the formation.
776. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation; and producing fluids from the formation through at least one production well that is located in at least two zones in the formation, the first zone having an initial permeability of at least 1 darcy, the second zone having an initial of at most 0.1 darcy and the two zones are separated by a substantially impermeable barrier.
777. The method of claim 776, wherein the substantially impermeable barrier has an initial permeability of at most 10 darcy.
778. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
wherein heat is transferred to at least two zones in the formation, at least two of the zones being separated by a substantially impermeable barrier, and one or more holes have been formed to connect the zones through the substantially impermeable barrier; and producing fluids from the formation.
779. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation;
maintaining a pressure in the formation below a fracture pressure of the formation while allowing the portion of the formation to heat to a selected average temperature of at least about 280 C and at most about 300 C;
reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the selected average temperature;
producing fluids from the formation;
turning off two or more of the heaters after a selected time; and continuing producing fluids from the formation after the heaters are turned off.
780. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation such that a drive fluid is produced in situ in the formation;
allowing the drive fluid to move at least some mobilized hydrocarbons from a first portion of the formation to a second portion of the formation; and producing at least some of the mobilized fluids from the formation.
781. The method of claim 780, wherein the drive fluid is steam.
782. A method for treating a tar sands formation, comprising:
providing a drive fluid to a first hydrocarbon containing layer of the formation to mobilize at least some hydrocarbons in the first layer;
allowing at least some of the mobilized hydrocarbons to flow into a second hydrocarbon containing layer of the formation;
providing heat to the second layer from one or more heaters located in the second layer;
and producing at least some hydrocarbons from the second layer of the formation.
783. The method of claim 782, further comprising providing the drive fluid to a third hydrocarbon containing layer of the formation to mobilize at least some hydrocarbons in the third layer.
784. The method of claim 782, further comprising providing the drive fluid to a third hydrocarbon containing layer of the formation to mobilize at least some hydrocarbons in the third layer, and allowing at least some of the mobilized hydrocarbons from the third layer to flow into the second layer.
785. The method of claim 782, wherein the first layer is above the second layer.
786. The method of claim 782, wherein the first layer is below the second layer.
787. The method of claim 782, further comprising producing hydrocarbons from the first layer.
788. The method of claim 782, further comprising using the produced hydrocarbons in a steam and electricity generation facility, wherein the facility provides steam as the drive fluid to the first layer of the formation, and electricity for at least some of the heaters in the second layer.
789. A method for treating a tar sands formation, comprising:
providing a drive fluid to a hydrocarbon containing layer of the formation to mobilize at least some hydrocarbons in the first layer;
producing at least some hydrocarbons from the layer;
providing heat to the layer from one or more heaters located in the formation;
and producing at least some upgraded hydrocarbons from the layer of the formation, the upgraded hydrocarbons comprising at least some hydrocarbons that are upgraded compared to hydrocarbons produced by using the drive fluid.
790. The method of claim 789, wherein the drive fluid is steam.
791. A method for treating a tar sands formation, comprising:

providing heat to a hydrocarbon containing layer from one or more heaters located in the formation, wherein the hydrocarbon containing layer has been previously treated using a steam injection and production process; and producing at least some hydrocarbons from the layer of the formation, the produced hydrocarbons comprising at least some hydrocarbons that are upgraded compared to hydrocarbons produced by the steam injection and production process.
792. A heating system for a subsurface formation, comprising:
a canister located in an opening in the subsurface formation;
a heater located in the canister, wherein the heater comprises:
an electrical conductor;
an insulation layer at least partially surrounding the electrical conductor;
an electrically conductive sheath at least partially surrounding the insulation layer; and a metal located in the canister outside of the heater, the metal being configured to melt at a temperature above about 100 C so that the metal is a molten metal in the canister at operating temperatures of the heater.
793. The system of claim 792, wherein the heater is configured to be buoyant in the molten metal.
794. The system of claim 792, wherein the metal comprises, before being molten, metal particles, pellets, or spheres in the canister.
795. The system of claim 792, wherein the metal comprises tin.
796. The system of claim 792, wherein the electrical conductor comprises ferromagnetic material that operates as a temperature limited heater.
797. The system of claim 792, wherein the metal, when molten, is configured to conduct electricity between the canister and the electrically conductive sheath.
798. A heating system for a subsurface formation, comprising:
a canister located in an opening in the subsurface formation;
a heater located in the canister, wherein the heater comprises:
an electrical conductor;
an insulation layer at least partially surrounding the electrical conductor;
an electrically conductive sheath at least partially surrounding the insulation layer; and a metal salt located in the canister outside of the heater, the metal salt being configured to melt at a temperature above about 100 C so that the metal salt is a molten liquid in the canister at operating temperatures of the heater.
799. The system of claim 798, wherein the heater is configured to be buoyant in the molten liquid.
800. The system of claim 798, wherein the electrical conductor comprises ferromagnetic material that operates as a temperature limited heater.
801. A heating system for a subsurface formation, comprising:
a sealed conduit positioned in an opening in the formation, wherein a heat transfer fluid is positioned in the conduit;
a heat source configured to provide heat to a portion of the sealed conduit to change phase of the heat transfer fluid from a liquid to a vapor; and wherein the vapor in the sealed conduit rises in the sealed conduit, condenses to transfer heat to the formation and returns to the portion as a liquid.
802. The heating system of claim 801, wherein the heat source comprises a downhole gas burner.
803. The heating system of claim 801, wherein the heat source comprises an electrical heater.
804. The heating system of claim 801, wherein the heat transfer fluid comprises a molten metal.
805. The heating system of claim 801, wherein the heat transfer fluid comprises a molten metal salt.
806. A system for heating a subsurface formation, comprising:
a plurality of heaters positioned in the formation, the plurality of heaters configured to heat a portion of the formation; and a plurality of heat pipes positioned in the heated portion, wherein at least one of the heat pipes comprises a liquid heating portion, wherein heat from one or more of the plurality of heaters is configured to provide heat to the liquid heating portion sufficient to vaporize at least a portion of a liquid in the heat pipe, wherein the vapor rises in the heat pipe, condenses in the heat pipe and transfers heat to the formation, and wherein condensed fluid flows back to the liquid heating portion.
807. A heating system for a subsurface formation, comprising:
a first heater configuration, comprising:
a conduit located in a first opening in the subsurface formation;
three electrical conductors located in the conduit;

a return conductor located inside the conduit, the return conductor being electrically coupled to the ends of the electrical conductors distal from the surface of the formation; and insulation located inside the conduit, the insulation being configured to electrically isolate the three electrical conductors, the return conductor, and the conduit.
808. The system of claim 807, wherein each of the electrical conductors is coupled to one phase of a single, three-phase wye transformer.
809. The system of claim 807, wherein the return conductor is coupled to the neutral of a single, three-phase wye transformer.
810. The system of claim 807, wherein each of the electrical conductors is coupled to one phase of a single, three-phase wye transformer, and the return conductor is coupled to the neutral of a single, three-phase wye transformer.
811. The system of claim 810, further comprising at least 4 additional heater configurations coupled to the single, three-phase wye transformer.
812. The system of claim 810, further comprising at least 10 additional heater configurations coupled to the single, three-phase wye transformer.
813. The system of claim 810, further comprising at least 25 additional heater configurations coupled to the single, three-phase wye transformer.
814. The system of claim 807, further comprising a second heater configuration, comprising:
a conduit located in a second opening in the subsurface formation;
three electrical conductors located in the conduit;
a return conductor located inside the conduit, the return conductor being electrically coupled to the ends of the electrical conductors distal from the surface of the formation; and insulation located inside the conduit, the insulation being configured to electrically isolate the three electrical conductors, the return conductor, and the conduit;
wherein the first heater configuration and the second heater configuration are electrically coupled to a single, three-phase wye transformer.
815. The system of claim 814, further comprising a third heater configuration, comprising:
a conduit located in a third opening in the subsurface formation;
three electrical conductors located in the conduit;
a return conductor located inside the conduit, the return conductor being electrically coupled to the ends of the electrical conductors distal from the surface of the formation; and insulation located inside the conduit, the insulation being configured to electrically isolate the three electrical conductors, the return conductor, and the conduit;
wherein the first heater configuration, the second heater configuration, and the third heater configuration are electrically coupled to the single, three-phase wye transformer.
816. The system of claim 807, wherein the electrical conductors comprise resistive heating portions located in a hydrocarbon layer in the formation, the hydrocarbon layer being configured to be heated.
817. The system of claim 807, wherein the electrical conductors comprise resistive heating portions located in a hydrocarbon layer in the formation, and a more electrically conductive portion located in an overburden section of the formation.
818. The system of claim 807, further comprising at least one additional substantially identical heating system located in an additional opening in the subsurface formation, wherein all the heating systems are electrically coupled to a single, three-phase transformer with each of the electrical conductors in each heating system being coupled to one phase of a single, three-phase wye transformer, and the return conductors of each heating system being coupled to the neutral of the single, three-phase wye transformer.
819. The system of claim 807, wherein the electrical conductors are at least partially surrounded by an insulation layer and an electrically conductive sheath, the sheath at least partially surrounding the insulation layer.
820. The system of claim 807, wherein the insulation comprises two or more layers of insulation in the conduit.
821. The system of claim 807, wherein the electrical conductors are the cores of insulated conductor heaters.
822. The system of claim 807, further comprising an outer tubular in the first opening, the first heater configuration being located in the outer tubular.
823. A heating system for a subsurface formation, comprising:
a three-phase wye transformer;
at least five heaters, each heater comprising:
a conduit located in a first opening in the subsurface formation;
three electrical conductors located in the conduit, each electrical conductor being electrically coupled to one phase of the transformer;
a return conductor located inside the conduit, the return conductor being electrically coupled to the ends of the electrical conductors distal from the surface of the formation, and the return conductor being electrically coupled to the neutral of the transformer; and insulation located inside the conduit, the insulation being configured to electrically isolate the three electrical conductors, the return conductor, and the conduit.
824. A method for making a heater for a subsurface formation, comprising:
coupling three heaters and a return conductor together, each of the three heaters comprising:
an electrical conductor;
an insulation layer at least partially surrounding the electrical conductor;
coupling additional insulation to the outside of the three heaters and the return conductor;
forming a conduit around the additional insulation, the three heaters, and the return conductor; and compacting the conduit so that against the additional insulation.
825. The method of claim 824, wherein the conduit is formed by rolling a metal plate into a tubular shape around the additional insulation layer, the three heaters, and the return conductor, and welding the lengthwise ends of the plate to form a tubular.
826. The method of claim 824, wherein the additional insulation comprises one or more preformed blocks of insulation.
827. A heating system for a subsurface formation, comprising:
a plurality of substantially horizontally oriented or inclined heater sections located in a hydrocarbon layer in the formation, wherein at least two of the heater sections are substantially parallel to each other in at least a majority of the hydrocarbon layer; and wherein the ends of at least two of the heater sections in the hydrocarbon layer are electrically coupled to a substantially horizontal, or inclined, electrical conductor oriented substantially perpendicular to the ends of the at least two heater sections.
828. The system of claim 827, wherein the single conductor is a neutral or a return for heater sections.
829. The system of claim 827, wherein the at least two heater sections are electrically coupled in parallel.
830. The system of claim 827, wherein the at least two heater sections are electrically coupled in series.
831. The system of claim 827, wherein the ends of the at least two heater sections are coupled to the single conductor using a mousetrap coupling.
832. The system of claim 827, wherein the ends of the at least two heater sections are coupled to the single conductor using molten metal.
833. The system of claim 827, wherein the ends of the at least two heater sections are coupled to the single conductor using explosive bonding.
834. The system of claim 827, wherein the single conductor is a tubular into which the ends of the at least two heater sections insert.
835. A method, comprising:
forming a first wellbore in the formation, wherein a portion of the wellbore is oriented substantially horizontally or at an incline;
positioning an electrical conductor in the first wellbore;
forming at least two additional wellbores in the formation, wherein ends of the additional wellbores intersect with the first wellbore, and wherein at least a majority of a section of the first additional wellbore that passes through a hydrocarbon layer to be heat treated by an in situ heat treatment process is substantially parallel to at least a majority of a section of the second additional wellbore that passes through the hydrocarbon layer;
placing a heater section in at least one of the additional wellbores; and coupling the heater section to the conductor in the first wellbore.
836. A method for treating a nahcolite containing subsurface formation, comprising:
removing water from a saline zone in or near the formation;
heating the removed water using a steam and electricity cogeneration facility;

providing the heated water to the nahcolite containing formation;
producing a fluid from the nahcolite containing formation, the fluid comprising at least some dissolved nahcolite; and providing at least some of the fluid to the saline zone.
837. The method of claim 836, wherein the saline zone is up dip from the nahcolite containing formation.
838. The method of claim 836, further comprising treating the nahcolite containing formation using an in situ heat treatment process after removing at least some of the nahcolite from the formation.
839. The method of claim 836, further comprising using at least some of the heat of the produced fluid to heat the removed water in the steam and electricity cogeneration facility.
840. The method of claim 836, further comprising storing the fluid in the saline zone.
841. An in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising:

one or more wellbores in the formation;
one or more oxidizers positioned in at least one of the wellbores;
a nuclear reactor configured to provide electricity; and wherein at least a portion of the electricity provided by the nuclear reactor is used to pressurize fluids provided to at least one of the oxidizers.
842. The system of claim 841, wherein the fluid is oxidizing fluid.
843. The system of claim 841, wherein the fluid is oxidizer fuel.
844. A method of heating a portion of a subsurface formation, comprising:
generating electricity using a nuclear reactor;
using at least a portion of the electricity to compress an oxidant stream;
providing the oxidant stream and a fuel stream to one or more wellbores; and reacting the oxidant and the fuel stream in oxidizers in one or more of the wellbores to generate heat, wherein at least a portion of the generated heat transfers to the formation.
845. The method of claim 844, wherein the oxidant stream comprises air.
846. The method of claim 844, further comprising using at least a portion of the electricity to compress the fuel.
847. A method of heating a portion of a subsurface formation, comprising:
introducing an oxidant into a wellbore through a first conduit;
introducing coal and a carrier gas into the wellbore in a second conduit;
passing a portion of the oxidant through one or more critical flow orifices to mix the oxidant with the coal at selected locations; and reacting the mixture of the coal and the oxidant to generate heat, wherein a portion of the generated heat transfers to the formation.
848. The method of claim 847, wherein the first conduit is positioned in the second conduit.
849. The method of claim 847, wherein the second conduit is positioned in the first conduit.
850. The method of claim 847, wherein the carrier gas comprises carbon dioxide.
851. The method of claim 847, wherein the carrier gas comprises nitrogen.
852. The method of claim 847, further comprising removing combustion gases from the formation through a third conduit, and wherein flow of combustion gases through the third conduit is countercurrent to flow of oxidant in the first conduit.
853. The method of claim 847, further comprising shielding at least one reaction zone where coal and oxidant react to stabilize the reaction zone.
854. A method of heating a portion of a subsurface formation, comprising:
introducing an oxidant into a wellbore through a first conduit;

introducing coal and a carrier gas into the wellbore in a second conduit;
passing a portion of the coal and the carrier gas through one or more critical flow orifices to mix the coal and the carrier gas with oxidant at selected locations; and reacting the mixture of the coal and the oxidant to generate heat, wherein a portion of the generated heat transfers to the formation.
855. The method of claim 854, wherein the first conduit is positioned in the second conduit.
856. The method of claim 854, wherein the second conduit is positioned in the first conduit.
857. The method of claim 854, wherein the carrier gas comprises carbon dioxide.
858. The method of claim 854, wherein the carrier gas comprises nitrogen.
859. The method of claim 854, further comprising removing combustion gases from the formation through a third conduit, and wherein flow of combustion gases through the third conduit is countercurrent to flow of oxidant in the first conduit.
860. The method of claim 854, further comprising shielding at least one reaction zone where coal and oxidant react to stabilize the reaction zone.
861. A heater assembly for heating a subsurface formation, comprising:
an oxidant conduit, wherein the oxidant conduit is configured to supply an oxidizing fluid; and a fuel conduit, wherein the fuel conduit is configured to supply a fuel fluid comprising pulverized coal.
862. A heater assembly for heating a subsurface formation, comprising:
an oxidant conduit, wherein the oxidant conduit is configured to supply an oxidizing fluid; and a fuel conduit, wherein the fuel conduit is configured to supply a fuel fluid comprising coal suspended in a carrier gas.
863. The assembly of claim 862, wherein the oxidant conduit comprises an inner conduit positioned in the fuel conduit.
864. The assembly of claim 862, wherein the fuel conduit comprises an inner conduit positioned in the oxidant conduit.
865. The assembly of claim 862, wherein the fuel conduit comprises an inner conduit positioned in the oxidant conduit, and wherein the fuel fluid is delivered at a higher pressure than the oxidant fluid.
866. The assembly of claim 862, wherein the fuel conduit comprises an inner conduit positioned in the oxidant conduit, and wherein the oxidant fluid is delivered at a higher pressure than the fuel fluid.
867. The assembly of claim 862, wherein the coal comprises pulverized coal.
868. The assembly of claim 862, wherein the carrier gas comprises a non-oxidizing gas.
869. The assembly of claim 862, wherein the carrier gas comprises a non-oxidizing gas comprising carbon dioxide gas and/or nitrogen gas.
870. The assembly of claim 862, wherein the fuel conduit comprises two or more heat shields coupled to the fuel conduit.
871. The assembly of claim 862, wherein the fuel conduit comprises two or more critical flow orifices.
872. The assembly of claim 862, wherein the oxidizing fluid comprises oxygen.
873. The assembly of claim 862, wherein the oxidizing fluid comprises air.
874. The assembly of claim 862, wherein the oxidizing fluid comprises oxygen-enriched air.
875. The assembly of claim 862, wherein the oxidant conduit comprises two or more critical flow orifices.
876. A method of heating a subsurface formation, comprising:
supplying an oxidizing fluid using an oxidant conduit to a subsurface formation; and supplying a fuel fluid using a fuel conduit to a subsurface formation, wherein the fuel fluid comprises coal suspended in a carrier fluid.
877. A method of suspending heaters in a well, comprising:
providing a first heater in a first opening and a second heater in a second opening, wherein the first and second openings are in a wellhead positioned over a well;
activating a movement control mechanism coupled to the wellhead;
inhibiting movement of the first and second heaters in a direction into the well using the activated movement control mechanism; and inhibiting movement of the first and second heaters in a direction out of the well using the activated movement control mechanism.
878. The method of claim 877, wherein the movement control mechanism comprises a two-way slip mechanism.
879. A system configured to suspend heaters in a well, comprising:
a wellhead positioned over a well;
a movement control mechanism positionable in the wellhead, wherein the movement control mechanism comprises a first opening and a second opening;
a first heater positionable in the first opening; and a second heater positionable in the second opening;

wherein the movement control mechanism is configured, when activated, to inhibit movement of the first and second heaters in a first direction into the well, and wherein the movement control mechanism is configured, when activated, to inhibit movement of the first and second heaters in a second direction out of the well.
880. The system of claim 879, wherein the movement control mechanism comprises a two-way slip mechanism.
881. A method of producing hydrogen, comprising:
heating a subsurface formation using an in situ heat treatment process;
producing fluid from the heated formation; and gasifying at least a portion of the fluid stream to produce hydrogen.
882. The method of claim 881, wherein gasifying comprises heating the formation fluid in the presence of a catalyst to produce the hydrogen stream.
883. The method of claim 881, wherein gasifying comprises heating the formation fluid in the presence of a catalyst and steam to produce the hydrogen stream.
884. The method of claim 881, further comprising introducing the hydrogen into the subsurface.
885. The method of claim 881, wherein the hydrogen stream comprises carbon dioxide and the method further comprises separating the carbon dioxide from the gas stream and sequestering the carbon dioxide in a portion of the subsurface formation.
886. A method for making coiled tubing and transporting such coiled tubing to a well, comprising:
making coiled tubing at a coiled tubing manufacturing site coupled to a coiled tubing transportation system, wherein the coiled tubing transportation system is coupled to one or more movable well drilling rigs; and using the coiled tubing transportation system to transport coiled tubing from the tubing manufacturing site to at least one of the movable well drilling rigs.
887. The method of claim 886, wherein the coiled tubing has an outer diameter of greater than about four inches.
888. The method of claim 886, further comprising making the coiled tubing from plate metal at a coiled tubing manufacturing site.
889. The method of claim 886, further comprising making the coiled tubing from flat rolled steel at a coiled tubing manufacturing site.
890. The method of claim 886, wherein making coiled tubing at a coiled tubing manufacturing site comprises using electrical resistance welding.
891. The method of claim 886, further comprising:
making the coiled tubing from flat rolled steel at a coiled tubing manufacturing site; and transporting the flat rolled steel to the coiled tubing manufacturing site in rolls having a diameter of at least fifty feet.
892. The method of claim 886, further comprising:
making the coiled tubing from flat rolled steel at a coiled tubing manufacturing site; and transporting the flat rolled steel to the coiled tubing manufacturing site in rolls having a diameter of at least one hundred feet.
893. The method of claim 886, wherein the well is a hydrocarbon well.
894. The method of claim 886, wherein the coiled tubing comprises a continuous length substantially equivalent to an assessed depth of a well.
895. The method of claim 886, further comprising using at least some of the coiled tubing to line a well.
896. The method of claim 886, further comprising using at least some of the coiled tubing to drill and line a well.
897. The method of claim 886, further comprising providing bottom hole assemblies to a well drilling rig and/or a coiled tubing manufacturing site using a carrier system coupled to a well drilling site and/or a tubing formation site.
898. The method of claim 886, further comprising providing bottom hole assemblies to a well drilling rig and/or a coiled tubing manufacturing site using a carrier system coupled to a well drilling site and/or a tubing formation site, wherein the carrier system comprises a carousel.
899. The method of claim 886, further comprising using the coiled tubing to drill a well and using the same coiled tubing for transporting materials to and/or from the surface.
900. The method of claim 886, wherein coiled tubing transportation system comprises a rail system.
901. The method of claim 886, wherein coiled tubing transportation system comprises at least one gantry and a rail system.
902. The method of claim 886, wherein coiled tubing transportation system comprises a rail system running in a continuous loop around a treatment area.
903. The method of claim 886, wherein the coiled tubing manufacturing site is less than five kilometers from one or more of the movable well drilling rigs.
904. The method of claim 886, wherein the coiled tubing manufacturing site is less than ten kilometers from one or more of the movable well drilling rigs.
905. The method of claim 886, wherein the coiled tubing manufacturing site is less than twenty kilometers from one or more of the movable well drilling rigs.
906. The method of claim 886, further comprising supplying and/or removing fluids to a well drilled by one or more of the movable well drilling rigs using elongated tubulars.
907. The method of claim 886, further comprising providing utilities to a well drilled by one or more of the movable well drilling rigs using elongated tubulars.
908. The method of claim 886, further comprising positioning one or more of the movable well drilling rigs using a global positioning system.
909. The method of claim 886, further comprising a tracking system configured to actively assess locations of a position and/or state of one or more of the movable well drilling rigs, a coiled tubing manufacturing site, and/or an associated support system.
910. The method of claim 886, further comprising forming at least a portion of a rail system using a positionable rail manufacturing rig, wherein the rail system is configured to assist in transporting the coiled tubing from the coiled tubing manufacturing site to one or more of the movable well drilling rigs.
911. The method of claim 886, further comprising coupling a hang-off assembly to a proximal end of the coiled tubing.
912. The method of claim 886, further comprising coupling a bottom hole assembly to a distal end of the coiled tubing.
913. The method of claim 886, further comprising coupling a bottom hole assembly to a distal end of the coiled tubing, wherein the bottom hole assembly is programmable.
914. The method of claim 886, further comprising coupling a bottom hole assembly to a distal end of the coiled tubing, wherein the bottom hole assembly is programmable to perform one or more autonomous tasks.
915. The method of claim 886, further comprising coupling a bottom hole assembly to a distal end of the coiled tubing, wherein the bottom hole assembly is configurable as a bottom hole electrical connector.
916. The method of claim 886, further comprising forming an insulation layer on at least a portion of the coiled tubing.
917. The method of claim 886, further comprising forming an insulation layer on at least a portion of the coiled tubing, wherein the insulation layer comprises a polymer coating.
918. The method of claim 886, further comprising forming an insulation layer on at least a portion of the coiled tubing, wherein the insulation layer comprises a polymer coating, and wherein the polymer coating comprises polyvinylchloride, high density polyethylene, and/or polystyrene.
919. The method of claim 886, further comprising forming an insulation layer on at least a portion of the coiled tubing at the coiled tubing manufacturing site.
920. The method of claim 886, further comprising forming an insulation layer on at least a portion of the coiled tubing at the movable well drilling rig.
921. A method for making coiled tubing, comprising:
assessing properties of at least a first portion of a treatment area;
making coiled tubing at a coiled tubing manufacturing site based on, at least in part, the assessed properties of the first portion of the treatment area, wherein the coiled tubing manufacturing site is coupled to the first portion of the treatment area with a coiled tubing transportation system;
transporting the coiled tubing from the coiled tubing manufacturing site to the first portion of the treatment area using a coiled tubing transportation system; and drilling a first well using a movable drilling rig and the coiled tubing.
922. A method for making coiled tubing and transporting such coiled tubing to a well, comprising:
drilling at least a portion of a well in a treatment area;
assessing properties of the well;
making coiled tubing at a coiled tubing manufacturing site based on, at least in part, the assessed properties of the well, wherein the coiled tubing manufacturing site is coupled to the well with a coiled tubing transportation system; and transporting the coiled tubing from the coiled tubing manufacturing site to the well using a coiled tubing transportation system.
923. The method of claim 922, further comprising drilling at least a portion of the well using a movable well drilling rig.
924. A method for making coiled tubing and transporting such coiled tubing to a well, comprising:
drilling at least a portion of a first well in a treatment area;
assessing properties of the first well;
making a first coiled tubing at a coiled tubing manufacturing site based on, at least in part, the assessed properties of the first well, wherein the coiled tubing manufacturing site is coupled to the first well with a coiled tubing transportation system;

transporting the first coiled tubing from the coiled tubing manufacturing site to the first well using the coiled tubing transportation system;
drilling at least a portion of a second well in the treatment area;
assessing properties of the second well;
making a second coiled tubing at the coiled tubing manufacturing site based on, at least in part, the assessed properties of the second well, wherein the coiled tubing manufacturing site is coupled to the second well with the coiled tubing transportation system;
and transporting the second coiled tubing from the coiled tubing manufacturing site to the second well.
925. The method of claim 924, wherein the second coiled tubing comprises at least one property different from properties of the first coiled tubing.
926. A system for removing protrusions from a well, comprising:
one or more cutting structures positioned along a length of a tubular in between the distal and proximal ends of the tubular, wherein the distal end of the tubular comprises a drill bit, wherein the cutting structures are configured to remove at least a portion of one or more of protrusions positioned along at least a portion of a well.
927. The system of claim 926, wherein one or more of the cutting structures are directed substantially away from the distal end of the tubular in an upward manner.
928. The system of claim 926, wherein one or more of the cutting structures are configured to cut at least a portion of one or more of protrusions positioned along at least a portion of a well.
929. The system of claim 926, wherein one or more of the cutting structures are positioned on an outside portion of the tubular comprising a diameter that is greater than an average diameter of the tubular.
930. A method for removing protrusions from a well, comprising:
removing at least a portion of one or more of protrusions positioned along at least a portion of a well using one or more cutting structures positioned along a length of a tubular in between the distal and proximal ends of the tubular.
931. The method of claim 930, wherein the distal end of the tubular comprises a drill bit.
932. The method of claim 930, wherein one or more of the cutting structures are directed substantially away from the distal end of the tubular in an upward manner.
933. The method of claim 930, wherein one or more of the cutting structures are configured to cut at least a portion of one or more of protrusions positioned along at least a portion of a well.
934. The method of claim 930, wherein one or more of the cutting structures are positioned on an outside portion of the tubular comprising a diameter that is greater than an average diameter of the tubular.
935. A method for treating a hydrocarbon formation, comprising:
providing heat to a first portion of hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the first portion to a second portion of hydrocarbon layer in the formation;
providing a mobilization fluid to the second portion of the hydrocarbon layer to move at least some formation fluids from the second portion of the formation; and producing at least some of the fluids from the formation.
936. The method of claim 935, wherein the mobilization fluid comprises water, hydrocarbons, surfactants, polymers, carbon disulfide, or mixtures thereof.
937. The method of claim 935, wherein the mobilization fluid comprises hydrocarbons, surfactants, polymers, carbon disulfide, or mixtures thereof.
938. The method of claim 935, wherein the mobilization fluid comprises hydrocarbons.
939. The method of claim 935, wherein the mobilization fluid comprises hydrocarbons produced from the first portion of the formation.
940. The method of claim 935, wherein the mobilization fluid comprises hydrocarbons produced from the first portion of the formation and wherein the hydrocarbon have a boiling range distribution from about 50 C to about 300 C.
941. The method of claim 940, wherein the naphtha comprises aromatic compounds.
942. The method of claim 935, wherein the mobilization fluid comprises naphtha.
943. The method of claim 935, wherein the produced fluids comprise formation fluids and/or mobilization fluid.
944. A method for treating a hydrocarbon formation, comprising:
providing heat to a first portion of hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the first portion to a second portion of hydrocarbon layer in the formation;
providing a mobilization fluid to the second portion of the hydrocarbon layer to move at least some formation fluids from the second portion of the formation;
producing at least some of the fluids from the formation;

providing a pressuring fluid to the second portion of the hydrocarbon layer to move at least a portion of the fluids from the second portion of the formation; and producing at least some of the pressured fluids from the formation.
945. The method of claim 944, wherein the pressuring fluid is carbon dioxide.
946. The method of claim 944, wherein the pressuring fluid is carbon dioxide and wherein at least a portion of the carbon dioxide is produced from the formation.
947. The method of claim 944, wherein the pressured fluids comprise at least a portion of the pressurizing gas, mobilization fluid, formation fluids, or mixtures thereof.
948. The method of claim 944, wherein the pressured fluids comprise at least a portion of the pressurizing gas and the method further comprises:
separating at least a portion of the pressurizing gas from the produced pressurized fluids;
and sequestering the pressurizing gas in a portion of the formation.
949. The method of claim 944, wherein the mobilization fluid comprises water, hydrocarbons, surfactants, polymers, carbon disulfide, or mixtures thereof.
950. The method of claim 944, wherein the mobilization fluid comprises hydrocarbons, surfactants, polymers, carbon disulfide, or mixtures thereof.
951. The method of claim 944, wherein the mobilization fluid comprises hydrocarbons.
952. The method of claim 944, wherein the mobilization fluid comprises hydrocarbons produced from the first portion of the formation.
953. The method of claim 944, wherein the mobilization fluid comprises hydrocarbons produced from the first portion of the formation and wherein the hydrocarbon have a boiling range distribution from about 50 C to about 300 C.
954. The method of claim 953, wherein the naphtha comprises aromatic compounds.
955. The method of claim 944, wherein the mobilization fluid comprises naphtha.
956. A method for treating a hydrocarbon formation, comprising:
providing heat to a first portion of hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the first portion to a second portion and third portion of hydrocarbon layer in the formation such that at least a portion of the formation fluids in the second and at least a portion of the formation fluids in the third portion flow to the first portion;
and producing at least some of the fluids from the formation.
957. A method for providing acidic gas to a subsurface formation, comprising:

providing heat from one or more heaters to a portion of a subsurface formation;
producing fluids from the formation using a heat treatment process, wherein the produced fluids comprise one or more sour gases; and introducing at least a portion of one of the sour gases into the formation, or into another formation, through one or more wellbores at a pressure below a lithostatic pressure of the formation in which the sour gas is introduced.
958. The method of claim 957, wherein at least a portion of the sour gas comprises hydrogen sulfide and/or carbon dioxide.
959. The method of claim 957, wherein at least a portion of the introduced sour gas comprises hydrogen sulfide and the hydrogen sulfide forms a sulfide layer on the surface of the walls of the wellbores.
960. The method of claim 959, wherein at least one of the sour gases comprises carbon dioxide, and the method further comprising introducing the carbon dioxide into the sulfided wellbore.
961. The method of claim 957, wherein at least a portion of the sour gas reacts in the formation.
962. The method of claim 957, wherein at least a portion of the sour gas is sequestered in the formation.
963. The method of claim 957, wherein at least a portion of the sour gas is introduced near the bottom of a saline aquifer.
964. The method of claim 957, wherein at least one of the heaters is a temperature limited heater.
965. The method of claim 957, wherein at least one of the heaters is an electrical heater.
966. A method for providing acidic gas to a subsurface formation, comprising:
providing heat from one or more heaters to a portion of a subsurface formation;
producing fluids from the formation using a heat treatment process, wherein the produced fluids comprise one or more acidic gases;
removing at least a portion of carbon dioxide from the acidic gases;
introducing at least a portion of the carbon dioxide into the formation, or into another formation, through one or more wellbores; and introducing a fluid in the wellbores used for carbon dioxide introduction to inhibit corrosion in the wellbores.
967. The method of claim 966, wherein at least a portion of the carbon dioxide reacts in the formation.
968. The method of claim 966, wherein at least a portion of the carbon dioxide is sequestered in the formation.
969. The method of claim 966, wherein the fluid comprises one or more corrosion inhibitors.
970. The method of claim 966, wherein the fluid comprises one or more polymers.
971. The method of claim 966, wherein the fluid comprises one or more surfactants.
972. The method of claim 966, wherein the fluid comprises one or more hydrocarbons.
973. The method of claim 966, wherein the fluid comprises one or more corrosion inhibitors, one or more surfactants, one or more hydrocarbons, one or more polymers or mixtures thereof.
974. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers positioned in the subsurface formation, the fuel comprising a synthesis gas;
supplying an oxidant to the plurality of oxidizers;
mixing a portion of the fuel with a portion of the oxidant; and combusting the fuel and oxidant mixture to produce heat that heats at least a portion of the subsurface formation.
975. The method of claim 974, wherein at least a portion of the fuel comprises hydrogen and carbon monoxide produced using an in situ conversion process.
976. The method of claim 974, wherein at least a portion of the fuel comprises a product produced from coal gasification.
977. The method of claim 974, wherein at least a portion of the fuel comprises a product produced from heavy oil gasification.
978. The method of claim 974, further comprising:
using hydrogen to enrich the fuel; and stopping the use of hydrogen after combusting the fuel and oxidant mixture.
979. The method of claim 974, wherein the fuel comprises a mixture of natural gas and a component from the group consisting of ethane, propane, butane, and carbon monoxide.
980. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers positioned in the subsurface formation via a fuel conduit;
supplying an oxidant to the plurality of oxidizers;
mixing a portion of the fuel with a portion of the oxidant;
combusting the fuel and oxidant mixture to produce heat that heats at least a portion of the subsurface formation; and decoking the fuel conduit.
981. The method of claim 980, wherein decoking comprises injecting steam into the fuel conduit.
982. The method of claim 980, wherein the decoking comprises injecting water into the fuel conduit.
983. The method of claim 980, wherein the decoking fluid comprises decreasing a residence time of fuel in the fuel conduit.
984. The method of claim 980, wherein decoking comprises pumping a pig through the fuel conduit.
985. The method of claim 980, wherein decoking comprises insulating a portion of the fuel conduit.
986. The method of claim 980, wherein insulating a portion of the fuel conduit comprises coating a portion of the fuel conduit with an insulating layer and a conductive layer.
987. A downhole burner, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit;
an oxidizer coupled to the fuel conduit; and an insulating sleeve positioned between the fuel conduit and the oxidizer;
wherein a portion of a fluid flowing through the oxidant conduit passes between the insulating sleeve and fuel conduit to provide cooling to at least a portion of the fuel conduit that passes through the oxidizer.
988. The burner of claim 987 wherein the insulating sleeve at least partially surrounds the fuel conduit.
989. The burner of claim 987, further comprising a conductive layer surrounding the insulating sleeve.
990. A method, comprising:
providing oxidant in an oxidant conduit to an oxidizer;
providing fuel through a fuel conduit to the oxidizer, wherein the fuel conduit is positioned in the oxidant conduit;
reacting fuel from the fuel conduit and oxidant from the oxidant conduit in the oxidizer to produce heat; and flowing a portion of the oxidant in the oxidant conduit between an insulating sleeve and the fuel conduit to provide cooling to at least a portion of the fuel conduit passing through the oxidizer.
991. The method of claim 990, wherein the insulating sleeve at least partially surrounds the fuel conduit.
992. The method of claim 990, wherein a conductive layer surrounds the insulating sleeve.
993. A method of heating a formation, comprising:
providing fuel to a plurality of oxidizers;
providing an oxidant to the plurality of oxidizers;
reacting the oxidant and fuel in the oxidizers to produce heat to heat a portion of the formation; and reducing the amount of excess oxidant supplied to the oxidizers to less than about 50%
excess oxidant by weight.
994. The method of claim 993, further comprising reducing the amount of excess oxidant to less than about 25%.
995. The method of claim 993, further comprising reducing the amount of excess oxidant to less than about 10%.
996. A method of heating a formation, comprising:
providing a plurality of oxidizers connected in series;
providing fuel to the plurality of oxidizers via a fuel conduit;
providing an oxidant to the plurality of oxidizers via an oxidant conduit;
reacting the oxidant and fuel in the oxidizers to produce heat to heat a portion of the formation; and reducing the oxidant supplied via the oxidant conduit when the temperature in the fuel conduit reaches a specified temperature.
997. The method of claim 996, further comprising permitting unburned material to be oxidized in the oxidant conduit.
998. The method of claim 996, wherein the specified temperature is about 1200 F.
999. The method of claim 996, wherein the specified temperature is about 1400 F.
1000. The method of claim 996, wherein the specified temperature is about 1800 F.
1001. A method of heating a formation, comprising:
providing a plurality of oxidizers comprising:
a first oxidizer;
one or more intermediate oxidizers connected in series; and a last oxidizer;
providing fuel to the plurality of oxidizers via a fuel conduit;
providing an oxidant to the plurality of oxidizers via an oxidant conduit;

reacting the oxidant and fuel in the oxidizers to produce heat to heat a portion of the formation; and reducing the oxidant supplied via the oxidant conduit so that the amount of oxygen in the oxidant supplied to the last oxidizer is minimized.
1002. A gas burner, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit; and an oxidizer configured to react fuel from the fuel conduit and oxidant from the oxidant conduit to produce heat, wherein the operating temperature of the oxidizer is configured to produce less than about 10 parts per million by weight of NO x from the gas burner.
1003. The gas burner of claim 1002, wherein the operating temperature of the oxidizer is configured by adding water to the fuel conduit.
1004. The gas burner of claim 1002, wherein the operating temperature of the oxidizer is configured by arranging openings in the oxidant conduit.
1005. A method of heating a formation comprising:
providing oxidant in an oxidant conduit to an oxidizer;
providing fuel to the oxidizer;
reacting fuel and oxidant to produce heat, wherein at least a portion of the heat transfers to the formation; and controlling flow of fuel and oxidant to produce less than about 10 parts per million by weight of NO x from the gas burner.
1006. The method of claim 1005, further comprising mixing water with the fuel.
1007. The method of claim 1005, further comprising arranging openings in the oxidant conduit.
1008. A method of initiating heating in a gas burner assembly in a formation, comprising:
supplying fuel through a fuel conduit in the formation, and oxidant through an oxidant conduit to provide a first combustible mixture to a last oxidizer of a plurality of oxidizers;
initiating combustion in the last oxidizer of the plurality of oxidizers to provide an ignited oxidizer;
adjusting the supply of oxidant through the oxidant conduit to supply a second-to-last oxidizer next to the ignited oxidizer with a second combustible mixture while maintaining ignition of the ignited oxidizer; and initiating combustion in the second-to-last oxidizer.
1009. The method of claim 1008, repeating adjusting the supply of oxidant to provide a combustible fuel and oxidant mixture to the next unignited oxidizer and initiating combustion in the unignited oxidizer until all oxidizers of the plurality of oxidizers are ignited.
1010. The method of claim 1008, wherein the fuel pressure is greater than the oxidant pressure at an oxidizer before initiating combustion in the oxidizer.
1011. The method of claim 1008, wherein the fuel comprises hydrogen.
1012. The method of claim 1008, wherein at least a portion of the hydrogen is produced using an in situ conversion process.
1013. The method of claim 1008, wherein at least a portion of the hydrogen is produced using a coal gasification process.
1014. A method of initiating heating in a gas burner assembly in a formation, comprising:
supplying fuel through a fuel conduit in the formation, and oxidant through an oxidant conduit to provide a first combustible mixture to a first oxidizer of a plurality of oxidizers;
initiating combustion in the last oxidizer of the plurality of oxidizers to provide an ignited oxidizer;
adjusting the supply of oxidant through the oxidant conduit to supply a second oxidizer next to the ignited oxidizer with a second combustible mixture while maintaining ignition of the ignited oxidizer; and initiating combustion in the second oxidizer.
1015. The method of claim 1014, further comprising repeating adjusting the supply of oxidant to provide a combustible fuel and oxidant mixture to the next unignited oxidizer and initiating combustion in the unignited oxidizer until all oxidizers of the plurality of oxidizers are ignited.
1016. The method of claim 1014, further comprising adjusting the fuel pressure by providing openings in the fuel conduit.
1017. The method of claim 1014, further comprising adjusting the fuel pressure by providing flow restrictions in the fuel conduit.
1018. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit; and a plurality of oxidizers coupled to the oxidant conduit, wherein at least one of the oxidizers comprises:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter;

a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit; and at least one flame stabilizer coupled to the shield.
1019. The assembly of claim 1018, wherein at least one flame stabilizer comprises a ring positioned in the shield downstream of a first set of openings in the shield, wherein the set of openings are radially positioned in the shield at a longitudinal distance along the shield.
1020. The assembly of claim 1019, wherein the ring is substantially perpendicular to the shield.
1021. The assembly of claim 1019, wherein the ring is angled away from the set of openings.
1022. The assembly of claim 1019, wherein the ring is angled towards the set of openings.
1023. The assembly of claim 1018, wherein the shield comprises two or more sets of openings, wherein a set of openings are radially positioned in the shield at specific longitudinal positions of the shield, and wherein flame stabilizers comprising rings are positioned between sets of openings.
1024. The assembly of claim 1018, wherein the shield comprises two or more sets of openings, wherein a set of openings are radially positioned in the shield at specific longitudinal positions of the shield, and wherein flame stabilizers comprising rings are positioned at an angle over the openings.
1025. The assembly of claim 1018, wherein at least one flame stabilizer comprises a deflection plate, wherein a portion of the deflection plate extends over an opening in the shield.
1026. The assembly of claim 1018, wherein the flame stabilizer alters the gas flow path in the shield.
1027. The assembly of claim 1018, wherein the fuel conduit is positioned in the oxidant conduit.
1028. The assembly of claim 1018, wherein fuel in the fuel conduit comprises a decoking agent.
1029. The assembly of claim 1018, further comprising a water conduit positioned in the oxidant conduit, the water conduit configured to deliver water to the fuel conduit prior to a first oxidizer.
1030. The assembly of claim 1029, wherein a portion of the water conduit passes through a heated zone generated by the first oxidizer prior to a water entry point into the fuel conduit.
1031. The assembly of claim 1018, wherein the fuel conduit is positioned in the oxidant conduit.
1032. The assembly of claim 1018, wherein the fuel conduit is positioned adjacent to one or more of the oxidizers, and wherein branches from the fuel conduit provide fuel to one or more of the oxidizers.
1033. The assembly of claim 1018, wherein the fuel conduit comprises one or more orifices to selectively control the pressure loss along the fuel conduit.
1034. The assembly of claim 1018, wherein the flame stabilizer comprises a plurality of slots in the shield with extensions that direct gas flow into the shield in a desired direction.
1035. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers;
supplying oxidant to the plurality of oxidizers;
mixing a portion of the fuel with a portion of the oxidant in an oxidizer of the plurality of oxidizers to produce a combustible mixture;
reacting the combustible mixture in the oxidizer to produce a flame; and using a flame stabilizer in the oxidizer to attach the flame to a shield.
1036. The method of claim 1035, using the flame stabilizer comprises passing gas in the oxidizer past a ring positioned in the shield.
1037. The method of claim 1036, wherein the ring is substantially perpendicular to the shield.
1038. The method of claim 1036, wherein the ring is angled in the shield.
1039. The method of claim 1036, wherein at least one flame stabilizer comprises an opening in the shield and an extension configured to direct gas flowing into the shield in a desired direction.
1040. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit; and a first oxidizer coupled to the oxidant conduit, the first oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit;
a second oxidizer coupled to the oxidant conduit, the second oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit; and wherein one or more of the plurality of openings of the first oxidizer are of a different size than the plurality of openings of the second oxidizer.
1041. The gas burner assembly of claim 1040, wherein at least one of the openings of the first oxidizer is of a different size than one or more other openings of the first oxidizer.
1042. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit;
a first oxidizer coupled to the oxidant conduit, the first oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit;
a second oxidizer coupled to the oxidant conduit, the second oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter;
a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit; and wherein one or more of the plurality of openings of the first oxidizer are of a different geometry than the plurality of openings of the second oxidizer.
1043. The gas burner assembly of claim 1042, wherein at least one of the openings of the first oxidizer is of a different geometry than one or more other openings of the first oxidizer.
1044. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit; and a first oxidizer coupled to the oxidant conduit, the first oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a first group of openings angled across the thickness of the shield.
1045. The gas burner assembly of claim 1044, further comprising a second group of openings not angled across the thickness of the shield.
1046. The gas burner assembly of claim 1045, wherein the first group of openings are located on a portion of the shield away from the fuel conduit.
1047. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit; and a first oxidizer coupled to the oxidant conduit, the first oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit and a baffled section proximate to the openings.
1048. The gas burner assembly of claim 1047, further comprising a second oxidizer coupled to the oxidant conduit, the second oxidizer comprising:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
an igniter; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit; and wherein one or more of the plurality of openings of the first oxidizer are of a different geometry than the plurality of openings of the second oxidizer.
1049. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit configured to react fuel from the fuel conduit and oxidant from the oxidant conduit;
wherein fuel supplied to a first oxidizer of the plurality of oxidizers is configured to pass into a heated region adjacent to the first oxidizer before entering the first oxidizer.
1050. The gas burner of claim 1049, further comprising a bypass conduit which forces fuel supplied to the first oxidizer to pass into the heated region before entering the first oxidizer.
1051. The gas burner of claim 1050, wherein the bypass conduit comprises a primary fuel hole upstream, of the first oxidizer and a secondary fuel hole inside the first oxidizer.
1052. The gas burner of claim 1049, wherein the fuel conduit is positioned in the oxidant conduit.
1053. The gas burner of claim 1049, wherein the fuel conduit is positioned adjacent to one or more of the oxidizers, and wherein branches from the fuel conduit provide fuel to one or more of the oxidizers.
1054. The gas burner of claim 1049, wherein the fuel conduit comprises one or more orifices to selectively control the pressure loss along the fuel conduit.
1055. A method for heating a subsurface formation, comprising:
providing oxidant to a plurality of oxidizers;
providing fuel to the oxidizers through a fuel conduit;
passing the fuel conduit through a heated zone adjacent to a first oxidizer before providing fuel to the first oxidizer; and reacting fuel and oxidant to produce heat, wherein at least a portion of the heat transfers to the formation.
1056. The gas burner of claim 1055, wherein the fuel conduit is positioned in the oxidant conduit.
1057. The gas burner of claim 1055, wherein the fuel conduit is positioned adjacent to one or more of the oxidizers, and wherein branches from the fuel conduit provide fuel to one or more of the oxidizers.
1058. The gas burner of claim 1055, wherein the fuel conduit comprises one or more orifices to selectively control the pressure loss along the fuel conduit.
1059. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit, and wherein the fuel conduit comprises at least two fuel entries into the shield at different positions along a length of the fuel conduit.
1060. The gas burner assembly of claim 1059, wherein one of the oxidizers with the fuel conduit comprising at least two fuel entries into the shield at different positions along the length of the fuel conduit is a first oxidizer of the plurality of oxidizers.
1061. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers through a fuel conduit;
supplying oxidant to the plurality of oxidizers through an oxidant conduit;
mixing a portion of the fuel with a portion of the oxidant in an oxidizer of the plurality of oxidizers to produce a combustible mixture;
reacting the combustible mixture in the oxidizer to produce a flame in a shield of the oxidizer; introducing additional fuel from the fuel conduit adjacent to the shield, and introducing additional oxidant through one or more openings in the shield to provide an extended length of the flame in the oxidizer; and heating a portion of the formation using heat generated by the flame.
1062. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit; and a plurality of oxidizers coupled to the oxidant conduit, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel conduit with oxidant from the oxidant conduit;
a catalyst chamber containing a catalyst, the catalyst configured to react a mixture from the mix chamber to produce reaction products at a temperature that is sufficient to ignite fuel and oxidant; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit.
1063. The assembly of claim 1062, wherein the shield comprises at least one flame stabilizer.
1064. The assembly of claim 1062, wherein oxidant supplied to the mix chamber comprises oxidant preheated by one or more previous oxidizers.
1065. The assembly of claim 1062, wherein the fuel conduit is positioned in the oxidant conduit.
1066. The assembly of claim 1062, wherein the fuel conduit is positioned adjacent to one or more of the oxidizers, and wherein branches from the fuel conduit provide fuel to one or more of the oxidizers.
1067. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers;
supplying oxidant to the plurality of oxidizers;

mixing a portion of the fuel with a portion of the oxidant in an oxidizer of the plurality of oxidizers to produce a first mixture;
passing the first mixture across a catalyst to produce reaction products at a temperature sufficient to ignite fuel and oxidant; and igniting a second mixture of fuel and oxidant to generate heat, wherein a portion of the heat is transferred to the formation.
1068. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit, wherein at least one of the oxidizers includes:
a mix chamber for mixing fuel from the fuel conduit with an oxidant;
an igniter in the mix chamber configured to ignite fuel and oxidant to preheat fuel and oxidant;
a catalyst chamber containing a catalyst, the catalyst configured to react preheated fuel and oxidant from the mix chamber to produce reaction products at a temperature sufficient to ignite fuel and oxidant; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit.
1069. The assembly of claim 1068, wherein the catalyst chamber comprises one or more openings configured to allow oxidant, fuel, or a mixture thereof to contact the catalyst.
1070. The assembly of claim 1068, wherein the catalyst chamber comprises one or more openings configured to allow the reaction products to exit the catalyst chamber and contact a mixture of fuel and oxidant.
1071. The assembly of claim 1068, further comprising a water conduit positioned in the oxidant conduit, the water conduit configured to deliver water that inhibits coking of fuel to the fuel conduit before a first oxidizer in the gas burner assembly.
1072. The assembly of claim 1068, wherein the shield comprises at least one flame stabilizer.
1073. The assembly of claim 1068, wherein the igniter comprises a glow plug.
1074. The assembly of claim 1068, wherein the igniter comprises a temperature limited heating element.
1075. A method of heating a subsurface formation, comprising:
supplying fuel to a plurality of oxidizers;
supplying oxidant to the plurality of oxidizers;

mixing a portion of the fuel with a portion of the oxidant in an oxidizer of the plurality of oxidizers to produce a first mixture;
using an igniter to ignite the first mixture and produce heat;
using the heat to preheat a second mixture;
passing the preheated second mixture over a catalyst to react the mixture and produce heat; and using the heat to ignite a third mixture of oxidant and fuel to produce a flame in the oxidizer and generate heat, wherein at least a portion of the heat transfers to the formation.
1076. The method of claim 1075, wherein the igniter comprises a temperature limited heating element.
1077. The method of claim 1075, wherein the igniter comprises a glow plug.
1078. A method of initiating heating in a gas burner assembly in a formation, comprising:
supplying fuel of a first composition through a fuel conduit in the formation, and oxidant through an oxidant conduit;
initiating combustion in an oxidizer; and adjusting the supply and composition of fuel in the conduit to supply fuel of a second composition to the formation.
1079. The method of claim 1078, wherein the first composition comprises hydrogen.
1080. The method of claim 1078, wherein the second composition comprises natural gas.
1081. A method of initiating heating in a gas burner assembly in a formation, comprising:
supplying fuel through a fuel conduit and oxidant through an oxidant conduit;
igniting the burner using a fuel composition comprising hydrogen; and adjusting the composition of the fuel in the fuel conduit so that the fuel comprises natural gas.
1082. A heating system for a subsurface formation, comprising:
an electrical conductor;
an insulation layer at least partially surrounding the electrical conductor;
and a jacket comprising ferromagnetic material, the jacket at least partially surrounding the insulation layer, wherein the outside surface of the jacket is configured to be at little or no potential while the jacket is at temperatures below the Curie temperature of the ferromagnetic material.
1083. The heating system of claim 1082, wherein the jacket has a thickness of at least 2 times the skin depth of the ferromagnetic material.
1084. The heating system of claim 1082, wherein the jacket has a thickness of at least 3 times the skin depth of the ferromagnetic material.
1085. The heating system of claim 1082, wherein a majority of electrical current passes through the jacket on the inside diameter of the jacket.
1086. The heating system of claim 1082, wherein the jacket and the electrical conductor are electrically coupled at distal ends of the jacket and the electrical conductor.
1087. The heating system of claim 1082, wherein the electrical conductor is copper.
1088. The heating system of claim 1082, wherein the jacket is formed from multiple layers of material.
1089. The heating system of claim 1082, wherein a majority of the heat generated by the heating system is generated in the jacket.
1090. A heating system for a subsurface formation, comprising:
an electrical conductor;
an insulation layer at least partially surrounding the electrical conductor;
and a jacket comprising ferromagnetic material, the jacket at least partially surrounding the insulation layer, wherein the jacket is configured to generate a majority of the heat in the heating system when a time-varying electrical current is applied to the heating system.
1091. A system for a subsurface formation, comprising:
a wellbore located in the subsurface formation;
a downhole load located in the wellbore;
a transformer located in the wellbore, the transformer being electrically coupled to the downhole load, and being configured to provide power to the downhole load; and a cooling system located in the wellbore, the cooling system being configured to maintain a temperature of the transformer below a selected temperature.
1092. The system of claim 1091, wherein the cooling system comprises a flow of cooling fluid substantially surrounding the transformer in the wellbore, wherein the cooling fluid is configured to transfer heat away from the transformer.
1093. The system of claim 1091, wherein the cooling system comprises a flow of water substantially surrounding the transformer in the wellbore, wherein the water is configured to transfer heat away from the transformer.
1094. The system of claim 1091, wherein the cooling system comprises a flow of cooling fluid in the wellbore, the transformer being immersed in the cooling fluid.
1095. The system of claim 1091, wherein the selected temperature is a maximum operating temperature of the transformer.
1096. The system of claim 1091, wherein the transformer is sealed to inhibit fluids from entering the transformer.
1097. The system of claim 1091, further comprising a packing located in the wellbore between the transformer and the downhole load, the packing being configured to inhibit fluid flow between the portion of the wellbore with the transformer and the portion of the wellbore with the downhole load.
1098. A method of providing at least a partial barrier for a subsurface formation, comprising:
providing a fluid comprising liquefied wax a plurality of openings in the formation, the fluid having a solidification temperature that is greater than the temperature of the portion of the formation in which the barrier to desired to be formed;
pressurizing the liquefied fluid such that at least a portion of the liquefied fluid flows into the formation; and allowing the fluid to solidify to form at least a partial barrier in the formation.
1099. The method of claim 1098, further comprising dewatering at least a portion of the formation.
1100. The method of claim 1098, further comprising providing the fluid to at least two openings such that the fluid from the two openings mixes in the formation and solidifies to form a barrier.
1101. The method of claim 1098, further comprising heating formation adjacent to one or more of the openings with one or more heaters to raise the temperature of the formation where the fluid is to be introduced.
1102. The method of claim 1098, further comprising providing heated water to the opening to heat the formation prior to introducing the fluid.
1103. The method of claim 1098, further comprising providing water to the opening, and heating the water in the formation prior to introducing the fluid.
1104. The method of claim 1098, further comprising inserting a conduit in the opening, and providing pressurized water to the conduit to at least partially flush wax from the opening.
1105. The method of claim 1098, wherein at least a portion of one or more of the openings are non-vertically oriented in the formation.
1106. The method of claim 1098, further comprising treating the formation on one side of the barrier and heating the barrier after treating the formation to remove at least a portion of the barrier and allow for fluid previously inhibited by the barrier.
1107. A method of inhibiting migration of formation fluid including hydrocarbons in one or more permeable portions of a subsurface formation, comprising:

using heaters to raise a temperature of a portion of the formation above a melting temperature of a material including wax, wherein the portion includes at least some of the one or more permeable portions adjacent to injection wells in the formation;
introducing molten material into the formation through one or more of the injection wells, wherein the molten material enters permeable portions of the formation;
and allowing the molten material to cool in the formation and congeal to form a barrier that inhibits migration of the formation fluid.
1108. The method of claim 1107, further comprising pressurizing the molten material to increase diffusion of the molten material into the permeable portions of the formation.
1109. The method of claim 1107, wherein the material comprises branched chain waxes to inhibit biological degradation of the material.
1110. The method of claim 1107, wherein the heated portion of the formation includes formation fluid with hydrocarbons.
1111. The method of claim 1107, wherein the barrier is formed in one or more permeable zones of the formation prior to generating formation fluids that include hydrocarbons.
1112. The method of claim 1107, wherein superposition of heat from the heaters raises the temperature of the formation between two adjacent injection wells above the melting temperature of the material.
1113. The method of claim 1107, wherein at least a portion of one or more of the injection wells are non-vertically oriented in the formation.
1114. A method of forming a wellbore in a formation through at least two permeable zones, comprising:
drilling a first portion of the wellbore to a depth between a first permeable zone and a second permeable zone;
heating a portion of the formation adjacent to the first permeable zone to a temperature above the melting temperature of a first fluid comprising wax;
introducing the first fluid through the wellbore into the first permeable zone, wherein a portion of the first fluid enters the first permeable zone and congeals in the first permeable zone to form a first barrier; and drilling a second portion of the wellbore through a second permeable zone to a desired depth.
1115. The method of claim 1114, wherein the first barrier inhibits contamination of fluid flowing in the first permeable zone with fluid flowing in the second permeable zone.
1116. The method of claim 1114, further comprising heating a portion of the formation adjacent to the second permeable zone to a temperature above a melting temperature of a second fluid comprising wax; and introducing the second fluid through the wellbore into the second permeable zone, wherein a portion of the second fluid enters the second permeable zone and congeals to form a second barrier.
1117. The method of claim 1114, wherein heating the portion of the formation adjacent to the first permeable zone comprises using one or more antennas to heat fluid in the first permeable zone.
1118. The method of claim 1114, wherein heating the portion of the formation adjacent to the first permeable zone comprises using one or more electrical heaters in the wellbore to heat the first permeable zone.
1119. The method of claim 1114, wherein the first fluid comprises branched chain waxes.
1120. A method for treating a tar sands formation, comprising:
heating at least a section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
controlling the heating so that at least a majority of the section reaches an average temperature of between about 200 C and about 240 C resulting in visbreaking of at least some hydrocarbons in the section; and producing at least some visbroken hydrocarbon fluids from the formation.
1121. The method of claim 1120, wherein the average temperature is between about 205 C
and about 230 C.
1122. The method of claim 1120, further comprising maintaining a pressure in the formation below a fracture pressure of the formation, wherein the fracture pressure of the formation is between about 2000 kPa and about 15000 kPa.
1123. The method of claim 1120, further comprising maintaining the pressure within about 1 MPa of a fracture pressure of the formation.
1124. The method of claim 1120, further comprising maintaining a pressure in the formation below a fracture pressure of the formation by removing at least some fluids from the formation.
1125. The method of claim 1120, further comprising operating the heaters at substantially full power until the portion of the formation reaches the average temperature of between about 200 C and about 240 C.
1126. The method of claim 1120, wherein the liquid hydrocarbon portion of the produced fluids has a viscosity of at most about 350 cp, the viscosity being measured at 1 atm and 5C.
1127. The method of claim 1120, wherein the liquid hydrocarbon portion of the produced fluids has an API gravity between 7 and 19.
1128. The method of claim 1120, wherein the liquid hydrocarbon portion of the produced fluids has an API gravity of at least 15, a viscosity of at most 350 cp (wherein the viscosity is measured at 1 atm and 5C), a p-factor of at least 1.1 (wherein P-value is determined by ASTM
Method D7060), and a bromine number of at most 2% (wherein bromine number is determined by ASTM Method D1159 on a hydrocarbon portion of the produced fluids having a boiling point below 246 C).
1129. The method of claim 1120, further comprising varying the amount of mobilized hydrocarbons and/or visbroken hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation and/or to vary the total recovery of hydrocarbons from the formation.
1130. The method of claim 1120, further comprising controlling the temperature and the pressure in at least a portion of the formation such that (a) at least a majority of the hydrocarbons in the formation are visbroken, (b) the pressure is below the fracture pressure of the portion of the formation, and (c) at least some hydrocarbons in the portion of the formation form a fluid comprising visbroken hydrocarbons that can be produced through a production well.
1131. A method for treating a tar sands formation, comprising:
heating at least a section of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
maintaining a pressure in the majority of the section below a fracture pressure of the formation;
reducing the pressure in the majority of the section to a selected pressure after the average temperature reaches a temperature that is above about 240 C
and is at or below pyrolysis temperatures of hydrocarbons in the section; and producing at least some hydrocarbon fluids from the formation.
1132. The method of claim 1131, further comprising operating the heaters at substantially full power until the portion of the formation reaches the visbreaking temperature.
1133. The method of claim 1131, further comprising maintaining the pressure within about 1 MPa of the fracture pressure.
1134. The method of claim 1131, further comprising maintaining the pressure in the formation below the fracture pressure of the formation by removing at least some fluids from the formation.
1135. The method of claim 1131, wherein the fracture pressure of the formation is between about 2000 kPa and about 15000 kPa.
1136. The method of claim 1131, wherein the selected pressure is between about 300 kPa and about 1000 kPa.
1137. The method of claim 1131, wherein reducing the pressure to the selected pressure inhibits coking in the formation.
1138. The method of claim 1131, further comprising increasing the temperature of the portion of the formation to temperatures above about 270 C after reducing the pressure to the selected pressure.
1139. The method of claim 1131, further comprising producing at least some mobilized hydrocarbons from the formation, at least some visbroken hydrocarbons from the formation, and/or at least some pyrolyzed hydrocarbons from the formation.
1140. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters to at least a first portion of the formation;
controlling conditions in the formation so that water vaporized by the heaters in the first portion is selectively condensed in a second portion of the formation; and producing fluids from the formation.
1141. The method of claim 1140, wherein conditions in the formation comprise temperature and pressure in the formation.
1142. The method of claim 1140, further comprising providing at least some heat to the formation using a drive fluid.
1143. The method of claim 1140, further comprising operating the heaters at substantially full power until at least some water is condensed.
1144. The method of claim 1140, further comprising maintaining the pressure in the formation below a fracture pressure of the formation by removing at least some fluids from the formation.
1145. The method of claim 1140, further comprising producing at least some mobilized hydrocarbons from the formation, at least some visbroken hydrocarbons from the formation, and/or at least some pyrolyzed hydrocarbons from the formation.
1146. The method of claim 1140, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and/or pyrolyzed hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation and/or to vary the total recovery of hydrocarbons from the formation.
1147. The method of claim 1140, wherein the provided heat mobilizes and/or pyrolyzes at least some hydrocarbons in the formation.
1148. The method of claim 1140, wherein the vaporized water moves from the first portion to the second portion of the formation.
1149. The method of claim 1140, wherein the condensing water heat hydrocarbons in the second portion of the formation.
1150. The method of claim 1140, wherein the second portion of the formation is heated by the condensing water before providing heat to the second portion with heaters.
1151. The method of claim 1140, wherein the condensed water mobilizes at least some hydrocarbons in the formation.
1152. The method of claim 1140, wherein the condensed water pyrolyzes at least some hydrocarbons in the formation.
1153. The method of claim 1140, further comprising controlling the temperature and the pressure in at least a portion of the formation such that (a) at least a majority of the hydrocarbons in the formation are mobilized, (b) the pressure is below the fracture pressure of the portion of the formation, and (c) at least some hydrocarbons in the portion of the formation form a fluid comprising mobilized hydrocarbons that can be produced through a production well.
1154. The method of claim 1140, further comprising using the produced fluids to make a transportation fuel.
1155. A method for treating a tar sands formation, comprising:
heating a first portion of a hydrocarbon layer in the formation from one or more heaters located in the first portion;
controlling the heating to increase a fluid injectivity of the first portion;
injecting and/or creating a drive fluid and/or an oxidizing fluid in the first portion to cause at least some hydrocarbons to move from a second portion of the hydrocarbon layer to a third portion of the hydrocarbon layer, the second portion being between the first portion and the third portion, and at least two of the first, second, and third portions being at least partially horizontally displaced from each other;
heating the third portion from one or more heaters located in the third portion; and producing hydrocarbons from the third portion of the formation, the hydrocarbons including at least some hydrocarbons from the second portion of the formation.
1156. The method of claim 1155, wherein the drive fluid and/or the oxidizing fluid comprise steam, water, carbon dioxide, carbon monoxide, methane, pyrolyzed hydrocarbons, and/or air.
1157. The method of claim 1155, further comprising providing heat to the second portion that is less than the heat provided to the first portion and less than the heat provided to the third portion.
1158. The method of claim 1155, further comprising providing heat to the second portion so that an average temperature of the second portion is at most about 100 C.
1159. The method of claim 1155, further comprising providing heat to the third portion so that an average temperature of the third portion is at least about 270 C.
1160. The method of claim 1155, further comprising providing heat to the first portion to produce coke in the first portion.
1161. The method of claim 1155, further comprising providing the oxidizing fluid to oxidize at least some hydrocarbons and/or coke in the first portion and increase the temperature in the first portion, and removing the oxidation products from the first portion.
1162. The method of claim 1155, further comprising providing the oxidizing fluid to oxidize at least some hydrocarbons and/or coke in the first portion and increase the temperature in the first portion and, then, adding steam to the first portion to heat the steam and drive fluids to the second and third portions.
1163. The method of claim 1155, wherein the formation has a horizontal permeability that is higher than a vertical permeability so that the moving hydrocarbons move substantially horizontally through the formation.
1164. The method of claim 1155, wherein the second portion has a larger volume than the first portion and/or the third portion.
1165. The method of claim 1155, further comprising providing heat to the third portion such that at least some hydrocarbons from the second portion are pyrolyzed in the third portion.
1166. The method of claim 1155, further comprising causing at least some hydrocarbons to move from the first portion to the third portion.
1167. The method of claim 1155, wherein the first portion has a substantially uniform porosity and/or a substantially uniform injectivity after heating.
1168. The method of claim 1155, wherein at least some of the heaters in the first portion are turned down and/or off after increasing the fluid injectivity in the first portion.
1169. The method of claim 1155, wherein the first portion has little or no initial injectivity.
1170. The method of claim 1155, further comprising controlling the temperature and the pressure in the first portion and/or the third portion such that (a) at least a majority of the hydrocarbons in the first portion and/or the third portion are visbroken, (b) the pressure is below the fracture pressure of the first portion and/or the third portion, and (c) at least some hydrocarbons in the first portion and/or the third portion form a fluid comprising visbroken hydrocarbons that can be produced through a production well.
1171. The method of claim 1155, further comprising mobilizing at least some hydrocarbons in the second portion using heat provided from heaters located in the second portion, heat transferred from the first portion, and/or heat transferred from the third portion.
1172. A method for treating a tar sands formation with one or more karsted zones, comprising:
providing heat from one or more heaters to one or more karsted zones of the tar sands formation;
mobilizing hydrocarbon fluids in the formation; and producing hydrocarbon fluids from the formation.
1173. The method of claim 1172, wherein one or more karsted zones are selectively heated.
1174. The method of claim 1172, further comprising flowing the mobilized hydrocarbon fluids in an interconnected pore network of the formation.
1175. The method of claim 1172, further comprising flowing the mobilized hydrocarbons fluids in an interconnected pore network of the formation, wherein the interconnected pore network comprises a plurality of vugs.
1176. The method of claim 1172, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
1177. The method of claim 1172, further comprising pyrolyzing at least some hydrocarbons in the formation.
1178. The method of claim 1172, wherein the formation includes vugs having a porosity of at least 20 porosity units in a formation with a porosity of at most about 15 porosity units, and wherein the vugs include unmobilized hydrocarbons prior to heating.
1179. The method of claim 1172, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
1180. The method of claim 1172, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation, and heating unmobilized hydrocarbons with the draining hydrocarbon fluids.
1181. The method of claim 1172, further comprising assessing the degree of karsted in the karsted zones, and selectively providing more heat to karsted zones with higher degrees of karsted than to karsted zones with less degrees of karsted.
1182. The method of claim 1172, wherein the formation is a karsted carbonate formation containing viscous hydrocarbons.
1183. The method of claim 1172, further comprising injecting steam into the formation.
1184. The method of claim 1172, further comprising heating the formation with the one or more heaters to increase steam injectivity, and then injecting steam in the formation.
1185. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing the provided heat to reduce the viscosity of at least some hydrocarbons in the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
1186. The method of claim 1185, wherein one or more of the karsted layers are selectively heated so that more heat is provided to karsted layers with more karsted.
1187. The method of claim 1185, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
1188. The method of claim 1185, further comprising pyrolyzing at least some hydrocarbons in the formation.
1189. The method of claim 1185, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
1190. The method of claim 1185, further comprising injecting steam into the formation.
1191. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing the provided heat to reduce the viscosity of at least some hydrocarbons in the karsted layers to get an injectivity in at least one of the karsted layers sufficient to allow a drive fluid to flow in the karsted layers;
providing the drive fluid into at least one of the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
1192. The method of claim 1191, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
1193. The method of claim 1191, further comprising pyrolyzing at least some hydrocarbons in the formation.
1194. The method of claim 1191, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
1195. The method of claim 1191, further comprising injecting steam into the formation.
1196. A method for treating a formation containing dolomite and hydrocarbons, comprising:
providing heat at less than the decomposition temperature of dolomite from one or more heaters to at least a portion of the formation;
mobilizing hydrocarbon fluids in the formation; and producing hydrocarbon fluids from the formation.
1197. The method of claim 1196, further comprising providing heat at or higher than the decomposition temperature of dolomite to produce carbon dioxide, the heating being provided such that the carbon dioxide mixes with hydrocarbons in the formation and reduces the viscosity of such hydrocarbons.
1198. The method of claim 1196, wherein the heat is less than about 400 C.
1199. The method of claim 1196, further comprising flowing the mobilized hydrocarbon fluids in an interconnected pore network of the formation.
1200. The method of claim 1196, further comprising flowing the mobilized hydrocarbons fluids in an interconnected pore network of the formation, wherein the interconnected pore network comprises a plurality of vugs.
1201. The method of claim 1196, wherein the heat is provided to mobilize hydrocarbons in vugs of the formation.
1202. The method of claim 1196, further comprising pyrolyzing at least some hydrocarbons in the formation.
1203. The method of claim 1196, further comprising draining mobilizing hydrocarbon fluids to a production well in the formation.
1204. The method of claim 1196, further comprising injecting steam into the formation.
1205. The method of claim 1196, further comprising heating the formation with the one or more heaters to increase steam injectivity, and then injecting steam in the formation.
1206. The method of claim 1196, further comprising controlling a pressure in the formation to control the decomposition of dolomite in the formation.
1207. A method for treating a karsted formation containing heavy hydrocarbons and dolomite, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing a temperature in at least one of the karsted layers to reach a decomposition temperature of dolomite in the formation;
allowing the dolomite to decompose; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
1208. A method for treating a formation containing dolomite and hydrocarbons, comprising:
providing heat to one or more portions of the formation containing dolomite and clay, wherein more heat is preferentially provided to portions of the formation with a clay weight percentage of at most about 2%; and producing hydrocarbon fluids from the formation.
1209. The method of claim 1208, further comprising providing more heat to the portions with the clay weight percentage of at most about 2% by having a higher heater density in such portions.
1210. The method of claim 1208, further comprising controlling the heat provided to portions of the formation with more than about 2% by weight clay so that temperatures in such portions is at most about 240 C.
1211. The method of claim 1208, wherein more heat is preferentially provided to portions of the formation with a clay weight percentage of at most about 1%.
1212. The method of claim 1208, wherein one or more of the heaters are substantially horizontal in the portions of the formation preferentially provided with more heat.
1213. The method of claim 1208, further comprising controlling a pressure in the formation to control the decomposition of dolomite in the formation.
1214. The method of claim 1208, further comprising assessing the clay weight percentage of the formation before providing heat to the formation.
1215. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the pressure to increase in an upper portion of the formation to provide a gas cap in the upper portion; and producing at least some hydrocarbons from a lower portion of the formation.
1216. The method of claim 1215, wherein at least a portion of the heaters are turned off and/or down after creating the gas cap.
1217. The method of claim 1215, further comprising providing at least some heat to the formation using a drive fluid.
1218. The method of claim 1215, further comprising operating the heaters at substantially full power until the gas cap is provided.
1219. The method of claim 1215, further comprising maintaining the pressure in the formation below a fracture pressure of the formation by removing at least some fluids from the formation.
1220. The method of claim 1215, further comprising producing at least some mobilized hydrocarbons from the formation, at least some visbroken hydrocarbons from the formation, and/or at least some pyrolyzed hydrocarbons from the formation.
1221. The method of claim 1215, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and/or pyrolyzed hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation and/or to vary the total recovery of hydrocarbons from the formation.
1222. The method of claim 1215, wherein the provided heat mobilizes and/or pyrolyzes at least some hydrocarbons in the formation.
1223. The method of claim 1215, wherein the hydrocarbons produced from the lower portion of the formation include at least some hydrocarbons from the upper portion of the formation.
1224. The method of claim 1215, further comprising producing at least some fluids from the upper portion of the formation.
1225. The method of claim 1215, further comprising controlling the temperature and the pressure in at least a portion of the formation such that (a) at least a majority of the hydrocarbons in the formation are mobilized, (b) the pressure is below the fracture pressure of the portion of the formation, and (c) at least some hydrocarbons in the portion of the formation form a fluid comprising mobilized hydrocarbons that can be produced through a production well.
1226. The method of claim 1215, further comprising using the produced fluids to make a transportation fuel.
1227. A method for treating a karsted formation containing heavy hydrocarbons, comprising:
providing heat to at least part of one or more karsted layers in the formation from one or more heaters located in the karsted layers;
allowing a temperature in at least one of the karsted layers to reach a decomposition temperature of dolomite in the formation;
allowing the dolomite to decompose and produce carbon dioxide;
maintaining the carbon dioxide in the formation to provide a gas cap in an upper portion of at least one of the karsted layers; and producing at least some hydrocarbons from at least one of the karsted layers of the formation.
1228. The method of claim 1227, wherein at least a portion of the heaters are turned off and/or down after creating the gas cap.
1229. The method of claim 1227, further comprising providing at least some heat to the formation using a drive fluid.
1230. The method of claim 1227, further comprising operating the heaters at substantially full power until the gas cap is provided.
1231. The method of claim 1227, further comprising maintaining the pressure in the formation below a fracture pressure of the formation by removing at least some fluids from the formation.
1232. The method of claim 1227, further comprising producing at least some mobilized hydrocarbons from the formation, at least some visbroken hydrocarbons from the formation, and/or at least some pyrolyzed hydrocarbons from the formation.
1233. The method of claim 1227, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and/or pyrolyzed hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation and/or to vary the total recovery of hydrocarbons from the formation.
1234. The method of claim 1227, wherein the provided heat mobilizes and/or pyrolyzes at least some hydrocarbons in the formation.
1235. The method of claim 1227, wherein the hydrocarbons produced from the formation include at least some hydrocarbons from the upper portion of the karsted layers.
1236. The method of claim 1227, further comprising controlling the temperature and the pressure in at least a portion of the formation such that (a) at least a majority of the hydrocarbons in the formation are mobilized, (b) the pressure is below the fracture pressure of the portion of the formation, and (c) at least some hydrocarbons in the portion of the formation form a fluid comprising mobilized hydrocarbons that can be produced through a production well.
1237. The method of claim 1227, further comprising using the produced fluids to make a transportation fuel.
1238. A method for treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the heaters to at least a portion of the formation such that a drive fluid is produced in situ in the formation;
allowing the drive fluid to move at least some mobilized, visbroken, and/or pyrolyzed hydrocarbons from a first portion of the formation to a second portion of the formation; and producing at least some of the mobilized, visbroken, and/or pyrolyzed hydrocarbons from the formation.
1239. The method of claim 1238, wherein the drive fluid is steam.
1240. The method of claim 1238, further comprising transferring heat in the formation using at least some of the drive fluid.
1241. The method of claim 1238, further comprising operating the heaters at substantially full power until the drive fluid is produced.
1242. The method of claim 1238, further comprising maintaining a pressure in the formation below a fracture pressure of the formation.
1243. The method of claim 1238, further comprising varying the amount of mobilized hydrocarbons, visbroken hydrocarbons, and/or pyrolyzed hydrocarbons produced from the formation to vary a quality of the fluids produced from the formation and/or to vary the total recovery of hydrocarbons from the formation.
1244. The method of claim 1238, wherein the provided heat mobilizes, visbreaks, and/or pyrolyzes at least some hydrocarbons in the formation.
1245. The method of claim 1238, wherein the drive fluid mobilizes, visbreaks, and/or pyrolyzes at least some hydrocarbons in the formation.
1246. The method of claim 1238, further comprising controlling the temperature and the pressure in at least a portion of the formation such that (a) at least a majority of the hydrocarbons in the formation are mobilized, (b) the pressure is below the fracture pressure of the portion of the formation, and (c) at least some hydrocarbons in the portion of the formation form a fluid comprising mobilized hydrocarbons that can be produced through a production well.
1247. A method for treating a hydrocarbon containing formation, comprising:
providing heat to a first section of the formation with one or more first heaters in the first section;
heating first hydrocarbons in the first section such that at least some of the first hydrocarbons are mobilized;
producing at least some of the mobilized first hydrocarbons through a production well located in a second section of the formation, the second section being located substantially adjacent to the first section, wherein a portion of the second section is provided some heat from the mobilized first hydrocarbons but is not conductively heated by heat from the first heaters;
and providing heat to the second section with one or more second heaters in the second section to further heat the second section.
1248. The method of claim 1247, further comprising heating second hydrocarbons in the second section such that at least some of the second hydrocarbons are mobilized, and producing at least some of the mobilized second hydrocarbons from the second section, wherein at least some of the hydrocarbons in the mobilized second hydrocarbons were initially located in the second section.
1249. The method of claim 1247, further comprising transferring heat to the second section by allowing the mobilized first hydrocarbons to flow from the first section to the second section.
1250. The method of claim 1247, wherein at least some heat from the mobilized first hydrocarbons is convectively transferred to the portion of the second section of the formation proximate the production well.
1251. The method of claim 1247, wherein the portion of the second section is proximate the production well.
1252. The method of claim 1247, wherein the one or more first heaters conductively heat the first section.
1253. The method of claim 1247, wherein the one or more second heaters conductively heat the second section.
1254. The method of claim 1247, wherein the provided heat increases the permeability of the first section and/or the second section.
1255. The method of claim 1247, wherein the provided heat pyrolyzes at least some hydrocarbons in the first section and/or the second section.
1256. The method of claim 1247, further comprising dewatering the first section and/or the second section prior to providing heat to the formation.
1257. The method of claim 1247, wherein the volume of the first section is between about 70%
and about 130% of the volume of the second section.
1258. The method of claim 1247, further comprising injecting a fluid into the first section to move at least some of the first hydrocarbons into the second section.
1259. The method of claim 1247, wherein superposition of heat from the first heaters does not overlap the portion proximate the production well in the second section.
1260. The method of claim 1247, further comprising controlling a temperature of the portion proximate the production well in the second section so that the temperature is at most about 200 c.
1261. The method of claim 1247, further comprising reducing or turning off production in the production well in the second section when a temperature in the portion proximate the production well reaches a temperature of about 200 C.
1262. The method of claim 1247, further comprising:
heating second hydrocarbons in the second section such that at least some of the second hydrocarbons are mobilized; and producing at least some of the mobilized second hydrocarbons through a production well located in a third section of the formation, wherein a portion of the third section proximate the production well is provided some heat from the mobilized second hydrocarbons.
1263. The method of claim 1262, wherein the third section of the formation is located substantially adjacent to the second section of the formation.
1264. The method of claim 1262, wherein the third section of the formation is not conductively heated by heat from the second heaters.
1265. The method of claim 1262, further comprising providing heat to the third section with one or more third heaters in the third section to further heat the third section.
1266. The method of claim 1262, further comprising heating third hydrocarbons in the third section such that at least some of the third hydrocarbons are mobilized, and producing at least some of the mobilized third hydrocarbons from the third section, wherein at least some of the hydrocarbons in the mobilized third hydrocarbons were initially located in the third section.
1267. The method of claim 1262, further comprising reducing or turning off production in the second section after production in the third section has started.
1268. A method for treating a hydrocarbon containing formation using a checkerboard pattern, comprising:
providing heat to two or more first sections of the formation with one or more first heaters in two or more of the first sections such that the provided heat mobilizes first hydrocarbons in two or more of the first sections;
producing at least some of the mobilized first hydrocarbons through production wells located in two or more second sections of the formation, the first sections and the second sections being arranged in a checkerboard pattern, the checkerboard pattern having at least one of the first sections substantially surrounded by three or more of the second sections and at least one of the second sections substantially surrounded by three or more of the first sections;
wherein a portion of at least one of the second sections proximate at least one production well is provided some heat from the mobilized first hydrocarbons but is not conductively heated by heat from the first heaters; and providing heat to the second sections with one or more second heaters in the second sections to further heat the second sections.
1269. The method of claim 1268, further comprising heating second hydrocarbons in the second sections such that at least some of the second hydrocarbons are mobilized, and producing at least some of the mobilized second hydrocarbons from the second sections, wherein at least some of the hydrocarbons in the mobilized second hydrocarbons were initially located in the second sections.
1270. The method of claim 1268, further comprising transferring heat to the second sections by allowing the mobilized first hydrocarbons to flow from the first sections to the second sections.
1271. The method of claim 1268, wherein at least some heat from the mobilized first hydrocarbons is convectively transferred to the portion of the second section of the formation proximate the production well.
1272. The method of claim 1268, wherein the one or more first heaters conductively heat the first sections.
1273. The method of claim 1268, wherein the one or more second heaters conductively heat the second sections.
1274. The method of claim 1268, wherein the provided heat increases the permeability of at least one of the first sections and/or at least one of the second sections.
1275. The method of claim 1268, wherein the provided heat pyrolyzes at least some hydrocarbons in the first sections and/or the second sections.
1276. The method of claim 1268, further comprising dewatering at least one of the first sections and/or at least one of the second sections prior to providing heat to the formation.
1277. The method of claim 1268, wherein the volume of at least one of the first sections is between about 70% and about 130% of the volume of at least one of the second sections.
1278. The method of claim 1268, further comprising injecting a fluid into the first sections to move at least some of the first hydrocarbons into the second sections.
1279. The method of claim 1268, wherein superposition of heat from the first heaters does not overlap a portion of at least one of the second sections proximate at least one production well.
1280. The method of claim 1268, further comprising controlling a temperature of a portion of at least one of the second sections proximate at least one production well so that the temperature is at most about 200 C.
1281. The method of claim 1268, further comprising reducing or turning off production in at least one production well in at least one of the second sections when a temperature in a portion proximate the production well reaches a temperature of about 200 C.
1282. A method for treating a hydrocarbon containing formation, comprising:
treating a first zone of the formation;
beginning treatment of a plurality of zones of the formation at selected times after the treatment of the first zone begins, the treatment of at least two successively treated zones beginning at a selected time after treatment of the previous zone begins;

wherein at least two of the successively treated zones are adjacent to the zone treated previously;
wherein the successive treatment of the zones proceeds in an outward, substantially spiral sequence from the first zone so that the treatment of the zones moves substantially spirally outwards towards a boundary of the treatment area;
wherein treatment of at least two of the zones comprises:
providing heat from one or more heaters located in two or more first sections of the zone;
allowing some of the heat to transfer from at least two of the first sections to two or more second sections of the zone;
wherein the first sections and the second sections are arranged in a checkerboard pattern within the zone, the checkerboard pattern having at least one of the first sections substantially surrounded by three or more of the second sections and at least one of the second sections substantially surrounded by three or more of the first sections; and producing at least some hydrocarbons from the second sections, wherein at least some of the hydrocarbons produced in the second sections comprise fluids initially in the first sections.
1283. The method of claim 1282, wherein the first zone is at or near a center of a treatment area.
1284. The method of claim 1282, further comprising providing heat from one or more heaters located in the second sections.
1285. The method of claim 1282, further comprising providing a barrier around at least a portion of the treatment area.
1286. The method of claim 1282, further comprising allowing outer zones of the formation to expand inwards into previously treated zones to inhibit shearing in the formation.
1287. The method of claim 1282, wherein the outward spiral sequence inhibits expansion stresses in the formation.
1288. The method of claim 1282, further comprising providing one or more support portions in the formation between one or more of the zones.
1289. The method of claim 1288, wherein the support portions provide support against geomechanical shifting, shearing, and/or expansion stress in the formation.
1290. The method of claim 1282, further comprising allowing at least some fluids to flow from the first sections to the second sections.
1291. The method of claim 1282, further comprising allowing at least some fluids to flow from the first sections to the second sections to convectively transfer heat from the first sections to the second sections.
1292. The method of claim 1282, wherein the provided heat increases the permeability of at least one of the first sections and/or at least one of the second sections.
1293. The method of claim 1282, wherein the provided heat mobilizes at least some hydrocarbons in the first sections and/or the second sections.
1294. The method of claim 1282, wherein the provided heat pyrolyzes at least some hydrocarbons in the first sections and/or the second sections.
1295. The method of claim 1282, further comprising dewatering at least one of the first sections and/or at least one of the second sections prior to providing heat to the formation.
1296. The method of claim 1282, wherein the volume of at least one of the first sections is between about 70% and about 130% of the volume of at least one of the second sections.
1297. The method of claim 1282, further comprising injecting a fluid into the first sections to move at least some of the hydrocarbons into the second sections.
1298. The method of claim 1282, wherein superposition of heat from the first heaters does not overlap a portion of at least one of the second sections proximate at least one production well.
1299. The method of claim 1282, further comprising controlling a temperature of a portion of at least one of the second sections proximate at least one production well so that the temperature is at most about 200 C.
1300. The method of claim 1282, further comprising reducing or turning off production in at least one production well in at least one of the second sections when a temperature in a portion proximate the production well reaches a temperature of about 200 C.
1301. A method of using geothermal energy to treat a subsurface treatment area containing or proximate to hydrocarbons, comprising:
producing geothermally heated fluid from at least one subsurface region;
transferring heat from at least a portion of the geothermally heated fluid to the subsurface treatment area to heat the subsurface treatment area; and producing a fluid comprising hydrocarbons.
1302. The method of claim 1301, wherein the geothermally heated fluid is produced from a geothermally pressurized geyser.
1303. The method of claim 1301, wherein the geothermally heated fluid is pumped from the subsurface region.
1304. The method of claim 1301, wherein the subsurface region is located below a subsurface treatment area.
1305. The method of claim 1301, wherein producing the geothermally heated fluid comprises introducing fluid into a hot layer of the region so that heat is transferred from the hot layer to the fluid, and producing at least a portion of the fluid heated by the hot layer.
1306. The method of claim 1301, wherein transferring heat from the geothermally heated fluid to the subsurface treatment area comprises circulating the geothermally heated fluid through wells in the subsurface treatment area.
1307. The method of claim 1301, wherein transferring heat from the geothermally heated fluid to the subsurface treatment area comprises introducing at least a portion of the geothermally heated fluid directly into the subsurface treatment area.
1308. The method of claim 1301, further comprising using at least a portion of the geothermally heated fluid to provide heat to the subsurface treatment area for solution mining.
1309. The method of claim 1301, further comprising introducing at least a portion of the geothermally heated fluid as a first fluid of a solution mining process and producing a second fluid from the formation, wherein the second fluid contains at least some minerals dissolved in the first fluid.
1310. The method of claim 1301, further comprising using the geothermally heated fluid to preheat at least a section of the subsurface treatment area and using heat sources to provide additional heat to the section to heat the section above a pyrolyzation temperature of hydrocarbons in the treatment area.
1311. The method of claim 1301, further comprising using the geothermally heated fluid to preheat at least a section of the subsurface treatment area and using heat sources to provide additional heat to the section to heat the section above a mobilization temperature of hydrocarbons in the treatment area.
1312. The method of claim 1301, further comprising directing the geothermally heated fluid to the subsurface treatment area without first producing the geothermally heated fluid to the surface.
1313. A method comprising:
heating a treatment area of a subsurface formation by transfer of heat from a geothermally heated fluid to the treatment area; and producing the geothermally heated fluid from a layer of the formation located below the treatment area.
1314. The method of claim 1313, further comprising introducing at least a portion of the geothermally heated fluid as a first fluid of a solution mining process and producing a second fluid from the formation, wherein the second fluid contains at least some minerals dissolved in the first fluid.
1315. A method for heating at least a portion of a subsurface treatment area, comprising:
introducing a fluid into a geothermal subsurface layer to transfer heat from the geothermal layer to the fluid;
producing at least a portion of the geothermally heated fluid, wherein the produced geothermally heated fluid is at a temperature higher than the temperature of the fluid introduced into the geothermal layer; and transferring heat from at least a portion of the geothermally heated fluid to the treatment area.
1316. The method of claim 1315, wherein transferring heat from the geothermally heated fluid to the treatment area comprises circulating geothermally heated fluid through wells in the treatment area.
1317. The method of claim 1315, wherein transferring heat from the geothermally heated fluid to the treatment area comprises introducing at least a portion of the geothermally heated fluid directly into the treatment area.
1318. The method of claim 1315, further comprising using the geothermally heated fluid to provide heat to the formation for solution mining.
1319. The method of claim 1315, further comprising using the geothermally heated fluid to preheat at least a section of the treatment area and using heat sources to provide additional heat to the section above a pyrolysis temperature of hydrocarbons in the treatment area.
1320. The method of claim 1315, further comprising directing the geothermally heated fluid to the treatment area without first producing the geothermally heated fluid to the surface.
1321. A method for treating a subsurface treatment area in a formation, comprising:
introducing a fluid into the formation from a plurality of wells offset from a treatment area of an in situ heat treatment process to inhibit outward migration of formation fluid from the in situ heat treatment process.
1322. The method of claim 1321, wherein a barrier is offset from the plurality of wells used to introduce the fluid into the formation.
1323. The method of claim 1321, wherein the fluid comprises carbon dioxide.
1324. The method of claim 1321, wherein the fluid comprises water.
1325. The method of claim 1321, further comprising providing heat to at least a portion the formation adjacent to at least one of the plurality of wells from one or more heat sources.
1326. The method of claim 1321, further comprising providing heat to at least a portion the formation adjacent to a well of the plurality of wells from one or more heat sources positioned in the well, wherein the one or more heat sources are configured to provide heat without raising the average temperature of a portion of the formation above a pyrolysis temperature of hydrocarbons in the formation or a dissociation temperature of minerals in the formation.
1327. The method of claim 1321, further comprising providing heat to at least a portion of the formation adjacent to at least one well of the plurality of wells from one or more heater wells in the formation that are offset from the plurality of wells, wherein the one or more heater wells are configured to provide heat without raising the formation above a pyrolysis temperature of hydrocarbons in the formation or a dissociation temperature of minerals in the formation.
1328. A method of treating a subsurface treatment area in a formation, comprising:
heating a treatment area as part of an in situ heat treatment process; and introducing a fluid into the formation outside of the treatment area to inhibit migration of formation fluid from the treatment area.
1329. The method of claim 1328, wherein the fluid comprises carbon dioxide.
1330. The method of claim 1328, wherein the fluid comprises low molecular weight hydrocarbon gases.
1331. The method of claim 1328, wherein the fluid is introduced into the formation in an area between a barrier and the treatment area.
1332. The method of claim 1328, wherein introducing the fluid into the formation comprises injecting the fluid into one or more permeable zones in the formation.
1333. The method of claim 1328, wherein introducing the fluid into the formation comprises injecting the fluid into one or more permeable zones in the formation through one or more injection wells, and further comprising heating a portion of the formation adjacent to one or more of the injection wells.
1334. The method of claim 1333, wherein heating the portion of the formation adjacent to one or more of the injection wells comprises providing heat from one or more heat sources to raise an average temperature of the heated portion to a temperature less than a pyrolysis temperature of hydrocarbons in the portion.
1335. A method for treating a subsurface treatment area in a formation, comprising:
providing a plurality of wells offset from a treatment area of an in situ heat treatment area process;

wherein at least some of the plurality of wells are injection wells configured to introduce fluid into the formation to inhibit migration of formation fluid from the in situ heat treatment process; and wherein at least some of the plurality of wells are configured to heat a portion of the formation adjacent to the injection wells.
1336. The method of claim 1335, wherein the fluid comprises carbon dioxide.
1337. The method of claim 1335, wherein the fluid comprises low molecular weight hydrocarbon gases.
1338. The method of claim 1335, wherein one of more of the injection wells are configured to introduce the fluid into one or more permeable zones of the formation.
1339. The method of claim 1335, further comprising forming a barrier offset from the plurality of wells, wherein the plurality of wells are positioned between the barrier and the treatment area.
1340. The method of claim 1339, wherein the barrier comprises a low temperature zone formed by freeze wells.
1341. An in situ heat treatment system for producing hydrocarbons from a subsurface formation, comprising:
a plurality of wellbores in the formation;
piping positioned in at least two of the wellbores;
a fluid circulation system coupled to the piping; and a heat supply configured to heat a liquid heat transfer fluid circulated by the circulation system through the piping to heat the temperature of the formation to temperatures that allow for hydrocarbon production from the formation.
1342. The system of claim 1341, wherein the heat supply comprises a nuclear reactor.
1343. The system of claim 1341, wherein the heat supply comprises a gas burning furnace.
1344. The system of claim 1341, wherein the heat transfer fluid comprises a molten salt.
1345. The system of claim 1341, wherein the heat transfer fluid comprises a molten metal.
1346. The system of claim 1341, further comprising one or more electric heaters positioned in the piping, the electric heaters configured to initially provide at least a portion of the heat needed to inhibit solidification of the liquid heat transfer fluid in the piping.
1347. The system of claim 1341 further comprising coupling one or more conductors to the piping, the conductors configured to apply electricity to the piping to resistively heat the piping to initially provide at least a portion of the heat needed to inhibit solidification of the liquid heat transfer fluid in the piping.
1348. The system of claim 1341, wherein the circulation system comprises a gas lift system configured to return molten salt to the surface.
1349. A method of heating a subsurface formation, comprising:
heating a liquid heat transfer fluid using heat exchange with a heat supply;
circulating the liquid heat transfer fluid through piping in the formation to heat a portion of the formation to allow hydrocarbons to be produced from the formation; and producing hydrocarbons from the formation.
1350. The method of claim 1349, wherein the heat supply comprises a nuclear reactor.
1351. The method of claim 1349, wherein the liquid heat transfer fluid comprises a molten salt.
1352. The method of claim 1349, further comprising returning the liquid heat transfer fluid to the surface using a gas lift system.
1353. The method of claim 1349, further comprising heating the piping to a temperature sufficient to inhibit solidification of the liquid heat transfer fluid in the piping using one or more electrical heaters.
1354. The method of claim 1353, wherein heating the piping using one or more electrical heaters comprises flowing current through the piping to resistively heat the piping.
1355. The method of claim 1353, wherein heating the piping using one more electrical heaters comprises placing a insulated conductor heater in or more portions of the piping and heating the insulated conductor heater to heat the piping.
1356. A method of heating a subsurface formation, comprising:
passing a liquid heat transfer fluid from a vessel to a heat exchanger;
heating the liquid heat transfer fluid to a first temperature;
flowing the liquid heat transfer fluid through a heater section to a sump, wherein heat transfers from the heater section to a treatment area in the formation;
gas lifting the liquid heat transfer fluid to the surface from the sump; and returning at least a portion of the liquid heat transfer fluid to the vessel.
1357. The method of claim 1356, wherein the liquid heat transfer fluid comprises a molten salt.
1358. The method of claim 1356, wherein a fluid used to gas lift the liquid heat transfer fluid comprises carbon dioxide.
1359. The method of claim 1356, wherein a fluid used to gas lift the liquid heat transfer fluid comprises methane.
1360. The method of claim 1356, wherein the liquid heat transfer fluid is gas lifted from the sump through a conduit, and further comprising heating the conduit to inhibit solidification of the liquid heat transfer fluid in the conduit.
1361. The method of claim 1356, wherein the heat exchanger comprises one or more gas burners.
1362. The method of claim 1356, wherein the heat exchanger comprises a tube-in-shell heat exchanger configured to transfer heat from a hot stream produced by a nuclear reactor.
1363. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel line positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit, wherein at least one of the oxidizers comprises:
a mix chamber for mixing fuel from the fuel conduit with a oxidizing fluid;
an igniter;
an ignition chamber;
a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit; and at least one flame stabilizer coupled to the shield.
1364. The assembly of claim 1363, further comprising a water conduit coupled to the fuel conduit, the water conduit configured to deliver water that inhibits coking of fuel to the fuel conduit before a first oxidizer in the gas burner assembly.
1365. The assembly of claim 1363, wherein a flame stabilizer comprises a ring.
1366. The assembly of claim 1363, wherein a flame stabilizer comprises a partial ring.
1367. The assembly of claim 1363, wherein a flame stabilizer comprises a ring that angles at least partially over one or more of the openings.
1368. The assembly of claim 1363, wherein a flame stabilizer comprises a ring that angles away from one or more of the openings.
1369. The assembly of claim 1363, wherein a flame stabilizer comprises a rounded deflector.
1370. The assembly of claim 1363, wherein a flame stabilizer comprises a louvered opening in the shield with an extension that directs gas entering the shield in a desired direction.
1371. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel conduit positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit, wherein at least one of the oxidizers comprises:
a mix chamber for mixing fuel from the fuel conduit with oxidizing fluid;

an catalyst chamber configured to produce hot reaction products to ignite fuel and oxidizing fluid;
an ignition chamber; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit.
1372. The assembly of claim 1371, further comprising a water conduit coupled to the fuel conduit, the water line configured to deliver water that inhibits coking of fuel to the fuel conduit before a first oxidizer in the gas burner assembly.
1373. The assembly of claim 1371, wherein a catalyst in the catalyst chamber comprises palladium on a ceramic support.
1374. The assembly of claim 1371, further comprising one or more rings coupled to an inside surface of the shield as a flame stabilizer.
1375. The assembly of claim 1371, further comprising a plurality of partial rings coupled to an inside surface of the shield as a flame stabilizer.
1376. The assembly of claim 1371, further comprising one or more rings coupled to an inside surface of the heat shield, wherein at least one ring is angled relative to the shield so that the ring extends towards one or more of the openings adjacent to the ring.
1377. The assembly of claim 1371, further comprising a plurality of rounded deflectors coupled to an inside surface of the shield downstream of one or more of the openings as flame stabilizers.
1378. A gas burner assembly for heating a subsurface formation, comprising:
an oxidant conduit;
a fuel line positioned in the oxidant conduit; and a plurality of oxidizers coupled to the fuel conduit, wherein at least one of the oxidizers comprises:
a mix chamber for mixing fuel from the fuel conduit with oxidizing fluid;
an igniter in the mix chamber configured to ignite fuel and oxidizing fluid to preheat fuel and oxidizing fluid;
a catalyst chamber configured to react preheated fuel and oxidizing fluid from the mix chamber to produce hot reaction products to ignite fuel and oxidizing fluid;
an ignition chamber; and a shield, wherein the shield comprises a plurality of openings in communication with the oxidant conduit.
1379. The assembly of claim 1378, further comprising a water conduit coupled to the fuel conduit, the water line configured to deliver water that inhibits coking of fuel to the fuel conduit before a first oxidizer in the gas burner assembly.
1380. The assembly of claim 1378, wherein a catalyst in the catalyst chamber comprises palladium on a ceramic support.
1381. The assembly of claim 1378, further comprising one or more rings coupled to an inside surface of the shield as a flame stabilizer.
1382. The assembly of claim 1378, further comprising a plurality of partial rings coupled to an inside surface of the shield as a flame stabilizer.
1383. The assembly of claim 1378, further comprising one or more rings coupled to an inside surface of the heat shield, wherein at least one ring is angled relative to the shield so that the ring extends towards one or more of the openings adjacent to the ring.
1384. A method for forming two or more wellbores in a subsurface formation, comprising:
forming a first wellbore in the formation;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
providing at least one magnetic field in the second wellbore using one or more magnets in the second wellbore located on a drilling string used to drill the second wellbore;
sensing at least one magnetic field in the first wellbore using at least two sensors in the first wellbore as the magnetic field passes by the at least two sensors while the second wellbore is being drilled;
continuously assessing a position of the second wellbore relative to the first wellbore using the sensed magnetic field; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1385. The method of claim 1384, wherein the second wellbore is formed substantially parallel to the first wellbore.
1386. The method of claim 1384, further comprising moving the at least two sensors after sensing the magnetic field so that the sensors are allowed to sense the magnetic field at a second position while drilling the second wellbore.
1387. The method of claim 1384, further comprising providing at least two magnetic fields with at least two magnets in the second wellbore.
1388. The method of claim 1384, wherein the at least two sensors are positioned in advance of the sensed magnetic field so that the sensors sense the magnetic field as the magnetic field passes the sensors.
1389. The method of claim 1384, wherein the at least two sensors are positioned in advance of the sensed magnetic field so that the sensors may be set to "null" the background magnetic field allowing direct measurement of the reference magnetic field as it passes the sensors.
1390. The method of claim 1384, further comprising continuously adjusting the direction of drilling of the second wellbore using the continuously assessed position of the second wellbore relative to the first wellbore.
1391. A method for forming two or more wellbores in a subsurface formation, comprising:
forming at least a first wellbore in the formation;
providing a voltage signal to the first wellbore;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
continuously sensing the voltage signal in the second wellbore;
continuously assessing a position of the second wellbore relative to the first wellbore using the sensed voltage signal; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1392. The method of claim 1391, further comprising:
providing the voltage signal to the first wellbore and a third wellbore, wherein the second wellbore is positioned substantially adjacent the first wellbore; and creating an electrical current and magnetic field signal.
1393. The method of claim 1391, wherein the provided voltage signal creates a magnetic field.
1394. The method of claim 1391, wherein the second wellbore is formed substantially parallel to the first wellbore.
1395. The method of claim 1391, wherein the voltage signal comprises a pulsed direct current (DC) signal.
1396. The method of claim 1391, further comprising providing the voltage signal through an electrical conductor that is to be used as a heater in the first wellbore.
1397. The method of claim 1391, further comprising continuously adjusting the direction of drilling of the second wellbore using the continuously assessed position of the second wellbore relative to the first wellbore.
1398. A method for forming two or more wellbores in a subsurface formation, comprising:

forming a first wellbore in the formation;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
providing an electromagnetic wave in the second wellbore;
continuously sensing the electromagnetic wave in the first wellbore using at least one electromagnetic antenna;
continuously assessing a position of the second wellbore relative to the first wellbore using the sensed electromagnetic wave; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1399. The method of claim 1398, wherein the second wellbore is formed substantially parallel to the first wellbore.
1400. The method of claim 1398, further comprising providing the electromagnetic wave using an electromagnetic sonde.
1401. The method of claim 1398, wherein the antenna is located in a heater that is to be used to provide heat in the first wellbore.
1402. The method of claim 1398, further comprising continuously adjusting the direction of drilling of the second wellbore using the continuously assessed position of the second wellbore relative to the first wellbore.
1403. A method for forming two or more wellbores in a subsurface formation, comprising:
forming a first wellbore in the formation;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
transmitting a first electromagnetic wave from a first transceiver in the first wellbore and sensing the first electromagnetic wave using a second transceiver in the second wellbore;
transmitting a second electromagnetic wave from the second transceiver in the second wellbore and sensing the second electromagnetic wave using the first transceiver in the first wellbore;
continuously assessing a position of the second wellbore relative to the first wellbore using the sensed first electromagnetic wave and the sensed second electromagnetic wave; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1404. The method of claim 1403, further comprising assessing natural electromagnetic fields using a third transceiver positioned at a distal end of the first wellbore.
1405. The method of claim 1403, wherein the first transceiver is coupled to a surface of the formation.
1406. The method of claim 1403, wherein the first transceiver is directly coupled to a surface of the formation via a wire.
1407. The method of claim 1403, wherein the first transceiver is directly coupled to a surface of the formation via a wire.
1408. A method for forming two or more wellbores in a subsurface formation, comprising:
forming a plurality of first wellbores in the formation;
providing a plurality of electromagnetic waves in the first wellbores;
directionally drilling one or more second wellbores in a selected relationship relative to the first wellbores;
continuously sensing the electromagnetic waves in the first wellbores using at least one electromagnetic antenna in the second wellbores;
continuously assessing a position of the second wellbores relative to the first wellbores using the sensed electromagnetic waves; and adjusting the direction of drilling of at least one of the second wellbores so that the second wellbore remains in the selected relationship relative to the first wellbores.
1409. The method of claim 1408, wherein at least one of the second wellbores is formed substantially perpendicular to at least one of the first wellbores.
1410. The method of claim 1408, further comprising providing the electromagnetic waves using electromagnetic sondes.
1411. The method of claim 1408, wherein the antenna is located in a heater that is to be used to provide heat in at least one of the second wellbores.
1412. The method of claim 1408, further comprising continuously adjusting the direction of drilling of at least one of the second wellbores using the continuously assessed position of the second wellbore relative to the first wellbore.
1413. A method for forming two or more wellbores in a subsurface formation, comprising:
forming a first wellbore in the formation;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
providing an electromagnetic field in the first wellbore using one or more magnets;
continuously sensing the electromagnetic field in the first wellbore using at least one electromagnetic field sensor positioned in the second wellbore;

continuously assessing a position of the second wellbore relative to the first wellbore using the sensed electromagnetic field; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1414. The method of claim 1413, further comprising continuously adjusting the direction of drilling of the second wellbore using the continuously assessed position of the second wellbore relative to the first wellbore.
1415. A method for forming two or more wellbores in a subsurface formation, comprising:
forming a first wellbore in the formation;
directionally drilling a second wellbore in a selected relationship relative to the first wellbore;
providing an electromagnetic field in the second wellbore using one or more magnets;
continuously sensing the electromagnetic field in the second wellbore using at least one electromagnetic field sensor positioned in the first wellbore;
continuously assessing a position of the second wellbore relative to the first wellbore using the sensed electromagnetic field; and adjusting the direction of drilling of the second wellbore so that the second wellbore remains in the selected relationship relative to the first wellbore.
1416. The method of claim 1415, further comprising continuously adjusting the direction of drilling of the second wellbore using the continuously assessed position of the second wellbore relative to the first wellbore.
1417. The method of claim 1415, further comprising calibrating the sensors to adjust for natural magnetic fields positioned adjacent the first wellbore.
1418. A system for forming wellbores in a formation, comprising:
composite coiled tubing;
a particle jet drilling nozzle coupled to the coiled tubing;
a downhole electric orienter coupled to the particle jet drilling nozzle;
downhole inertial navigation system coupled to the composite tubing; and a computer system coupled to the downhole inertial navigation system and the downhole electric orienter to control the direction of the opening formed by particles passing through the particle jet drilling nozzle.
1419. The system of claim 1418, further comprising bubble entrained mud as the drilling fluid.
1420. The system of claim 1419, wherein the computer system is used to control the density of the bubble entrained mud as a function of real time gains and losses of fluid while drilling.
1421. The system of claim 1418, further comprising a multiphase fluid as the drilling fluid.
1422. The system of claim 1418, wherein the downhole inertial navigation system provides depth, azimuth and inclination information to the computer system.
1423. The system of claim 1418, wherein power for the downhole electric orienter is provided through a power line formed in the composite coiled tubing.
1424. The system of claim 1418, further comprising steel abrasives as particles used to form the wellbore.
1425. The system of claim 1424, further comprising a magnetic separator for separating steel abrasives from drilling fluid.
1426. The system of claim 1418, further comprising one or more piston membrane pumps used to move drilling fluid.
1427. The system of claim 1418, further comprising one or more annular pressure exchange pumps.
1428. A method for forming wellbores in a formation comprising:
flowing particles entrained in drilling fluid down composite coil tubing;
passing particles through one or more nozzles to impinge upon formation and remove material from the formation to extend an opening in the formation;
using a downhole inertial navigation system to provide at least depth, azimuth and inclination information to a computer system;
sending control information from a computer system to a downhole electric orienter; and adjusting the position of the one or more nozzles to form the opening in the desired direction using the downhole electric orienter.
1429. The method of claim 1428, further comprising transferring data to and from the computer system in data lines built into the composite coil tubing.
1430. The method of claim 1428, further comprising powering downhole components through power lines built into the composite coil tubing.
1431. The method of claim 1428, further comprising pumping drilling fluid using one or more piston member pumps.
1432. The method of claim 1428, further comprising pumping drilling fluid using one or more annular pressure exchange pumps.
1433. The method of claim 1428, wherein the drilling fluid comprises a multiphase fluid, and further comprising using the computer system to control injection rates of gas and/or liquid comprising the multiphase fluid.
1434. A method, comprising:

coupling a robot to coiled tubing positioned in a wellbore, wherein the robot comprises one or more batteries;
moving the robot down the coiled tubing to the bottom hole assembly in the borehole;
electrically coupling the robot to the bottom hole assembly to charge the one or more batteries of the robot;
decoupling the robot from the bottom hole assembly; and using the robot to perform a task in the wellbore.
1435. The method of claim 1434, wherein the robot is a tractor robot, and using the robot to apply force to formation adjacent to the wellbore and to apply force to the bottom hole assembly to move the bottom hole assembly.
1436. The method of claim 1434, wherein the task comprises surveying the position of the bottom hole assembly.
1437. The method of claim 1434, wherein task comprises removing cuttings.
1438. The method of claim 1434, wherein the task comprises logging.
1439. The method of claim 1434, wherein the task comprises pipe freeing.
1440. A method for forming a wellbore in a heated formation, comprising:
flowing liquid drilling fluid to a bottom hole assembly;
vaporizing at least a portion of the drilling fluid at or near a drill bit;
and removing the drilling fluid and cuttings from the wellbore.
1441. The method of claim 1440, further comprising maintaining a high pressure on the drilling fluid flowing to the drill bit to maintain the drilling fluid in a liquid phase.
1442. The method of claim 1440, wherein the drilling fluid is directed down the drill pipe to the drill bit using conventional circulation.
1443. The method of claim 1440, wherein the drilling fluid is directed to the drill bit using reverse circulation.
1444. The method of claim 1440, wherein the drilling fluid provided to the bottom hole assembly is a two-phase mixture comprising a non-condensable gas in a liquid.
1445. The method of claim 1440, further comprising lifting the cuttings at least partially using pressure and velocity resulting from phase change of drilling fluid to vapor.
1446. The method of claim 1440, further comprising removing heat from the drill bit by vaporizing drilling fluid.
1447. The method of claim 1440, further comprising controlling down hole pressure by maintaining a desired back pressure on the drilling fluid.
1448. A method for forming a wellbore in a heated formation, comprising:

flowing a two-phase drilling fluid to a bottom hole assembly;
vaporizing at least a portion of a liquid phase of the two-phase drilling fluid at or near a drill bit; and removing cuttings and the drilling fluid from the wellbore.
1449. The method of claim 1448, further comprising maintaining a high pressure on the drilling fluid flowing to the drill bit to maintain the a liquid phase of the drilling fluid as a liquid.
1450. The method of claim 1448, wherein the drilling fluid is directed down the drill pipe to the drill bit using conventional circulation.
1451. The method of claim 1448, wherein the drilling fluid is directed to the drill bit using reverse circulation.
1452. The method of claim 1448, further comprising lifting the cuttings partially using pressure and velocity resulting from phase change of drilling fluid to vapor.
1453. The method of claim 1448, further comprising removing heat from the drill bit by vaporizing drilling fluid.
1454. The method of claim 1448, further comprising controlling down hole pressure by maintaining a desired back pressure on the drilling fluid.
1455. A system for forming a wellbore in a heated formation, comprising:
drilling fluid;
a drill bit configured to form an opening in the formation;
a drill pipe coupled to the drill bit, the drill pipe configured to transport drilling fluid to the drill bit and facilitate removal of drilling fluid and cuttings from the wellbore; and a pressure activated valve coupled to the drilling pipe, the pressure activated valve configured to maintain a high pressure on the drilling fluid flowing to the drill bit so that a portion of the drilling fluid directed to the drilling bit is in a liquid phase.
1456. The system of claim 1455, further comprising one or more chokes coupled to the drill pipe, wherein at least one of the chokes is configured to maintain a high pressure on the drilling fluid flowing to the drill bit so that a portion of the drilling fluid is in a liquid phase.
1457. The system of claim 1456, wherein at least one of the chokes comprises a jet nozzle.
1458. The system of claim 1456, wherein at least one of the chokes comprises an orifice.
1459. The system of claim 1455, wherein the drilling fluid provided to the drill bit comprises a two-phase mixture of a non-condensable gas added to a liquid.
1460. The system of claim 1455, wherein the drilling fluid comprises nitrogen.
1461. A conduit for flowing a refrigerant in a wellbore used to form a low temperature zone in a formation, comprising:

a plastic conduit;
an outer sleeve configured to couple to plastic conduit; and an inner sleeve positioned in the outer sleeve, wherein the inner sleeve is in fluid communication with the plastic conduit, and wherein the inner sleeve comprises:
a first stop configured to limit insertion depth of the outer sleeve relative the inner sleeve;
one or more openings in the inner sleeve located below a lowermost position of the outer sleeve; and a latch configured to couple to a casing that the conduit is to be positioned in; and wherein thermal contraction of the plastic conduit due to refrigerant flowing through the plastic conduit is compensated by the outer sleeve rising relative to the inner sleeve.
1462. The conduit of claim 1461, wherein the outer sleeve is a metal sleeve.
1463. The conduit of claim 1461, wherein the inner sleeve is a metal sleeve.
1464. The conduit of claim 1461, further comprising a plurality of slip rings coupled to the inner sleeve.
1465. The conduit of claim 1461, further comprising at least one shear pin positioned in openings in the inner sleeve and the outer sleeve to facilitate insertion of the conduit in the casing.
1466. A freeze well for forming a low temperature zone, comprising:
a casing configured to be positioned in a wellbore, the casing comprising a closed bottom end;
a catch secured to the closed bottom end;
an inner conduit configured to be positioned in the casing, the inner conduit comprising:
a plastic conduit;
an outer sleeve coupled to the plastic conduit;
an inner sleeve positioned in the outer sleeve, wherein the inner sleeve is in fluid communication with the plastic conduit, and wherein a portion of the inner sleeve has one or more openings in communication with the casing; and a latch coupled to a bottom portion of the inner sleeve, wherein the latch is configured to engage the catch to releasably couple the inner conduit to the casing.
1467. The freeze well of claim 1466, further comprising a plurality of slip rings coupled to the inner sleeve.
1468. The freeze well of claim 1466, further comprising at least one shear pin positioned in openings in the inner sleeve and the outer sleeve to facilitate insertion of the conduit in the casing.
1469. A method of cooling a portion of a formation adjacent to a freeze well, comprising:
flowing refrigerant downward in an inner conduit positioned in a casing;
returning the refrigerant upwards in a space between the inner conduit and a casing; and accommodating thermal contraction of the inner conduit using a bottom portion of the inner conduit, wherein an inner sleeve of the bottom portion is coupled to the casing, and wherein an outer sleeve is able to move upwards relative to the inner sleeve.
1470. The method of claim 1469, further comprising decoupling the inner sleeve from the casing to remove the inner conduit from the casing.
1471. A method for installing a horizontal or inclined subsurface heater, comprising:
placing a heating section of a heater in a horizontal or inclined section of a wellbore with an installation tool;
uncoupling the tool from the heating section; and mechanically and electrically coupling a lead-in section of the heater to the heating section of the heater, wherein the lead-in section is located in an angled or vertical section of the wellbore.
1472. The method of claim 1471, further comprising removing the tool from the wellbore after uncoupling the tool from the heating section.
1473. The method of claim 1471, wherein the lead-in section has an electrical resistance less than the heating section of the heater.
1474. The method of claim 1471, wherein the lead-in section is mechanically coupled to the heating section using a wet connect stab device.
1475. The method of claim 1471, wherein the heating section comprises a receptacle at one end for accepting and coupling to the lead-in section.
1476. The method of claim 1471, wherein the heater section is mechanically secured in the wellbore with the installation tool.
1477. An electrical insulation system for a subsurface electrical conductor, comprising:
at least three electrical insulators coupled to the electrical conductor, each insulator comprising a metal piece at least partially surrounded by ceramic insulation, the metal piece being connected to the ceramic insulation, and each insulator being coupled to the electrical conductor by connecting the metal piece to the electrical conductor; and the insulators being coupled to the exterior of the electrical conductor so that each insulator is separated from another insulator by a gap at or near the exterior of the electrical conductor.
1478. The system of claim 1477, wherein the gap allows debris to move along the exterior of the electrical conductor in between the insulators.
1479. The system of claim 1477, wherein the electrical conductor comprises a conductor used in a heater.
1480. The system of claim 1477, wherein the gap allows debris to move vertically along the exterior of the electrical conductor.
1481. The system of claim 1477, wherein the insulators are attached to the electrical conductor before the electrical conductor is installed in the subsurface.
1482. The system of claim 1477, wherein the electrical conductor is installed vertically in the subsurface.
1483. The system of claim 1477, wherein at least one metal piece is brazed to the ceramic insulation.
1484. The system of claim 1477, wherein at least one of the electrical insulators is coupled to the electrical conductor by welding or brazing the metal piece to the electrical conductor.
1485. The system of claim 1477, wherein at least one of the electrical insulators is coupled around a circumference of the electrical conductor.
1486. A method for electrically insulating a subsurface electrical conductor, comprising:
coupling at least three electrical insulators around the circumference of the electrical conductor so that each insulator is separated from the another insulator by a gap around the outside surface of the electrical conductor;
wherein each insulator comprising a metal piece surrounded by ceramic insulation, the metal piece being brazed to the ceramic insulation, and each insulator being coupled to the heater by welding the metal piece to the electrical conductor.
1487. A method for treating a subsurface formation using an electrically insulated electrical conductor, comprising:
providing at least one heater comprising:
at least three electrical insulators coupled to the electrical conductor, each insulator comprising a metal piece at least partially surrounded by ceramic insulation, the metal piece being connected to the ceramic insulation, and each insulator being coupled to the electrical conductor by connecting the metal piece to the electrical conductor;

the insulators being coupled to the exterior of the electrical conductor so that each insulator is separated from another insulator by a gap at or near the exterior of the electrical conductor; and heating at least a portion of the subsurface formation by providing electrical current to the heater.
1488. A method for assessing one or more temperatures of an electrically powered subsurface heater, comprising:
assessing an impedance profile of the electrically powered subsurface heater while the heater is being operated in the subsurface; and analyzing the impedance profile with a frequency domain algorithm to assess one or more temperatures of the heater.
1489. The method of claim 1488, wherein the impedance profile is assessed using timed domain reflectometer measurements.
1490. The method of claim 1488, wherein the frequency domain algorithm comprises partial discharge measurement technology.
1491. The method of claim 1488, wherein the impedance profile comprises the impedance profile along the length of the heater.
1492. The method of claim 1488, wherein the frequency domain algorithm utilizes laboratory data for the heater to assess the temperature profile of the heater.
1493. The method of claim 1488, further comprising assessing a temperature profile of the heater.
1494. The method of claim 1488, further comprising using one or more of the temperatures of the heater to assess reactive power consumption of the heater in the subsurface.
1495. The method of claim 1488, further comprising using one or more of the temperatures of the heater to assess real power consumption of the heater in the subsurface.
1496. The method of claim 1488, further comprising using one or more of the temperatures to identify and/or predict failure locations along the length of the heater.
1497. A method for forming a longitudinal subsurface heater, comprising:
longitudinally welding an electrically conductive sheath of an insulated conductor heater along at least one longitudinal strip of metal; and forming the longitudinal strip into a tubular around the insulated conductor heater with the insulated conductor heater welded along the inside surface of the tubular.
1498. The method of claim 1497, wherein forming the longitudinal strip of metal into the tubular comprises rolling the strip of metal into the tubular.
1499. The method of claim 1497, further comprising electrically shorting a distal end of the tubular to a distal end of the sheath and a center conductor of the insulated conductor heater.
1500. The method of claim 1497, further comprising forming the tubular by welding the longitudinal lengths of the strip of metal together.
1501. The method of claim 1497, further comprising forming the tubular by welding the longitudinal lengths of the strip of metal together at a circumferential location away from the point of contact between the tubular and the insulated conductor heater.
1502. The method of claim 1497, wherein the tubular is formed from a plurality of longitudinal strips of metal.
1503. The method of claim 1497, wherein the insulated conductor heater comprises a center conductor at least partially surrounded by an electrical insulator, and the sheath at least partially surrounding the electrical insulator.
1504. A method for forming a longitudinal subsurface heater, comprising:
longitudinally welding an electrically conductive sheath of an insulated conductor heater along an inside surface of a metal tubular.
1505. The method of claim 1504, wherein the tubular is formed from one or more longitudinal strips of metal.
1506. The method of claim 1504, further comprising electrically shorting a distal end of the tubular to a distal end of the sheath and a center conductor of the insulated conductor heater.
1507. The method of claim 1504, wherein the insulated conductor heater comprises a center conductor at least partially surrounded by an electrical insulator, and the electrically conductive sheath at least partially surrounding the electrical insulator.
1508. A longitudinal subsurface heater, comprising:
an insulated conductor heater, comprising:
an electrical conductor;
an electrical insulator at least partially surrounding the electrical conductor; and an electrically conductive sheath at least partially surrounding the electrical insulator;
a metal tubular at least partially surrounding the insulated conductor heater;
and wherein the sheath of the insulated conductor heater is longitudinally welded along an inside surface of the metal tubular.
1509. The heater of claim 1508, wherein a distal end of the tubular is electrically shorted to a distal end of the sheath and the electrical conductor of the insulated conductor heater.
1510. The heater of claim 1508, wherein the tubular is formed from one or more longitudinal strips of metal.
1511. The heater of claim 1508, wherein the tubular has been formed by welding longitudinal lengths of a strip of metal together.
1512. The heater of claim 1508, wherein the tubular is configured to allow fluids to flow through the tubular.
1513. The heater of claim 1508, wherein the metal tubular is ferromagnetic.
1514. The heater of claim 1508, wherein the electrical conductor comprises copper.
1515. The heater of claim 1508, wherein the electrical insulator comprises magnesium oxide.
1516. The heater of claim 1508, wherein the metal tubular is non-ferromagnetic, and the metal tubular is coated with thin electrically insulating coating.
1517. The heater of claim 1508, wherein the heater is a temperature limited heater.
1518. A method for treating a subsurface formation using an electric heater, comprising:
providing the electric heater to an opening in the subsurface formation, the electric heater comprising:
an insulated conductor heater, comprising:
an electrical conductor;
an electrical insulator at least partially surrounding the electrical conductor; and an electrically conductive sheath at least partially surrounding the electrical insulator;
a metal tubular at least partially surrounding the insulated conductor heater;

wherein the sheath of the insulated conductor heater is longitudinally welded along an inside surface of the metal tubular; and heating the subsurface formation by providing electrical current to the electric heater.
1519. The method of claim 1518, further comprising providing at least one heat transfer fluid to the tubular.
1520. The method of claim 1518, further comprising heating the subsurface formation by providing time-varying electrical current to the electric heater.
1521. A heating system for a subsurface formation, comprising:
three substantially u-shaped heaters, first ends of the heaters being electrically coupled to a single, three-phase wye transformer, second ends of the heaters being electrically coupled to each other and/or to ground;

wherein the three heaters enter the formation through a first common wellbore and exit the formation through a second common wellbore so that the magnetic fields of the three heaters at least partially cancel out in the common wellbores.
1522. The system of claim 1521, wherein at least two of the heaters have heating sections that are substantially parallel in a hydrocarbon layer of the formation.
1523. The system of claim 1521, wherein at least one of the three heaters comprises an exposed metal heating section.
1524. The system of claim 1521, wherein at least one of the three heaters comprises an insulated conductor heating section.
1525. The system of claim 1521, wherein at least one of the three heaters comprises a conductor-in-conduit heating section.
1526. The system of claim 1521, wherein the three heaters comprise 410 stainless steel in heating sections of the heaters, and copper in overburden sections of the heaters.
1527. The system of claim 1521, further comprising a ferromagnetic casing in the overburden section of the first common wellbore.
1528. The system of claim 1521, further comprising a ferromagnetic casing in the overburden section of the second common wellbore.
1529. The system of claim 1521, wherein each heater is coupled to one phase of the transformer.
1530. The system of claim 1521, further comprising multiples of three additional heaters entering through the first common wellbore.
1531. The system of claim 1521, further comprising multiples of three additional heaters entering through the first common wellbore and exiting through the second common wellbore.
1532. The system of claim 1521, wherein at least one of the heaters is used to directionally steer drilling of an opening in the formation used for at least one of the other heaters.
1533. The system of claim 1521, wherein the three heaters are electrically coupled together in the second common wellbore.
1534. The system of claim 1521, wherein the three heaters are located in three openings extending between the first common wellbore and the second common wellbore.
1535. The system of claim 1521, wherein at least one of the three heaters provides different heat outputs along the length of the heater.
1536. The system of claim 1521, wherein at least one of the three heaters has different materials along the length of the heater to provide different heat outputs along the length of the heater.
1537. The system of claim 1521, wherein at least one of the three heaters has different dimensions along the length of the heater to provide different heat outputs along the length of the heater.
1538. A heating system for a subsurface formation, comprising:
a substantially u-shaped electrical conductor extending between a first wellbore and a second wellbore; and a ferromagnetic tubular at least partially surrounding the electrical conductor and spaced from the electrical conductor;
wherein the electrical conductor, when energized with time-varying electrical current, induces electrical current flow in the skin depth of the ferromagnetic tubular.
1539. The system of claim 1538, wherein the tubular comprises carbon steel.
1540. The system of claim 1538, wherein the tubular comprises 410 stainless steel.
1541. The system of claim 1538, wherein the electrical conductor is the core of an insulated conductor.
1542. The system of claim 1538, wherein the tubular has a thickness of at least two times the skin depth of the ferromagnetic material in the tubular.
1543. The system of claim 1538, wherein the tubular is configured to provide different heat outputs along the length of the tubular.
1544. The system of claim 1538, wherein the tubular has different materials along the length of the tubular to provide different heat outputs along the length of the tubular.
1545. The system of claim 1538, wherein the tubular has different dimensions along the length of the tubular to provide different heat outputs along the length of the tubular.
1546. The system of claim 1538, further comprising coating the tubular with a corrosion resistant material.
1547. The system of claim 1538, wherein the tubular is between about 1.5" and about 5" in diameter.
1548. A gas burner assembly, comprising:
an outer conduit;
an oxidant conduit positioned in the outer conduit, wherein exhaust returns to the surface in a space between the oxidant conduit and the outer conduit;
a plurality of oxidizers positioned in the oxidant conduit;
a plurality of fuel conduits positioned in the space between the oxidant conduit and the outer conduit; and one or more taps from the fuel conduit that pass through the oxidant conduit to supply fuel to one or more mix chambers of the plurality of oxidizers.
1549. The gas burner assembly of claim 1548, further comprising one or more igniter supplies positioned in the space between the oxidant conduit and the outer conduit, and one or more igniter taps that pass through the oxidant conduit and into ignition chambers of the plurality of oxidizers.
1550. The gas burner assembly of claim 1548, further comprising one or more igniter supplies positioned in the oxidant conduit, and one or more igniter taps that pass from the one or more igniter supplies to the plurality of oxidizers.
1551. The gas burner assembly of claim 1548, wherein at least one oxidizer of the plurality of oxidizers comprises a mix chamber, wherein the mix chamber receives fuel from one of the plurality of fuel conduits, wherein the mix chamber has one or more openings that receive oxidant from the oxidant conduit, and wherein the mix chamber has an exit to an ignition chamber.
1552. The gas burner assembly of claim 1551, wherein the exit to the ignition chamber is located along a central axis of the oxidizer.
1553. The gas burner assembly of claim 1548, where each fuel conduit of the plurality of fuel conduits supplies fuel to a single oxidizer of the plurality of oxidizers.
1554. The gas burner assembly of claim 1548, where a fuel conduit of the plurality of fuel conduits supplies fuel to two or more oxidizers of the plurality of oxidizers.
1555. A method of heating a portion of a subsurface formation, comprising:
flowing oxidant into an oxidant conduit to supply oxidant to a plurality of oxidizers positioned in the oxidant conduit;
flowing fuel into a plurality of fuel conduits, wherein the fuel conduits are located between the oxidant conduit and an outer conduit;
directing fuel from at least one of the fuel conduits to a mix chamber of each oxidizer;
mixing the fuel and oxidant in the mix chambers to form mixtures; and combusting the mixtures to produce heat.
1556. The method of claim 1555, further comprising returning exhaust through a space between the oxidant conduit and the outer conduit.
1557. The method of claim 1555, wherein each fuel conduit supplies fuel to an oxidizer of the plurality of oxidizers.
1558. The method of claim 1555, wherein at least one fuel conduit supplies fuel to two or more oxidizers of the plurality of oxidizers.
1559. The method of claim 1555, further comprising initiating combustion of the mixtures with one or more igniters.
1560. A method of forming a downhole gas burner, comprising:
coupling a plurality of oxidizers to an oxidant conduit.
placing a fuel tap through the oxidant conduit into a mix chamber of each oxidizer;
coupling the fuel taps to a plurality of fuel conduits;
coupling an igniter conduit to an ignition chamber of one or more of the oxidizers; and placing the oxidant conduit, fuel conduits and igniter conduits in an outer conduit.
1561. The method of claim 1560, further comprising coiling the outer conduit on a reel.
1562. The method of claim 1560, wherein the igniter conduit is positioned inside of the oxidizer conduit.
1563. The method of claim 1560, wherein the igniter conduit is positioned outside of the oxidizer conduit.
1564. The method of claim 1560, wherein one or more of the oxidizers comprise catalyst so that the one or more oxidizers are self-igniting.
1565. A method of heating a formation, comprising:
providing fuel through a fuel conduit to a plurality of oxidizers positioned in a wellbore in the formation;
combusting fuel from the fuel conduit and oxidant from an oxidant conduit in the oxidizers to produce heat that heats fuel in the fuel conduit; and mixing heated fuel from the fuel conduit with oxidant in a section of the oxidant conduit past an oxidizer of the plurality of oxidizers, wherein the heated fuel reacts with oxidant in the oxidant conduit to generate heat.
1566. A method of treating a formation fluid, comprising:
producing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises carbon dioxide, hydrogen sulfide, hydrocarbons, hydrogen, or mixtures thereof; and combusting at least a portion of the first gas stream to provide heat used to heat a treatment area of a formation.
1567. The method of claim 1566, wherein the combusting at least the portion of the first gas stream comprises combusting the gas in a plurality of oxidizer assemblies.
1568. The method of claim 1566, wherein combusting at least a portion of the first gas produces carbon dioxide and/or SO x.
1569. The method of claim 1566, wherein combusting at least a portion of the first gas stream produces carbon dioxide and/or SOX, and further comprising sequestering at least a portion of the carbon dioxide and/or SO x.
1570. The method of claim 1566, wherein combusting at least a portion of the first gas stream produces carbon dioxide, and providing at least a portion of the carbon dioxide to one or more fuel conduits of the one or more downhole burners.
1571. A method of treating a formation fluid, comprising:
providing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises carbon dioxide, hydrogen sulfide, hydrocarbons, hydrogen or mixtures thereof;
separating molecular oxygen from air to form an molecular oxygen stream;
combining the first gas stream with the molecular oxygen stream to form a combined stream comprising molecular oxygen and the first gas stream; and providing the combined stream to one or more downhole burners.
1572. The method of claim 1571, wherein separating the molecular oxygen from air comprises cryogenically distilling the air.
1573. The method of claim 1571, wherein separating the molecular oxygen from air comprises providing the air through one or more separation units operated above -180 C at 0.101 MPa.
1574. The method of claim 1571, wherein separating air comprises forming a nitrogen stream.
1575. The method of claim 1574, further comprising providing the nitrogen to one or more barrier wells.
1576. The method of claim 1574, further comprising providing the nitrogen to one or more processing facilities.
1577. A method of treating formation fluid, comprising:
providing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises carbon dioxide, hydrogen sulfide, hydrocarbons, hydrogen, or mixtures thereof;
applying current to water to form an oxygen stream and a hydrogen stream;
combining the first gas stream with the oxygen stream to form a combined stream comprising molecular oxygen and the first gas stream; and providing the combined stream to one or more downhole burners.
1578. The method of claim 1577, wherein applying current comprising heating the water to a temperature of at least 600 C.
1579. The method of claim 1578, wherein heating the water comprising applying energy from a using nuclear power source.
1580. The method of claim 1577, further comprising providing the hydrogen stream to one or more fuel conduits of the one or more downhole burners.
1581. The method of claim 1577, further comprising providing the hydrogen stream to one or more portions of the formation.
1582. The method of claim 1577, further comprising providing the hydrogen stream to one or more process facilities.
1583. A system, comprising:
a separating unit configured to receive formation fluid and separate the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises carbon dioxide, sulfur compounds, hydrocarbons, hydrogen, or mixtures thereof;
a fuel conduit configured to receive the first gas stream and transport the first gas stream;
a oxidizing fluid conduit configured to receive the oxidizing fluid and transport the oxidizing fluid; and one or more burners coupled to the fuel conduit and oxidizing fluid conduit, wherein at least one of the burners is configured to receive the first gas stream and/or the oxidizing fluid from the fuel and/or oxidizing fluid conduits and combust the first gas stream and/or the oxidizing fluid stream.
1584. A method of treating formation fluid, comprising:
providing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce a liquid stream and a gas stream, wherein the gas stream comprises hydrocarbons;
providing the gas stream to a reformation unit;
reforming the gas stream to produce a hydrogen gas stream; and providing the hydrogen gas stream to one or more downhole burners.
1585. A method of heating a portion of a formation comprising:
placing fuel on a train;
initiating combustion of the fuel on the train;
pulling the train through a u-shaped opening in the formation;
supplying oxygen to the opening through a conduit; and burning the fuel to provide heat to the formation.
1586. The method of claim 1585, wherein the fuel comprises coal.
1587. The method of claim 1585, wherein the fuel comprises biomass.
1588. The method of claim 1585, further comprising treating flue gas exiting the opening.
1589. The method of claim 1585, wherein initiating combustion of the fuel occurs at or near a transition from overburden to a portion of the formation that is to be heated.
1590. A method for treating a hydrocarbon containing formation, comprising:
providing heat to a section of the formation with one or more heaters in the section;
producing fluids from the formation through a production well located in the section;
wherein the heaters are arranged in a geometric pattern around the production well, the heaters being arranged so that the density of heaters increases as the distance of the heaters from the production well increases.
1591. The method of claim 1590, further comprising reducing or turning off heating in the heaters nearest the production well when a temperature in at or near the production well reaches a temperature of about 100 C.
1592. The method of claim 1590, further comprising reducing or turning off heating in the heaters nearest the production well when a temperature in at or near the production well reaches a temperature of about 200 C.
1593. The method of claim 1590, further comprising turning on the heaters in a sequence with the heaters furthest from the production well being turned on first and the heaters nearest the production well being turned on last.
1594. The method of claim 1590, wherein increasing the density of heaters as the distance of the heaters from the production well increases provides less heating at or near the production well.
1595. The method of claim 1590, wherein the geometric pattern of heaters around the production well increases waste heat recovery from the formation by reducing the energy recovered in the produced fluids.
1596. The method of claim 1590, wherein the geometric pattern of heaters comprises an irregular hexagonal pattern of heaters.
1597. A method for treating a tar sands formation with one or more karsted layers, comprising:
providing heat from one or more heaters to at least one first karsted layer having a higher oil quality and being vertically above at least one second karsted layer with a lower oil quality;
providing heat to the second karsted layer with the lower oil quality so that at least some hydrocarbons in the second karsted layer are mobilized, and at least some of the mobilized hydrocarbons in the second karsted layer move to the first karsted layer; and producing hydrocarbon fluids from the first karsted layer.
1598. The method of claim 1597, wherein the karsted layers are selectively heated so that more heat is provided to the first karsted layer than the second karsted layer.
1599. The method of claim 1597, further comprising providing more heat to the first karsted layer than the second karsted layer by having a higher heater density in the first karsted layer.
1600. The method of claim 1597, further comprising providing heat to the second karsted layer so that thermal expansion in the second karsted layer moves the mobilized hydrocarbons to the first karsted layer.
1601. The method of claim 1597, further comprising providing heat to the second karsted layer so that gas pressure in the second karsted layer moves the mobilized hydrocarbons to the first karsted layer.
1602. The method of claim 1597, further comprising providing heat to the first karsted layer to visbreak and/or pyrolyze at least some hydrocarbons in the first karsted layer.
1603. The method of claim 1597, wherein at least some of the produced hydrocarbon fluids from the first karsted layer comprise hydrocarbons from the second karsted layer.
1604. The method of claim 1597, further comprising providing heat from one or more heaters to a third karsted layer with a lower oil quality than the first karsted layer, the third karsted layer being vertically above the first karsted layer.
1605. The method of claim 1604, further comprising mobilizing at least some hydrocarbons in the third karsted layer and allowing the mobilized hydrocarbons to drain into the first karsted layer.
1606. A method of treating a tar sands formation, comprising:
providing heat to at least part of a layer in the formation from a plurality of heaters located in the formation;
producing fluids from the formation;
separating at least a portion of the hydrocarbons from the produced fluids, wherein a majority of condensable hydrocarbons in the produced fluids are separated from the produced fluids; and controlling operating conditions in the formation to inhibit a P-value of the separated hydrocarbons from decreasing below 1.1, wherein P-value is determined by ASTM
Method D7060.
1607. The method of claim 1606, wherein controlling operating conditions comprises maintaining a pressure in the formation below a fracture pressure of the formation while allowing a portion of the portion to heat to at least a visbreaking temperature.
1608. The method of claim 1606, wherein controlling operating conditions comprises reducing a pressure in the formation to a selected pressure after at least a portion of the formation reaches a visbreaking temperature.
1609. The method of claim 1606, wherein controlling operating conditions comprises heating a portion of the formation to a temperature between about 200 C and about 240 C by allowing heat to transfer from the heaters to the portion.
1610. The method of claim 1606, wherein controlling operating conditions comprises reducing the pressure in the formation to between about 2000 kPa and about 10000 kPa.
1611. The method of claim 1606, wherein the separated hydrocarbons comprise mobilized hydrocarbon, visbroken hydrocarbons, pyrolyzed hydrocarbon, and/or mixtures thereof.
1612. The method of claim 1606, wherein producing fluids comprises producing a selected amount of fluids such that a pressure in the formation is maintained below the fracture pressure of the formation.
1613. The method of claim 1606, wherein the separated hydrocarbons have an API
gravity of at least 10.
1614. The method of claim 1606, wherein the separated hydrocarbons has an API
gravity of at least 19.
1615. The method of claim 1606, wherein the produced fluids comprise at least 85 vol% of hydrocarbon liquids and at most 15 vol% gases.
1616. A method of treating a tar sands formation, comprising:
providing heat to at least part of a layer in the formation from a plurality of heaters located in the formation;
producing fluids from the formation;
separating at least a portion of the hydrocarbons from the produced fluids, wherein a majority of condensable hydrocarbons in the produced fluids are separated from the produced fluids; and controlling operating conditions in the formation to inhibit a bromine factor of the separated hydrocarbons to increasing above 3%, wherein bromine number is determined by ASTM Method D 1159 on a hydrocarbon portion of the produced fluids have a boiling point of 246 C.
1617. The method of claim 1616, wherein the bromine number is at most 1%.
1618. The method of claim 1616, wherein the bromine number is at most 0.5%.
1619. The method of claim 1616, wherein controlling operating conditions comprises reducing an amount of heat provided to the formation.
1620. The method of claim 1616, wherein controlling operating conditions comprises reducing pressure in the formation to between about 2000 kPa and about 10000 kPa.
1621. The method of claim 1616, wherein the separated hydrocarbons comprise mobilized hydrocarbon, visbroken hydrocarbons, pyrolyzed hydrocarbon, and/or mixtures thereof.
1622. The method of claim 1616, wherein the produced fluids comprise at least 85 vol% of hydrocarbon liquids and at most 15 vol% gases.
1623. A method of treating a tar sands formation, comprising:
providing heat to at least part of a layer in the formation from a plurality of heaters located in the formation;
producing fluids from the formation;
separating at least a portion of the hydrocarbons from the produced fluids, wherein a majority of condensable hydrocarbons in the produced fluids are separated from the produced fluids; and controlling operating conditions in the formation to inhibit a bromine factor of the separating at least a portion of the hydrocarbons from the produced fluids to increasing above 2% as 1-decene equivalent, wherein the percentage of olefins as 1-decene equivalent is measured using the Canadian Association of Petroleum Producers Olefin Test.
1624. The method of claim 1623, wherein controlling operating conditions comprises reducing an amount of heat provided to the formation.
1625. The method of claim 1623, wherein controlling operating conditions comprises reducing pressure in the formation to between about 2000 kPa and about 10000 kPa.
1626. A method for treating a hydrocarbon containing formation, comprising:
providing heat to a first section of the formation from a plurality of heaters in the first section, the heaters being located in heater wells in the first section;
producing fluids through one or more production wells in a second section of the formation, the second section being substantially adjacent to the first section;
reducing or turning off the heat provided to the first section after a selected time;
providing an oxidation fluid through one or more of the heater wells in the first section;
providing heat to the first section and the second section through oxidation of at least some hydrocarbons in the first and second sections; and producing fluids comprising at least some oxidation products through at least one of the production wells in the second section.
1627. The method of claim 1626, further comprising producing fluids comprising at least some oxidation products through one or more production wells located in a third section of the formation, the third section being substantially adjacent to the second section.
1628. The method of claim 1626, further comprising controlling the pressure in the formation to control the oxidation of hydrocarbons in the formation.
1629. The method of claim 1626, further comprising using at least some of the produced fluids to power one or more turbines at the surface of the formation.
1630. A method of treating a tar sands formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters so that at least a portion of the formation reaches a selected temperature;
allowing fluids to gravity drain to a bottom portion of the layer;
producing a substantial portion of the drained fluids from one or more production wells located at or proximate the bottom portion of the layer, wherein at least a majority of the produced fluids are condensable hydrocarbons;
reducing the pressure in the formation to a selected pressure after the portion of the formation reaches the selected temperature and after producing a majority of the condensable hydrocarbons in the part of the hydrocarbon layer;
providing a solvation fluid to the formation, wherein the solvation fluid solvates at least a portion of remaining condensable hydrocarbons in the part of the hydrocarbon layer to form a mixture of solvation fluid and condensable hydrocarbons; and producing the mixture.
1631. The method of claim 1630, wherein the selected temperature ranges between 200 C and 240 C.
1632. The method of claim 1630, wherein the solvation fluid comprises water.
1633. The method of claim 1630, wherein the solvation fluid comprises carbon disulfide.
1634. The method of claim 1630, wherein the solvation fluid comprises carbon dioxide.
1635. The method of claim 1630, wherein the solvation fluid comprises water, hydrocarbons, surfactants, polymers, carbon disulfide, caustic, alkaline water solutions, or mixtures thereof.
1636. The method of claim 1630, wherein the produced mixture comprises bitumen.
1637. The method of claim 1630, wherein the produced drained fluids comprise visbroken hydrocarbons.
1638. The method of claim 1630, wherein the produced drained fluids comprise about 85 vol%
hydrocarbon liquids and 15 vol% gas.
1639. The method of claim 1630, further comprising controlling formation conditions to maintain a majority of the hydrocarbons as liquids in the formation.
1640. The method of claim 1630, wherein the produced mixture comprises hydrocarbon liquids have an API gravity of at least 10 but less than 25.
1641. The method of claim 1630, further comprising separating at least a portion of the drained produced fluids from the produced fluids, wherein the separated hydrocarbon liquids have an API gravity between 19 and 25, a viscosity of at most 350 cp at 5C, a P-value of at least 1.1, and a bromine number of at most 2%, wherein P-value is determined using ASTM
Method D7060 and bromine number is determined by ASTM Method D1159 on a portion of the separated hydrocarbons having a boiling range distribution between 204 C and 343 C.
1642. The method of claim 1630, further comprising separating at least a portion of the drained produced fluids from the produced fluids, wherein the separated hydrocarbon liquids have an API gravity between 19 and 25, a viscosity ranging at most 350 cp at 5C, a CAPP number of at most 2% as 1-decene equivalent, and a P-value of at least 1.1, wherein P-value is determined using ASTM Method D7060.
1643. A method for treating a hydrocarbon formation, comprising:
providing heat to a first portion of hydrocarbon layer in the formation from one or more heaters located in the formation;
allowing the heat to transfer from the first portion to one or more portions of hydrocarbon layer in the formation;
providing a solvation fluid to at least one of the portions of the hydrocarbon layer to solvate at least at least a portion of the formation fluids to form a mixture of solvation fluid and condensable hydrocarbons;
allowing at least a portion of the mixture to flow to another portion of the formation; and producing at least some of the mixture from the formation.
1644. The method of claim 1643, wherein the solvation fluid comprises carbon disulfide.
1645. The method of claim 1643, wherein the solvation fluid comprises carbon dioxide.
1646. The method of claim 1643, wherein the solvation fluid comprises water.
1647. The method of claim 1643, wherein the solvation fluid comprises water, hydrocarbons, surfactants, polymers, carbon disulfide, or mixtures thereof.
1648. The method of claim 1643, wherein the solvation fluid comprises hydrocarbons produced from the first portion of the formation.
1649. The method of claim 1643, wherein the solvation fluid comprises hydrocarbons produced from the first portion of the formation and wherein the hydrocarbon have a boiling range distribution from about 50 C to about 300 C.
1650. The method of claim 1649, wherein the hydrocarbon have a boiling range distribution from about 50 C to about 300 C comprise aromatic compounds.
1651. The method of claim 1643, wherein the produced fluids comprise formation fluids and/or solvation fluid.
1652. The method of claim 1643, further comprising providing a pressurizing fluid to the other portion to move at least a portion of the fluids from the other portion of the formation and wherein the pressurizing fluid is carbon dioxide.
1653. A method for treating a nahcolite containing subsurface formation, comprising:
solution mining a nahcolite bed above a treatment area and a nahcolite bed below a treatment using one or more substantially horizontal solution mining wells in the nahcolite beds;
providing heat to the treatment area and the nahcolite beds using one or more heaters located in the formation;
converting the substantially horizontal solution mining wells to production wells;
producing gas hydrocarbons through at least one of the production wells in the nahcolite bed above the treatment area; and producing liquid hydrocarbons through at least one of the production wells in the nahcolite bed below the treatment area.
1654. A method of treating a formation fluid, comprising:
providing formation fluid from a subsurface in situ heat treatment process;
separating the formation fluid to produce a liquid stream and a first gas stream, wherein the first gas stream comprises at least 0.1 vol% of carbon oxides, sulfur compounds, hydrocarbons, hydrogen, or mixtures thereof; and cryogenically separating the first gas stream to form a second gas stream and a third gas stream, wherein the second gas stream comprises methane and/or hydrogen and wherein the third gas stream comprises carbon oxide, hydrocarbons having a carbon number of at least 2, sulfur compounds, or mixtures thereof.
1655. The method of claim 1654, further comprising separating at least a portion of the H2 from the second gas stream.
1656. The method of claim 1654, further comprising separating at least a portion of the hydrocarbons having a carbon number of at least 3 from the third gas stream.
1657. The method of claim 1654, further comprising separating the third gas stream to form an additional stream, wherein the additional stream comprises carbon oxide compounds, hydrocarbons having a carbon number of at most 2, sulfur compounds, or mixtures thereof; and sequestering the additional stream.
1658. The method of claim 1654, further comprising separating the third gas stream to form a fourth gas stream and a fifth gas stream, wherein the fourth gas stream comprises hydrocarbons having a carbon number of at most 2 and/or carbon oxides, and wherein the fifth gas stream comprises sulfur compounds.
1659. The method of claim 1654, further comprising separating the third gas stream to form a fourth gas stream and a fifth gas stream, wherein the fourth gas stream comprises hydrocarbons having a carbon number of at most 2 and/or carbon oxides, and wherein the fifth gas stream comprises sulfur compounds and/or hydrocarbons having a carbon number of at least 3.
1660. The method of claim 1659, further comprising separating the fifth gas stream into a stream comprising sulfur compounds and a stream comprising hydrocarbons having a carbon number of at least 3.
1661. The method of claim 1654, further comprising separating at least a portion of the hydrocarbons having a carbon number of at least 3 from the third gas stream, and providing the hydrocarbons having a carbon number of at least 3 to other processing facilities.
1662. The method of claim 1654, further comprising separating hydrocarbons having a carbon number of at most 2 from the third gas stream, and providing the hydrocarbons having a carbon number of at most 2 to an ammonia processing facilities.
1663. The method of claim 1654, further comprising separating hydrocarbons having a carbon number of at most 2 from the third gas stream, and providing the hydrocarbons having a carbon number of at most 2 to one or more barrier wells.
1664. A system of treating formation fluid, comprising:
one or more separating units configured to receive formation fluid from a subsurface in situ heat treatment process and separate the formation fluid to form a liquid stream and a first gas stream, wherein the first gas stream comprises at least 0.1 mol% carbon dioxide, hydrogen sulfide, hydrocarbons, hydrogen, or mixtures thereof; and one or more cryogenic separation units configured to cryogenically separate the first gas stream to form a second gas stream and a third gas stream, wherein the second gas stream comprises methane and/or H2.
1665. A method of treating a subsurface hydrocarbon formation, comprising:

providing a catalyst system in a carrier fluid to a least a first portion of the subsurface hydrocarbon formation, wherein the first portion has previously at least partially been subjected to an in situ heat treatment process;
introducing hydrocarbon fluid into the first portion;
contacting the hydrocarbon fluid with the catalyst system to produce a second fluid; and producing the second fluid from the formation.
1666. The method of claim 1665, wherein the catalyst system comprises one or more catalysts, and wherein at least one of the catalysts comprises one or more metals from Columns 1 and 2 of the Periodic Table and/or one or more compounds of one or more metals from Columns 1 and 2 of the Periodic Table.
1667. The method of claim 1665, wherein the catalyst system comprises one or more catalysts, and wherein at least one of the catalysts comprises a one or more carbonates of one or more metals from Columns I and 2 of the Periodic Table.
1668. The method of claim 1665, wherein the catalyst system comprises one or more catalysts, and wherein at least one of the catalysts comprises one or more metals from Columns 6-10 of the Periodic Table and/or one or more compounds of one or more metals from Columns 6-10 of the Periodic Table.
1669. The method of claim 1665, wherein the catalyst system comprises dolomite.
1670. The method of claim 1665, wherein the first portion vaporizes at least a portion of the carrier fluid leaving at least a portion of the catalyst system in the formation.
1671. The method of claim 1665, wherein introducing the hydrocarbon fluid comprises driving formation fluid from an adjacent portion of the formation into the first portion.
1672. The method of claim 1665, wherein introducing the hydrocarbon fluid comprises injecting the hydrocarbon fluid into the first portion of the formation.
1673. The method of claim 1665, wherein the carrier fluid comprises steam, water, condensable hydrocarbons, in situ heat treatment process gas, or mixtures thereof.
1674. The method of claim 1665, wherein the formation fluid comprises bitumen.
1675. The method of claim 1665, wherein the produced mixture comprises liquid hydrocarbons having an API of at least 20.
1676. The method of claim 1665, wherein the produced mixture comprises non-condensable hydrocarbons.
1677. The method of claim 1665, wherein the produced mixture comprises at most 0.25 grams of aromatics per gram of total hydrocarbons.
1678. The method of claim 1665, wherein the produced mixture comprises at least a portion of the catalyst system.
1679. The method of claim 1665, further comprising allowing formation fluid from a second portion of the subsurface hydrocarbon formation flow into the first portion.
1680. The method of claim 1665, further comprising providing one or more oxidants and heat to at least a portion of the formation containing one or more of the catalysts, wherein at least one of the oxidants in the presence of heat removes coke from the catalyst.
1681. The method of claim 1665, wherein contacting the hydrocarbon fluid with the catalyst system produces coke, and further comprising providing one or more oxidants to the portion of the formation containing coke; and allowing the coke to oxidize to form gas.
1682. A method of forming a reaction zone in a subsurface formation, comprising:
introducing a slurry into a heated portion of a formation previously subjected to an in situ heat treatment process;

wherein the slurry comprises a catalyst system;

providing hydrocarbon fluid to the heated portion of the formation; and contacting the catalyst system with the hydrocarbon fluid to produce a second fluid.
1683. A method of treating a subsurface formation, comprising:
providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation;
allowing the heat to transfer from the heaters so that at least a portion of the formation reaches a selected temperature;
mobilizing fluids in the formation at the selected temperature;
producing at least a portion of the mobilized formation fluids;
providing a catalyst system to the portion of the formation;

contacting the at least a portion of the fluids remaining in the formation with the catalyst system to produce formation fluids; and producing at least a portion of the formation fluids.
1684. The method of claim 1683, wherein the formation fluids comprise mobilized fluids, visbroken fluids, condensable hydrocarbons or mixtures thereof.
1685. A method treating a formation, comprising heating a portin of the formation.
Description  (OCR text may contain errors)

DEMANDE OU BREVET VOLUMINEUX

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PLUS D'UN TOME.

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SYSTEMS AND PROCESSES FOR USE IN TREATING SUBSURFACE FORMATIONS
BACKGROUND
1. Field of the Invention [0001] The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations.

2. Description of Related Art [0002] Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from'the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation.
A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
100031 During some in situ processes, wax may be used to reduce vapors and/or to encapsulate contaminants in the ground. Wax may be used during remediation of wastes to encapsulate contaminated material. U.S. Patent Nos. 7,114,880 to Carter, and 5,879,110 to Carter describe methods for treatment of contaminants using wax during the remediation procedures.
[0004] In some embodiments, a casing or other pipe system may be placed or formed in a wellbore. U.S. Patent No. 4,572,299 issued to Van Egmond et al. describes spooling an electric heater into a well. In some embodiments, components of a piping system may be welded together. Quality of formed wells may be monitored by various techniques. In some embodiments, quality of welds may be inspected by a hybrid electromagnetic acoustic transmission technique known as EMAT. EMAT is described in U.S. Patent Nos.
5,652,389 to Schaps et al.; 5,760,307 to Latimer et al.; 5,777,229 to Geier et al.; and 6,155,117 to Stevens et al.

[0005] In some embodiments, an expandable tubular may be used in a wellbore.
Expandable tubulars are described in U.S. Patent Nos. 5,366,012 to Lohbeck, and 6,354,373 to Vercaemer et al.

[0006] Heaters may be placed in wellbores to heat a formation during an in situ process.
Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Patent Nos.
2,634,961 to Ljungstrom; 2,732,195 to Ljungstrom; 2,780,450 to Ljungstrom;
2,789,805 to Ljungstrom; 2,923,535 to Ljungstrom; and 4,886,118 to Van Meurs et al.
[0007] Application of heat to oil shale formations is described in U.S. Patent Nos. 2,923,535 to Ljungstrom and 4,886,1 18 to Van Meurs et al. Heat may be applied to the oil shale formation to pyrolyze kerogen in the oil shale formation. The heat may also fracture the formation to increase permeability of the formation. The increased permeability may allow formation fluid to travel to a production well where the fluid is removed from the oil shale formation. In some processes disclosed by Ljungstrom, for example, an oxygen containing gaseous medium is introduced to a permeable stratum, preferably while still hot from a preheating step, to initiate combustion.
[0008] A heat source may be used to heat a subterranean formation. Electric heaters may be used to heat the subterranean formation by radiation and/or conduction. An electric heater may resistively heat an element. U.S. Patent No. 2,548,360 to Germain describes an electric heating element placed in a viscous oil in a wellbore. The heater element heats and thins the oil to allow the oil to be pumped from the weilbore. U.S. Patent No. 4,716,960 to Eastlund et al. describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Patent No. 5,065,818 to Van Egmond describes an electric heating element that is cemented into a well borehole without a casing surrounding the heating element.
[0009] U.S. Patent No. 6,023,554 to Vinegar et al. describes an electric heating element that is positioned in a casing. The heating element generates radiant energy that heats the casing. A
granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn conductively heats the formation.
[0010] U.S. Patent No. 4,570,715 to Van Meurs et al. describes an electric heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength, and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
[0011] U.S. Patent No. 5,060,287 to Van Egmond describes an electrical heating element having a copper-nickel alloy core.
[0012] Obtaining permeability in an oil shale formation between injection and production wells tends to be difficult because oil shale is often substantially impermeable.
Many methods have attempted to link injection and production wells. These methods include:
hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center; electrical fracturing by methods investigated by Laramie Energy Research Center; acid leaching of limestone cavities by methods investigated by Dow Chemical; steam injection into permeable nahcolite zones to dissolve the nahcolite by methods investigated by Shell Oil and Equity Oil;
fracturing with chemical explosives by methods investigated by Talley Energy Systems;
fracturing with nuclear explosives by methods investigated by Project Bronco;
and combinations of these methods. Many of these methods, however, have relatively high operating costs and lack sufficient injection capacity.
[0013] Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained in relatively permeable formations (for example in tar sands) are found in North America, South America, Africa, and Asia. Tar can be surface-mined and upgraded to lighter hydrocarbons such as crude oil, naphtha, kerosene, and/or gas oil. Surface milling processes may further separate the bitumen from sand. The separated bitumen may be converted to light hydrocarbons using conventional refinery methods. Mining and upgrading tar sand is usually substantially more expensive than producing lighter hydrocarbons from conventional oil reservoirs.
[0014] In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting a gas into the formation. U.S. Patent Nos. 5,211,230 to Ostapovich et al. and 5,339,897 to Leaute describe a horizontal production well located in an oil-bearing reservoir. A
vertical conduit may be used to inject an oxidant gas into the reservoir for in situ combustion.
[0015] U.S. Patent No. 2,780,450 to Ljungstrom describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.
[0016] U.S. Patent No. 4,597,441 to Ware et al. describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
[0017] U.S. Patent No. 5,046,559 to Glandt and 5,060,726 to Glandt et al.
describe preheating a portion of a tar sand formation between an injector well and a producer well.
Steam may be injected from the injector well into the formation to produce hydrocarbons at the producer well.

[0018] As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.

SUMMARY
[0019] Embodiments described herein generally relate to systems, methods, and heaters for treating a subsurface formation. Embodiments described herein also-generally relate to heaters that have novel components therein. Such heaters can be obtained by using the systems and methods described herein.
[0020] In certain embodiments, the invention provides one or more systems, methods, and/or heaters. In some embodiments, the systems, methods, and/or heaters are used for treating a subsurface formation.
100211 In some embodiments, the invention describes a method for treating a tar sands includes heating a portion of a hydrocarbon layer in the formation from one or more heaters located in the portion; controlling the heating to increase the permeability of at least part of the portion to create an injection zone in the portion with an average permeability sufficient to allow injection of a fluid through the injection zone; providing a drive fluid and/or an oxidizing fluid into the injection zone; and producing at least some hydrocarbons from the portion.
[0022] In further embodiments, features from specific embodiments may be combined with features from other embodiments. For example, features from one embodiment may be combined with features from any of the other embodiments.
[0023] In further embodiments, treating a subsurface formation is performed using any of the methods, systems, or heaters described herein.
[0024] In further embodiments, additional features may be added to the specific embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS
[0025] Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description and upon reference to the accompanying drawings in which:

[0026] FIG. I depicts an illustration of stages of heating a hydrocarbon containing formation.
[0027] FIG. 2 shows a schematic view of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon containing formation.
[0028] FIG. 3 depicts a schematic of an embodiment of a Kalina cycle for producing electricity.
[0029] FIG. 4 depicts a schematic of an embodiment of a Kalina cycle for producing electricity.
[0030] FIG. 5 depicts a schematic representation of an embodiment of a system for treating the mixture produced from an in situ heat treatment process.
[0031] FIG. 5A depicts a schematic representation of an embodiment of a system for treating a liquid stream produced from an in situ heat treatment process.
[0032] FIG. 6 depicts a schematic representation of an embodiment of a system for treating in situ heat conversion process gas.
[0033] FIG. 7 depicts a schematic representation of an embodiment of a system for treating in situ heat conversion process gas.
[0034] FIG. 8 depicts a schematic representation of an embodiment of a system for treating in situ heat conversion process gas.
100351 FIG. 9 depicts a schematic representation of an embodiment of a system for treating in situ heat conversion process gas.
[0036] FIG. 10 depicts a schematic representation of another embodiment of a system for treating a liquid stream produced from an in situ heat treatment process.
[0037] FIG. 11 depicts a schematic representation of an embodiment of a system for forming and transporting tubing to a treatment area.
[0038] FIG. 12 depicts an embodiment for assessing a position of a first wellbore relative to a second wellbore using multiple magnets.
100391 FIG. 13 depicts an alternative embodiment for assessing a position of a first wellbore relative to a second wellbore using a continuous pulsed signal.
[00401 FIG. 14 depicts an alternative embodiment for assessing a position of a first wellbore relative to a second wellbore using a radio ranging signal.
[0041] FIG. 15 depicts an embodiment for assessing a position of a plurality of first wellbores relative to a plurality of second wellbores using radio ranging signals.
[0042] FIGS. 16 and 17 depict an embodiment for assessing a position of a first wellbore relative to a second wellbore using a heater assembly as a current conductor.
[0043] FIGS. 18 and 19 depict an embodiment for assessing a position of a first wellbore relative to a second wellbore using two heater assemblies as current conductors.

[00441 FIG. 20 depicts an embodiment of an umbilical positioning control system employing a wireless linking system.

[0045] FIG. 21 depicts an embodiment of an umbilical positioning control system employing a magnetic gradiometer system.
[0046] FIG. 22 depicts an embodiment of an umbilical positioning control system employing a combination of systems being used in a first stage of deployment.
[0047] FIG. 23 depicts an embodiment of an umbilical positioning control system employing a combination of systems being used in a second stage of deployment.
100481 FIG. 24 depicts two examples of the relationship between power received and distance based upon two different formations with different resistivities.
[0049] FIG. 25A depicts an embodiment of a drilling string including cutting structures positioned along the drilling string.
100501 FIG. 25B depicts an embodiment of a drilling string including cutting structures positioned along the drilling string.
[0051] FIG. 25C depicts an embodiment of a drilling string including cutting structures positioned along the drilling string.
[0052] FIG. 26 depicts an embodiment of a drill bit including upward cutting structures.
100531 FIG. 27 depicts an embodiment of a tubular including cutting structures positioned in a wellbore.
[0054] FIG. 28 depicts a schematic drawing of an embodiment of a drilling system.
[0055] FIG. 29 depicts a schematic drawing of an embodiment of a drilling system for drilling into a hot formation.
[0056] FIG. 30 depicts a schematic drawing of an embodiment of a drilling system for drilling into a hot formation.
[0057] FIG. 31 depicts a schematic drawing of an embodiment of a drilling system for drilling into a hot formation.

[0058] FIG. 32 depicts an embodiment of a freeze well for a circulated liquid refrigeration system, wherein a cutaway view of the freeze well is represented below ground surface.
[0059] FIG. 33 depicts a cross-sectional representation of a portion of a freeze well embodiment.
[0060] FIG. 34 depicts an embodiment of a wellbore for introducing wax into a formation to form a wax grout barrier.
[0061] FIG. 35 depicts a representation of a wellbore drilled to an intermediate depth in a formation.

[0062] FIG. 35B depicts a representation of the wellbore drilled to the final depth in the formation.
[0063] FIG. 36 depicts an embodiment of a device for longitudinal welding of a tubular using ERW.
[0064] FIGS. 37, 38, and 39 depict cross-sectional representations of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section.
[0065] FIGS. 40, 41, 42, and 43 depict cross-sectional representations of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section placed inside a sheath.
[0066] FIGS. 44A and 44B depict cross-sectional representations of an embodiment of a temperature limited heater.
[0067] FIGS. 45A and 45B depict cross-sectional representations of an embodiment of a temperature limited heater.
[0068] FIGS. 46A and 46B depict cross-sectional representations of an embodiment of a temperature limited heater.
[0069] FIGS. 47A and 47B depict cross-sectional representations of an embodiment of a temperature limited heater.
[00701 FIGS. 48A and 48B depict cross-sectional representations of an embodiment of a temperature limited heater.
[00711 FIG. 49 depicts a cross-sectional representation of an embodiment of a composite conductor with a support member.
[0072] FIG. 50 depicts a cross-sectional representation of an embodiment of a composite conductor with a support member separating the conductors.
[0073] FIG. 51 depicts a cross-sectional representation of an embodiment of a composite conductor surrounding a support member.
[0074] FIG. 52 depicts a cross-sectional representation of an embodiment of a composite conductor surrounding a conduit support member. , [0075] FIG. 53 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit heat source.
100761 FIG. 54 depicts a cross-sectional representation of an embodiment of a removable conductor-in-conduit heat source.

[0077] FIG. 55 depicts an embodiment of a temperature limited heater in which the support member provides a majority of the heat output below the Curie temperature of the ferromagnetic conductor.

[0078] FIGS. 56 and 57 depict embodiments of temperature limited heaters in which the jacket provides a majority of the heat output below the Curie temperature of the ferromagnetic conductor.

[0079] FIG. 58 depicts a high temperature embodiment of a temperature limited heater.
[0080] FIG. 59 depicts hanging stress versus outside diameter for the temperature limited heater shown in FIG. 55 with 347H as the support member.
100811 FIG. 60 depicts hanging stress versus temperature for several materials and varying outside diameters of the temperature limited heater.
100821 FIGS. 61, 62, 63, and 64 depict examples of embodiments for temperature limited heaters that vary the materials and/or dimensions along the length of the heaters to provide desired operating properties.
[0083] FIGS. 65 and 66 depict examples of embodiments for temperature limited heaters that vary the diameter and/or materials of the support member along the length of the heaters to provide desired operating properties and sufficient mechanical properties.
[0084] FIGS. 67A and 67B depict cross-sectional representations of an embodiment of a temperature limited heater component used in an insulated conductor heater.
[0085] FIGS. 68A and 68B depict an embodiment of a system for installing heaters in a wellbore.
[0086] FIG. 68C depicts an embodiment of an insulated conductor with the sheath shorted to the conductors.
[0087] FIG. 69 depicts a top view representation of three insulated conductors in a conduit.
[0088] FIG. 70 depicts an embodiment of three-phase wye transformer coupled to a plurality of heaters.
[0089] FIG. 71 depicts a side view representation of an end section of three insulated conductors in a conduit.

[0090] FIG. 72 depicts one alternative embodiment of a heater with three insulated cores in a conduit.
[0091] FIG. 73 depicts another alternative embodiment of a heater with three insulated conductors and an insulated return conductor in a conduit.
[0092] FIG. 74 depicts an embodiment of an insulated conductor heater in a conduit with molten metal.

[0093] FIG. 75 depicts an embodiment of an insulated conductor heater iri a conduit where the molten metal functions as the heating element.
100941 FIG. 76 depicts an embodiment of a substantially horizontal insulated conductor heater in a conduit with molten metal.
100951 FIG. 77 depicts schematic cross-sectional representation of a portion of a formation with heat pipes positioned adjacent to a substantially horizontal portion of a heat source.
[0096] FIG. 78 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with the heat pipe located radially around an oxidizer assembly.
[0097] FIG. 79 depicts a cross-sectional representation of an angled heat pipe embodiment with an oxidizer assembly located near a lowermost portion of the heat pipe.
[0098] FIG. 80 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with an oxidizer located at the bottom of the heat pipe.
[0099] FIG. 81 depicts a cross-sectional representation of an angled heat pipe embodiment with an oxidizer.located at the bottom of the heat pipe.
[0100] FIG. 82 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with an oxidizer that produces a flame zone adjacent to liquid heat transfer fluid in the bottom of the heat pipe.
[0101] FIG. 83 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with a tapered bottom that accommodates multiple oxidizers.
[0102] FIG. 84 depicts a cross-sectional representation of a heat pipe embodiment that is angled within the formation.
[0103] FIG. 85 depicts an embodiment for coupling together sections of a long temperature limited heater.
[0104] FIG. 86 depicts an embodiment of a shield for orbital welding sections of a long temperature limited heater.
[0105] FIG. 87 depicts a schematic representation of an embodiment of a shut off circuit for an orbital welding machine.
101061 FIG. 88 depicts an embodiment of a temperature limited heater with a low temperature ferromagnetic outer conductor.
[0107] FIG. 89 depicts an embodiment of a temperature limited conductor-in-conduit heater.
[0108] FIG. 90 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit temperature limited heater.
[0109] FIG. 91 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit temperature limited heater.

[0110] FIG. 92 depicts a cross-sectional view of an embodiment of a conductor-in-conduit temperature limited heater.
[0111] FIG. 93 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit temperature limited heater with an.insulated conductor.

[0112] FIG. 94 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit temperature limited heater with an insulated conductor.
[0113] FIG. 95 depicts an embodiment of a three-phase temperature limited heater with a portion shown in cross section., [0114] FIG. 96 depicts an embodiment of temperature limited heaters coupled together in a three-phase configuration.
[0115] FIG. 97 depicts an embodiment of three heaters coupled in a three-phase configuration.
[0116] FIG. 98 depicts a side view representation of an embodiment of a centralizer on a heater.
[0117] FIG. 99 depicts an end view representation of an embodiment of a centralizer on a heater.
101181 FIG. 100 depicts a side view representation of an embodiment of a substantially u-shaped three-phase heater.

[0119] FIG. 101 depicts a top view representation of an embodiment of a plurality of triads of three-phase heaters in a formation.
[0120] FIG. 102 depicts a top view representation of the embodiment depicted in FIG. 101 with production wells.
101211 FIG. 103 depicts a top view representation of an embodiment of a plurality of triads of three-phase heaters in a hexagonal pattern.
[0122] FIG. 104 depicts a top view representation of an embodiment of a hexagon from FIG.
103.
[0123] FIG. 105 depicts an embodiment of triads of heaters coupled to a horizontal bus bar.
[01241 FIGS. 106 and 107 depict embodiments for coupling contacting elements of three legs of a heater.

[01251 FIG. 108 depicts an embodiment of a container with an initiator for melting the coupling material.
[0126] FIG. 109 depicts an embodiment of a container for coupling contacting elements with bulbs on the contacting elements.
[0127] FIG. 110 depicts an alternative embodiment of a container.
[0128] FIG. 1 11 depicts an alternative embodiment for coupling contacting elements of three legs of a heater.

[0129] FIG. 112 depicts a side-view representation of an embodiment for coupling contacting elements using temperature limited heating elements.
[0130[ FIG. 113 depicts a side view representation of an alternative embodiment for coupling contacting elements using temperature limited heating elements.
[0131[ FIG. 114 depicts a side view representation of another alternative embodiment for coupling contacting elements using temperature limited heating elements.
[0132] FIG. 115 depicts a side view representation of an alternative embodiment for coupling contacting elements of three legs of a heater.
[0133] FIG. 116 depicts a top view representation of the alternative embodiment for coupling contacting elements of three legs of a heater depicted in FIG. 1] 5.
[0134] FIG. 117 depicts an embodiment of a contacting element with a brush contactor.
[0135] FIG. 118 depicts an embodiment for coupling contacting elements with brush contactors.
[0136] FIG. 119 depicts an embodiment of two temperature limited heaters coupled together in a single contacting section.
[0137] FIG. 120 depicts an embodiment of two temperature limited heaters with legs coupled in a contacting section.
[0138] FIG. 121 depicts an embodiment of three diads coupled to a three-phase transformer.
[0139] FIG. 122 depicts an embodiment of groups of diads in a hexagonal pattern.
[0140] FIG. 123 depicts an embodiment of diads in a triangular pattern.
[0141] FIG. 124 depicts a side-view representation of an embodiment of substantially u-shaped heaters.
[0142] FIG. 125 depicts a representational top view of an embodiment of a surface pattern of heaters depicted in FIG. 124.
[0143] FIG. 126 depicts a cross-sectional representation of substantially u-shaped heaters in a hydrocarbon layer.
[0144] FIG. 127 depicts a side view representation of an embodiment of substantially vertical heaters coupled to a substantially horizontal wellbore.
[0145] FIG. 128 depicts an embodiment of pluralities of substantially horizontal heaters coupled to bus bars in a hydrocarbon layer [0146] FIG. 129 depicts an alternative embodiment of pluralities of substantially horizontal heaters coupled to bus bars in a hydrocarbon layer.
[0147] FIG. 130 depicts an enlarged view of an embodiment of a bus bar coupled to heater with connectors.

[0148] FIG. 131 depicts an enlarged view of an embodiment of a bus bar coupled to a heater with connectors and centralizers.
[0149] FIG. 132 depicts a cross-section representation of a connector coupling to a bus bar.
[0150] FIG. 133 depicts a three-dimensional representation of a connector coupling to a bus bar.
[0151] FIG. 134 depicts an embodiment of three u-shaped heaters with common overburden sections coupled to a single three-phase transformer.
[0152] FIG. 135 depicts a top view of an embodiment of a heater and a drilling guide in a wellbore.

[0153] FIG. 136 depicts a top view of an embodiment of two heaters and a drilling guide in a wellbore.

101541 FIG. 137 depicts a top view of an embodiment of three heaters and a centralizer in a wellbore.
[0155] FIG. 138 depicts an embodiment for coupling ends of heaters in a wellbore.
[0156] FIG. 139 depicts a schematic of an embodiment of multiple heaters extending in different directions from a wellbore.
[0157] FIG. 140 depicts a schematic of an embodiment of multiple levels of heaters extending between two wellbores.
[0158] FIG. 141 depicts an embodiment of a u-shaped heater that has an inductively energized tubular.
[0159] FIG. 142 depicts an embodiment of a substantially u-shaped heater that electrically isolates itself from the formation.
101601 FIG. 143 depicts an embodiment of a single-ended, substantially horizontal heater that electrically isolates itself from the formation.
101611 FIG. 144 depicts an embodiment of a single-ended, substantially horizontal heater that electrically isolates itself from the formation using an insulated conductor as the center conductor.
[0162] FIG. 145 depicts an embodiment of a single-ended, substantially horizontal insulated conductor heater that electrically isolates itself from the formation.
[0163] FIGS. 146A and 146B depict cross-sectional representations of an embodiment of an insulated conductor that is electrically isolated on the outside of the jacket.
[0164] FIG. 147 depicts a side view representation of an embodiment of an insulated conductor inside a tubular.
[0165] FIG. 148 depicts an end view representation of an embodiment of an insulated conductor inside a tubular.

[0166] FIG. 149 depicts a cross-sectional representation of an embodiment of a distal end of an insulated conductor inside a tubular.

[0167] FIGS. 150A and 150B depict an embodiment for using substantially u-shaped wellbores to time sequence heat two layers in a hydrocarbon containing formation.
[0168] FIGS. 151A and 151B depict an embodiment for using horizontal wellbores to time sequence heat two layers in a hydrocarbon containing formation.
[0169] FIG. 152 depicts an embodiment of a wellhead.
[0170] FIG. 153 depicts an embodiment of a heater that has been installed in two parts.
[0171] FIG. 154 depicts an embodiment of a dual continuous tubular suspension mechanism including threads cut on the dual continuous tubular over a built up portion.
[0172] FIG. 155 depicts an embodiment of a dual continuous tubular suspension mechanism including a built up portion on a continuous tubular.
[0173] FIGS. 156A-B depict embodiments of dual continuous tubular suspension mechanisms including slip mechanisms.
[0174] FIG. 157 depicts an embodiment of a dual continuous tubular suspension mechanism including a slip mechanism and a screw lock system.
101751 FIG. 158 depicts an embodiment of a dual continuous tubular suspension mechanism including a slip mechanism and a screw lock system with counter sunk bolts.
[01761 FIG. 159 depicts an embodiment of a pass-through fitting used to suspend tubulars.
[01771 FIG. 160 depicts an embodiment of a dual slip mechanism for inhibiting movement of tubulars.
101781 FIG. 161A-B depict embodiments of split suspension mechanisms and split slip assemblies for hanging dual continuous tubulars.
[0179] FIG. 162 depicts an embodiment of a dual slip mechanism for inhibiting movement of tubulars with a reverse configuration.
[0180] FIG. 163 depicts an embodiment of a two-part dual slip mechanism for inhibiting movement of tubulars.
[0181] FIG. 164 depicts an embodiment of a two-part dual slip mechanism for inhibiting movement of tubulars with separate locks.
[0182] FIG. 165 depicts an embodiment of a dual slip mechanism locking plate for inhibiting movement of tubulars.
[0183] FIG. 166 depicts an embodiment of a segmented dual slip mechanism with locking screws for inhibiting movement of tubulars.

[01841 FIG. 167 depicts a top view representation of the embodiment of a transformer showing the windings and core of the transformer.
[0185] FIG. 168 depicts a side view representation of the embodiment of the transformer showing the windings, the core, and the power leads.
[0186] FIG. 169 depicts an embodiment of a transformer in a wellbore.
[0187] FIG. 170 depicts an embodiment of a transformer in a wellbore with heat pipes.
[0188] FIG. 171 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a relatively thin hydrocarbon layer.
[0189] FIG. 172 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 171.
[0190] FIG. 173 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 172.
[0191] FIG. 174 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that has a shale break.
[0192] FIG. 175 depicts a top view representation of an embodiment for preheating using heaters for the drive process.
[0193] FIG. 176 depicts a side view representation of an embodiment for preheating using heaters for the drive process.
101941 FIG. 177 depicts a side view representation of an embodiment using at least three treatment sections in a tar sands formation.
[0195] FIG. 178 depicts a representation of an embodiment for producing hydrocarbons from a tar sands formation.
[0196] FIG. 179 depicts a representation of an embodiment for producing hydrocarbons from multiple layers in a tar sands formation.
[0197] FIG. 180 depicts an embodiment for heating and producing from a formation with a temperature limited heater in a production wellbore.
[0198] FIG. 181 depicts an embodiment for heating and producing from a formation with a temperature limited heater and a production wellbore.
[0199] FIG. 182 depicts an embodiment of a first stage of treating a tar sands formation with electrical heaters.
[0200] FIG. 183 depicts an embodiment of a second stage of treating a tar sands formation with fluid injection and oxidation.

102011 FIG. 184 depicts an embodiment of a third stage of treating a tar sands formation with fluid injection and oxidation.
[0202] FIG. 185 depicts a schematic representation of an embodiment of a downhole oxidizer assembly.

[0203] FIG. 186 depicts a schematic representation of an embodiment of a system for producing fuel for downhole oxidizer assemblies.
[0204] FIG. 187 depicts a schematic representation of an embodiment of a system for producing oxygen for use in downhole oxidizer assemblies.
[0205] FIG. 188 depicts a schematic representation of an embodiment of a system for producing oxygen for use in downhole oxidizer assemblies.

[0206] FIG. 189 depicts a schematic representation of an embodiment of a system for producing hydrogen for use in downhole oxidizer assemblies.
[0207] FIG. 190 depicts a cross-sectional representation of an embodiment of a downhole oxidizer including an insulating sleeve.

102081 FIG. 191 depicts a cross-sectional representation of an embodiment of a downhole oxidizer with a gas cooled insulating sleeve.
[0209] FIG. 192 depicts a perspective view of an embodiment of a portion of an oxidizer of a downhole oxidizer assembly.
[0210] FIG. 193 depicts a cross-sectional representation of an embodiment of an oxidizer shield.
[0211] FIG. 194 depicts a cross-sectional representation of an embodiment of an oxidizer shield.
102121 FIG. 195 depicts a cross-sectional representation of an embodiment of an oxidizer shield.
[0213] FIG. 196 depicts a cross-sectional representation of an embodiment of an oxidizer shield.
[0214] FIG. 197 depicts a cross-sectional representation of an embodiment of an oxidizer shield with multiple flame stabilizers.
[0215] FIG. 198 depicts a cross-sectional representation of an embodiment of an oxidizer shield.
[0216] FIG. 199 depicts a perspective representation of an embodiment of a portion of an oxidizer of a downhole oxidizer assembly with louvered openings in the shield.
[0217] FIG. 200 depicts a cross-sectional representation of a portion of a shield with a louvered opening.
[0218] FIG. 201 depicts a perspective representation of an embodiment of a sectioned oxidizer.
102191 FIG. 202 depicts a perspective representation of an embodiment of a sectioned oxidizer.
102201 FIG. 203 depicts a perspective representation of an embodiment of a sectioned oxidizer.
[0221] FIG. 204 depicts a cross-sectional of an embodiment of a first oxidizer of an oxidizer assembly.

[0222] FIG. 205 depicts a cross-sectional representation of an embodiment of a catalytic burner.
[0223] FIG. 206 depicts a cross-sectional representation of an embodiment of a catalytic burner with an igniter.
[0224] FIG. 207 depicts a cross-sectional representation of an oxidizer assembly.
[0225] FIG. 208 depicts a cross-sectional representation of an oxidizer of an oxidizer assembly.
[02261 FIG. 209 depicts a schematic representation of an oxidizer assembly with flameless distributed combustors and oxidizers.
[0227] FIG. 210 depicts a schematic representation of an embodiment of a heater that uses coal as fuel.
[0228] FIG. 211 depicts a schematic representation of an embodiment of a heater that uses coal as fuel.
[0229] FIG. 212 depicts an embodiment of a wellbore for heating a formation using a burning fuel moving through the formation.
[0230] FIG. 213 depicts a top view representation of a portion of the fuel train used to heat the treatment area.

[0231] FIG. 214 depicts a side view representation of a portion of the fuel train used to heat the treatment area.

[0232] FIG. 215 depicts an aerial view representation of a system that heats the treatment area using burning fuel that is moved through the treatment area.
[0233] FIG. 216 depicts a schematic representation of an embodiment of a system for heating the formation using gas lift to return the heat transfer fluid to the surface.

[0234] FIG. 217 depicts a schematic representation of a closed loop circulation system for heating a portion of a formation.
[02351 FIG. 218 depicts a plan view of wellbore entries and exits from a portion of a formation to be heated using a closed loop circulation system.
[0236] FIG. 219 depicts a cross sectional representation of piping of a circulation system with an insulated conductor heater positioned in the piping.
[0237] FIG. 220 depicts a side view representation of an embodiment of a system for heating the formation that can use a closed loop circulation system and/or electrical heating.
[0238] FIG. 221 depicts a schematic representation of an embodiment of an in situ heat treatment system that uses a nuclear reactor.
[0239] FIG. 222 depicts an elevational view of an in situ heat treatment system using pebble bed reactors.

[0240] FIG. 223 depicts a side view representation of an embodiment for an in situ staged heating and producing process for treating a tar sands formation.
[0241] FIG. 224 depicts a top view of a rectangular checkerboard pattern embodiment for the in situ staged heating and production process.
[0242] FIG. 225 depicts a top view of a ring pattern embodiment for the in situ staged heating and production process.

[0243] FIG. 226 depicts a top view of a checkerboard ring pattern embodiment for the in situ staged heating and production process.
102441 FIG. 227 depicts a top view an embodiment of a plurality of rectangular checkerboard patterns in a treatment area for the in situ staged heating and production process.
[0245] FIG. 228 depicts an embodiment of varied heater spacing around a production.well.
102461 FIG. 229 depicts a side view representations of embodiments for producing mobilized fluids from a hydrocarbon formation.
[0247] FIG. 230 depicts a schematic representation of a system for inhibiting migration of formation fluid from a treatment area.
[0248] FIG. 231 depicts an embodiment of a windmill for generating electricity for subsurface heaters.
[0249] FIG. 232 depicts an embodiment of a solution mining well.
[0250] FIG. 233 depicts a representation of a portion of a solution mining well.
[0251] FIG. 234 depicts a representation of a portion of a solution mining well.
[0252] FIG. 235 depicts an elevational view of a well pattern for solution mining and/or an in situ heat treatment process.
102531 FIG. 236 depicts a representation of wells of an in situ heating treatment process for solution mining and producing hydrocarbons from a formation.
[0254] FIG. 237 depicts an embodiment for solution mining a formation.
[0255] FIG. 238 depicts an embodiment of a formation with nahcolite layers in the formation before solution mining nahcolite from the formation.
[0256] FIG. 239 depicts the formation of FIG. 238 after the nahcolite has been solution mined.
[0257] FIG. 240 depicts an embodiment of two injection wells interconnected by a zone that has been solution mined to remove nahcolite from the zone.
[0258] FIG. 241 depicts an embodiment for heating a formation with dawsonite in the formation.
[0259] FIG. 242 depicts a representation of an embodiment for solution mining with a steam and electricity cogeneration facility.

[02601 FIG. 243 depicts an embodiment of treating a hydrocarbon containing formation with a combustion front.

[0261] FIG. 244 depicts an embodiment of cross-sectional view of treating a hydrocarbon containing formation with a combustion front.
[0262] FIG. 245 depicts a schematic representation of a system for producing formation fluid and introducing sour gas into a subsurface formation.
[0263] FIG. 246 depicts electrical resistance versus temperature at various applied electrical currents for a 446 stainless steel rod.
[0264] FIG. 247 shows resistance profiles as a function of temperature at various applied electrical currents for a copper rod contained in a conduit of Sumitomo HCM12A.
[0265] FIG. 248 depicts electrical resistance versus temperature at various applied electrical currents for a temperature limited heater.
[0266] FIG. 249 depicts raw data for a temperature limited heater.
[0267] FIG. 250 depicts electrical resistance versus temperature at various applied electrical currents for a temperature limited heater.

[0268] FIG. 251 depicts power versus temperature at various applied electrical currents for a temperature limited heater.
[0269] FIG. 252 depicts electrical resistance versus temperature at various applied electrical currents for a temperature limited heater.
[0270] FIG. 253 depicts data of electrical resistance versus temperature for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at various applied electrical currents.
[0271] FIG. 254 depicts data of electrical resistance versus temperature for a composite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rod has an outside diameter to copper diameter ratio of 2: l) at various applied electrical currents.
[0272J FIG. 255 depicts data of power output versus temperature for a composite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rod has an outside diameter to copper diameter ratio of 2:1) at various applied electrical currents.
[0273] FIG. 256 depicts data for values of skin depth versus temperature for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at various applied AC electrical currents.
[0274] FIG. 257 depicts temperature versus time for a temperature limited heater.
[0275] FIG. 258 depicts temperature versus log time data for a 2.5 cm solid 410 stainless steel rod and a 2.5 cm solid 304 stainless steel rod.

[0276] FIG. 259 depicts experimentally measured resistance versus temperature at several currents for a temperature limited heater with a copper core, a carbon steel ferromagnetic conductor, and a stainless steel 347H stainless steel support member.
[0277] FIG. 260 depicts experimentally measured resistance versus temperature at several currents for a temperature limited heater with a copper core, an iron-cobalt ferromagnetic conductor, and a stainless steel 347H stainless steel support member.
[0278] FIG. 261 depicts experimentally measured power factor versus temperature at two AC
currents for a temperature limited heater with a copper core, a carbon steel ferromagnetic conductor, and a 347H stainless steel support member.
[0279] FIG. 262 depicts experimentally measured turndown ratio versus maximum power delivered for a temperature limited heater with a copper core, a carbon steel ferromagnetic conductor, and a 347H stainless steel support member.
[0280] FIG. 263 depicts examples of relative magnetic permeability versus magnetic field for both the found correlations and raw data for carbon steel.
[0281] FIG. 264 shows the resulting plots of skin depth versus magnetic field for four temperatures and 400 A current.
[0282] FIG. 265 shows a comparison between the experimental and numerical (calculated) results for currents of 300 A, 400 A, and 500 A.
[0283] FIG. 266 shows the AC resistance per foot of the heater element as a function of skin depth at 1100 F calculated from the theoretical model.
[0284] FIG. 267 depicts the power generated per unit length in each heater component versus skin depth for a temperature limited heater.
[0285] FIGS. 268A-C compare the results of theoretical calculations with experimental data for resistance versus temperature in a temperature limited heater.
[0286] FIG. 269 displays temperature of the center conductor of a conductor-in-conduit heater as a function of formation depth for a Curie temperature heater with a turndown ratio of 2: 1.
[0287] FIG. 270 displays heater heat flux through a formation for a turndown ratio of 2:1 along with the oil shale richness profile.
[0288] FIG. 271 displays heater temperature as a function of formation depth for a turndown ratio of 3:1.
[0289] FIG. 272 displays heater heat flux through a formation for a turndown ratio of 3:1 along with the oil shale richness profile.
[0290] FIG. 273 displays heater temperature as a function of formation depth for a turndown ratio of 4:1.

[0291] FIG. 274 depicts heater temperature versus depth for heaters used in a simulation for heating oil shale.
[0292] FIG. 275 depicts heater heat flux versus time for heaters used in a simulation for heating oil shale.

102931 FIG. 276 depicts accumulated heat input versus time in a simulation for heating oil shale.
[0294] FIG. 277 depicts a plot of heater power versus core diameter.
[0295] FIG. 278 depicts power, resistance, and current versus temperature for a heater with core diameters of 0.105".

[0296] FIG. 279 depicts actual heater power versus time during the simulation for three different heater designs.
102971 FIG. 280 depicts heater element temperature (core temperature) and average formation temperature versus time for three different heater designs.
[0298] FIG. 281 depicts experimental calculations of weight percentages of ferrite and.austenite phases versus temperature for iron alloy TC3.
102991 FIG. 282 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for iron alloy FM=4.
[0300] FIG. 283 depicts the Curie temperature and phase transformation temperature range for several iron alloys.
[0301] FIG. 284 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for an iron-cobalt alloy with 5.63% by weight cobalt and 0.4% by weight manganese.
[0302] FIG. 285 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by weight manganese, and 0.0 1% carbon.
[0303] FIG. 286 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085% carbon.
[0304] FIG. 287 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for an iron-cobalt alloy with 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% carbon, and 0.4% titanium.
[0305] FIG. 288 depicts experimental calculations of weight percentages of ferrite and austenite phases versus temperature for an iron-chromium alloy having 12.25% by weight chromium, 0.1 % by weight carbon, 0.5% by weight manganese, and 0.5% by weight silicon.

[0306] FIG. 289 depicts experimental calculation of weight percentages of phases versus weight percentages of chromium in an alloy.
[0307] FIG. 290 depicts experimental calculation of weight percentages of phases versus weight percentages of silicon in an alloy.
[0308] FIG. 291 depicts experimental calculation of weight percentages of phases versus weight percentages of tungsten in an alloy.
[0309] FIG. 292 depicts experimental calculation of weight percentages of phases versus weight percentages of niobium in an alloy.
[0310] FIG. 293 depicts experimental calculation of weight percentages of phases versus weight perceritages of carbon in an alloy.
[0311] FIG. 294 depicts experimental calculation of weight percentages of phases versus weight percentages of nitrogen in an alloy.
[0312] FIG. 295 depicts experimental calculation of weight percentages of phases versus weight percentages of titanium in an alloy.
[0313] FIG. 296 depicts experimental calculation of weight percentages of phases versus weight percentages of copper in an alloy.
103141 FIG. 297 depicts experimental calculation of weight percentages of phases versus weight percentages of manganese in an alloy.
[0315] FIG. 298 depicts experimental calculation of weight percentages of phases versus weight percentages of nickel in an alloy.
[0316] FIG. 299 depicts experimental calculation of weight percentages of phases versus weight percentages of molybdenum in an alloy.
[0317] FIG. 300A depicts yield strengths and ultimate tensile strengths for different metals.
[0318] FIG. 300B depicts yield strengths for different metals.
[0319] FIG. 300C depicts ultimate tensile strengths for different metals.
[0320] FIG. 300D depicts yield strengths for different metals.
[0321] FIG. 300E depicts ultimate tensile strengths for different metals.
[0322] FIG. 301 depicts a temperature profile in the formation after 360 days using the STARS
simulation.
[0323] FIG. 302 depicts an oil saturation profile in the formation after 360 days using the STARS simulation.
[0324] FIG. 303 depicts the oil saturation profile in the formation after 1095 days using the STARS simulation.

[0325] FIG. 304 depicts the oil saturation profile in the formation after 1470 days using the STARS simulation.
[0326] FIG. 305 depicts the oil saturation profile in the formation after 1826 days using the STARS simulation.
[0327] FIG. 306 depicts the temperature profile in the formation after 1826 days using the STARS simulation.
103281 FIG. 307 depicts oil production rate and gas production rate versus time.
[0329] FIG. 308 depicts weight percentage of original bitumen in place (OBIP)(left axis) and volume percentage of OBIP (right axis) versus temperature ( C).
103301 FIG. 309 depicts bitumen conversion percentage (weight percentage of (OBIP))(left axis) and oil, gas, and coke weight percentage (as a weight percentage of OBIP)(right axis) versus temperature ( C).
[0331] FIG. 310 depicts API gravity ( )(left axis) of produced fluids, blow down production, and oil left in place along with pressure (psig)(right axis) versus temperature ( C).
[0332] FIG. 311A-D depict gas-to-oil ratios (GOR) in thousand cubic feet per barrel ((Mcf/
bbl)(y-axis) for versus temperature ( C)(x-axis) for different types of gas at a low temperature blow down (about 277 C) and a high temperature blow down (at about 290 C).
[0333] FIG. 312 depicts coke yield (weight percentage)(y-axis) versus temperature ( C)(x-axis).
[0334] FIG. 313A-D depict assessed hydrocarbon isomer shifts in fluids produced from the experimental cells as a function of temperature and bitumen conversion.
[0335] FIG. 314 depicts weight percentage (Wt%)(y-axis) of saturates from SARA
analysis of the produced fluids versus temperature ( C)(x-axis).
[0336] FIG. 315 depicts weight percentage (Wt%)(y-axis) of n-C7 of the produced fluids versus temperature ( C)(x-axis).
[0337] FIG. 316 depicts oil recovery (volume percentage bitumen in place (vol%
BIP)) versus API gravity ( ) as determined by the pressure (MPa) in the formation in an experiment.
[0338] FIG. 317 depicts recovery efficiency (%) versus temperature ( C) at different pressures in an experiment.
[0339] While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION
103401 The following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.
[0341] "Alternating current (AC)" refers to a time-varying current that reverses direction substantially sinusoidally. AC produces skin effect electricity flow in a ferromagnetic conductor.
[0342] "API gravity" refers to API gravity at 15.5 C (60 F). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.
[0343] "ASTM" refers to American Standard Testing and Materials.
[0344] In the context of reduced heat output heating systems, apparatus, and methods, the term "automatically" means such systems, apparatus, and methods function in a certain way without the use of external control (for example, external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller).
103451 "Bare metal" and "exposed metal" refer to metals of elongated members that do not include a layer of electrical insulation, such as mineral insulation, that is designed to provide electrical insulation for the metal throughout an operating temperature range of the elongated member. Bare metal and exposed metal may encompass a metal that includes a corrosion inhibiter such as a naturally occurring oxidation layer, an applied oxidation layer, and/or a film.
Bare metal and exposed metal include metals with polymeric or other types of electrical insulation that cannot retain electrical insulating properties at typical operating temperature of the elongated member. Such material may be placed on the metal and may be thermally degraded during use of the heater.
[0346] Boiling range distributions for the formation fluid and liquid streams described herein are as determined by ASTM Method D5307 or ASTM Method D2887. Content of hydrocarbon components in weight percent for paraffins, iso-paraffins, olefins, naphthenes and aromatics in the liquid streams is as determined by ASTM Method D6730. Content of aromatics in volume percent is as determined by ASTM Method D1319. Hydrogen Content in hydrocarbons in weight percent is as determined by ASTM Method D3343.

[0347] Bromine number" refers to a weight percentage of olefins in grams per 100 gram of portion of the produced fluid that has a boiling range below 246 C and testing the portion using ASTM Method D1159.
[0348] "Carbon number" refers to the number of carbon atoms in a molecule. A
hydrocarbon fluid may include various hydrocarbons with different carbon numbers. The hydrocarbon fluid may be described by a carbon number distribution. Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.

[0349] "Cenospheres" refers to hollow particulate that are formed in thermal processes at high temperatures when molten components are blown up like balloons by the volatilization of organic components.
[0350] "Chemically stability" refers to the ability of a formation fluid to be transported without components in the formation fluid reacting to form polymers and/or compositions that plug pipelines, valves, and/or vessels.
[0351] "Clogging" refers to impeding and/or inhibiting flow of one or more compositions through a process vessel or a conduit.
[0352] "Column X element" or "Column X elements" refer to one or more elements of Column X of the Periodic Table, and/or one or more compounds of one or more elements of Column X
of the Periodic Table, in which X corresponds to a column number (for example, 13-18) of the Periodic Table. For example, "Column 15 elements" refer to elements from Column 15 of the Periodic Table and/or compounds of one or more elements from Column 15 of the Periodic Table.
[0353] "Column X metal" or "Column X metals" refer to one or more metals of Column X of the Periodic Table and/or one or more compounds of one or more metals of Column X of the Periodic Table, in which X corresponds to a column number (for example, 1-12) of the Periodic Table. For example, "Column 6 metals" refer to metals from Column 6 of the Periodic Table and/or compounds of one or more metals from Column 6 of the Periodic Table.
[0354] "Condensable hydrocarbons" are hydrocarbons that condense at 25 C and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. "Non-condensable hydrocarbons" are hydrocarbons that do not condense at 25 C and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.
[0355] "Coring" is a process that generally includes drilling a hole into a formation and removing a substantially solid mass of the formation from the hole.

103561 "Cracking" refers to a process involving decomposition and molecular recombination of organic compounds to produce a greater number of molecules than were initially present. In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and Hz.

[0357] "Curie temperature" is the temperature above which a ferromagnetic material loses all of its ferromagnetic properties. In addition to losing all of its ferromagnetic properties above the Curie temperature, the ferromagnetic material begins to lose its ferromagnetic properties when an increasing electrical current is passed through the ferromagnetic material.
[0358] "Cycle oil" refers to a mixture of light cycle oil and heavy cycle oil.
"Light cycle oil"
refers to hydrocarbons having a boiling range distribution between 430 F (221 C) and 650 F
(343 C) that are produced from a fluidized catalytic cracking system. Light cycle oil content is determined by ASTM Method D5307. "Heavy cycle oil" refers to hydrocarbons having a boiling range distribution between 650 F (343 C) and 800 F (427 C) that are produced from a fluidized catalytic cracking system. Heavy cycle oil content is determined by ASTM Method D5307.

[0359] "Diad" refers to a group of two items (for example, heaters, wellbores, or other objects) coupled together.
[0360] "Diesel" refers to hydrocarbons with a boiling range distribution between 260 C and 343 C (500-650 F) at 0.101 MPa. Diesel content is determined by ASTM Method D2887.
[0361] "Enriched air" refers to air.having a larger mole fraction of oxygen than air in the atmosphere. Air is typically enriched to increase combustion-supporting ability of the air.
[0362] "Fluid pressure" is a pressure generated by a fluid in a formation.
"Lithostatic pressure"
(sometimes referred to as "lithostatic stress") is a pressure in a formation equal to a weight per unit area of an overlying rock mass. "Hydrostatic pressure" is a pressure in a formation exerted by a column of water.
[0363] A "formation" includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers"
refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material. The "overburden" and/or the "underburden"
include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate.
In some embodiments of in situ heat treatment processes, the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden. For example, the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process. In some cases, the overburden and/or the underburden may be somewhat permeable.

[0364] "Formation fluids" refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. The term "mobilized fluid" refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. "Produced fluids" refer to fluids removed from the formation.
[0365] "Freezing point" of a hydrocarbon liquid refers to the temperature below which solid hydrocarbon crystals may form in the liquid. Freezing point is as determined by ASTM Method D5901.

[0366] "Gasoline hydrocarbons" refer to hydrocarbons having a boiling point range from 32 C
(90 F) to about 204 C (400 F). Gasoline hydrocarbons include, but are not limited to, straight run gasoline, naphtha, fluidized or thermally catalytically cracked gasoline, VB gasoline, and coker gasoline. Gasoline hydrocarbons content is determined by ASTM Method D2887.
103671 "Heat of Combustion" refers to an estimation of the net heat of combustion of a liquid.
Heat of combustion is as determined by ASTM Method D3338.
[0368] A "heat source" is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit. A heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In some embodiments, heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation.
It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. Thus, for example, for a given formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A

chemical reaction may include an exothermic reaction (for example, an oxidation reaction). A
heat source may also include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.
[0369] A "heater" is any system or heat source for generating heat in a well or a near wellbore region. Heaters may be, but are not limited to, electric heaters, burners, combustors that react with material in or produced from a formation, and/or combinations thereof.
[0370] "Heavy hydrocarbons" are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20 . Heavy oil, for example, generally has an API
gravity of about 10-20 , whereas tar generally has an API gravity below about 10 . The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15 C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.
[0371] Heavy hydrocarbons may be found in a relatively permeable formation.
The relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate. "Relatively permeable" is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy).
"Relatively low permeability" is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy. One darcy is equal to about 0.99 square micrometers. An impermeable layer generally has a permeability of less than about 0'.1 millidarcy.
[0372] Certain types of formations that include heavy hydrocarbons may also include, but are not limited to, natural mineral waxes, or natural asphaltites. "Natural mineral waxes" typically occur in substantially tubular veins that may be several meters wide, several kilometers long, and hundreds of meters deep. "Natural asphaltites" include solid hydrocarbons of an aromatic composition and typically occur in large veins. In situ recovery of hydrocarbons from formations such as natural mineral waxes and natural asphaltites may include melting to form liquid hydrocarbons and/or solution mining of hydrocarbons from the formations.
[0373] "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites.

Hydrocarbons may be located in or adjacent to mineral matrices in the earth.
Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. "Hydrocarbon fluids" are fluids that include hydrocarbons.
Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.
[0374] An "in situ conversion process" refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation.
[0375] An "in situ heat treatment process" refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation.
[0376] "Insulated conductor" refers to any elongated material that is able to conduct electricity and that is covered, in whole or in part, by an electrically insulating material.
[0377] "Karst" is a subsurface shaped by the dissolution of a soluble layer or layers of bedrock, usually carbonate rock such as limestone or dolomite. The dissolution may be caused by meteoric or acidic water. The Grosmont formation in Alberta, Canada is an example of a karst (or "karsted") carbonate formation.
[03781 "Kerogen" is a solid, insoluble hydrocarbon that has been converted by natural degradation and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples of materials that contain kerogen.
"Bitumen" is a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.
"Oil" is a fluid containing a mixture of condensable hydrocarbons.
103791 "Kerosene" refers to hydrocarbons with a boiling range distribution between 204 C and 260 C at 0.101 MPa. Kerosene content is determined by ASTM Method D2887.
[0380] "Modulated direct current (DC)" refers to any substantially non-sinusoidal time-varying current that produces skin effect electricity flow in a ferromagnetic conductor.
103811 "Naphtha" refers to hydrocarbon components with a boiling range distribution between 38 C and 200 C at 0.101 MPa. Naphtha content is determined by American Standard Testing and Materials (ASTM) Method D5307.
[0382] "Nitride" refers to a compound of nitrogen and one or more other elements of the Periodic Table. Nitrides include, but are not limited to, silicon nitride, boron nitride, or alumina nitride.

[0383] "Nitrogen compound content" refers to an amount of nitrogen in an organic compound.
Nitrogen content is as determined by ASTM Method D5762.
[0384] "Octane Number" refers to a calculated numerical representation of the antiknock properties of a motor fuel compared to a standard reference fuel. A calculated octane number is determined by ASTM Method D6730.
[0385] "Olefins" are molecules that include unsaturated hydrocarbons having one or more non-aromatic carbon-carbon double bonds.
103861 "Olefin content" refers to an amount of non-aromatic olefins in a fluid. Olefin content for a produced fluid is determined by obtaining a portion of the produce fluid that has a boiling point of 246 C and testing the portion using ASTM Method D1159 and reporting the result as a bromine factor in grams per 100 gram of portion. Olefin content is also determined by the Canadian Association of Petroleum Producers (CAPP) olefin method and is reported in percent olefin as 1-decene equivalent.
[0387] "Orifices" refer to openings, such as openings in conduits, having a wide variety of sizes and cross-sectional shapes including, but not limited to, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes.
[0388] ""P (peptization) value" or "P-value" refers to a numerical value, which represents the flocculation tendency of asphaltenes in a formation fluid. P-value is determined by ASTM
method D7060.
[0389] "Pebble" refers to one or more spheres, oval shapes, oblong shapes, irregular or elongated shapes.
[0390] "Periodic Table" refers to the Periodic Table as specified by the International Union of Pure and Applied Chemistry (IUPAC), November 2003. In the scope of this application, weight of a metal from the Periodic Table, weight of a compound of a metal from the Periodic Table, weight of an element from the Periodic Table, or weight of a compound of an element from the Periodic Table is calculated as the weight of metal or the weight of element.
For example, if 0.1 grams of Mo03 is used per gram of catalyst, the calculated weight of the molybdenum metal in the catalyst is 0.067 grams per gram of catalyst.
[0391] "Physical stability" refers the ability of a formation fluid to not exhibit phase separate or flocculation during transportation of the fluid. Physical stability is determined by ASTM
Method D7060.
[0392] "Pyrolysis" is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.

[0393] "Pyrolyzation fluids" or "pyrolysis products" refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone" refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

[0394] "Residue" refers to hydrocarbons that have a boiling point above 537 C
(1000 F).
[0395] "Rich layers" in a hydrocarbon containing formation are relatively thin layers (typically about 0.2 m to about 0.5 m thick). Rich layers generally have a richness of about 0.150 L/kg or greater. Some rich layers have a richness of about 0.170 L/kg or greater, of about 0.190 L/kg or greater, or of about 0.2 10 L/kg or greater. Lean layers of the formation have a richness of about 0.100 L/kg or less and are generally thicker than rich layers. The richness and locations of layers are determined, for example, by coring and subsequent Fischer assay of the core, density or neutron logging, or other logging methods. Rich layers may have a lower initial thermal conductivity than other layers of the formation. Typically, rich layers have a thermal conductivity 1.5 times to 3 times lower than the thermal conductivity of lean layers. In addition, rich layers have a higher thermal expansion coefficient than lean layers of the formation.
[0396] "Smart well technology" or "smart wellbore" refers to wells that incorporate downhole measurement and/or control. For injection wells, smart well technology may allow for controlled injection of fluid into the formation in desired zones. For production wells, smart well technology may allow for controlled production of formation fluid from selected zones.
Some wells may include smart well technology that allows for formation fluid production from selected zones and simultaneous or staggered solution injection into other zones. Smart well technology may include fiber optic systems and control valves in the wellbore.
A smart wellbore used for an in situ heat treatment process may be Westbay Multilevel Well System MP55 available from Westbay Instruments Inc. (Burnaby, British Columbia, Canada).
[0397] "Subsidence" is a downward movement of a portion of a formation relative to an initial elevation of the surface. [0398] "Sulfur compound content" refers to an amount of sulfur in an organic compound.

Sulfur content is as determined by ASTM Method D4294.
[0399] "Superposition of heat" refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.

[0400] "Synthesis gas" is a mixture including hydrogen and carbon monoxide.
Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane, and other gases. Synthesis gas may be generated by a variety of processes and feedstocks. Synthesis gas may be used for synthesizing a wide range of compounds.
[0401] "TAN" refers to a total acid number expressed as milligrams ("mg") of KOH per gram ("g") of sample. TAN is as determined by ASTM Method D3242.
[0402] "Tar" is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15 C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10 .
104031 A "tar sands formation" is a formation in which hydrocarbons are predominantly present in'the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate). Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela.
[0404] "Temperature limited heater" generally refers to a heater that regulates heat output (for example, reduces heat output) above a specified temperature without the use of external controls such as temperature controllers, power regulators, rectifiers, or other devices. Temperature limited heaters may be AC (alternating current) or modulated (for example, "chopped") DC
(direct current) powered electrical resistance heaters.
[0405] "Thermally conductive fluid" includes fluid that has a higher thermal conductivity than air at standard temperature and pressure (STP) (0 C and 101.325 kPa).
104061 "Thermal conductivity" is a property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.
104071 "Thermal fracture" refers to fractures created in a formation caused by expansion or contraction of a formation and/or fluids in the formation, which is in turn caused by increasing/decreasing the temperature of the formation and/or fluids in the formation, and/or by increasing/decreasing a pressure of fluids in the formation due to heating.
[0408] "Thermal oxidation stability" refers to thermal oxidation stability of a liquid. Thermal Oxidation Stability is as determined by ASTM Method D3241.
[0409] "Thickness" of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer.

[0410] "Time-varying current" refers to electrical current that produces skin effect electricity flow in a ferromagnetic conductor and has a magnitude that varies with time.
Time-varying current includes both alternating current (AC) and modulated direct current (DC).
[0411] "Triad" refers to a group of three items (for example, heaters, wellbores, or other objects) coupled together.
[0412] "Turndown ratio" for the temperature limited heater is the ratio of the highest AC or modulated DC resistance below the Curie temperature to the lowest resistance above the Curie temperature for a given current.
[0413] A "u-shaped wellbore" refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation. In this context, the wellbore may be only roughly in the shape of a"v" or "u", with the understanding that the "legs" of the "u" do not need to be parallel to each other, or perpendicular to the "bottom" of the "u" for the wellbore to be considered "u-shaped".
[0414] "Upgrade" refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons.
[0415] "Visbreaking" refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.
[0416] "Viscosity" refers to kinematic viscosity at 40 C unless specified.
Viscosity is as determined by ASTM Method D445.
[0417] "VGO" or "vacuum gas oil" refers to hydrocarbons with a boiling range distribution between 343 C and 538 C at 0.10I MPa. VGO content is determined by ASTM
Method D5307.
[0418] A "vug" is a cavity, void or large pore in a rock that is commonly lined with mineral precipitates.
[0419] "Wax" refers to a low melting organic mixture, or a compound of high molecular weight that is a solid at lower temperatures and a liquid at higher temperatures, and when in solid form can form a barrier to water. Examples of waxes include animal waxes, vegetable waxes, mineral waxes, petroleum waxes, and synthetic waxes.
104201 The term "wellbore" refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. As used herein, the terms "well" and "opening,"
when referring to an opening in the formation may be used interchangeably with the term "wellbore."

104211 Hydrocarbons in formations may be treated in various ways to produce many different products. In certain embodiments, hydrocarbons in formations are treated in stages. FIG. I
depicts an illustration of stages of heating the hydrocarbon containing formation. FIG. I also depicts an example of yield ("Y") in barrels of oil equivalent per ton (y axis) of formation fluids from the formation versus temperature ("T") of the heated formation in degrees Celsius (x axis).
[0422] Desorption of methane and vaporization of water occurs during stage I
heating. Heating of the formation through stage I may be performed as quickly as possible. For example, when the hydrocarbon containing formation is initially heated, hydrocarbons in the formation desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water in the hydrocarbon containing formation is vaporized. Water may occupy, in some hydrocarbon containing formations, between 10% and 50% of the pore volume in the formation. In other formations, water occupies larger or smaller portions of the pore volume. Water typically is vaporized in a formation between 160 C and 285 C at pressures of 600 kPa absolute to 7000 kPa absolute. In some embodiments, the vaporized water produces wettability changes in the formation and/or increased formation pressure. The wettability changes and/or increased pressure may affect pyrolysis reactions or other reactions in the formation. In certain embodiments, the vaporized water is produced from the formation. In other embodiments, the vaporized water is used for steam extraction and/or distillation in the formation or outside the formation. Removing the water from and increasing the pore volume in the formation increases the storage space for hydrocarbons in the pore volume.
[0423] In certain embodiments, after stage I heating, the formation is heated further, such that a temperature in the formation reaches (at least) an initial pyrolyzation temperature (such as a temperature at the lower end of the temperature range shown as stage 2).
Hydrocarbons in the formation may be pyrolyzed throughout stage 2. A pyrolysis temperature range varies depending on the types of hydrocarbons in the formation. The pyrolysis temperature range may include temperatures between 250 C and 900 C. The pyrolysis temperature range for producing desired products may extend through only a portion of the total pyrolysis temperature range. In some embodiments, the pyrolysis temperature range for producing desired products may include temperatures between 250 C and 400 C or temperatures between 270 C and 350 C. If a temperature of hydrocarbons in the formation is slowly raised through the temperature range from 250 C to 400 C, production of pyrolysis products may be substantially complete when the temperature approaches 400 C. Average temperature of the hydrocarbons may be raised at a rate of less than 5 C per day, less than 2 C per day, less than 1 C per day, or less than 0.5 C per day through the pyrolysis temperature range for producing desired products.
Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that slowly raise the temperature of hydrocarbons in the formation through the pyrolysis temperature range.
104241 The rate of temperature increase through the pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Raising the temperature slowly through the pyrolysis temperature range for desired products may inhibit mobilization of large chain molecules in the formation. Raising the temperature slowly through the pyrolysis temperature range for desired products may limit reactions between mobilized hydrocarbons that produce undesired products.
Slowly raising the temperature of the formation through the pyrolysis temperature range for desired products may allow for the production of high quality, high API
gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the pyrolysis temperature range for desired products may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.
[0425] In some in situ heat treatment embodiments, a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range. In some embodiments, the desired temperature is 300 C, 325 C, or 350 C. Other temperatures may be selected as the desired temperature. Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at the desired temperature. The heated portion of the formation is maintained substantially at the desired temperature until pyrolysis declines such that production of desired formation fluids from the formation becomes uneconomical. Parts of the formation that are subjected to pyrolysis may include regions brought into a pyrolysis temperature range by heat transfer from only one heat source.
[0426] In certain embodiments, formation fluids including pyrolyzation fluids are produced from the formation. As the temperature of the formation increases, the amount of condensable hydrocarbons in the produced formation fluid may decrease. At high temperatures, the formation may produce mostly methane and/or hydrogen. If the hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.

[0427] After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen may still be present in the formation. A significant portion of carbon remaining in the formation can be produced from the formation in the form of synthesis gas. Synthesis gas generation may take place during stage 3 heating depicted in FIG. 1. Stage 3 may include heating a hydrocarbon containing formation to a temperature sufficient to allow synthesis gas generation. For example, synthesis gas may be produced in a temperature range from about 400 C to about 1200 C, about 500 C to about 1100 C, or about 550 C to about 1000 C. The temperature of the heated portion of the formation when the synthesis gas generating fluid is introduced to the formation determines the composition of synthesis gas produced in the formation. The generated synthesis gas may be removed from the formation through a production well or production wells.
[0428] Total energy content of fluids produced from the hydrocarbon containing formation may stay relatively constant throughout pyrolysis and synthesis gas generation.
During pyrolysis at relatively low formation temperatures, a significant portion of the produced fluid may be condensable hydrocarbons that have a high energy content. At higher pyrolysis temperatures, however, less of the formatiorrfluid may include condensable hydrocarbons.
More non-condensable formation fluids may be produced from the formation. Energy content per unit volume of the produced fluid may decline slightly during generation of predominantly non-condensable formation fluids. During synthesis gas generation, energy content per unit volume of produced synthesis gas declines significantly compared to energy content of pyrolyzation fluid. The volume of the produced synthesis gas, however, will in many instances increase substantially, thereby compensating for the decreased energy content.
[0429] FIG. 2 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation. The in situ heat treatment*
system may include barrier wells 200. Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area. Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof. In some embodiments, barrier wells 200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated. In the embodiment depicted in FIG. 2, the barrier wells 200 are shown extending only along one side of heat sources 202, but the barrier wells typically encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.

[0430] Heat sources 202 are placed in at least a portion of the formation.
Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204. Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation. In some embodiments, electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants.
The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.
[0431) When the formation is heated, the heat input into the formation may cause expansion of the formation and geomechanical motion. The heat sources turned on before, at the same time, or during a dewatering process. Computer simulations may model formation response to heating. The computer simulations may be used to develop a pattern and time sequence for activating heat sources in the formation so that geomechanical motion of the formation does not adversely affect the functionality of heat sources, production wells, and other equipment in the formation.
[0432] Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 206 to be spaced relatively far apart in the formation.
[0433] Production wells 206 are used to remove formation fluid from the formation. In some embodiments, production well 206 includes a heat source. The heat source in the production well may heat one or more portions of the formation at or near the productioh well. In some in situ heat treatment process embodiments, the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source. Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.
104341 More than one heat source may be positioned in the production well. A
heat source in a lower portion of the production well may be turned off when superposition of heat from adjacent heat sources heats the formation sufficiently to counteract benefits provided by heating the formation with the production well. In some embodiments, the heat source in an upper portion of the production well may remain on after the heat source in the lower portion of the production well is deactivated. The heat source in the upper portion of the well may inhibit condensation and reflux of formation fluid.
[0435] In some embodiments, the heat source in production well 206 allows for vapor phase removal of formation fluids from the formation. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C6 and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.
104361 Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells.
[0437] In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been pyrolyzed.
Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, the selected quality includes an API gravity of at least about 20 , 30 , or 40 . Inhibiting production until at least some hydrocarbons are pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons. Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.
[0438] In some hydrocarbon containing formations, hydrocarbons in the formation may be heated to pyrolysis temperatures before substantial permeability has been generated in the heated portion of the formation. An initial lack of permeability may inhibit the transport of generated fluids to production wells 206. During initial heating, fluid pressure in the formation may increase proximate heat sources 202. The increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 202. For example, selected heat sources 202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.
[0439] In some embodiments, pressure generated by expansion of pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to production wells 206 or any other pressure sink may not yet exist in the formation. The fluid pressure may be allowed to increase towards a lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure. For example, fractures may form from heat sources 202 to production wells 206 in the heated portion of the formation.
The generation of fractures in the heated portion may relieve some of the pressure in the portion.
Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation.
[0440] After pyrolysis temperatures are reached and production from the formation is allowed, pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component.
The condensable fluid component may contain a larger percentage of olefins.
[0441] In some in situ heat treatment process embodiments, pressure in the formation may be maintained high enough to promote production of formation fluid with an API
gravity of greater than 20 . Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may facilitate vapor phase production of fluids from the formation. Vapor phase production may allow for a reduction in size of collection conduits used to transport fluids produced from the formation. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities.

[0442] Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number. The selected carbon number may be at most 25, at most 20, at most 12, or at most 8. Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor. High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.
[0443] Generation of relatively low molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen in a portion of the hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into the liquid phase within the formation. Heating the portion to a temperature in a pyrolysis temperature range may pyrolyze hydrocarbons in the formation to generate liquid phase pyrolyzation fluids. The generated liquid phase pyrolyzation fluids components may include double bonds and/or radicals. Hydrogen (H2) in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids.
In addition, H2 may also neutralize radicals in the generated pyrolyzation fluids. Therefore, HZ
in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation.
104441 Formation fluid produced from production wells 206 may be transported through collection piping 208 to treatment facilities 210. Formation fluids may also be produced from heat sources 202. For example, fluid may be produced from heat sources 202 to control pressure in the formation adjacent to the.heat sources. Fluid produced from heat sources 202 may be transported through tubing or piping to collection piping 208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 210.
Treatment facilities 210 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids. The treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation. In some embodiments, the transportation fuel may be jet fuel, such as JP-8.

[0445] Formation fluid may be hot when produced from the formation through the production wells. Hot formation fluid may be produced during solution mining processes and/or during in situ heat treatment processes. In some embodiments, electricity may be generated using the heat of the fluid produced from the formation. Also, heat recovered from the formation after the in situ process may be used to generate electricity. The generated electricity may be used to supply power to the in situ heat treatment process. For example, the electricity may be used to power heaters, or to power a refrigeration system for forming or maintaining a low temperature barrier.
Electricity may be generated using a Kalina cycle or a modified Kalina cycle.
[0446] FIG. 3 depicts a schematic representation of a Kalina cycle that uses relatively high pressure aqua ammonia as the working fluid. In other embodiments, other fluids such as alkanes, hydrochlorofluorocarbons, hydrofluorocarbons, or carbon dioxide may be used as the working fluid. Hot produced fluid from the formation may pass through line 212 to heat exchanger 214. The produced fluid may have a temperature greater than about 100 C. Line 216 from heat exchanger 214 may direct the produced fluid to a separator or other treatment unit. In some embodiments, the produced fluid is a mineral containing fluid produced during solution mining. In some embodiments, the produced fluid includes hydrocarbons produced using an in situ heat treatment process or using an in situ mobilization process. Heat from the produced fluid is used to evaporate aqua ammonia in heat exchanger 214.
104471 Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214 and heat exchanger 222. Aqua ammonia from heat exchangers 214, 222 passes to separator 224.
Separator 224 forms a rich ammonia gas stream and a lean ammonia gas stream.
The rich ammonia gas stream is sent to turbine 226 to generate electricity.
[0448] The lean ammonia gas stream from separator 224 passes through heat exchanger 222.
The lean gas stream leaving heat exchanger 222 is combined with the rich ammonia gas stream leaving turbine 226. The combination stream is passed through heat exchanger 228 and returned to tank 218. Heat exchanger 228 may be water cooled. Heater water from heat exchanger 228 may be sent to a surface water reservoir through line 230.
[0449] FIG. 4 depicts a schematic representation of a modified Kalina cycle that uses lower pressure aqua ammonia as the working fluid. In other embodiments, other fluids such as alkanes, hydrochlorofluorcarbons, hydrofluorocarbons, or carbon dioxide may be used as the working fluid. Hot produced fluid from the formation may pass through line 212 to heat exchanger 214. The produced fluid may have a temperature greater than about 100 C. Second heat exchanger 232 may further reduce the temperature of the produced fluid from the formation before the fluid is sent through line 216 to a separator or other treatment unit. Second heat exchanger may be water cooled.
104501 Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 234. The temperature of the aqua ammonia from tank 218 is heated in heat exchanger 234 by transfer with a combined aqua ammonia stream from turbine 226 and separator 224. The aqua ammonia stream from heat exchanger 234 passes to heat exchanger 236. The temperature of the stream is raised again by transfer of heat with a lean ammonia stream that exits separator 224. The stream then passes to heat exchanger 214. Heat from the produced fluid is used to evaporate aqua ammonia in heat exchanger 214. The aqua ammonia passes to separator 224.
104511 Separator 224 forms a rich ammonia gas stream and a lean ammonia gas stream. The rich ammonia gas stream is sent to turbine 226 to generate electricity. The lean ammonia gas stream passes through heat exchanger 236. After heat exchanger 236, the lean ammonia gas stream is combined with the rich ammonia gas stream leaving turbine 226. The combined gas stream is passed through heat exchanger 234 to cooler 238. After cooler 238, the stream returns to tank 218.
[04521 FIGS. 5 and 5A depict schematic representations of an embodiment of a system for producing crude products and/or commercial products from the in situ heat treatment process liquid stream and/or the in situ heat treatment process gas stream. Formation fluid 320 enters fluid separation unit 322 and is separated into in situ heat treatment process liquid stream 324, in situ heat treatment process gas 240 and aqueous stream 326. In some embodiments, fluid separation unit 322 includes a quench zone. As produced formation fluid enters the quench zone, quenching fluid such as water, nonpotable water and/or other components may be added to the formation fluid to quench and/or cool the formation fluid to a temperature suitable for handling in downstream processing equipment. Quenching the formation fluid may inhibit formation of compounds that contribute to physical and/or chemical instability of the fluid (for example, inhibit formation of compounds that may precipitate from solution, contribute to corrosion, and/or fouling of downstream equipment and/or piping). The quenching fluid may be introduced into the formation fluid as a spray and/or a liquid stream. In 'some embodiments, the formation fluid is introduced into the quenching fluid. In some embodiments, the formation fluid is cooled by passing the fluid through a heat exchanger to remove some heat from the formation fluid. The quench fluid may be added to the cooled formation fluid when the temperature of the formation fluid is near or at the dew point of the quench fluid. Quenching the formation fluid near or at the dew point of the quench fluid may enhance solubilization of salts that may cause chemical and/or physical instability of the quenched fluid (for example, ammonium salts). In some embodiments, an amount of water used in the quench is minimal so that salts of inorganic compounds and/or other components do not separate from the mixture. In separation unit 322, at least a portion of the quench fluid may be separated from the quench mixture and recycled to the quench zone with a minimal amount of treatment.
Heat produced from the quench may be captured and used in other facilities. In some embodiments, vapor may be produced during the quench. The produced vapor may be sent to gas separation unit 328 and/or sent to other facilities for processing.
[0453] In situ heat treatment process gas 240 may enter gas separation unit 328 to separate gas hydrocarbon stream 330 from the in situ heat treatment process gas. The gas separation unit is, in some embodiments, a rectified adsorption and high pressure fractionation unit. Gas hydrocarbon stream 330 includes hydrocarbons having a carbon number of at least 3.
[0454] In situ heat treatment process liquid stream 324 enters liquid separation unit 332. In some embodiments, liquid separation unit 332 is not necessary. In liquid separation unit 332, separation of in situ heat treatment process liquid stream 324 produces gas hydrocarbon stream 336 and salty process liquid stream 338. Gas hydrocarbon stream 336 may include hydrocarbons having a carbon number of at most 5. A portion of gas hydrocarbon stream 336 may be combined with gas hydrocarbon stream 330.
104551 In situ heat conversion process gas 240 enters gas separation unit 328.
In gas separation unit 328, treatment of in situ heat conversion process gas 240 removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gas stream 330. In some embodiments, situ heat conversion process gas 240 includes 20 vol% hydrogen, 30% methane, 12% carbon dioxide, 14 vol% C2 hydrocarbons, 5 vol% hydrogen sulfide, 10 vol% C3 hydrocarbons, 7 vol%

hydrocarbons, 2 vol /a C5 hydrocarbons, with the balance being heavier hydrocarbons, water, ammonia, COS, mercaptans and thiophenes.
[0456] Gas separation unit 328 may include a physical treatment system and/or a chemical treatment system. The physical treatment system includes, but is not limited to, a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, and/or a cryogenic unit. The chemical treatment system may include units that use amines (for example, diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereof in the treatment process.
In some embodiments, gas separation unit 328 uses a Sulfinol gas treatment process for removal of sulfur compounds. Carbon dioxide may be removed using Catacarb (Catacarb, Overland Park, Kansas, U.S.A.) and/or Benfield (UOP, Des Plaines, Illinois, U.S.A.) gas treatment processes. The gas separation unit is, in some embodiments, a rectified adsorption and high pressure fractionation unit. In some embodiments, in suit heat conversion process gas is treated to remove at least 50%, at least 60%, at least 70%, at least 80% or at least 90% by volume of ammonia present in the gas stream.
[0457] As depicted in FIG. 6, in situ heat conversion process gas 240 may enter compressor 2300 of gas separation unit 328 to form compressed gas stream 2302 and heavy stream 2304.
Heavy stream 2304 may be transported to one or more liquid separation units described herein for further processing. Compressor 2300 may be any compressor suitable for compressing gas.
In certain embodiments, compressor 2300 is a multistage compressor (for example 2 to 3 compressor trains) having an outlet pressure of about 40 bars. In some embodiments, compressed gas stream 2302 may include at least 1 vol% carbon dioxide, at least 10 vol%
hydrogen, at least I vol% hydrogen sulfide, at least 50 vol% of hydrocarbons having a carbon number of at most 4, or mixtures thereof. Compression of in situ heat conversion process gas 240 removes hydrocarbons having a carbon number of least 4 and water. Removal of water and hydrocarbons having a carbon number of at least 4 from the in situ process allows compressed gas stream 2302 to be treated cryogenically. Cryogenic treatment of compressed gas stream 2302 having small amounts of high boiling materials may be done more efficiently. In certain embodiments, compressed gas stream 2302 is dried by passing the gas through a water adsorption unit.
[0458] As shown in FIGS. 6 through 9, gas separation unit 328 includes one or more cryogenic units. Cryogenic units described herein may include one or more distillation stages. In FIGS. 6 through 9, one or more heat exchangers may be positioned prior or after cryogenic units and/or separation units described herein to assist in removing and/or adding heat to one or more streams described herein. At least a portion or all of the separated hydrocarbons streams and/or the separated carbon dioxides streams may be transported to the heat exchangers.
In some embodiments, distillation stages may include from about 1 to about 100 stages, about 5 to about 50 stages, or about 10 to about 40 stages. Stages of the cryogenic units may be cooled to temperatures ranging from about -110 C to about 0 C. For example, stage 1(top stage) in a cryogenic unit is cooled to about -110 C, stage 5 cooled to about -25 C, stage 1 cooled to about -l C. Total pressures in cryogenic units may range from about I bar to about 50 bar, from about 5 bar to about 40 bar, or from about 10 bar to about 30 bar. Cryogenic units described herein may include condenser recycle conduits 2306 and reboiler recycle conduits 2308. Condenser recycle conduits 2306 allows recycle of the cooled separated gases so that the feed may be cooled as it enters cryogenic unit the cryogenic units.
Temperatures in condensation loops may range from about -110 C to about -1 C, from about -90 C to about -5 C, or from about -80 C to about -10 C. Temperatures in reboiler loops may range from about 25 C to about 200 C, from about 50 C to about 150 C, or from about 75 C
to about 100 C.
Reboiler recycle conduits 2308 allow recycle of the stream exiting the cryogenic unit to heat the stream as it exits the cryogenic unit. Recycle of the cooled and/or warmed separated stream may enhance energy efficiency of the cryogenic unit.
[0459] As shown in FIG. 6, compressed gas stream 2302 enters methane/hydrogen cryogenic unit 2310. In cryogenic unit 2310, compressed gas stream 2302 may be separated into a methane/hydrogen stream 2312 and a bottoms stream 2314. Bottoms stream 2314 may include, but is not limited to carbon dioxide, hydrogen sulfide, and hydrocarbons having a carbon number of at least 2. Methane/hydrogen stream 2312 may include a minimal amount of.C2 hydrocarbons and carbon dioxide. For example, methane/hydrogen stream 2312 may include about I vol% C2 hydrocarbons and about I vol% carbon dioxide. In some embodiments, the methane/hydrogen stream is recycled to one or more heat exchangers positioned prior to the cryogenic unit 2310. In some embodiments, the methane/hydrogen stream is used as a fuel for downhole burners and/or an energy source for surface facilities.
[0460] In some embodiments, cryogenic unit 2310 may include one distillation column with about I to about 30 stages, about 5 to about 25 stages, or about 10 to about 20 stages. Stages of cryogenic unit 2310 may be cooled to temperatures ranging from about -110 C
to about 10 C.
For example, stage 1(top stage) cooled to about -138 C, stage 5 cooled to about -25 C, stage C cooled to at about -1 C. At temperatures lower than -79 C cryogenic separation of the carbon dioxide from other gases may be difficult due to the freezing point of carbon dioxide. In some embodiments, cryogenic unit 2310 is about 17 ft. tall and includes about 20 distillation stages. Cryogenic unit 2310 may be operated at a pressure of 40 bar with distillation temperatures ranging from about -45 C to about -94 C.
[0461] Compressed gas stream 2302 may include sufficient hydrogen and/or hydrocarbons having a carbon number of at least 1 to inhibit solid carbon dioxide formation. For example, in situ heat conversion process gas 240 may include from about 30 vol % to about 40 vol% of hydrogen, from about 50 vol% to 60 vol% of hydrocarbons having a carbon number from 1 to 2, from about 0.1 vol% to about 3 vol% of carbon dioxide with the balance being other gases such as, but not limited to, carbon monoxide, nitrogen, and hydrogen sulfide.
Inhibiting solid carbon dioxide formation may allow for better separation of gases and/or less fouling of the cryogenic unit. In some embodiments, hydrocarbons having a carbon number of at least five may be added to cryogenic unit 2310 to inhibit formation of solid carbon dioxide. The resulting methane/hydrogen gas stream 2312 may be used as an energy source. For example, methane/hydrogen gas stream 2312 may be transported to surface facilities and burned to generate electricity.
[0462] As shown in FIG. 6, bottoms stream 2314 enters cryogenic separation unit 2316. In cryogenic separation unit 2316, bottoms stream 2314 is separated into gas stream 2320 and liquid stream 2318. Gas stream 2320 may include hydrocarbons having a carbon number of at least 3. In some embodiments, gas stream 2320 includes at least 0.9 vol% of C3-hydrocarbons, and at most I ppm of carbon dioxide and about 0.1 vol% of hydrogen sulfide. In some embodiments, gas stream 2320 includes hydrogen sulfide in quantities sufficient to require treatment of the stream to remove the hydrogen sulfide. In some embodiments, gas stream 2320 is suitable for transportation and/or use as an energy source without further treatment. In some embodiments, gas stream 2320 is used as an energy source for in situ heat treatment processes.
[0463] A portion of liquid stream 2318 may be transported via conduit 2322 to one or more portions of the formation and sequestered. In some embodiments, all of liquid stream 2318 is sequestered in one or more portions of the formation. In some embodiments, a portion of liquid stream 2318 enters cryogenic unit 2324. In cryogenic unit 2324, liquid stream 2318 is separated into C2 hydrocarbons/carbon dioxide stream 2326 and hydrogen sulfide stream 2328. In some embodiments, C2 hydrocarbons/carbon dioxide stream 2326 includes at most 0.5 vol% of hydrogen sulfide.
[0464] Hydrogen sulfide stream 2328 includes, in some embodiments, about 0.01 vol% to about vol% of C3 hydrocarbons. In some embodiments, hydrogen sulfide stream 2328 includes hydrogen sulfide, carbon dioxide, C3 hydrocarbons, or mixtures thereof. For example, hydrogen sulfide stream 2328 includes, about 32 vol% of hydrogen sulfide, 67 vol%
carbon dioxide, and I
vol% C3 hydrocarbons. In some embodiments, hydrogen sulfide stream 2328 is used as an energy source for an in situ heat treatment process and/or sent to a Claus plant for further treatment.
[0465] C2 hydrocarbons/carbon dioxide stream 2326 may enter separation unit 2330. In separation unit 2330 C2 hydrocarbons/carbon dioxide stream 2326 is separated into C2 hydrocarbons stream 2332 and carbon dioxide stream 2334. Separation of CZ
hydrocarbons from carbon dioxide is performed using separation methods known in the art, for example, pressure swing adsorption units, and/or extractive distillation units. In some embodiments, C2 hydrocarbons are separated from carbon dioxide using extractive distillation methods. For example, hydrocarbons having a carbon number from 3 to 8 may be added to separation unit =
2330. Addition of a higher carbon number hydrocarbon solvent allows C2 hydrocarbons to be extracted from the carbon dioxide. C2 hydrocarbons are then separated from the higher carbon number hydrocarbons using distillation techniques. In some embodiments, C2 hydrocarbons stream 2332 is transported to other process facilities and used as an energy source. Carbon dioxide stream 2334 may be sequestered in one or more portions of the fonnation. In some embodiments, carbon dioxide stream 2334 contains at most 0.005 grams of non-carbon dioxide compounds per gram of carbon dioxide stream. In some embodiments, carbon dioxide stream 2334 is mixed with one or more oxidant sources supplied to one or more downhole burners.
[0466] In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are sequestered and/or transported to other facilities via conduit 2336. In some embodiments, a portion or all of C? hydrocarbons/carbon dioxide stream 2326 is mixed with one or more oxidant sources supplied to one or more downhole burners.
[0467] As depicted in FIG. 7, bottoms stream 2314 enters cryogenic separation unit 2338. In cryogenic separation unit 2338, bottoms stream 2314 may be separated into C2 hydrocarbons/carbon dioxide stream 2326 and hydrogen sulfide/hydrocarbon gas stream 2340.
In some embodiments, C2 hydrocarbons/carbon dioxide stream 2326 contains hydrogen sulfide.
Hydrogen sulfide/hydrocarbon gas stream 2340 may include hydrocarbons having a carbon number of at least 3.
[0468] In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are transported via conduit 2336 to one or more portions of the formation and sequestered. In some embodiments, a portion or all of C2 hydrocarbons/carbon dioxide stream 2326 are treated in separation unit 2330. Separation unit 2330 is described above with reference to FIG. 6.
[0469] Hydrogen sulfide/hydrocarbon gas stream 2340 may enter cryogenic separation unit 2342. In cryogenic separation unit 2342, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 2328 and C3 hydrocarbon stream 2320. Hydrogen sulfide stream 2328 may include, but is not limited to, hydrogen sulfide, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 2328 may contain from about 20 vol% to about 80 vol%
of hydrogen sulfide, from about 4 vol% to about 18 vol% of propane and from about 2 vol%
to about 70 vol% of carbon dioxide. In some embodiments, hydrogen sulfide stream 2328 is burned to produce SO,. The SOX may sequestered and/or treated using known techniques in the art.
104701 In some embodiments, C3 hydrocarbon stream 2320 includes a minimal amount of hydrogen sulfide and carbon dioxide. For example, C3 hydrocarbon stream 2320 may include about 99.6 vol% of hydrocarbons having a carbon number of at least 3, about 0.4 vol% of hydrogen sulfide and at most I ppm of carbon dioxide. In some embodiments, C3 hydrocarbon stream 2320 is transported to other processing facilities as an energy source.
In some embodiments, C3 hydrocarbon stream 2320 needs no further treatment.
[0471] As depicted in FIG. 8, bottoms stream 2314 may enter cryogenic separation unit 2344.
In cryogenic separation unit 2344, bottoms stream 2314 may be separated into hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 2346 and hydrogen sulfide/hydrocarbon gas stream 2340. In some embodiments, cryogenic separation unit 2338 is 12 ft tall and includes 45 distillation stages. A top stage of cryogenic separation unit 2338 may be operated at a temperature of -31 C and a pressure20 bar.
[0472] A portion or all of C2 hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 2346 and hydrocarbon stream 2348 may enter cryogenic separation unit 2350.
Hydrocarbon stream 2348 may be any hydrocarbon stream suitable for use in a cryogenic extractive distillation system. In some embodiments, hydrocarbon stream 2348 is n-hexane. In cryogenic separation unit 2350, C) hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 2346 is separated into carbon dioxide stream 2334 and hydrocarbon/H-,S stream 2352. In some embodiments, carbon dioxide stream 2334 includes about 2.5 vol% of hydrocarbons having a carbon number of at most 2. In some embodiments, carbon dioxide stream 2334 may be mixed with diluent fluid for downhole burners, may be used as a carrier fluid for oxidizing fluid for downhole burners, may be used as a drive fluid for producing hydrocarbons, may be vented, and/or may be sequestered.
In some embodiments, cryogenic separation unit 2350 is 4 m tall and includes 40 distillation stages. Cryogenic separation unit 2350 may be operated at a temperature of about -19 C and a pressure of about 20 bar.
104731 Hydrocarbon/hydrogen sulfide stream 2352 may enter cryogenic separation unit 2354.
Hydrocarbon/hydrogen stream 2352 may include solvent hydrocarbons, C2 hydrocarbons and hydrogen sulfide. In cryogenic separation unit 2354, hydrocarbon/hydrogen sulfide stream 2352 may be separated into C2 hydrocarbons/hydrogen sulfide stream 2382 and hydrocarbon stream 2384. Hydrocarbon stream 2384 may contain hydrocarbons having a carbon number of at least 3. In some embodiments, separation unit 2354 is about 6.5 m. tall and includes 20 distillation stages. Cryogenic separation unit 2354 may be operated at temperatures of about -16 C and a pressure of about 10 bar.
[0474] Hydrogen sulfide/hydrocarbon gas stream 2340 may enter cryogenic separation unit 2342. In cryogenic separation unit 2342, hydrogen sulfide may be separated from hydrocarbons having a carbon number of at least 3 to produce hydrogen sulfide stream 2328 and C3 hydrocarbon stream 2320. Hydrogen sulfide stream 2328 may include, but is not limited to, hydrogen sulfide, C2 hydrocarbons, C3 hydrocarbons, carbon dioxide, or mixtures thereof. In some embodiments, hydrogen sulfide stream 2328 contains from about 31 vol%
hydrogen sulfide with the balance being C2 and C3 hydrocarbons. Hydrogen sulfide stream 2328 may be burned to produce SO,. The SO, may be sequestered and/or treated using known techniques in the art.

[0475] In some embodiments, cryogenic separation unit 2342 is about 4.3 m tall and includes about 40 distillation stages. Temperatures in cryogenic separation unit 2342 may range from about 0 C to about 10 C. Pressure in cryogenic separation unit 2342 may be about 20 bar.
[0476] C3 hydrocarbon stream 2320 may include a minimal amount of hydrogen sulfide and carbon dioxide. In some embodiments, C3 hydrocarbon stream 2320 includes about 50 ppm of hydrogen sulfide. In some embodiments, C3 hydrocarbon stream 2320 is transported to other processing facilities as an energy source. In some embodiments, hydrocarbon stream C3 hydrocarbon stream 2320 needs no further treatment.
[0477] As depicted in FIG. 9, compressed gas stream 2302 may be treated using a Ryan/Holmes process to recover the carbon dioxide from the compressed gas stream 2302.
Compressed gas stream 2302 enters cryogenic separation unit 2356. In some embodiments cryogenic separation unit 2356 is about 7.6 m tall and includes 40 distillation stages. Cryogenic separation unit 2356 may be operated at a temperature ranging from about 60 C to about -56 C and a pressure of about 30 bar. In cryogenic separation unit 2356, compressed gas stream 2302 may be separated into methane/carbon dioxide/hydrogen sulfide stream 2358 and hydrocarbon/HzS
stream 2360.
[0478] Methane/carbon dioxide/hydrogen sulfide stream 2358 may include hydrocarbons having a carbon number of at most 2 and hydrogen sulfide. Methane/carbon dioxide/hydrogen sulfide stream 2358 may be compressed in compressor 2362 and enter cryogenic separation unit 2364.
In cryogenic separation unit 2364, methane/carbon dioxide/hydrogen sulfide stream 2358 is separated into carbon dioxide stream 2334 and methane/hydrogen sulfide stream 2312. In some embodiments, cryogenic separation unit 2364 is about 2.1 m tall and includes 20 distillation stages. Temperatures in cryogenic separation unit 2364 may range from about -56 C to about -96 C at a pressure of about 45 bar.
[0479] Carbon dioxide stream 2334 may include some hydrogen sulfide. For example carbon dioxide stream 2334 may include about 80 ppm of hydrogen sulfide. At least a portion of carbon dioxide stream 2334 may be used as a heat exchange medium in heat exchanger 2366. In some embodiments, at least a portion of carbon dioxide stream 2334 is sequestered in the formation and/or at least a portion of the carbon dioxide stream is used as a diluent in downhole oxidizer assemblies.

[0480] Hydrocarbon/hydrogen sulfide stream 2360 may include hydrocarbons having a carbon number of at least 2 and hydrogen sulfide. Hydrocarbon/hydrogen sulfide stream 2360 may pass through heat exchanger 2366 and enter separation unit 2368. In separation unit 2368, hydrocarbon/hydrogen sulfide stream 2360 may be separated into hydrocarbon stream 2370 and hydrogen sulfide stream 2328. In some embodiments, separation unit 2368 is about 7 m tall and includes 30 distillation stages. Temperatures in separation unit 2368 may range from about 60 C to about 27 C at a pressure of about 10 bar.
104811 Hydrocarbon stream 2370 may include hydrocarbons having a carbon number of at least 3. Hydrocarbon stream 2370 may pass through expansion unit 2372 and form purge stream 2374 and hydrocarbon stream 2376. Purge stream 2374 may include some hydrocarbons having a carbon number greater than 5. Hydrocarbon stream 2376 may include hydrocarbons having a carbon number of at most 5. In some embodiments, hydrocarbon stream 2376 includes 10 vol%
n-butanes and 85 vol% hydrocarbons having a carbon number of 5. At least a part of hydrocarbon stream 2376 may be recycled to cryogenic separation unit 2356 to maintain a ratio of about 1.4:1 of hydrocarbons to compressed gas stream 2302.
[0482] Hydrogen sulfide stream 2328 may include hydrogen sulfide, C2 hydrocarbons, and some carbon dioxide. In some embodiments, hydrogen sulfide stream 2328 includes from about 13 vol% hydrogen sulfide, about 0.8 vol% carbon dioxide with the balance being C2 hydrocarbons.
At least a portion of the hydrogen sulfide stream 2328 may be burned as an energy source. In some embodiments, hydrogen sulfide stream 2328 is used as a fuel source in downhole burners.
[0483] As shown in FIGS. 5 and 5A, Salty process liquid stream 338 may be processed through desalting unit 340 to form liquid stream 334. Desalting unit 340 removes mineral salts and/or water from salty process liquid stream 338 using known desalting and water removal methods.
In certain embodiments, desalting unit 340 is upstream of liquid separation unit 332.
[0484] Liquid stream 334 includes, but is not limited to, hydrocarbons having a carbon number of at least 5 and/or hydrocarbon containing heteroatoms (for example, hydrocarbons containing nitrogen, oxygen, sulfur, and phosphorus). Liquid stream 334 may include at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between about 95 C and about 200 C at 0.101 MPa; at least 0.01 g, at least 0.005 g, or at least 0.001 g of hydrocarbons with a boiling range distribution between about 200 C and about 300 C at 0.101 MPa; at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between about 300 C and about 400 C at 0.101 MPa; and at least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with a boiling range distribution between 400 C and 650 C at 0.101 MPa. In some embodiments, liquid stream 334 contains at most 10% by weight water, at most 5% by weight water, at most 1% by weight water, or at most 0.1%
by weight water.
[0485] In some embodiments, the separated liquid stream may have a boiling range distribution between about 50 C and about 350 C, between about 60 C and 340 C, between about 70 C
and 330 C or between about 80 C and 320 C. In some embodiments, the separated liquid stream has a boiling range distribution between 180 C and 330 C.
[0486] In some embodiments, at least 50%, at least 70%, or at least 90% by weight of the total hydrocarbons in the separated liquid stream have a carbon number from 8 to 13.
The separated Iiquid stream may have from about 50% to about 100%, about 60% to about 95%, about 70% to about 90%, or about 75% to 85% by weight of liquid stream may have a carbon number distribution from 8 to 13. At least 50% by weight to the total hydrocarbon in the separated Iiquid stream may have a carbon number from about 9 to 12 or from 10 to 11.
[0487] In some embodiments the separated liquid stream has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 30%, at most 20%, or at most 10% by weight aromatics.
[0488] In some embodiments, the separated liquid stream has a nitrogen compound content of at least 0.01%, at least 0.1% or at least 0.4% by weight nitrogen compound. The separated liquid stream may have a sulfur compound content of at least 0.01 %, at least 0.5% or at least 1% by weight sulfur compound.
[0489] After exiting desalting unit 340, liquid stream 334 enters filtration system 342. In some embodiments, filtration system 342 is connected to the outlet of the desalting unit. Filtration system 342 separates at least a portion of the clogging compounds from liquid stream 334. In some embodiments, filtration system 342 is skid mounted. Skid mounting filtration system 342 may allow the filtration system to be moved from one processing unit to another. In some embodiments, filtration system 342 includes one or more membrane separators, for example, one or more nanofiltration membranes or one or more reserve osmosis membranes.
[0490] In some embodiments, liquid stream 334 is contacted with hydrogen in the presence of one or more catalysts to change one or more desired properties of the crude feed to meet transportation and/or refinery specifications using known hydrodemetallation, hydrodesulfurization, hydrodenitrofication techniques. Other methods to change one or more desired properties of the crude feed are described in U.S. Published Patent Applications Nos.
2005-0133414; 2006-0231465; and 2007-0000810 to Bhan et al.; 2005-0133405 to Wellington et al.; and 2006-0289340 to Brownscombe et al.

[0491] In some embodiments, the hydrotreated liquid stream has a nitrogen compound content of at most 200 ppm by weight, at most 150 ppm, at most 110 ppm, at most 50 ppm, or at most ppm of nitrogen compounds. The separated liquid stream may have a sulfur compound content of at most 100 ppm, at most 500 ppm, at most 300 ppm, at most 100 ppm, or at most 10 ppm by weight of sulfur compounds.
[0492] In some embodiments, hydrotreating unit 350 is a selective hydrogenation unit. In hydrotreating unit 350, liquid stream 334 and/or filtered liquid stream 344 are selectively hydrogenated such that di-olefins are reduced to mono-olefins. For example, liquid stream 334 and/or filtered liquid stream 344 is contacted with hydrogen in the presence of a DN-200 (Criterion Catalysts & Technologies, Houston Texas, U.S.A.) at temperatures ranging from 100 C to 200 C and total pressures of 0.1 MPa to 40 MPa to produce liquid stream 352. In some embodiments, filtered liquid stream 344 is hydrotreated at a temperature ranging from about 190 C and about 200 C at least 6 MPa. Liquid stream 352 includes a reduced content of di-olefins and an increased content of mono-olefins relative to the di-olefin and mono-olefin content of liquid stream 334. The conversion of di-olefins to mono-olefins under these conditions is, in some embodiments, at least 50%, at least 60%, at least 80% or at least 90%.
Liquid stream 352 exits hydrotreating unit 350 and enters one or more processing units positioned downstream of hydrotreating unit 350. The units positioned downstream of hydrotreating unit 350 may include distillation units, catalytic reforming units, hydrocracking units, hydrotreating units, hydrogenation units, hydrodesulfurization units, catalytic cracking units, delayed coking units, gasification units, or combinations thereof. In some embodiments, hydrotreating prior to fractionation is not necessary. In some embodiments, liquid stream 352 may be severely hydrotreated to remove undesired compounds from the liquid stream prior to fractionation. In certain embodiments, liquid stream 352 may be fractionated and then produced streams may each be hydrotreated to meet industry standards and/or transportation standards.
104931 Liquid stream 352 may exit hydrotreating unit 350 and enter fractionation unit 354. In fractionation unit 354, liquid stream 352 may be distilled to form one or more crude products.
Crude products include, but are not limited to, C3-C5 hydrocarbon stream 356, naphtha stream 358, kerosene stream 360, diesel stream 362, and bottoms stream 364.
Fractionation unit 354 may be operated at atmospheric and/or under vacuum conditions.
[0494] As shown in FIG. 5A, fractionation unit 354 includes two or more zones operated at different temperatures and pressures. Operating the two zones at different temperatures and pressures may inhibit or substantially reduce fouling of fractionation columns, heat exchangers and/or other equipment associated with fractionation unit 354. Liquid stream 352 may enter first fractionation zone 2000. Fractionation zone KC200 may be operated at a temperature ranging from about 50 C to about 350 C, or from about 100 C to 325 C, or from about 150 C to 300 C at 0.101 MPa to separate compounds boiling above 350 from the liquid stream to produce one or more crude products including, but not limited to, C3-C5 hydrocarbon stream 356a, naphtha stream 358', kerosene stream 360', and diesel stream 362'.
Hydrocarbons having a boiling point above 350 C (for example bottoms stream 364') may enter second fractionation zone 2002. Second fractionation zone 2002 may be operated at temperatures greater than 350 C at 0.101 MPa to separate form one or more crude products, including but not limited to, C3-C5 hydrocarbon stream 356b', naphtha stream 358", kerosene stream 360", diesel stream 362", and bottoms stream 364". In some embodiments, second fractionation zone 2002 is operated under vacuum. Bottoms stream 364, bottoms stream 364', and/or bottoms stream 364" generally includes hydrocarbons having a boiling range distribution of at least 340 C
at 0.101 MPa. In some embodiments, bottoms stream 364 is vacuum gas oil. In other embodiments, bottoms stream 364 bottoms stream 364', and/or bottoms stream 364" includes hydrocarbons with a boiling range distribution of at least 537 C. One or more of the crude products may be sold and/or further processed to gasoline or other commercial products. In certain embodiments, one or more of the crude products may be hydrotreated to meet industry standards and/or transportation standards.
[0495] As shown in FIG. 10'hydrotreated liquid stream may be treated in fractionation unit 354 to remove compounds boiling below 180 C to produce distilled stream 355.
Distilled stream 355 may have a boiling range distribution between about 140 C and about 350 C, between about 180 C and about 330 C, or between about 190 C and about 310 C. In some embodiments distilled stream 355 may be hydrotreated prior to fractionation to remove undesired compounds (for example, sulfur and/or nitrogen compounds). In certain embodiments, distilled stream 355 is sent to a hydrotreating unit and hydrotreated to meet transportation standards for metals, nitrogen compounds and/or sulfur compounds.
[0496] In some embodiments, at least 50%, at least 70%, or at least 90% by weight of the total hyd'rocarbons in distilled liquid stream 355 have a carbon number from 8 to 13. Distilled liquid stream 355 may have from about 50% to about 100%, about 60% to about 95%, about 70% to about 90%, or about 75% to 85% by weight may have a carbon number from 8 to 13. At least 50% by weight to the total hydrocarbon in distilled liquid stream 355 may have a carbon number from about 9 to 12 or from 10 to 11.
[0497] In some embodiments, hydrotreated and distilled liquid stream 355 has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 25%, at most 20%, or at most 15% by weight aromatics.
[0498] In some embodiments, hydrotreated and distilled liquid stream 355 has a nitrogen compound content of at most 200 ppm by weight, at most 150 ppm, at most 110 ppm, at most 50 ppm, at most 10 ppm, or at most 5 ppm of nitrogen compounds. The hydrotreated and distilled liquid stream may have a sulfur content of at most 50 ppm, at most 30 ppm or at most 10 ppm by weight sulfur compound.
[0499] In some embodiments, hydrotreated and/or distilled liquid stream 355 has a wear scar diameter as measured by ASTM D5001, ranging from about 0.1 mm to about 0.9 mm, from about 0.2 mm to about 0.8 mm, or from 0.3 mm to about 0.7 mm. In some embodiments, hydrotreated and/or distilled liquid stream 355 has a wear scar diameter, as measured by ASTM
D5001 of at most 0.85 mm, at most 0.8 mm, at most 0.6 mm, at most 0.5 mm, or at most 0.3 mm. A wear scar diameter, as determined by ASTM D5001, may indicate the hydrotreated and/or distilled stream may have acceptable lubrication properties for transportation fuel (for example, commercial aviation fuel, fuel for military purposes, JP-8 fuel, Jet A-1 fuel).
[0500] Hydrotreating to remove undesired compounds (for example, sulfur compounds and nitrogen compounds) from the liquid stream may decrease the liquid stream to be an effective lubricant (for example, lubricity properties when used as a transportation fuel). In some embodiments, hydrotreated and/or distilled liquid stream 355 has a minimal concentration and/or no detectable amounts of sulfur compounds. A low sulfur, nonadditized hydrotreated and/or distilled liquid stream 355 may have acceptable lubricity properties (for example, an acceptable wear scar diameter as measured by ASTM D5001). For example, the hydrotreated and distilled liquid stream may have a boiling range distribution from about 140 C to about 260 C, a sulfur content of at most 30 ppm by weight, and a wear scar diameter of at most 0.85 mm.
[0501] In some embodiments, naphtha stream 358, kerosene stream 360, diesel stream 362, distilled liquid stream 355 are evaluated to determine an amount, if any, of additives and/or hydrocarbons that may be added to prepare a fully formulated transportation fuel and/or lubricant. For example, a distilled stream made by the processes described herein was evaluated for use in military vehicles against Department of Defense standard MIL-DTL-83133E using ASTM test methods. The results of the test are listed in TABLE 1.
TABLE I
M I L-DTL-83133 E Standard Specification Test Liquid Stream Min Max ASTM Test Method MIL-DTL-83133E Standard Specification Test Liquid Stream Min Max ASTM Test Method Total Acid Number, mg 0.007 0.015 D3242 KOH/g Aromatics, % volume 11.4 25.0 D1319 Mercaptan Sulfur, % mass 0.000 0.001 D3227 Total Sulfur, % mass 0.00 0.3 D4294 Distillation: D2887 IBP, C 180 report 10% recovered, C 188 186 20% recovered, C 191 Report 50% recovered, C 199 Report 90% recovered, C 215 Report EP, C 229 330 Residue, % volume 0.9 1.5 Loss, % volume 03 1.5 Flash point, C 60 38 D56 Cetane Index (calculated) 43.7 report D976 Freeze Point, C -55 -47 D5901 Viscosity -20 C, cSt 4.4 8 D445 Viscosity @ -40 C, cSt 9.0 Heat of Combustion 18644 42.8 D3338 (calculated), BTU/Ib Hydrogen Content, % mass 14.0 13.4 D3343 Smoke Point, mm 26 25.0 D1322 Copper Strip Corrosion 1 a D130 Thermal Stability @ 260 C:
Tube Deposit Rating I D3241 Change in Pressure, mm Hg 0 Existent Gum, mg/100 mL-- 1.4 D381 Water Reaction I D1094 Conductivity, pS/m 6* D2624 Density 15 C 0.801 0.775 0.840 D1298 Lubricity (BOCLE), wear <0.85 D5001 scar mm [0502] To enhance. the use of the streams produced from formation fluid, hydrocarbons produced during fractionation of the liquid stream and hydrocarbon gases produced during separating the process gas may be combined to form hydrocarbons having a higher carbon number. The produced hydrocarbon gas stream may include a level of olefins acceptable for alkylation reactions.
[0503] In some embodiments, hydrotreated liquid streams and/or streams produced from fractions (for example, distillates and/or naphtha) are blended with the in situ heat treatment process liquid and/or formation fluid to produce a blended fluid. The blended fluid may have enhanced physical stability and chemical stability as compared to the formation fluid. The blended fluid may have a reduced amount of reactive species (for example, di-olefins, other olefins and/or compounds containing oxygen, sulfur and/or nitrogen) relative to the formation fluid., Thus, chemical stability of the blended fluid is enhanced. The blended fluid may decrease an amount of asphaltenes relative to the formation fluid. Thus, physical stability of the blended fluid is enhanced. The blended fluid may be a more a fungible feed than the formation fluid and/or the liquid stream produced from an in situ heat treatment process. The blended feed may be more suitable for transportation, for use in chemical processing units and/or for use in refining units than formation fluid.
[0504] In some embodiments, a fluid produced by methods described herein from an oil shale formation may be blended with heavy oil/tar sands in situ heat treatment process (IHTP) fluid.
Since the oil shale liquid is substantially paraffinic and the heavy oil/tar sands IHTP fluid is substantially aromatic, the blended fluid exhibits enhanced stability. In certain embodiments, in situ heat treatment process fluid may be blended with bitumen to obtain a feed suitable for use in refining units. Blending of the IHTP fluid and/or bitumen with the produced fluid may enhance the chemical and/or physical stability of the blended product. Thus, the blend may be transported and/or distributed to processing units.
[0505] As shown in FIGS. 5, 5A, and 10, C3-C5 hydrocarbon stream 356 produced from fractionation unit 354 and hydrocarbon gas stream 330 enter alkylation unit 368. In alkylation unit 368, reaction of the olefins in hydrocarbon gas stream 330 (for example, propylene, butylenes, amylenes, or combinations thereof) with the iso-paraffins in C3-C5 hydrocarbon stream 356 produces hydrocarbon stream 370. In some embodiments, the olefin content in hydrocarbon gas stream 330 is acceptable and an additional source of olefins is not needed.
Hydrocarbon stream 370 includes hydrocarbons having a carbon number of at least 4.
Hydrocarbons having a carbon number of at least 4 include, but are not limited to, butanes, pentanes, hexanes, heptanes, and octanes. In certain embodiments, hydrocarbons produced from alkylation unit 368 have an octane number greater than 70, greater than 80, or greater than 90.
In some embodiments, hydrocarbon stream 370 is suitable for use as gasoline without further processing.
[0506] In some embodiments, bottoms stream 364 may be hydrocracked to produce naphtha and/or other products. The resulting naphtha may, however, need reformation to alter the octane level so that the product may be sold commercially as gasoline. Alternatively, bottoms stream 364 may be treated in a catalytic cracker to produce naphtha and/or feed for an alkylation unit.

In some embodiments, naphtha stream 358, kerosene stream 360, and diesel stream 362 have an imbalance of paraffinic hydrocarbons, olefinic hydrocarbons, and/or aromatic hydrocarbons.
The streams may not have a suitable quantity of olefins and/or aromatics for use in commercial products. This imbalance may be changed by combining at least a portion of the streams to form combined stream 366 which has a boiling range distribution from about 38 C to about 343 C. Catalytically cracking combined stream 366 may produce olefins and/or other streams suitable for use in an alkylation unit and/or other processing units. In some embodiments, naphtha stream 358 is hydrocracked to produce olefins.
[0507] In FIG. 5 and FIG. 5A, combined stream 366 and bottoms stream 364 from fractionation unit 354 enters catalytic cracking unit 372. In FIG. 5A, combined stream 366 may include all or portions of streams 358', 360', 362', 358", 360", 362". Under controlled cracking conditions (for example, controlled temperatures and pressures), catalytic cracking unit 372 produces additional C3-C5 hydrocarbon stream 356', gasoline hydrocarbons stream 374, and additional kerosene stream 360'.
[0508] Additional C3-C5 hydrocarbon stream 356' may be sent to alkylation unit 368, combined with C3-C5 hydrocarbon stream 356, and/or combined with hydrocarbon gas stream 330 to produce gasoline suitable for commercial sale. In some embodiments, the olefin content in hydrocarbon gas stream 330 is acceptable and an additional source of olefins is not needed.
[0509] Many wells are needed for treating the hydrocarbon formation using the in situ heat treatment process. In some embodiments, vertical or substantially vertical wells are formed in the formation. In some embodiments, horizontal or U-shaped wells are formed in the formation.
In some embodiments, combinations of horizontal and vertical wells are formed in the formation.
[0510] A manufacturing approach for the formation of wellbores in the formation may be used due to the large number of wells that need to be formed for the in situ heat treatment process.
The manufacturing approach may be particularly applicable for forming wells for in situ heat treatment processes that utilize u-shaped wells or other types of wells that have long non-vertically oriented sections. Surface openings for the wells may be positioned in lines running along one or two sides of the treatment area. FIG. 1 I depicts a schematic representation of an embodiment of a system for forming wellbores of an in situ heat treatment process.
[0511] The manufacturing approach for the formation of wellbores may include:
1) delivering flat rolled steel to near site tube manufacturing plant that forms coiled tubulars and/or pipe for surface pipelines; 2) manufacturing large diameter coiled tubing that is tailored to the required well length using electrical resistance welding (ERW), wherein the coiled tubing has customized ends for the bottom hole assembly (BHA) and hang off at the wellhead; 3) deliver the coiled tubing to a drilling rig on a large diameter reel; 4) drill to total depth with coil and a retrievable bottom hole assembly; 5) at total depth, disengage the coil and hang the coil on the wellhead; 6) retrieve the BHA; 7) launch an expansion cone to expand the coil against the formation; 8) return empty spool to the tube manufacturing plant to accept a new length of coiled tubing; 9) move the gantry type drilling platform to the next well location; and 10) repeat.
[0512] In situ heat treatment process locations may be distant from established cities and transportation networks. Transporting formed pipe or coiled tubing for wellbores to the in situ process location may be untenable due to the lengths and quantity of tubulars needed for the in situ heat treatment process. One or more tube manufacturing facilities 2004 may be formed at or near to the in situ heat treatment process location. The tubular manufacturing facility may form plate steel into coiled tubing. The plate steel may be delivered to tube manufacturing facilities 2004 by truck, train, ship or other transportation system. In some embodiments, different sections of the coiled tubing may be formed of different alloys. The tubular manufacturing facility may use ERW to longitudinally weld the coiled tubing.
[0513] Tube manufacturing facilities 2004 may be able to produce tubing having various diameters. Tube manufacturing facilities may initially be used to produce coiled tubing for forming wellbores. The tube manufacturing facilities may also be used to produce heater components, piping for transporting formation fluid to surface facilities, and other piping and tubing needs for the in situ heat treatment process.
[0514] Tube manufacturing facilities 2004 may produce coiled tubing used to form wellbores in the formation. The coiled tubing may have a large diameter. The diameter of the coiled tubing may be from about 4 inches to about 8 inches in diameter. In some embodiments, the diameter of the coiled tubing is about 6 inches in diameter. The coiled tubing may be placed on large diameter reels. Large diameter reels may be needed due to the large diameter of the tubing. The diameter of the reel may be from about 10 m to about 50 m. One reel may hold all of the tubing needed for completing a single well to total depth.
[0515] In some embodiments, tube manufacturing facilities 2004 has the ability to apply expandable zonal inflow profiler (EZIP) material to one or more sections of the tubing that the facility produces. The EZIP material may be placed on portions of the tubing that are to be positioned near and next to aquifers or high permeability layers in the formation. When activated, the EZIP material forms a seal against the formation may serves to inhibit migration of formation fluid between different layers. The use of EZIP layers may inhibit saline formation fluid from mixing with non-saline formation fluid.

105161 The size of the reels used to hold the coiled tubing may prohibit transport of the reel using standard moving equipment and roads. Because tube manufacturing facility 2004 is at or near the in situ heat treatment location, the equipment used to move the coiled tubing to the well sites does not have to meet existing road transportation regulations and can be designed to move large reels of tubing. In some embodiments the equipment used to move the reels of tubing is similar to cargo gantries used to move shipping containers at ports and other facilities. In some embodiments, the gantries are wheeled units. In some embodiments, the coiled tubing may be moved using a rail system or other transportation system.
[0517] The coiled tubing may be moved from the tubing manufacturing facility to the well site using gantries 2006. Drilling gantry 2008 may be used at the well site.
Several drilling gantries 2008 may be used to form wellbores at different locations. Supply systems for drilling fluid or other needs may be coupled to drilling gantries 2008 from central facilities 2010.
[0518] Drilling gantry 2008 or other equipment may be used to set the conductor for the well.
Drilling gantry 2008 takes coiled tubing, passes the coiled tubing through a straightener, and a BHA attached to the tubing is used to drill the wellbore to depth. In some embodiments, a composite coil is positioned in the coiled tubing at tube manufacturing facility 2004. The composite coil allows the wellbore to be formed without having drilling fluid flowing between the formation and the tubing. The composite coil also allows the BHA to be retrieved from the wellbore. The composite coil may be pulled from the tubing after wellbore formation. The composite coil may be returned to the tubing manufacturing facility to be placed in another length of coiled tubing. In some embodiments, the BHAs are not retrieved from the wellbores.
[0519] In some embodiments, drilling gantry 2008 takes the reel of coiled tubing from gantry 2006. In some embodiments, gantry 2006 is coupled to drilling gantry 2008 during the formation of the wellbore. For example, the coiled tubing may be fed from gantry 2006 to drilling gantry 2008, or the drilling gantry lifts the cargo gantry to a feed position and the tubing is fed from the cargo gantry to the drilling gantry.
[0520] The wellbore may be formed using the bottom hole assembly, coiled tubing and the drilling gantry. The BHA may be self-seeking to the destination. The BHA may form the opening at a fast rate. In some embodiments, the BHA forms the opening at a rate of about 100 m per hour.
[0521] After the wellbore is drilled to total depth, the tubing may be suspended from the wellhead. An expansion cone may be used to expand the tubular against the formation. In some embodiments, the drilling gantry is used to install a heater and/or other equipment in the wellbore.

[05221 When drilling gantry 2008 is finished at well site 2012, the drilling gantry may release gantry 2006 with the empty reel or return the empty reel to the gantry. Gantry 2006 may take the empty reel back to tube manufacturing facility 2004 to be loaded with another coiled tube.
Gantries 2006 may move on looped path 2014 from tube manufacturing facility 2004 to well sites 2012 and back to the tube manufacturing facility.
[0523] Drilling gantry 2008 may be moved to the next well site. Global positioning satellite information, lasers and/or other information may be used to position the drilling gantry at desired locations. Additional wellbores may be formed until all of the wellbores for the in situ heat treatment process are formed.
[0524] In some embodiments, positioning and/or tracking system may be utilized to track gantries 2006, drilling gantries 2008, coiled tubing reels and other equipment and materials used to develop the in situ heat treatment location. Tracking systems may include bar code tracking systems to ensure equipment and materials arrive where and when needed.
[0525] FIG. 12 depicts an embodiment for assessing a position of a first wellbore relative to a second wellbore using multiple magnets. First wellbore 452A is formed in a subsurface formation. Wellbore 452A may be formed by directionally drilling in the formation along a desired path. For example, wellbore 452A may be horizontally or vertically drilled in the subsurface formation.
105261 Second wellbore 452B may be formed in the subsurface formation with drill bit 2022 on drilling string 2016. In certain embodiments, drilling string 2016 includes one or more magnets 2546. Wellbore 452B may be formed in a selected relationship to wellbore 452A.
In certain embodiments, wellbore 452B is formed substantially parallel to wellbore 452A.
In other embodiments, wellbore 452B is formed at other angles relative to wellbore 452A. In some embodiments, wellbore 452B is formed perpendicular relative to wellbore 452A.
105271 In certain embodiments, wellbore 452A includes sensing array 2548.
Sensing array 2548 may include two or more sensors 2550. Sensors 2550 may sense magnetic fields produced by magnets 2546 in wellbore 452B. The sensed magnetic fields may be used to assess a position of wellbore 452A relative to wellbore 452B. In some embodiments, sensors 2550 measure two or more magnetic fields provided by magnets 2546.
[0528] Two or more sensors 2550 in wellbore 452A may allow for continuous assessment of the relative position of wellbore 452A versus welibore 452B. Using two or more sensors 2550 in wellbore 452A may also allow the sensors to be used as gradiometers. In some embodiments, sensors 2550 are positioned in advance (ahead of) magnets 2546. Positioning sensors 2550 in advance of magnets 2546 allows the magnets to traverse past the sensors so that the magnet's position (the position of wellbore 452B) is measurable continuously or "live"
during drilling of wellbore 452B. Sensing array 2548 may be moved intermittently (at selected intervals) to move sensors 2550 ahead of magnets 2546. Positioning sensors 2550 in advance of magnets 2546 also allows the sensors to measure, store, and zero the Earth's field before sensing the magnetic fields of the magnets. The Earth's field may be zeroed by, for example, using a null function before arrival of the magnets, calculating background components from a known sensor attitude, or using a gradiometer setup.
[0529] The relative position of wellbore 452B versus wellbore 452A may be used to adjust the drilling of wellbore 452B using drilling string 2016. For example, the direction of drilling for wellbore 452B may be adjusted so that wellbore 452B remains a set distance away from wellbore 452A and the wellbores remain substantially parallel. In certain embodiments, the drilling of wellbore 452B is continuously adjusted based on continuous position assessments made by sensors 2550. Data from drilling string 2016 (for example, orientation, attitude, and/or gravitational data) may be combined or synchronized with data from sensors 2550 to continuously assess the relative positions of the wellbores and adjust the drilling of wellbore 452B accordingly. Continuously assessing the relative positions of the wellbores may allow for coiled tubing drilling of wellbore 452B.
[0530] In some embodiments, drilling string 2016 may include two or more sensing arrays 2548.
Sensing arrays 2548 may include two or more sensors 2550. Using two or more sensing arrays 2548 in drilling string 2016 may allow for the direct measurement of magnetic interference of magnets 2546 on the measurement of the Earth's magnetic field. Directly measuring any magnetic interference of magnets 2546 on the measurement of the Earth's magnetic field may reduce errors in readings (for example, error to pointing azimuth). The direct measurement of the field gradient from the magnets from withiri drill string 2016 also provides confirmation of reference field strength of the field to be measured from within wellbore 452A.
105311 FIG. 13 depicts an alternative embodiment for assessing a position of a first wellbore relative to a second wellbore using a continuous pulsed signal. Signal wire 2552 may be placed in wellbore 452A. Sensor 2550 may be located in drilling string 2016 in wellbore 452B. In certain embodiments, wire 2552 provides a reference voltage signal (for example, a pulsed DC
reference signal). In one embodiment, the reference voltage signal is a 10 Hz pulsed DC signal.
In one embodiment, the reference voltage signal is a 5 Hz pulsed DC signal.
[0532] The electromagnetic field provided by the voltage signal may be sensed by sensor 2550.
The sensed signal may be used to assess a position of wellbore 452B relative to wellbore 452A.

[0533] In some embodiments, wire 2552 is a ranging wire located in wellbore 452A. In some embodiments, the voltage signal is provided by an electrical conductor that will be used as part of a heater in wellbore 452A. In some embodiments, the voltage signal is provided by an electrical conductor that is part of a heater or production equipment located in wellbore 452A.
Wire 2552, or other electrical conductors used to provide the voltage signal, may be grounded so that there is no current return along the wire or in the wellbore. Return current may cancel the electromagnetic field produced by the wire.
[0534] Where return current exists, the current may be measured and modeled to generate a "net current" from which a voltage signal may be resolved. For example, in some areas, a 600A
signal current may only yield a 3 - 6A net current. Where it is not feasible to eliminate sufficient return current along the wellbore containing the conductor, in some embodiments, two conductors may be utilized installed in separate wellbores. In this method, signal wires from each of the existing wellbores are connected to opposite voltage terminals of the signal generator. The return current path is in this way guided through the earth from the contactor region of one conductor to the other.
[0535] In certain embodiments, the reference voltage signal is turned on and off (pulsed) so that multiple measurements are taken by sensor 2550 over a selected time period.
The multiple measurements may be averaged to reduce or eliminate resolution error in sensing the reference voltage signal. In some embodiments, providing the reference voltage signal, sensing the signal, and adjusting the drilling based on the sensed signals are performed continuously without providing any data to the surface or any surface operator input to the downhole equipment. For example, an automated system located downhole may be used to perform all the downhole sensing and adjustment operations.
[0536] The signal field generated by the net current passing through the conductors needs to be resolved from the general background field existing when the signal field is "off'. A method for resolving the signal field from the general background field on a continuous basis may include:
1.) calculating background components based on the known attitude of the sensors and the known value background field strength and dip; 2.) a synchronized "null"
function to be applied immediately before the reference field is switched "on"; and/or 3.) synchronized sampling of forward and reversed DC polarities (the subtraction of these sampled values may effectively remove the background field yielding the reference total current field).
105371 FIG. 14 depicts an alternative embodiment for assessing a position of a first wellbore relative to a second wellbore using a radio ranging signal. Sensor 2550 may be placed in wellbore 452A. Source 2554 may be located in drilling string 2016 in wellbore 452B. In some embodiments, source 2554 is located in wellbore 452A and sensor 2550 is located in wellbore 452B. In certain embodiments, source 2554 is an electromagnetic wave producing source. For example, source 2554 may be an electromagnetic sonde. Sensor 2550 may be an antenna (for example, an electromagnetic or radio antenna). In some embodiments sensor 2550 is located in part of a heater in wellbore 452A.
[0538] The signal provided by source 2554 may be sensed by sensor 2550. The sensed signal may be used to assess.a position of wellbore 452B relative to wellbore 452A.
In certain embodiments, the signal is continuously sensed using sensor 2550. The continuously sensed signal may be used to continuously and/or automatically adjust the drilling of wellbore 452B.
The continuous sensing of the electromagnetic signal may be dual direction -creating a data link between transceivers. The antenna / sensor 2550 may be directly connected to a surface interface allowing for a data link between surface and subsurface to be established.
105391 In some embodiments, source 2554 and/or sensor 2550 are sources and sensors used in a walkover radio locater system. Walkover radio locater systems are, for example, used in telecommunications to locate underground lines. In some embodiments, the walkover radio located system components may be modified to be located in wellbore 452A and wellbore 452B
so that the relative positions of the wellbores are assessable using the walkover radio located system components.
[0540] In certain embodiments, multiple sources and multiple sensors may be used to assess and adjust the drilling of one or more wellbores. FIG. 15 depicts an embodiment for assessing a position of a plurality of first wellbores relative to a plurality of second wellbores using radio ranging signals. Sources 2554 may be located in a plurality of wellbores 452A.
Sensors 2550 may be located in one or more wellbores 452B. In some embodiments, sources 2554 are located in wellbores 452B and sensors 2550 are located in wellbores 452A.
[0541] In one embodiment, wellbores 452A are drilled substantially vertically in the formation and wellbores 452B are drilled substantially horizontally in the formation.
Thus, wellbores 452B are substantially perpendicular relative to wellbores 452A. Sensors 2550 in wellbores 452B may detect signals from one or more of sources 2554. Detecting signals from more than one source may allow for more accurate measurement of the relative positions of the wellbores in the formation. In some embodiments, electromagnetic attenuation and phase shift detected from multiple sources is used to define the position of a sensor (and the wellbore). The paths of the electromagnetic radio waves may be predicted to allow detection and use of the electromagnetic attenuation and the phase shift to define the sensor position.

[0542] FIGS. 16 and 17 depict an embodiment for assessing a position of a first wellbore relative to a second wellbore using a heater assembly as a current conductor.
In some embodiments, a heater may be used as a long conductor for a reference current (pulsed DC or AC) to be injected for assessing a position of a first wellbore relative to a second wellbore. If a current is injected onto an insulated internal heater element, the current may pass to the end of heater element 716 where it makes contact with heater casing 2562. This is the same current path when the heater is in heating mode. Once the current passes across to bottom hole assembly 2018B, one may assume at least some of the current is absorbed by the earth on the current's return trip back to the surface, resulting in a net current (difference in Amps in (A;) versus Amps out (Ao)).
[0543] Resulting electromagnetic field 2564 is measured by sensor 2550 (for example, a transceiving antenna) in bottom hole assembly 2018A of first wellbore 452A
being drilled in proximity to the location of heater 716. A predetermined "known" net current in the formation may be relied upon to provide a reference magnetic field.
105441 The injection of the reference current may be rapidly pulsed and synchronized with the receiving antenna and/or sensor data. Access to a high data rate signal from the magnetometers can be used to filter the effects of sensor movement during drilling. The measurement of the reference magnetic field may provide a distance and direction to the heater.
Averaging many of these results will provide the position of the actively drilled hole. The known position of the heater and known depth of the active sensors may be used to assess position coordinates of easting, northing, and elevation.
[0545] The quality of data generated with such a method may depend on the accuracy of the net current prediction along the length of the heater. Using formation resistivity data, a model may be used to predict the losses to earth along the bottom hole assembly. The bottom hole assembly may be in direct contact with the formation and borehole fluids.
[0546] The current may be measured on both the element and the bottom hole assembly at the surface. The difference in values is the overall current loss to the formation. It is anticipated that the net field strength will vary along the length of the heater. The field is expected to be greater at the surface when the positive voltage applies to the bottom hole assembly.
[0547] If there are minimal losses to earth in the formation, the net field may not be strong enough to provide a useful detection range. In some embodiments, a net current in the range of about 2A to about 50A, about 5A to about 40A, or about l0A to about 30A, may be employed.
[0548] In some embodiments, two heaters are used as a long conductor for a reference current (pulsed DC or AC) to be injected for assessing a position of a first wellbore relative to a second wellbore. Utilizing two separate heater elements may result in relatively better control of return current path and therefore better control of reference current strength.
[0549] A two heater method may not rely on the accuracy of a "model of current loss to formation", as current is contained in the heater element along the full length of the heaters.
Current may be rapidly pulsed and synchronized with the transceiving antenna and/or sensor data to resolve distance and direction to the heater. FIGS. 18 and 19 depict an embodiment for assessing a position of first wellbore 452A relative to second wellbore 452B
using two heater assemblies 716A and 716B as current conductors. Resulting electromagnetic field 2564 is measured by sensor 2550 (for example, a transceiving antenna) in bottom hole assembly 2018A
of first wellbore 452A being drilled in proximity to the location of heaters 716A and 716A in second wellbore 452B.

105501 In some embodiments, parallel well tracking may be used for assessing a position of a first wellbore relative to a second wellbore. Parallel well tracking may utilize magnets of a known strength and a known length positioned in the pre-drilled second wellbore. Magnetic sensors positioned in the active first wellbore may be used to measure the field from the magnets in the second wellbore. Measuring the generated magnetic field in the second wellbore with sensors in the first wellbore may assess distance and direction of the active first wellbore. In some embodiments, magnets positioned in the second wellbore may be carefully positioned and multiple static measurements taken to resolve any general "background"
magnetic field.
Background magnetic fields may be resolved through use of a null function before positioning the magnets in the second wellbore, calculating background components from known sensor attitudes, and/or a gradiometer setup.
[0551] In some embodiments, reference magnets may be positioned in the drilling bottom hole assembly of the first wellbore. Sensors may be positioned in the passive second wellbore. The prepositioned sensors may be nulled prior to the arrival of the magnets in the detectable range in order to eliminate Earth's background field. This may significantly reduce the time required to assess the position and direction of the first wellbore during drilling as the bottom hole assembly may continue drilling with no stoppages. The commercial availability of low cost sensors such as a terrella (utilizing magnetoresistives rather than fluxgates) may be incorporated into the wall of a deployment coil at useful separations.
[0552] In some embodiments, multiple types of sources may be used in combination with two or more sensors to assess and adjust the drilling of one or more wellbores. A
method of assessing a position of a first wellbore relative to a second wellbore may include a combination of angle sensors, telemetry, and/or ranging systems. Such a method may be referred to as umbilical position control.
[0553] Angle sensors may assess an attitude (azimuth, inclination, and roll) of a bottom hole assembly. Assessing the attitude of a bottom hole assembly may include measuring, for example, azimuth, inclination, and/or roll. Telemetry may transmit data (for example, measurements) between the surface and, for example, sensors positioned in a wellbore. Ranging may assess the position of a bottom hole assembly in a first wellbore relative to a second wellbore. The second wellbore, in some embodiments, may include an existing, previously drilled wellbore.
105541 FIG. 20 depicts a first embodiment of the umbilical positioning control system employing a wireless linking system. Second transceiver 2556B may be deployed from the surface down second wellbore 452B, which effectively functions as a telemetry system for first wellbore 452A. A transceiver may communicate with the surface via a wire or fiber optics (for example, wire 2558) coupled to the transceiver.
[0555] In the first wellbore , sensors 2550A may be coupled to first transceiving antenna 2556A.
First transceiving antenna 2556A may communicate with second transceiving antenna 2556B in second wellbore 452B. The first transceiving antenna may be positioned on bottom hole assembly 2018. Sensors coupled to the first transceiving antenna may include, for example, magnetometers and/or accelerometers. In certain embodiments, sensors coupled to the first transceiving antenna may include dual magnetometers/accelerometer sets.
[0556] To accomplish data transfer 2560, first transceiving antenna 2556A
transmits ("short hops") measured data through the ground to second transceiving antenna 2556B
located in the second wellbore. The data may then be transmitted to the surface via embedded wires 2558 in the deployment tubular.
[0557] Two redundant ranging systems may be utilized for umbilical control systems. A first ranging system may include a version of a plasma wave tracker (PWT). FIG. 21 depicts an embodiment of umbilical positioning control system employing a magnetic gradiometer system.
A PWT may include a pair of sensors 2550B (for example, magnetometer/accelerometer sets) embedded in the wall of second wellbore 452B deployment coil (the umbilical).
These sensors act as a magnetic gradiometer to detect the magnetic field from reference magnet 2546 installed in bottom hole assembly 2018 of first wellbore 452A. In a horizontal section of the second wellbore, a relative position of the umbilical to the first wellbore reference magnet(s) may be determined by the gradient.

[0558] FIGS. 22 and 23 depict an embodiment of umbilical positioning control system employing a combination of systems being used in a first stage of deployment and a second stage of deployment, respectively. A third set of sensors 2550C (for example, magnetometers) may be located on the leading end of wire 2558. The role of sensors 2550C may include mapping the Earth's magnetic field ahead of the arrival of the gradient sensors and to confirm the angle of the deployment tubular matches that of the originally defined hole geometry. Since the attitude of the magnetic field sensors are known based on the original survey of the hole and the checks of sensor package, the values for the Earth's field can be calculated based on current sensor package orientation (inclinometers measure the roll and inclination and the model defines azimuth, Mag total, and Mag dip). Using this method, an estimation of the field vector due to the reference magnet can be calculated allowing distance and direction to be resolved.
[0559] A second ranging system may be based on using the signal strength and phase of the "through the earth" wireless link (for example, radio) established between the first transceiving antenna in the first wellbore and the second transceiving antenna in the second wellbore. Given the close spacing of holes, the variability in electrical properties of the formation and, thus, attenuation rates for the electromagnetic signal are expected to be predictable. Predictable attenuation rates for the electromagnetic signal allow the signal strength to be used as a measure of separation between the first and second transceiver pairs. The vector direction of the magnetic field induced by the electromagnetic transmissions from the first wellbore may provide the direction.
105601 With a known resistivity of the formation and operating frequency, the distance between the source and point of measurement may be calculated. FIG. 24 depicts two examples of the relationship between power received and distance based upon two different formations with different resistivities 2566 and 2568. If 10 W is transmitted at a 12 Hz frequency in a 20 ohm-m formation 2566, the power received amounts to approximately 9.10 W at 30 m distance. The resistivity was chosen at random and may vary depending on where you are in the ground. If a higher resistivity was chosen at the given frequency, such as 100 ohm-m 2568, a lower attenuation is observed, and a low characterization occurs whereupon it receives 9.58 W at 30 m distance. Thus, high resistivity, although transmitting power desirably, shows a negative affect in electromagnetic ranging possibilities. Since the main influence in attenuation is the distance itself, calculations may be made solving for the distance between a source and a point of measurement.
[0561] Another factor which affects attenuation is the frequency the electromagnetic source operates on. Typically, the higher the frequency, the higher the attenuation and vice versa. A

strategy for choosing between various frequencies may depend on the formation chosen. For example, while the attenuation at a resistivity of 100 ohm-m may be good for data communications, it may not be sufficient for distance calculations. Thus, a higher frequency may be chosen to'increase attenuation. Alternatively, a lower frequency may be chosen for the opposite purpose.
[0562] Wireless data communications in ground may allow an opportunity for electromagnetic ranging and the variable frequency it operates on must be observed to balance out benefits for both functionalities. Benefits of wireless data communication may include, but not be limited to: 1) automatic depth sync through the use of ranging and telemetry; 2) fast communications with dedicated hardwired (for example, optic fiber) coil for a transceiving antenna running in, for example, the second wellbore; 3) functioning as an alternative method for fast communication when hardwire in, for example, the first wellbore is not available; 4) functioning in under balanced and over balanced drilling; 5) providing a similar method for transmitting control commands to a bottom hole assembly; 6) sensors are reusable reducing costs and waste;
7) decreasing noise measurement functions split between the first wellbore and the second wellbore; and/or 8) multiple position measurement techniques simultaneously supported may provide real time best estimate of position and attitude.
[0563] In some embodiments, it may be advisable to employ sensors able to compensate for magnetic fields produced internally by carbon steel casing built in the vertical section of a reference hole (for example, high range magnetometers). In some embodiments, modification may be made to account for problems with wireless antenna communications between wellbores penetrating through wellbore casings.
[0564] Pieces of formation or rock may protrude or fall into the wellbore due to various failures including rock breakage or plastic deformation during and/or after wellbore formation.
Protrusions may interfere with drill string movement and/or the flow of drilling fluids.
Protrusions may prevent running tubulars into the wellbore after the drill string has been removed from the wellbore. Significant amounts of material entering or protruding into the wellbore may cause wellbore integrity failure and/or lead to the drill string becoming stuck in the wellbore. Some causes of wellbore integrity failure may be in situ stresses and high pore pressures. Mud weight may be increased to hold back the formation and inhibit wellbore integrity failure during wellbore formation. When increasing the mud weight is not practical, the wellbore may be reamed.
105651 Reaming the wellbore may be accomplished by moving the drill string up and down one joint while rotating and circulating. Picking the drill string up can be difficult because of material protruding into the borehole above the bit or BHA (bottom hole assembly). Picking up the drill string may be facilitated by placing upward facing cutting structures on the drill bit.
Without upward facing cutting structures on the drill bit, the rock protruding into the borehole above the drill bit must be broken by grinding or crushing rather than by cutting. Grinding or crushing may induce additional wellbore failure.
[0566] Moving the drill string up and down may induce surging or pressure pulses that contribute to wellbore failure. Pressure surging or fluctuations may be aggravated or made worse by blockage of normal drilling fluid flow by protrusions into the wellbore. Thus, attempts to clear the borehole of debris may cause even more debris to enter the wellbore.
[0567] When the wellbore fails further up the drill string than one joint from the drill bit, the drill string must be raised more than one joint. Lifting more than one joint in length may require that joints be removed from the drill string during lifting and placed back on the drill string when lowered. Removing and adding joints requires additional time and labor, and increases the risk of surging as circulation is stopped and started for each joint connection.
[0568] In some embodiments, cutting structures may be positioned at various points along the drill string. Cutting structures may be positioned on the drill string at selected locations, for example, where the diameter of the drill string or BHA changes. FIG. 25A and FIG. 25B depict cutting structures 2020 located at or near diameter changes in drill string 2016 near to drill bit 2022 and/or BHA 2018. As depicted in FIG. 25C, cutting structures 2020 may be positioned at selected locations along the length of BHA 2018 and/or drill string 2016 that has a substantially uniform diameter. Cuttings formed by the cutting structures 2020 may be removed from the wellbore by the normal circulation used during the formation of the wellbore.
[0569] FIG. 26 depicts an embodiment of drill bit 2022 including cutting structures 2020. Drill bit 2022 includes downward facing cutting structures 2020b for forming the wellbore. Cutting structures 2020a are upwardly facing cutting structures for reaming out the wellbore to remove protrusions from the wellbore.
[0570] In some embodiments, some cutting structures may be upwardly facing, some cutting structures may be downwardly facing, and/or some cutting structures may be oriented substantially perpendicular to the drill string. FIG. 27 depicts an embodiment of a portion of drilling string 2016 including upward facing cutting structures 2020a, downward facing cutting structures 2020b, and cutting structures 2020c that are substantially perpendicular to the drill string. Cutting structures 2020a may remove protrusions extending into wellbore 452 that would inhibit upward movement of drill string 2016. Cutting structures 2020a may facilitate reaming of wellbore 452 and/or removal of drill string 2016 from the wellbore for drill bit change, BHA maintenance and/or when total depth has been reached. Cutting structures 2020b may remove protrusions extending into wellbore 452 that would inhibit downward movement of drill string 2016. Cutting structures 2020c may ensure that enlarged diameter portions of drill string 2016 do not become stuck in wellbore 452.
[0571] Positioning downward facing cutting structures 2020b at various locations along a length of the drill string may allow for reaming of the wellbore while the drill bit forms additional borehole at the bottom of the wellbore. The ability to ream while drilling may avoid pressure surges in the wellbore caused by the lifting the drill string. Reaming while drilling allows the wellbore to be reamed without interrupting normal drilling operation. Reaming while drilling allows the wellbore to be formed in less time because a separate reaming operation is avoided.
Upward facing cutting structures 2020a allow for easy removal of the drill string from the wellbore.
105721 In some embodiments, the drill string includes a plurality of cutting structures positioned along the length of the drill string, but not necessarily along the entire length of the drill string.
The cutting structures may be positioned at regular or irregular intervals along the length of the drill string. Positioning cutting structures along the length of the drill string allows the entire wellbore to be reamed without the need to remove the entire drill string from the wellbore.
[0573] Cutting structures may be coupled or attached to the drill string using techniques known in the are (for example, by welding). In some embodiments, cutting structures are formed as part of a hinged ring or multi-piece ring that may be bolted, welded, or otherwise attached to the drill string. In some embodiments, the distance that the cutting structures extend beyond the drill string may be adjustable. For example, the cutting element of the cutting structure may include threading and a locking ring that allows for positioning and setting of the cutting element.
105741 In some wellbores, a wash over or over-coring operation may be needed to free or recover an object in the wellbore that is stuck in the wellbore due to caving, closing, or squeezing of the formation around the object. The object may be a canister, tool, drill string, or other item. A wash-over pipe with downward facing cutting structures at the bottom of the pipe may be used. The wash over pipe may also include upward facing cutting structures and downward facing cutting structures at locations near the end of the wash-over pipe. The additional upward facing cutting structures and downward facing cutting structures may facilitate freeing and/or recovery of the object stuck in the wellbore. The formation holding the object may be cut away rather than broken by relying on hydraulics and force to break the portion of the formation holding the stuck object.

[0575] A problem in some formations is that the formed borehole begins to close soon after the drill string is removed from the borehole. Boreholes which close up soon after being formed make it difficult to insert objects such as tubulars, canisters, tools, or other equipment into the wellbore. In some embodiments, reaming while drilling applied to the core drill string allows for emplacement of the objects in the center of the core drill pipe. The core drill pipe includes one or more upward facing cutting structures in addition to cutting structures located at the end of the core drill pipe. The core drill pipe may be used to form the wellbore for the object to be inserted in the formation. The object may be positioned in the core of the core drill pipe. Then, the core drill pipe may be removed from the formation. Any parts of the formation that may inhibit removal of the core drill pipe are cut by the upward facing cutting structures as the core drill pipe is removed from the formation.
105761 Replacement canisters may be positioned in the formation using over core drill pipe.
First, the existing canister to be replaced is over cored. The existing canister is then pulled from within the core drill pipe without removing the core drill pipe from the borehole. The replacement canister is then run inside of the core drill pipe. Then, the core drill pipe is removed from the borehole. Upward facing cutting structures positioned along the length of the core drill pipe cut portions of the formation that may inhibit removal of the core drill pipe.
[0577] FIG. 28 depicts a schematic drawing of a drilling system. Pilot bit 432 may form an opening in the formation. Pilot bit 432 may be followed by final diameter bit 434. In some embodiments, pilot bit 432 may be about 2.5 cm in diameter. Pilot bit 432 may be one or more meters below final diameter bit 434. Pilot bit 432 may rotate in a first direction and final diameter bit 434 may rotate in the opposite direction. Counter-rotating bits may allow for the formation of the wellbore along a desired path. Standard mud may be used in both pilot bit 432 and final diameter bit 434. In some embodiments, air or mist may be used as the drilling fluid in one or both bits.
[0578] During some in situ heat treatment processes, wellbores may need to be formed in heated formations. Wellbores drilled into hot formation may be additional or replacement heater wells, additional or replacement production wells and/or monitor wells. Cooling while drilling may enhance wellbore stability, safety, and longevity of drilling tools. When the drilling fluid is liquid, significant wellbore cooling can occur due to the circulation of the drilling fluid.
[0579] In some in situ heat treatment processes, a barrier formed around all or a portion of the in situ heat treatment process is formed by freeze wells that form a low temperature zone around the freeze wells. A portion of the cooling capacity of the freeze well equipment may be utilized to cool the equipment needed to drill into the hot formation. Drilling bits may be advanced slowly in hot sections to ensure that the formed wellbore cools sufficiently to preclude drilling problems.
105801 When using conventional circulation, drilling fluid flows down the inside of the drillpipe and back up the outside of the drillpipe. Other circulation systems, such as reverse circulation, may also be used. In some embodiments, the drill pipe may be positioned in a pipe-in-pipe configuration.

[0581] Drillpipe used to form the wellbore may function as a counter-flow heat exchanger. The deeper the well, the more the drilling fluid heats up on the way down to the drill bit as the drillpipe passes through heated portions of the fonnation. Thus the counter-flow heat exchanger effect reduces downhole cooling. When normal circulation does not deliver low enough temperature drilling fluid to the drill bit to provide adequate cooling, two options have been employed to enhance cooling. Mud coolers on the surface can be used to reduce the inlet temperature of the drilling fluid being pumped downhole. If cooling is still inadequate, insulated drillpipe can be used to reduce the counter-flow heat exchanger effect.
[0582] FIG. 29 depicts a schematic drawing of a system for drilling into a hot formation. Cold mud is introduced to drilling bit 434 through conduit 436. As the drill bit penetrates into the formation, the mud cools the drill bit and the surrounding formation. In an embodiment, a pilot hole is formed first and the wellbore is finished with a larger drill bit later. In an embodiment, the finished wellbore is formed without a pilot hole being formed. Well advancement is very slow to ensure sufficient cooling.
[0583] In some embodiments, all or a portion of conduit 436 may be insulated to reduce heat transfer to the cooled mud as the mud passes into the formation. Insulating all or a portion of conduit 436 may allow colder mud to be provided to the drill bit than if the conduit is not insulated. Conduit 436 may be insulated for greater than 1/4 of the length of the conduit, for greater than 1/2 the length of the conduit, for greater than'/4 the length of the conduit, or for substantially all of the length of the conduit.
[0584] FIG. 30 depicts a schematic drawing of a system for drilling into a hot formation. Mud is introduced through conduit 436. Closed loop system 438 is used to circulate cooling fluid within conduit 436. Closed loop system 438 may include a pump, a heat exchanger system, inlet leg 2378, and exit leg 2380. The pump may be used to draw cooling fluid through exit leg 2380 to the heat exchanger system. The pump and the heat exchanger system may be located at the surface. The heat exchanger system may be used to remove heat from cooling fluid returning through exit leg 2380. Cooling fluid may exit the heat exchanger system into inlet leg 2378.
Cooling fluid may flow down inlet leg 2378 in conduit 436 to a region near drill bit 434. The cooling fluid flows out of conduit 436 through exit leg 2380. The cooling fluid cools the drilling mud and the formation as drilling bit 434 slowly penetrates into the formation. The cooled drilling mud may also cool the bottom hole assembly.
[0585] All or a portion of inlet leg 2378 may be insulated to inhibit heat transfer to the cooling fluid entering closed loop system 438 from cooling fluid leaving the closing loop system through exit leg 2380 and/or with the drilling mud. Insulating all or a portion of inlet leg 2378 may also maintain the cooling fluid at a low temperature so that the cooling fluid is able to absorb heat from the drilling mud in a region near drill bit 434 so that the drilling mud is able to 'cool the drill bit and/or the formation. In some embodiments, all or a portion of inlet leg 2378 is made of a material with low thermal conductivity to limit heat transfer to the cooling fluid in the inlet leg. For example, all or a portion of inlet leg 2378 may be made of a polyethylene pipe.
[0586] In some embodiments, inlet leg 2378 and the exit leg 2380 for the cooling fluid are arranged in a conduit-in-conduit configuration. In one embodiment, cooling fluid flows down the inner conduit (the inlet leg) and returns through the space between the inner conduit and the outer conduit (the exit leg). The inner conduit may be insulated or made of a material with low thermal conductivity to inhibit or reduce heat transfer between the cooling fluid going down the inner conduit and the cooling fluid returning through the space between the inner conduit and the outer conduit. In some embodiments, the inner conduit may be made of a polymer, such as high density polyethylene.
[0587] FIG. 31 depicts a schematic drawing of a system for drilling into a hot formation.
Drilling mud is introduced through conduit 436. Pilot bit 432 is followed by final diameter drill bit 434. Closed loop system 438 is used to circulate cooling fluid. Closed loop system may be the same type of system as described with reference to FIG. 30, with the addition of inlet leg 2378' and exit leg 2380' that supply and remove cooling fluid that cools the drilling mud supplied to pilot bit 432. The cooling fluid cools the drilling mud supplied to the drill bits 432, 434. The cooled drilling mud cools drill bits 432, 434 and/or the formation near the drill bits.
[0588] For various reasons including lost circulation, wells are frequently drilled with gas (for, example air, nitrogen, carbon dioxide, methane, ethane, and other light hydrocarbon gases) as the drilling fluid primarily to maintain a low equivalent circulating density (low downhole pressure gradient). Gas has low potential for cooling the wellbore because mass flow rates of gas drilling are much lower than when liquid drilling fluid is used. Also, gas has a low heat capacity compared to liquid. As a result of heat flow from the outside to the inside of the drillpipe, the gas arrives at the drill bit at close to formation temperature.
Controlling the inlet temperature of the gas (analogous to using mud coolers when drilling with liquid) or using insulated drillpipe only marginally reduces the counter-flow heat exchanger effect when gas drilling. Some gases are more effective than others at transferring heat, but the use of gasses with better transfer properties does not significantly improve wellbore cooling while gas drilling.
[0589] Gas drilling may deliver the drilling fluid to the drill bit at close to the formation temperature. The gas may have little capacity to absorb heat. A defining feature of gas drilling is the low density column in the annulus. Immaterial to the benefits of gas drilling is the phase of the drilling fluid flowing down the inside of the drilling pipe. Thus, the benefits of gas drilling can be accomplished if the drilling fluid is liquid while flowing down the drillpipe and gas while flowing back up the annulus. The heat of vaporization is used to cool the drill bit and the formation rather than the sensible heat of the drilling fluid.
[0590] An advantage of this approach is that even though the liquid arrives at the bit at close to formation temperature, it can absorb heat by vaporizing. In fact, the heat of vaporization is typically larger than the heat that can be absorbed by a temperature rise. As a comparison, consider drilling a 7-7/8" wellbore with 3-'/z'.' drillpipe circulating low density mud at about 203 gpm and with about a 100 ft/min typical annular velocity. Drilling through a 450 F zone at 1000 feet will result in a mud exit temperature about 8 F hotter than the inlet temperature. This results in the removal of about 14,000 Btu/min. The removal of this much heat lowers the bit temperature from about 450 F to about 285 F. If liquid water is injected down the drillpipe and allowed to boil at the bit and steam is produced up the annulus, the mass flow required to remove '/z" cuttings is about 34 lbm/min assuming the back pressure is about 100 psia. At 34 Ibm/min the heat removed from the wellbore would be about 34 Ibm/min x (1187 -180) Btu/Ibm or about 34,000 Btu/min. This heat removal amount is about 2.4 times the liquid cooling case.
Thus, at reasonable annular steam flow rates, a significant amount of heat can be removed by vaporization.
[0591] The high velocities required for gas drilling are achieved by the expansion that occurs during vaporization rather than by employing compressors on the surface.
Eliminating the need for compressors may simplify the drilling process, eliminate the cost of the compressor, and eliminate a source of heat applied to the drilling fluid on the way to the drill bit.
[0592] Critical to the process of delivering liquid to the drill bit is preventing boiling within the drillpipe. If the drilling fluid flowing downwards boils before reaching the drill bit, the heat of vaporization is used to extract heat from the drilling fluid flowing up the annulus. The heat transferred from the annulus (outside the drillpipe) to inside the drillpipe boiling the fluid is heat that is not rejected from the well when drilling fluid reaches the surface.
Boiling that occurs inside of the drillpipe before the drilling fluid reaches the bottom of the hole is not beneficial to drill bit and/or wellbore cooling.

[0593] If the pressure in the drillpipe is maintained above the boiling pressure for a given temperature by use of a back pressure device, then the transfer of heat from outside the drillpipe to inside can be minimized or essentially eliminated. The liquid supplied to the drill bit may be vaporized. Vaporization may result in the drilling fluid adsorbing the heat of vaporization from the drill bit and formation. For example, if the back pressure device is set to allow flow only when the back pressure is above 250 psi, the fluid within the drillpipe will not boil unless the temperature is above 400 F. If the temperature of the formation is above this (for example, 500 F) steps may be taken to inhibit boiling of the fluid on the way down to the drill bit. In an embodiment; the back pressure device is set to maintain a back pressure that inhibits boiling of the drilling fluid at the temperature of the formation (for example, 580 psi to inhibit boiling up to a temperature of 500 F). In another embodiment, the drilling pipe is insulated and/or the drilling fluid is cooled so that the back pressure device is able to maintain the drilling fluid that reaches the drill bit as a liquid.
[0594] Two back pressure devices that may be used to maintain elevated pressure within the drilipipe are a choke and a pressure activated valve. Other types of back pressure devices may also be used. Chokes have a restriction in flow area that creates back pressure by resisting flow.
Resisting the flow results in increased upstream pressure to force the fluid through the restriction. Pressure activated valves do not open until a minimum upstream pressure is obtained. The pressure difference across a pressure activated valves may determine if the pressure activated valve is open to allow flow or closed.
[0595] In some embodiments, both a choke and pressure activated valve may be used. A choke can be the bit nozzles allowing the liquid to be jetted toward the drill bit and the bottom of the hole. The bit nozzles may enhance drill bit cleaning and help prevent fouling of the drill bit and pressure activated valve. Fouling may occur if boiling in the drill bit or pressure activated valve caused solids to precipitate. The pressure activated valve may prevent premature boiling at low flow rates below flow rates at which the chokes are effective.
[0596] Additives may be added to the drilling fluid. The additives may modify the properties of the fluids in the liquid phase and/or the gas phase. Additives may include, but are not limited to surfactants to foam the fluid, additives to chemically alter the interaction of the fluid with the formations (for example, to stabilize the formation), additives to control corrosion, and additives for other benefits.

[0597] In some embodiments, a non-condensable gas may be added to the drilling fluid pumped down the drillpipe. The non-condensable gas may be, but is not limited to nitrogen, carbon dioxide, air, and mixtures thereof. Adding the non-condensable gas results in pumping a two phase mixture down the drillpipe. One reason for adding the non-condensable gas is to enhance the flow of the fluid out of the formation. The presence of the non-condensable gas may inhibit condensation of the vaporized drilling fluid and help to carry cuttings out of the formation. In some embodiments, one or more heaters may be present at one or more locations in the wellbore to provide heat that inhibits condensation and reflux of drilling fluid leaving the formation.
[0598] Managed pressure drilling and/or managed volumetric drilling may be used during formation of wellbores. The back pressure on the wellbore may be held to a prescribed value to control the down hole pressure. Similarly, the volume of fluid entering and exiting the well may be balanced so that there is no net influx or but-flux of drilling fluid into the formation.
[0599] In some embodiments, one piece of equipment may be used to drill multiple wellbores in a single day. The wellbores may be formed at penetration rates that are many times faster than the penetration rates using conventional drilling with drilling bits. The high penetration rate allows separate equipment to accomplish drilling and casing operations in a more efficient manner than using a one-trip approach. The high penetration rate requires accurate, real time directional drilling in three dimensions.
106001 In some embodiments, high penetration rates may be attained using composite coiled tubing in combination with particle jet drilling. Particle jet drilling forms an opening in a formation by impacting the formation with high pressure fluid containing particles to remove material from the formation. The particles may function as abrasives. In addition to composite coiled tubing and particle jet drilling, a downhole electric orienter, bubble entrained mud, downhole inertial navigation, and a computer control system may be needed.
Other types of drilling fluid and drilling fluid systems may be used instead of using bubble entrained mud.
Such drilling fluid systems may include, but are not limited to, straight liquid circulation systems, multiphase circulation systems using liquid and gas, and/or foam circulation systems.
[0601] Composite coiled tubing has a fatigue life that is significantly greater than the fatigue life of coiled steel tubing. Composite coiled tubing is available from Airborne Composites BV (The Hague, The Netherlands). Composite coiled tubing can be used to form many boreholes in a formation. The composite coiled tubing may include integral power lines for providing electricity to downhole tools. The composite coiled tubing may include integral data lines for providing real time information regarding downhole conditions to the computer control system and for sending real time control information from the computer control system to the downhole equipment.

[0602] The coiled tubing may include an abrasion resistant outer sheath. The outer sheath may inhibit damage to the coiled tubing due to sliding experienced by the coiled tubing during deployment and retrieval. In some embodiments, the coiled tubing may be rotated during use in lieu of or in addition to having an abrasion resistant outer sheath to minimize uneven wear of the composite coiled tubing.
[0603] Particle jet drilling may advantageously allow for stepped changes in the drilling rate.
Drill bits are no longer needed and downhole motors are eliminated. Particle jet drilling may decouple cutting formation to form the borehole from the bottom hole assembly.
Decoupling cutting formation to form the borehole from the bottom hole assembly reduces the impact that variable formation properties (for example, formation dip, vugs, fractures and transition zones) have on wellbore trajectory. By decoupling cutting formation to form the borehole from the bottom hole assembly, directional drilling may be reduced to orienting one or more particle jet nozzles in appropriate directions. Additionally, particle jet drilling may be used to under ream one or more portions of a wellbore to form a larger diameter opening.
106041 Particles may be introduced into a high pressure injection stream during particle jet drilling. The ability to achieve and circulate high particle laden fluid under high pressure may facilitate the successful use of particle jet drilling. One type of pump that may be used for particle jet drilling is a heavy duty piston membrane pump. Heavy duty piston membrane pumps may be available from ABEL GmbH & Co. KG (Buchen, Germany). Piston membrane pumps have been used for long term, continuous pumping of slurries containing high total solids in the mining and power industries. Piston membrane pumps are similar to triplex pumps used for drilling operations in the oil and gas industry except heavy duty preformed membranes separate the slurry from the hydraulic side of the pump. In this fashion, the solids laden fluid is brought up to pressure in the injection line in one step and circulated downhole without damaging the internal mechanisms of the pump.
[0605] Another type of pump that may be used for particle jet drilling is an annular pressure exchange pump. Annular pressure exchange pumps may be available from Macmahon Mining Services Pty Ltd (Lonsdale, Australia). Annular pressure exchange pumps have been used for long term, continuous pumping of slurries containing high total solids in the mining industry.
Annular pressure exchange pumps use hydraulic oil to compress a hose inside a high-strength pressure chamber in a peristaltic like way to displace the contents of the hose. Annular pressure exchange pumps may obtain continuous flow by having twin chambers. One chamber fills while the other chamber is purged.
[0606] The bottom hole assembly may include a downhole electric orienter. The downhole electric orienter may allow for directional drilling by directing one or more particle jet drilling nozzles in desired directions. The downhole electric orienter may be coupled to a computer control system through one or more integral data lines of the composite coiled tubing. Power for the downhole electric orienter may be supplied through an integral power line of the composite coiled tubing or through a battery system in the bottom hole assembly.
[0607] Bubble entrained mud may be used as the drilling fluid. Bubble entrained mud may allow for particle jet drilling without raising the equivalent circulating density to unacceptable levels. A form of managed pressure drilling may be affected by varying the density of bubble entrainment. In some embodiments, particles in the drilling fluid may be separated from the drilling fluid using magnetic recovery when the particles include iron or alloys that may be influenced by magnetic fields. Bubble entrained mud may be used because using air or other gas as the drilling fluid may result in excessive wear of components from high velocity particles in the return stream. The density of the bubble entrained mud going downhole as a function of real time gains and losses of fluid may be automated using the computer control system.
[0608] In some embodiments, multiphase systems are used. For example, if gas injection rates are low enough that wear rates are acceptable, a gas-liquid circulating system may be used.
Bottom hole circulating pressures may be adjusted by the computer control system. The computer control system may adjust the gas and/or liquid injection rates.
[0609] In some embodiments, pipe-in-pipe drilling is used. Pipe-in-pipe drilling may include circulating fluid through the space between the outer pipe and the inner pipe instead of between the wellbore and the drill string. Pipe-in-pipe drilling may be used if contact of the drilling fluid with one or more fresh water aquifers is not acceptable. Pipe-in-pipe drilling may be used if the density of the drilling fluid cannot be adjusted low enough to effectively reduce potential lost circulation issues.
[0610] Downhole inertial navigation may be part of the bottom hole assembly.
The use of downhole inertial navigation allows for determination of the position (including depth, azimuth and inclination) without magnetic sensors. Magnetic interference from casings and/or emissions from the high density of wells in the formation may interfere with a system that determines the position of the bottom hole assembly based on magnet sensors.
[0611] The computer control system may receive information from the bottom hole assembly.
The computer control system may process the information to determine the position of the bottom hole assembly. The computer control system may control drilling fluid rate, drilling fluid density, drilling fluid pressure, particle density, other variables, and/or the downhole electric orienter to control the rate of penetration and/or the direction of borehole formation.
[0612] In some embodiments, robots are used to perform a task in a wellbore formed or being formed using composite coiled tubing. The task may be, but is not limited to, providing traction to move the coiled tubing, surveying, removing cuttings, logging, and/or freeing pipe. For example, a robot may be used when drilling a horizontal opening if enough weight cannot be applied to bottom hole assembly to advance the coiled tubing and bottom hole assembly in the formed borehole. The robot may be sent down the borehole. The robot may clamp to the composite coiled tubing. Portions of the robot may extend to engage the formation. Traction between the robot and the formation may be used to advance the robot forward so that the composite coiled tubing and the bottom hole assembly advance forward.
106131 The robots may be battery powered. To use the robot, drilling could be stopped, and the robot could be connected to the outside of the composite coiled tubing. The robot would run along the outside of the composite coiled tubing to the bottom of the hole. If needed, the robot could electrically couple to the bottom hole assembly. The robot could couple to a contact plate on the bottom hole assembly. The bottom hole assembly may include a step-down transformer that brings the high voltage, low current electricity supplied to the bottom hole assembly to a lower voltage and higher current (for example, one third the voltage and three times the amperage supplied to the bottom hole assembly). The lower voltage, higher current electricity supplied from the step-down transformer may be used to recharge the batteries of the robot. In some embodiments, the robot may function while coupled to the bottom hole assembly. The batteries may supply sufficient energy for the robot to travel to the drill bit and back to the surface.
[0614] In some embodiments, one or more portions of a wellbore may need to be isolated from other portions of the wellbore to establish zonal isolation. In some embodiments, an expandable may be positioned in the wellbore adjacent to a section of the wellbore that is to be isolated. A
pig or hydraulic pressure may be used to enlarge the expandable to establish zonal isolation.
[0615] In some embodiments, pathways may be formed in the formation after the wellbores are formed. Pathways may be formed adjacent to heater wellbores and/or adjacent to production wellbores. The pathways may promote better fluid flow and/or better heat conduction. In some embodiments, pathways are formed by hydraulically fracturing the formation.
Other fracturing techniques may also be used. In some embodiments, small diameter bores may be formed in the formation. In some embodiments, heating the formation may expand and close or substantially close the fractures or bores formed in the formation. The fractures or holes may extend when the formation is heated. The presence of fractures of holes may increase heat conduction in the formation.
[0616] Some wellbores formed in the formation may be used to facilitate formation of a perimeter barrier around a treatment area. Heat sources in the treatment area may heat hydrocarbons in the formation within the treatment area. The perimeter barrier may be, but is not limited to, a low temperature or frozen barrier formed by freeze wells, dewatering wells, a grout wall formed in the formation, a sulfur cement barrier, a barrier formed by a gel produced in the formation, a barrier formed by precipitation of salts in the formation, a barrier formed by a polymerization reaction in the formation, and/or sheets driven into the formation. Heat sources, production wells, injection wells, dewatering wells, and/or monitoring wells may be installed in the treatment area defined by the barrier prior to, simultaneously with, or after installation of the barrier.
[0617] A low temperature zone around at least a portion of a treatment area may be formed by freeze wells. In an embodiment, refrigerant is circulated through freeze wells to form low temperature zones around each freeze well. The freeze wells are placed in the formation so that the low temperature zones overlap and form a low temperature zone around the treatment area.
The low temperature zone established by freeze wells is maintained below the freezing temperature of aqueous fluid in the formation. Aqueous fluid entering the low temperature zone freezes and forms the frozen barrier. In other embodiments, the freeze barrier is formed by batch operated freeze wells. A cold fluid, such as liquid nitrogen, is introduced into the freeze wells to form low temperature zones around the freeze wells. The fluid is replenished as needed.
[0618] In some embodiments, two or more rows of freeze wells are located about all or a portion of the perimeter of the treatment area to form a thick interconnected low temperature zone.
Thick low temperature zones may be formed adjacent to areas in the formation where there is a high flow rate of aqueous fluid in the formation. The thick barrier may ensure that breakthrough of the frozen barrier established by the freeze wells does not occur.
[0619] In some embodiments, a double barrier system is used to isolate a treatment area. The double barrier system may be formed with a first barrier and a second barrier.
The first barrier may be formed around at least a portion of the treatment area to inhibit fluid from entering or exiting the treatment area. The second barrier may be formed around at least a portion of the first barrier to isolate an inter-barrier zone between the first barrier and the second barrier. The inter-barrier zone may have a thickness from about 1 m to about 300 m. In some embodiments, the thickness of the inter-barrier zone is from about 10 m to about 100 m, or from about 20 m to about 50 m.

[0620] The double barrier system may allow greater project depths than a single barrier system.
Greater depths are possible with the double barrier system because the stepped differential pressures across the first barrier and the second barrier is less than the differential pressure across a single barrier. The smaller differential pressures across the first barrier and the second barrier make a breach of the double barrier system less likely to occur at depth for the double barrier system as compared to the single barrier system.
[0621] The double barrier system reduces the probability that a barrier breach will affect the treatment area or the formation on the outside of the double barrier. That is, the probability that the location and/or time of occurrence of the breach in the first barrier will coincide with the location and/or time of occurrence of the breach in the second barrier is low, especially if the distance between the first barrier and the second barrier is relatively large (for example, greater than about 15 m). Having a double barrier may reduce or eliminate influx of fluid into the treatment area following a breach of the first barrier or the second barrier.
The treatment area may not be affected if the second barrier breaches. If the first barrier breaches, only a portion of the fluid in the inter-barrier zone is able to enter the contained zone. Also, fluid from the contained zone will not pass the second barrier. Recovery from a breach of a barrier of the double barrier system may require less time and fewer resources than recovery from a breach of a single barrier system. For example, reheating a treatment area zone following a breach of a double barrier system may require less energy than reheating a similarly sized treatment area zone following a breach of a single barrier system.
[0622] The first barrier and the second barrier may be the same type of barrier or different types of barriers. In some embodiments, the first barrier and the second barrier are formed by freeze wells. In some embodiments, the first barrier is formed by freeze wells, and the second barrier is a grout wall. The grout wall may be formed of cement, sulfur, sulfur cement, or combinations thereof. In some embodiments, a portion of the first barrier and/or a portion of the second barrier is a natural barrier, such as an impermeable rock formation.
[0623] Vertically positioned freeze wells and/or horizontally positioned freeze wells may be positioned around sides of the treatment area. If the upper layer (the overburden) or the lower layer (the underburden) of the formation is likely to allow fluid flow into the treatment area or out of the treatment area, horizontally positioned freeze wells may be used to form an upper and/or a lower barrier for the treatment area. In some embodiments, an upper barrier and/or a lower barrier may not be necessary if the upper layer and/or the lower layer are at least WO 2008/051495 . PCT/US2007/022376 substantially impermeable. If the upper freeze barrier is formed, portions of heat sources, production wells, injection wells, and/or dewatering wells that pass through the low temperature zone created by the freeze wells forming the upper freeze barrier wells may be insulated and/or heat traced so that the low temperature zone does not adversely affect the functioning of the heat sources, production wells, injection wells and/or dewatering wells passing through the low temperature zone.
106241 Spacing between adjacent freeze wells may be a function of a number of different factors. The factors may include, but are not limited to, physical properties of formation material, type of refrigeration system, coldness and thermal properties of the refrigerant, flow rate of material into or out of the treatment area, time for forming the low temperature zone, and economic considerations. Consolidated or partially consolidated formation material may allow for a large separation distance between freeze wells. A separation distance between freeze wells in consolidated or partially consolidated formation material may be from about 3 m to about 20 m, about 4 m to about 15 m, or about 5 m to about 10 m. In an embodiment, the spacing between adjacent freeze wells is about 5 m. Spacing between freeze wells in unconsolidated or substantially unconsolidated formation material, such as in tar sand, may need to be smaller than spacing in consolidated formation material. A separation distance between freeze wells in unconsolidated material may be from about I m to about 5 m.
106251 Freeze wells may be placed in the formation so that there is minimal deviation in orientation of one freeze well relative to an adjacent freeze well. Excessive deviation may create a large separation distance between adjacent freeze wells that may not permit formation of an interconnected low temperature zone between the adjacent freeze wells. Factors that influence the manner in which freeze wells are inserted into the ground include, but are not limited to, freeze well insertion time, depth that the freeze wells are to be inserted, formation properties, desired well orientation, and economics.
[0626] Relatively low depth wellbores for freeze wells may be impacted and/or vibrationally inserted into some formations. Wellbores for freeze wells may be impacted and/or vibrationally inserted into formations to depths from about I m to about 100 m without excessive deviation in orientation of freeze wells relative to adjacent freeze wells in some types of formations.
[0627] Wellbores for freeze wells placed deep in the formation, or wellbores for freeze wells placed in formations with layers that are difficult to impact or vibrate a well through, may be placed in the formation by directional drilling and/or geosteering. Acoustic signals, electrical signals, magnetic signals, and/or other signals produced in a first wellbore may be used to guide directionally drilling of adjacent wellbores so that desired spacing between adjacent wells is maintained. Tight control of the spacing between wellbores for freeze wells is an important factor in minimizing the time for completion of barrier formation.
106281 In some embodiments, one or more portions of freeze wells may be angled in the formation. The freeze wells may be angled in the formation adjacent to aquifers. In some embodiments, the angled portions are angled outwards from the treatment area.
In some embodiments, the angled portions may be angled inwards towards the treatment area. The angled portions of the freeze wells allow extra length of freeze well to be positioned in the aquifer zones. Also, the angled portions of the freeze wells may reduce the shear load applied to the frozen barrier by water flowing in the aquifer.
106291 After formation of the wellbore for the freeze well, the wellbore may be backflushed with water adjacent to the part of the formation that is to be reduced in temperature to form a portion of the freeze barrier. The water may displace drilling fluid remaining in the wellbore.
The water may displace indigenous gas in cavities adjacent to the formation.
In some embodiments, the wellbore is filled with water from a conduit up to the level of the overburden.
In some embodiments, the wellbore is backflushed with water in sections. The wellbore maybe treated in sections having lengths of about 6 m, 10 m, 14 m, 17 m, or greater.
Pressure of the water in the wellbore is maintained below the fracture pressure of the formation. In some embodiments, the water, or a portion of the water is removed from the wellbore, and a freeze well is placed in the formation.
106301 FIG. 32 depicts an embodiment of freeze well 440. Freeze well 440 may include canister 442, inlet conduit 444, spacers 446, and wellcap 448. Spacers 446 may position inlet conduit 444 in canister 442 so that an annular space is fonned between the canister and the conduit.
Spacers 446 may promote turbulent flow of refrigerant in the annular space between inlet conduit 444 and canister 442, but the spacers may also cause a significant fluid pressure drop.
Turbulent fluid flow in the annular space may be promoted by roughening the inner surface of canister 442, by roughening the outer surface of inlet conduit 444, and/or by having a small cross-sectional area annular space that allows for high refrigerant velocity in the annular space.
In some embodiments, spacers are not used. Wellhead 450 may suspend canister 442 in wellbore 452.
[0631] Formation refrigerant may flow through cold side conduit 454 from a refrigeration unit to inlet conduit 444 of freeze well 440. The formation refrigerant may flow through an annular space between inlet conduit 444 and canister 442 to warm side conduit 456.
Heat may transfer from the formation to canister 442 and from the canister to the formation refrigerant in the annular space. Inlet conduit 444 may be insulated to inhibit heat transfer to the formation refrigerant during passage of the formation refrigerant into freeze well 440.
In an embodiment, inlet conduit 444 is a high density polyethylene tube. At cold temperatures, some polymers may exhibit a large amount of thermal contraction. For example, a 260 m initial length of polyethylene conduit subjected to a temperature of about -25 C may contract by 6 m or more.
If a high density polyethylene conduit, or other polymer conduit, is used, the large thermal contraction of the material must be taken into account in determining the final depth of the freeze well. For example, the freeze well may be drilled deeper than needed, and the conduit may be allowed to shrink back during use. In some embodiments, inlet conduit 444 is an insulated metal tube. In some embodiments, the insulation may be a polymer coating, such as, but not limited to, polyvinylchloride, high density polyethylene, and/or polystyrene.
[0632] Freeze well 440 may be introduced into the formation using a coiled tubing rig. In an embodiment, canister 442 and inlet conduit 444 are wound on a single reel. The coiled tubing rig introduces the canister and inlet conduit 444 into the formation. In an embodiment, canister 442 is wound on a first reel and inlet conduit 444 is wound on a second reel.
The coiled tubing rig introduces canister 442 into the formation. Then, the coiled tubing rig is used to introduce inlet conduit 444 into the canister. In other embodiments, freeze well is assembled in sections at the wellbore site and introduced into the formation.
[0633] An insulated section of freeze well 440 may be placed adjacent to overburden 458. An uninsulated section of freeze well 440 may be placed adjacent to layer or layers 460 where a low temperature zone is to be formed. In some embodiments, uninsulated sections of the freeze wells may be positioned adjacent only to aquifers or other permeable portions of the formation that would allow fluid to flow into or out of the treatment area. Portions of the formation where uninsulated sections of the freeze wells are to be placed may be determined using analysis of cores and/or logging techniques.
[0634] FIG. 33 depicts an embodiment of the lower portion of freeze well 440.
Freeze well may include canister 442, and inlet conduit 444. Latch pin 2388 may be welded to canister 442.
Latch pin 2388 may include tapered upper end 2390 and groove 2392. Tapered upper end 2390 may facilitate placement of a latch of inlet conduit 444 on latch pin 2388. A
spring ring of the latch may be positioned in groove 2392 to couple inlet conduit 444 to canister 442.
[0635] Inlet conduit 444 may include plastic portion 2394, transition piece 2396, outer sleeve 2398, and inner sleeve 2400. Plastic portion 2394 may be a plastic conduit that carries refrigerant into freeze well 440. In some embodiments, plastic portion 2394 is high density polyethylene pipe.

[0636] Transition piece 2396 may be a transition between plastic portion 2394 and outer sleeve 2398. A plastic end of transition piece 2396 may be fusion welded to the end of plastic portion 2394. A metal portion of transition piece may be butt welded to outer sleeve 2398. In some embodiments, the metal portion and outer sleeve 2398 are formed of 304 stainless steel. Other material may be used in other embodiments. Transition pieces 2396 may be available from Central Plastics Company (Shawnee, Oklahoma).
[0637] In some embodiments, outer sleeve 2398 may include stop 2402. Stop 2402 may engage a stop of inner sleeve 2400 to limit a bottom position of the outer sleeve relative to the inner sleeve. In some embodiments, outer sleeve 2398 may include opening 2404.
Opening 2404 may align with a corresponding opening in inner sleeve 2400. A shear pin may be positioned in the openings during insertion of inlet conduit 444 in canister 442 to inhibit movement of outer sleeve 2398 relative to inner sleeve 2400. Shear pin is strong enough to support the weight of inner sleeve 2400, but weak enough to shear due to force applied to the shear pin when outer sleeve 2398 moves upwards in the wellbore due to thermal contraction or during installation of the inlet conduit after inlet conduit is coupled to canister 442.
[0638] Inner sleeve 2400 may be positioned in outer sleeve 2398. Inner sleeve has a length sufficient to inhibit separation of the inner sleeve from outer sleeve 2398 when inlet conduit has fully contracted due to exposure of the inlet conduit to low temperature refrigerant. Inner sleeve 2400 may include a plurality of slip rings 2406 held in place by positioners 2408, a plurality of openings 2410, stop 2412, and latch 2414. Slip rings 2406 may position inner sleeve 2400 relative to outer sleeve 2398 and allow the outer sleeve to move relative to the inner sleeve. In some embodiments, slip rings 2406 are TEFLON rings, such as polytetrafluoroethylene rings.
Slip rings 2406 may be made of different material in other embodiments.
Positioners 2408 may be steel rings welded to inner sleeve. Positioners 2408 may be thinner than slip rings 2406.
Positioners 2408 may inhibit movement of slip rings 2406 relative to inner sleeve 2400.
106391 Openings 2410 may be formed in a portion of inner sleeve 2400 near the bottom of the inner sleeve. Openings 2410 may allow refrigerant to pass from inlet conduit 444 to canister 442. A majority of refrigerant flowing through inlet conduit 444 may pass through openings 2410 to canister 442. Some refrigerant flowing through inlet conduit 444 may pass to canister 442 through the space between inner sleeve 2400 and outer sleeve 2398.
[0640] Stop 2412 may be located above openings 2410. Stop 2412 interacts with stop 2402 of outer sleeve 2398 to limit the downward movement of the outer sleeve relative to inner sleeve 2400.

[0641] Latch 2414 may be welded to the bottom of inner sleeve 2400. Latch 2414 may include flared opening 2416 that engages tapered end 2390 of latch pin 2388. Latch 2414 may include spring ring 2418 that snaps into groove of latch pin 2392 to couple inlet conduit 444 to canister 442.
[0642] To install freeze well 440, a wellbore is formed in the formation and canister 442 is placed in the wellbore. The bottom of canister 442 has latch pin 2388.
Transition piece is fusion welded to an end of coiled plastic portion 2394 of inlet conduit 444.
Latch 2414 is placed in canister 442 and inlet conduit is spooled into the canister. Spacers may be coupled to plastic portion 2394 at selected positions. Latch may be lowered until flared opening 2416 engages tapered end 2390 of latch pin 2388 and spring ring 2406 snaps into the groove of the latch pin.
After spring ring 2406 engages latch pin 2388, inlet conduit 444 may be moved upwards to shear the pin joining outer sleeve 2398 to inner sleeve 2400. Inlet conduit 444 may be coupled to the refrigerant supply piping and canister may be coupled to the refrigerant return piping.
[0643] If needed, inlet conduit 444 may be removed from canister 442. Inlet conduit may be pulled upwards to separate outer sleeve 2398 from inner sleeve 2400. Plastic portion 2394, transition piece 2396, and outer sleeve 2398 may be pulled out of canister 442. A removal instrument may belowered into canister 442. The removal instrument may secure to inner sleeve 2400. The removal instrument may be pulled upwards to pull spring ring 2418 of latch 2414 out of groove 2392 of latch pin 2388. The removal tool may be withdrawn out of canister 442 to remove inner sleeve 2400 from the canister.
[0644] Various types of refrigeration systems may be used to form a low temperature zone.
Determination of an appropriate refrigeration system may be based on many factors, including, but not limited to: a type of freeze well; a distance between adjacent freeze wells; a refrigerant; a time frame in which to form a low temperature zone; a depth of the low temperature zone; a temperature differential to which the refrigerant will be subjected; one or more chemical and/or physical properties of the refrigerant; one or more environmental concerns related to potential refrigerant releases, leaks or spills; one or more economic factors; water flow rate in the formation; composition and/or properties of formation water including the salinity of the formation water; and one or more properties of the formation such as thermal conductivity, thermal diffusivity, and heat capacity.
[0645] A circulated fluid refrigeration system may utilize a liquid refrigerant (formation refrigerant) that is circulated through freeze wells. Some of the desired properties for the formation refrigerant are: low working temperature, low viscosity at and near the working temperature, high density, high specific heat capacity, high thermal conductivity, low cost, low corrosiveness, and low toxicity. A low working temperature of the formation refrigerant allows a large low temperature zone to be established around a freeze well. The low working temperature of formation refrigerant should be about -20 C or lower.
Formation refrigerants having low working temperatures of at least -60 C may include aqua ammonia, potassium formate solutions such as Dynalene HC-50 (Dynalene Heat Transfer Fluids (Whitehall, Pennsylvania, U.S.A.)) or FREEZIUM (Kemira Chemicals (Helsinki, Finland));
silicone heat transfer fluids such as Syltherm XLT (Dow Corning Corporation (Midland, Michigan, U.S.A.); hydrocarbon refrigerants such as propylene; and chlorofluorocarbons such as R-22.
Aqua ammonia is a solution of ammonia and water with a weight percent of ammonia between about 20% and about 40%. Aqua ammonia has several properties and characteristics that make use of aqua ammonia as the formation refrigerant desirable. Such properties and characteristics include, but are not limited to, a very low freezing point, a low viscosity, ready availability, and low cost.
[0646] Formation refrigerant that is capable of being chilled below a freezing temperature of aqueous formation fluid may be used to form the low temperature zone around the treatment area. The following equation (the Sanger equation) may be used to model the time ti needed to form a frozen barrier of radius R around a freeze well having a surface temperature of Ts:
z r (EQN. 1 ) 1 1 = R L' I 21n R + cVw 4kfv,.l r Li in which:

Li = L a;
c~ vo 2 In a, RA
a, = R

[0647] In these equations, kJ is the thermal conductivity of the frozen material; cvf and cv are the volumetric heat capacity of the frozen and unfrozen material, respectively; ro is the radius of the freeze well; vs is the temperature difference between the freeze well surface temperature T,s and the freezing point of water To; vo is the temperature difference between the ambient ground temperature Tg and the freezing point of water To; L is the volumetric latent heat of freezing of the formation; R is the radius at the frozen-unfrozen interface; and RA is a radius at which there is no influence from the refrigeration pipe. The Sanger equation may provide a conservative estimate of the time needed to form a frozen barrier of radius R because the equation does not take into consideration superposition of cooling from other freeze wells. The temperature of the formation refrigerant is an adjustable variable that may significantly affect the spacing between freeze wells.

[0648] EQN. 1 implies that a large low temperature zone may be formed by using a refrigerant having an initial temperature that is very low. The use of formation refrigerant having an initial cold temperature of about -30 C or lower is desirable. Formation refrigerants having initial temperatures warmer than about -30 C may also be used, but such formation refrigerants require longer times for the low temperature zones produced by individual freeze wells to connect. In addition, such formation refrigerants may require the use of closer freeze well spacings and/or more freeze wells.
[0649] The physical properties of the material used to construct the freeze wells may be a factor in the determination of the coldest temperature of the formation refrigerant used to form the low temperature zone around the treatment area. Carbon steel may be used as a construction material of freeze wells. ASTM A333 grade 6 steel alloys and ASTM A333 grade 3 steel alloys may be used for low temperature applications. ASTM A333 grade 6 steel alloys typically contain little or no nickel and have a low working temperature limit of about -50 C. ASTM
A333 grade 3 steel alloys typically contain nickel and have a much colder low working temperature limit. The nickel in the ASTM A333 grade 3 alloy adds ductility at cold temperatures, but also significantly raises the cost of the metal. In some embodiments, the coldest temperature of the refrigerant is from about -35 C to about -55 C, from about -38 C to about -47 C, or from about -40 C to about -45 C to allow for the use of ASTM A333 grade 6 steel alloys for construction of canisters for freeze wells. Stainless steels, such as 304 stainless steel, may be used to form freeze wells, but the cost of stainless steel is typically much more than the cost of ASTM A333 grade 6 steel alloy.
106501 In some embodiments, the metal used to form the canisters of the freeze wells may be provided as pipe. In some embodiments, the metal used to form the canisters of the freeze wells may be provided in sheet form. The sheet metal may be longitudinally welded to form pipe and/or coiled tubing. Forming the canisters from sheet metal may improve the economics of the system by allowing for coiled tubing insulation and by reducing the equipment and manpower needed to form and install the canisters using pipe.
[0651] A refrigeration unit may be used to reduce the temperature of formation refrigerant to the low working temperature. In some embodiments, the refrigeration unit may utilize an ammonia vaporization cycle. Refrigeration units are available from Cool Man Inc.
(Milwaukee, Wisconsin, U.S.A.), Gartner Refrigeration & Manufacturing (Minneapolis, Minnesota, U.S.A.), and other suppliers. In some embodiments, a cascading refrigeration system may be utilized with a first stage of ammonia and a second stage of carbon dioxide. The circulating refrigerant through the freeze wells may be 30% by weight ammonia in water (aqua ammonia).
Alternatively, a single stage carbon dioxide refrigeration system may be used.
[0652] In some embodiments, refrigeration systems for forming a low temperature barrier for a treatment area may be installed and activated before freeze wells are formed in the formation.
As the freeze well wellbores are formed, freeze wells may be installed in the wellbores.
Refrigerant may be circulated through the wellbores soon after the freeze well is installed into the wellbore. Limiting the time between wellbore formation and cooling initiation may limit or inhibit cross mixing of formation water between different aquifers.
[0653] Grout, wax, polymer or other material may be used in combination with freeze wells to provide a barrier for the in situ heat treatment process. The material may fill cavities (vugs) in the formation and reduces the permeability of the formation. The material may have higher thermal conductivity than gas and/or formation fluid that fills cavities in the formation. Placing material in the cavities may allow for faster low temperature zone formation.
The material may form a perpetual barrier in the formation that may strengthen the formation.
The use of material to form the barrier in unconsolidated or substantially unconsolidated formation material may allow for larger well spacing than is possible without the use of the material. The combination of the material and the low temperature zone formed by freeze wells may constitute a double barrier for environmental regulation purposes. In some embodiments, the material is introduced into the formation as a liquid, and the liquid sets in the formation to form a solid. The material may be, but is not limited to, fine cement, micro fine cement, sulfur, sulfur cement, viscous thermoplastics, and/or waxes. The material may include surfactants, stabilizers or other chemicals that modify the properties of the material. For example, the presence of surfactant in the material may promote entry of the material into small openings in the formation.
[06541 Material may be introduced into the formation through freeze well wellbores. The material may be allowed to set. The integrity of the wall formed by the material may be checked. The integrity of the material wall may be checked by logging techniques and/or by hydrostatic testing. If the permeability of a section formed by the material is too high, additional material grout may be introduced into the formation through freeze well wellbores. After the permeability of the section is sufficiently reduced, freeze wells may be installed in the freeze well wellbores.
[0655] Material may be injected into the formation at a pressure that is high, but below the fracture pressure of the formation. In some embodiments, injection of material is performed in 16 m increments in the freeze wellbore. Larger or smaller increments may be used if desired. In some embodiments, material is only applied to certain portions of the formation. For example, material may be applied to the formation through the freeze wellbore only adjacent to aquifer zones and/or to relatively high permeability zones (for example, zones with a permeability greater than about 0.1 darcy). Applying material to aquifers may inhibit migration of water from one aquifer to a different aquifer. For material placed in the formation through freeze well wellbores, the material may inhibit water migration between aquifers during formation of the low temperature zone. The material may also inhibit water migration between aquifers when an established low temperature zone is allowed to thaw.
[06561 In some embodiments, the material used to form a barrier may be fine cement and micro fine cement. Cement may provide structural support in the formation. Fine cement may be ASTM type 3 Portland cement. Fine cement may be less expensive than micro fine cement. In an embodiment, a freeze wellbore is formed in the formation. Selected portions of the freeze wellbore are grouted using fine cement. Then, micro fine cement is injected into the formation through the freeze wellbore. The fine cement may reduce the permeability down to about 10 millidarcy. The micro fine cement may further reduce the permeability to about 0.1 millidarcy.
After the grout is introduced into the formation, a freeze wellbore canister may be inserted into the formation. The process may be repeated for each freeze well that will be used to form the barrier.
[06571 In some embodiments, fine cement is introduced into every other freeze wellbore. Micro fine cement is introduced into the remaining wellbores. For example, grout may be used in a formation with freeze wellbores set at about 5 m spacing. A first wellbore is drilled and fine cement is introduced into the formation through the wellbore. A freeze well canister is positioned in the first wellbore. A second wellbore is drilled 10 m away from the first wellbore.
Fine cement is introduced into the formation through the second wellbore. A
freeze well canister is positioned in the second wellbore. A third wellbore is drilled between the first wellbore and the second wellbore. In some embodiments, grout from the first and/or second wellbores may be detected in the cuttings of the third wellbore. Micro fine cement is introduced into the formation through the third wellbore. A freeze wellbore canister is positioned in the third wellbore. The same procedure is used to form the remaining freeze wells that will form the barrier around the treatment area.
[06581 In some embodiments, material including wax is used to form a barrier in a formation.
Wax barriers may be formed in wet, dry, or oil wetted formations. Wax barriers may be formed above, at the bottom of, and/or below the water table. Material including liquid wax introduced into the formation may permeate into adjacent rock and fractures in the formation. The material may permeate into rock to fill rriicroscopic as well as macroscopic pores and vugs in the rock.

The wax solidifies to form a barrier that inhibits fluid flow into or out of a treatment area. A
wax barrier may provide a minimal amount of structural support in the formatiori. Molten wax may reduce the strength of poorly consolidated soil by reducing inter-grain friction so that the poorly consolidated soil sloughs or liquefies. Poorly consolidated layers may be consolidated by use of cement or other binding agents before introduction of molten wax.
[0659] In some embodiments, the formation where a wax barrier is to be established is dewatered before and/or during formation of the wax barrier. In some embodiments, the portion of the formation where the wax barrier is to form is dewatered or diluted to remove or reduce saline water that could adversely affect the properties of the material introduced into the formation to form the wax barrier.
[0660] In some embodiments, water is introduced into the formation during formation of the wax barrier. Water may be introduced into the formation when the barrier is to be formed below the water table or in a dry portion of the formation. The water may be used to heat the formation to a desired temperature before introducing the material that forms the wax barrier. The water may be introduced at an elevated temperature and/or the water may be heated in the formation from one or more heaters.

10661] The wax of the barrier may be a branched paraffin to inhibit biological degradation of the wax. The wax may include stabilizers, surfactants or other chemicals that modify the physical and/or chemical properties of the wax. The physical properties may be tailored to meet specific needs. The wax may melt at a relative low temperature (for example, the wax may have a typical melting point of about 52 C). The temperature at which the wax congeals may be at least 5 C, 10 C, 20 C, or 30 C above the ambient temperature of the formation prior to any heating of the formation. When molten, the wax may have a relatively low viscosity (for example, 4 to 10 cp at about 99 C). The flash point of the wax may be relatively high (for example, the flash point may be over 204 C). The wax may have a density less than the density of water and may have a heat capacity that is less than half the heat capacity of water. The solid wax may have a low thermal conductivity (for example, about 0.18 W/m C) so that the solid wax is a thermal insulator. Waxes suitable for forming a barrier are available as WAXFIXTM
from Carter Technologies Company (Sugar Land, Texas, U.S.A.). WAXFIXTM is very resistant to microbial attack. WAXFIXTM may have a half life of greater than 5000 years.
106621 In some embodiments, a wax barrier or wax barriers may be used as the barriers for the in situ heat treatment process. In some embodiments, a wax barrier may be used in conjunction with freeze wells that form a low temperature barrier around the treatment area. In some embodiments, the wax barrier is formed and freeze wells are installed in the wellbores used for introducing wax into the formation. In some embodiments, the wax barrier is formed in wellbores offset from the freeze well wellbores. The wax barrier may be on the outside or the inside of the freeze wells. In some embodiments, a wax barrier may be formed on both the inside and outside of the freeze wells. The wax barrier may inhibit water flow in the formation that would inhibit the formation of the low temperature zone by the freeze wells. In some embodiments, a wax barrier is formed in the inter-barrier zone between two freeze barriers of a double barrier system.
[0663] Material used to form the wax barrier may be introduced into the formation through wellbores. The wellbores may include vertical wellbores, slanted wellbores, and/or horizontal wellbores (for example, wellbores with sections that are horizontally or near horizontally oriented). The use of vertical wellbores, slanted wellbores, and/or horizontal welibores for forming the wax barrier allows the formation of a barrier that seals both horizontal and vertical fractures.
[0664] Wellbores may be formed in the formation around the treatment area at a close spacing.
In some embodiments, the spacing is from about 1.5 m to about 4 m. Larger or smaller spacings may be used. Low temperature heaters may be inserted in the wellbores. The heaters may operate at temperatures from about 260 C to about 320 C so that the temperature at the formation face is below the pyrolysis temperature of hydrocarbons in the formation. The heaters may be activated to heat the formation until the overlap between two adjacent heaters raises the temperature of the zone between the two heaters above the melting temperature of the wax.
Heating the formation to obtain superposition of heat with a temperature above the melting temperature of the wax may take one month, two months, or longer. After heating, the heaters may be turned off. In some embodiments, the heaters are downhole antennas that operate at about 10 MHz to heat the formation.
[0665] After heating, the material used to form the wax barrier may be introduced into the wellbores to form the barrier. The material may flow into the formation and fill any fractures and porosity that has been heated. The wax in the material congeals when the wax flows to cold regions beyond the heated circumference. This wax barrier formation method may form a more complete barrier than some other methods of wax barrier formation, but the time for heating may be longer than for some of the other methods. Also, if a low temperature barrier is to be formed with the freeze wells placed in the wellbores used for injection of the material used to form the barrier, the freeze wells will have to remove the heat supplied to the formation to allow for introduction of the material used to form the barrier. The low temperature barrier may take longer to form. ' 106661 In some embodiments, the wax barrier may be formed using a conduit placed in the wellbore. FIG. 34 depicts an embodiment of a system for forming a wax barrier in a formation.
Wellbore 452 may extend into one or more layers 460 below overburden 458.
Wellbore 452 may be an open wellbore below overburden 458. One or more of the layers 460 may include fracture systems 462. One or more of the layers may be vuggy so that the layer or a portion of the layer has a high porosity. Conduit 464 may be positioned in wellbore 452.
In some embodiments, low temperature heater 466 may be strapped or attached to conduit 464. In some embodiments, conduit 464 may be a heater element. Heater 466 may be operated so that the heater does not cause pyrolysis of hydrocarbons adjacent to the heater. At least a portion of wellbore 452 may be filled with fluid. The fluid may be formation fluid or water. Heater 466 may be activated to heat the fluid. A portion of the heated fluid may move outwards from heater 466 into the formation. The heated fluid may be injected into the fractures and permeable vuggy zones. The heated fluid may be injected into the fractures and permeable vuggy zones by introducing heated barrier material into wellbore 452 in the annular space between conduit 464 and the wellbore. The introduced material flows to the areas heated by the fluid and congeals when the fluid reaches cold regions not heated by the fluid. The material fills fracture systems 462 and permeable vuggy pathways heated by the fluid, but the material may not permeate through a significant portion of the rock matrix as when the hot material is introduced into a heated formation as described above. The material flows into fracture systems 462 a sufficient distance to join with material injected from an adjacent well so that a barrier to fluid flow through the fracture systems forms when the wax congeals. A portion of material may congeal along the wall of a fracture or a vug without completely blocking the fracture or filling the vug.
The congealed material may act as an insulator and allow additional liquid wax to flow beyond the congealed portion to penetrate deeply into the formation and form blockages to fluid flow when the material cools below the melting temperature of the wax in the material.
[0667] Material in the annular space of wellbore 452 between conduit 464 and the formation may be removed through conduit by displacing the material with water or other fluid. Conduit 464 may be removed and a freeze well may be installed in the wellbore. This method may use less material than the method described above. The heatingof the fluid may be accomplished in less than a week or within a day. The small amount of heat input may allow for quicker formation of a low temperature barrier if freeze wells are to be positioned in the wellbores used to introduce material into the formation.
[0668] In some embodiments, a heater may be suspended in the well without a conduit that allows for removal of excess material from the wellbore. The material may be introduced into the well. After material introduction, the heater may be removed from the well. In some embodiments, a conduit may be positioned in the wellbore, but a heater may not be coupled to the conduit. Hot material may be circulated through the conduit so that the wax enters fractures systems and/or vugs adjacent to the wellbore.
[0669] In some embodiments, material may be used during the formation of a wellbore to improve inter-zonal isolation and protect a low-pressure zone from inflow from a high-pressure zone. During wellbore formation where a high pressure zone and a low pressure zone are penetrated by a common wellbore, it is possible for fluid from the high pressure zone to flow into the low pressure zone and cause an underground blowout. To avoid this, the wellbore may be formed through the first zone. Then, an intermediate casing may be set and cemented through the first zone. Setting casing may be time consuming and expensive.
Instead of setting a casing, material may be introduced to form a wax barrier that seals the first zone. The material may also inhibit or prevent mixing of high salinity brines from lower, high pressure zones with fresher brines in upper, lower pressure zones.
[0670] FIG. 35A depicts wellbore 452 drilled to a first depth in formation 758. After the surface casing for wellbore 452 is set and cemented in place, the wellbore is drilled to the first depth which passes through a permeable zone, such as an aquifer. The permeable zone may be fracture system 462'. In some embodiments, a heater is placed in wellbore 452 to heat the vertical interval of fracture system 462'. In some embodiments, hot fluid is circulated in wellbore 452 to heat the vertical interval of fracture system 462'. After heating, molten material is pumped down wellbore 452. The molten material flows a selected distance into fracture system 462' before the material cools sufficiently to solidify and form a seal. The molten material is introduced into formation 758 at a pressure below the fracture pressure of the formation. In some embodiments, pressure is maintained on the wellhead until the material has solidified. In some embodiments, the material is allowed to cool until the material in wellbore 452 is almost to the congealing temperature of the material. The material in wellbore 452 may then be displaced out of the wellbore. Wax in the material makes the portion of formation 758 near wellbore 452 into a substantially impermeable zone. Wellbore 452 may be drilled to depth through one or more permeable zones that are at higher pressures than the pressure in the first permeable zone, such as fracture system 462". Congealed wax in fracture system 462' may inhibit blowout into the lower pressure zone. FIG. 35B depicts wellbore 452 drilled to depth with congealed wax 492 in formation 758.
[0671] In some embodiments, a material including wax may be used to contain and inhibit migration in a subsurface formation that has liquid hydrocarbon contaminants (for example, compounds such as benzene, toluene, ethylbenzene and xylene) condensed in fractures in the formation. The location of the contaminants may be surrounded with heated injection wells.
The material may be introduced into the wells to form an outer wax barrier.
The material injected into the fractures from the injection wells may mix with the contaminants. The contaminants may be solubilized into the material. When the material congeals, the contaminants may be permanently contained in the solid wax phase of the material.
[0672] In some embodiments, a portion or all of the wax barrier may be removed after completion of the in situ heat treatment process. Removing all or a portion of the wax barrier may allow fluid to flow into and out of the treatment area of the in situ heat treatment process.
Removing all or a portion of the wax barrier may return flow conditions in the formation to substantially the same conditions as existed before the in situ heat treatment process. To remove a portion or all of the wax barrier, heaters may be used to heat the formation adjacent to the wax barrier. In some embodiments, the heaters raise the temperature above the decomposition temperature of the material forming the wax barrier. In some embodiments, the heaters raise the temperature above the melting temperature of the material forming the wax barrier. Fluid (for example water) may be introduced into the formation to drive the molten material to one or more production wells positioned in the formation. The production wells may remove the material from the formation.
[0673] In some embodiments, a composition that includes a cross-linkable polymer may be used with or in addition to a material that includes wax to form the barrier. Such composition may be provided to the formation as is described above for the material that includes wax. The composition may be configured to react and solidify after a selected time in the formation, thereby allowing the composition to be provided as a liquid to the formation.
The cross-linkable polymer may include, for example, acrylates, methacrylates, urethanes, and/or epoxies. A cross-linking initiator may be included in the composition. The composition may also include a cross-linking inhibitor. The cross-linking inhibitor may be configured to degrade while in the formation, thereby allowing the composition to solidify.
[0674] In situ heat treatment processes and solution mining processes may heat the treatment area, remove mass from the treatment area, and greatly increase the permeability of the treatment area. In certain embodiments, the treatment area after being treated may have a permeability of at least 0.1 darcy. In some embodiments, the treatment area after being treated has a permeability of at least I darcy, of at least 10 darcy, or of at least 100 darcy. The increased permeability allows the fluid to spread in the formation into fractures, microfractures, and/or pore spaces in the formation. Outside of the treatment area, the permeability may remain at the initial permeability of the formation. The increased permeability allows fluid introduced to flow easily within the formation.
[0675] In certain embodiments, a barrier may be formed in the formation after a solution mining process and/or an in situ heat treatment process by introducing a fluid into the formation. The barrier may inhibit formation fluid from entering the treatment area after the solution mining and/or in situ heat treatment processes have ended. The barrier formed by introducing fluid into the formation may allow for isolation of the treatment area.
[0676] The fluid introduced into the formation to form a barrier may include wax, bitumen, heavy oil, sulfur, polymer, gel, saturated saline solution, and/or one or more reactants that react to form a precipitate, solid or high viscosity fluid in the formation. In some embodiments, bitumen, heavy oil, reactants and/or sulfur used to form the barrier are obtained from treatment facilities associated with the in situ heat treatment process. For example, sulfur may be obtained from a Claus process used to treat produced gases to remove hydrogen sulfide and other sulfur compounds.
[0677] The fluid may be introduced into the formation as a liquid, vapor, or mixed phase fluid.
The fluid may be introduced into a portion of the formation that is at an elevated temperature. In some embodiments, the fluid is introduced into the formation through wells located near a perimeter of the treatment area. The fluid may be directed away from the treatment area. The elevated temperature of the formation maintains or allows the fluid to have a low viscosity so that the fluid moves away from the wells. A portion of the fluid may spread outwards in the formation towards a cooler portion of the formation. The relatively high permeability of the formation allows fluid introduced from one wellbore to spread and mix with fluid introduced from other wellbores. In the cooler portion of the formation, the viscosity of the fluid increases, a portion of the fluid precipitates, and/or the fluid solidifies or thickens so that the fluid forms the barrier to flow of formation fluid into or out of the treatment area.
[0678] In some embodiments, a low temperature barrier formed by freeze wells surrounds all or a portion of the treatment area. As the fluid introduced into the formation approaches the low temperature barrier, the temperature of the formation becomes colder. The colder temperature increases the viscosity of the fluid, enhances precipitation, and/or solidifies the fluid to form the barrier to the flow of formation fluid into or out of the formation. The fluid may remain in the formation as a highly viscous fluid or a solid after the low temperature barrier has dissipated.
[0679] In certain embodiments, saturated saline solution is introduced into the formation.
Components in the saturated saline solution may precipitate out of solution when the solution reaches a colder temperature. The solidified particles may form the barrier to the flow of formation fluid into or out of the formation. The solidified components may be substantially insoluble in formation fluid.
[0680] In certain embodiments, brine is introduced into the formation as a reactant. A second reactant, such as carbon dioxide, may be introduced into the formation to react with the brine.
The reaction may generate a mineral complex that grows in the formation. The mineral complex may be substantially insoluble to formation fluid. In an embodiment, the brine solution includes a sodium and aluminum solution. The second reactant introduced in the formation is carbon dioxide. The carbon dioxide reacts with the brine solution to produce dawsonite. The minerals may solidify and form the barrier to the flow of formation fluid into or out of the formation.
[0681] In some embodiments, the barrier may be formed around a treatment area using sulfur.
Advantageously, elemental sulfur is insoluble in water. Liquid and/or solid sulfur in the formation may form a barrier to formation fluid flow into or out of the treatment area.
[0682] A sulfur barrier may be established in the formation during or before initiation of heating to heat the treatment area of the in situ heat treatment process. In some embodiments, sulfur may be introduced into wellbores in the formation that are located between the treatment area and a first barrier (for example, a low temperature barrier established by freeze wells). The formation adjacent to the wellbores that the sulfur is introduced into may be dewatered. In some embodiments, the formation adjacent to the wellbores that the sulfur is introduced into is heated to facilitate removal of water and to prepare the wellbores and adjacent formation for the introduction of sulfur. The formation adjacent to the wellbores may be heated to a temperature below the pyrolysis temperature of hydrocarbons in the formation. The formation may be heated so that the temperature of a portion of the formation between two adjacent heaters is influenced by both heaters. In some embodiments, the heat may increase the permeability of the formation so that a first wellbore is in fluid communication with an adjacent wellbore.
[0683] After the formation adjacent to the wellbores is heated, molten sulfur at a temperature below the pyrolysis temperature of hydrocarbons in the formation is introduced into the formation. Over a certain temperature range, the viscosity of molten sulfur increases with increasing temperature. The molten sulfur introduced into the formation may be near the melting temperature of sulfur (about 115 C) so that the sulfur has a relatively low viscosity (about 4-10 cp). Heaters in the wellbores may be temperature limited heaters with Curie temperatures near the melting temperature of sulfur so that the temperature of the molten sulfur stays relatively constant and below temperatures resulting in the formation of viscous molten sulfur. In some embodiments, the region adjacent to the wellbores may be heated to a temperature above the melting point of sulfur, but below the pyrolysis temperature of hydrocarbons in the formation. The heaters may be turned off and the temperature in the wellbores may be monitored (for example, using a fiber optic temperature monitoring system).
When the temperature in the wellbore cools to a temperature near the melting temperature of sulfur, molten sulfur may be introduced into the formation.
[0684] The sulfur introduced into the formation is allowed to flow and diffuse into the formation from the wellbores. As the sulfur enters portions of the formation below the melting temperature, the sulfur solidifies and forms a barrier to fluid flow in the formation. Sulfur may be introduced until the formation is not able to accept additional sulfur.
Heating may be stopped, and the formation may be allowed to naturally cool so that the sulfur in the formation solidifies. After introduction of the sulfur, the integrity of the formed barrier may be tested using pulse tests and/or tracer tests.
[0685] A barrier may be formed around the treatment area after the in situ heat treatment process. The sulfur may form a substantially permanent barrier in the formation. In some embodiments, a low temperature barrier formed by freeze wells surrounds the treatment area.
Sulfur may be introduced on one or both sides of the low temperature barrier to form a barrier in the formation. The sulfur may be introduced into the formation as vapor or a liquid. As the sulfur approaches the low temperature barrier, the sulfur may condense and/or solidify in the formation to form the barrier.
[0686] In some embodiments, the sulfur may be introduced in the heated portion of the portion.
The sulfur may be introduced into the formation through wells located near the perimeter of the treatment area. The temperature of the formation may be hotter than the vaporization temperature of sulfur (about 445 C). The sulfur may be introduced as a liquid, vapor or mixed phase fluid. If a part of the introduced sulfur is in the liquid phase, the heat of the formation may vaporize the sulfur. The sulfur may flow outwards from the introduction wells towards cooler portions of the formation. The sulfur may condense and/or solidify in the formation to form the barrier.
[0687] In some embodiments, the Claus reaction may be used to form sulfur in the formation after the in situ heat treatment process. The Claus reaction is a gas phase equilibrium reaction.
The Claus reaction is:
(EQN. 2) 4H2)S + 2SO2 H 3S2 + 4H20 [0688] Hydrogen sulfide may be obtained by separating the hydrogen sulfide from the produced fluid of an ongoing in situ heat treatment process. A portion of the hydrogen sulfide may be burned to form the needed sulfur dioxide. Hydrogen sulfide may be introduced into the formation through a number of wells in the formation. Sulfur dioxide may be introduced into the formation through other wells. The wells used for injecting sulfur dioxide or hydrogen sulfide may have been production wells, heater wells, monitor wells or other type of well during the in situ heat treatment process. The wells used for injecting sulfur dioxide or hydrogen sulfide may be near the perimeter of the treatment area. The number of wells may be enough so that the formation in the vicinity of the injection wells does not cool to a point where the sulfur dioxide and the hydrogen sulfide can form sulfur and condense, rather than remain in the vapor phase. The wells used to introduce the sulfur dioxide into the formation may also be near the perimeter of the treatment area. In some embodiments, the hydrogen sulfide and sulfur dioxide may be introduced into the formation through the same wells (for example, through two conduits positioned in the same wellbore). The hydrogen sulfide and the sulfur dioxide may react in the formation to form sulfur and water. The sulfur may flow outwards in the formation and condense and/or solidify to form the barrier in the formation.
[0689] The sulfur barrier may form in the formation beyond the area where hydrocarbons in formation fluid generated by the heat treatment process condense in the formation. Regions near the perimeter of the treated area may be at lower temperatures than the treated area. Sulfur may condense and/or solidify from the vapor phase in these lower temperature regions. Additional hydrogen sulfide, and/or sulfur dioxide may diffuse to these lower temperature regions.
Additional sulfur may form by.the Claus reaction to maintain an equilibrium concentration of sulfur in the vapor phase. Eventually, a sulfur barrier may form around the treated zone. The vapor phase in the treated region may remain as an equilibrium mixture of sulfur, hydrogen sulfide, sulfur dioxide, water vapor and other vapor products present or evolving from the formation.
[0690] The conversion to sulfur is favored at lower temperatures, so the conversion of hydrogen sulfide and sulfur dioxide to sulfur may take place a distance away from the wells that introduce the reactants into the formation. The Claus reaction may result in the formation of sulfur where the temperature of the formation is cooler (for example where the temperature of the formation is at temperatures from about 180 C to about 240 C).
[0691] A temperature monitoring system may be installed in wellbores of freeze wells and/or in monitor wells adjacent to the freeze wells to monitor the temperature profile of the freeze wells and/or the low temperature zone established by the freeze wells. The monitoring system may be used to monitor progress of low temperature zone formation. The monitoring system may be used to determine the location of high temperature areas, potential breakthrough locations, or breakthrough locations after the low temperature zone has formed. Periodic monitoring of the temperature profile of the freeze wells and/or low temperature zone established by the freeze wells may allow additional cooling to be provided to potential trouble areas before breakthrough occurs. Additional cooling may be provided at or adjacent to breakthroughs and high temperature areas to ensure the integrity of the low temperature zone around the treatment area.
Additional cooling may be provided by increasing refrigerant flow through selected freeze wells, installing an additional freeze well or freeze wells, and/or by providing a cryogenic fluid, such as liquid nitrogen, to the high temperature areas. Providing additional cooling to potential problem areas before breakthrough occurs may be more time efficient and cost efficient than sealing a breach, reheating a portion of the treatment area that has been cooled by influx of fluid, and/or remediating an area outside of the breached frozen barrier.
[0692] In some embodiments, a traveling thermocouple may be used to monitor the temperature profile of selected freeze wells or monitor wells. In some embodiments, the temperature monitoring system includes thermocouples placed at discrete locations in the wellbores of the freeze wells, in the freeze wells, and/or in the monitoring wells. In some embodiments, the temperature monitoring system comprises a fiber optic temperature monitoring system.
106931 Fiber optic temperature monitoring systems are available from Sensornet (London, United Kingdom), Sensa (Houston, Texas, U.S.A.), Luna Energy (Blacksburg, Virginia, U.S.A.), Lios Technology GMBH (Cologne, Germany), Oxford Electronics Ltd.
(Hampshire, United Kingdom), and Sabeus Sensor Systems (Calabasas, California, U.S.A.).
The fiber optic temperature monitoring system includes a data system and one or more fiber optic cables. The data system includes one or more lasers for sending light to the fiber optic cable; and one or more computers, software and peripherals for receiving, analyzing, and outputting data. The data system may be coupled to one or more fiber optic cables.
[0694] A single fiber optic cable may be several kilometers long. The fiber optic cable may be installed in many freeze wells and/or monitor wells. In some embodiments, two fiber optic cables may be installed in each freeze well and/or monitor well. The two fiber optic cables may be coupled. Using two fiber optic cables per well allows for compensation due to optical losses that occur in the wells and allows for better accuracy of measured temperature profiles.
[0695] The fiber optic temperature monitoring system may be used to detect the location of a breach or a potential breach in a frozen barrier. The search for potential breaches may be performed at scheduled intervals, for example, every two or three months. To determine the location of the breach or potential breach, flow of formation refrigerant to the freeze wells of interest is stopped. In some embodiments, the flow of formation refrigerant to all of the freeze wells is stopped. The rise in the temperature profiles, as well as the rate of change of the temperature profiles, provided by the fiber optic temperature monitoring system for each freeze well can be used to determine the location of any breaches or hot spots in the low temperature zone maintained by the freeze wells. The temperature profile monitored by the fiber optic temperature monitoring system for the two freeze wells closest to the hot spot or fluid flow will show the quickest and greatest rise in temperature. A temperature change of a few degrees Centigrade in the temperature profiles of the freeze wells closest to a troubled area may be sufficient to isolate the location of the trouble area. The shut down time of flow of circulation fluid in the freeze wells of interest needed to detect breaches, potential breaches, and hot spots may be on the order of a few hours or days, depending on the well spacing and the amount of fluid flow affecting the low temperature zone.
[0696] Fiber optic temperature monitoring systems may also be used to monitor temperatures in heated portions of the formation during in situ heat treatment processes. The fiber of a fiber optic cable used in the heated portion of the formation may be clad with a reflective material to facilitate retention of a signal or signals transmitted down the fiber. In some embodiments, the fiber is clad with gold, copper, nickel, aluminum and/or alloys thereof. The cladding may be formed of a material that is able to withstand chemical and temperature conditions in the heated portion of the formation. For example, gold cladding may allow an optical sensor to be used up to temperatures of 700 C. In some embodiments, the fiber is clad with aluminum. The fiber may be dipped in or run through a bath of liquid aluminum. The clad fiber may then be allowed to cool to secure the aluminum to the fiber. The gold or aluminum cladding may reduce hydrogen darkening of the optical fiber.
[0697] A potential source of heat loss from the heated formation is due to reflux in wells.
Refluxing occurs when vapors condense in a well and flow into a portion of the well adjacent to the heated portion of the formation. Vapors may condense in the well adjacent to the overburden of the formation to form condensed fluid. Condensed fluid flowing into the well adjacent to the heated formation absorbs heat from the formation. Heat absorbed by condensed fluids cools the fonnation and necessitates additional energy input into the formation to maintain the formation at a desired temperature. Some fluids that condense in the overburden and flow into the portion of the well adjacent to the heated formation may react to produce undesired compounds and/or coke. Inhibiting fluids from refluxing may significantly improve the thermal efficiency of the in situ heat treatment system and/or the quality of the product produced from the in situ heat treatment system.
[0698] For some well embodiments, the portion of the well adjacent to the overburden section of the formation is cemented to the formation. In some well embodiments, the well includes packing material placed near the transition from the heated section of the formation to the overburden. The packing material inhibits formation fluid from passing from the heated section of the formation into the section of the wellbore adjacent to the overburden.
Cables, conduits, devices, and/or instruments may pass through the packing material, but the packing material inhibits formation fluid from passing up the wellbore adjacent to the overburden section of the formation.
[0699] In some embodiments, one or more baffle systems may be placed in the wellbores to inhibit reflux. The baffle systems may be obstructions to fluid flow into the heated portion of the formation. In some embodiments, refluxing fluid may revaporize on the baffle system before coming into contact with the heated portion of the formation.
[0700] In some embodiments, a gas may be introduced into the formation through welibores to inhibit reflux in the wellbores. In some embodiments, gas may be introduced into wellbores that include baffle systems to inhibit reflux of fluid in the wellbores. The gas may be carbon dioxide, methane, nitrogen or other desired gas. In some embodiments, the introduction of gas may be used in conjunction with one or more baffle systems in the wellbores.
The introduced gas may enhance heat exchange at the baffle systems to help maintain top portions of the baffle systems colder than the lower portions of the baffle systems.
[0701] The flow of production fluid up the well to the surface is desired for some types of wells, especially for production wells. Flow of production fluid up the well is also desirable for some heater wells that are used to control pressure in the formation. The overburden, or a conduit in the well used to transport formation fluid from the heated portion of the formation to the surface, may be heated to inhibit condensation on or in the conduit. Providing heat in the overburden, however, may be costly and/or may lead to increased cracking or coking of formation fluid as the formation fluid is being produced from the formation.
[0702] To avoid the need to heat the overburden or to heat the conduit passing through the overburden, one or more diverters may be placed in the wellbore to inhibit fluid from refluxing into the wellbore adjacent to the heated portion of the formation. In some embodiments, the diverter retains fluid above the heated portion of the formation. Fluids retained in the diverter may be removed from the diverter using a pump, gas lifting, and/or other fluid removal technique. In certain embodiments, two or more diverters that retain fluid above the heated portion of the formation may be located in the production well. Two or more diverters provide a simple way of separating initial fractions of condensed fluid produced from the in situ heat treatment system. A pump may be placed in each of the diverters to remove condensed fluid from the diverters.

[0703] In some embodiments, the diverter directs fluid to a sump below the heated portion of the formation. An inlet for a lift system may be located in the sump. In some embodiments, the intake of the lift system is located in casing in the sump. In some embodiments, the intake of the lift system is located in an open wellbore. The sump is below the heated portion of the formation. The intake of the pump may be located 1 m, 5 m, 10 m, 20 m or more below the deepest heater used to heat the heated portion of the formation. The sump may be at a cooler temperature than the heated portion of the formation. The sump may be more than 10 C, more than 50 C, more than 75 C, or more than 100 C below the temperature of the heated portion of the formation. A portion of the fluid entering the sump may be liquid. A
portion of the fluid entering the sump may condense within the sump. The lift system moves the fluid in the sump to the surface.
[0704] Production well lift systems may be used to efficiently transport formation fluid from the bottom of the production wells to the surface. Production well lift systems may provide and maintain the maximum required well drawdown (minimum reservoir producing pressure) and producing rates. The production well lift systems may operate efficiently over a wide range of high temperature/multiphase fluids (gas/vapor/steam/water/hydrocarbon liquids) and production rates expected during the life of a typical project. Production well lift systems may include dual concentric rod pump lift systems, chamber lift systems and other types of lift systems.
[0705] Temperature limited heaters may be in configurations and/or may include materials that provide automatic temperature limiting properties for the heater at certain temperatures. In certain embodiments, ferromagnetic materials are used in temperature limited heaters.
Ferromagnetic material may self-limit temperature at or near the Curie temperature of the material and/or the phase transformation temperature range to provide a reduced amount of heat when a time-varying current is applied to the material. In certain embodiments, the ferromagnetic material self-limits temperature of the temperature limited heater at a selected temperature that is approximately the Curie temperature and/or in the phase transformation temperature range. In certain embodiments, the selected temperature is within about 35 C, within about 25 C, within about 20 C, or within about 10 C of the Curie temperature and/or the phase transformation temperature range. In certain embodiments, ferromagnetic materials are coupled with other materials (for example, highly conductive materials, high strength materials, corrosion resistant materials, or combinations thereof) to provide various electrical and/or mechanical properties. Some parts of the temperature limited heater may have a lower resistance (caused by different geometries and/or by using different ferromagnetic and/or non-ferromagnetic materials) than other parts of the temperature limited heater.
Having parts of the temperature limited heater with various materials and/or dimensions allows for tailoring the desired heat output from each part of the heater.
107061 Temperature limited heaters may be more reliable than other heaters.
Temperature limited heaters may be less apt to break down or fail due to hot spots in the formation. In some embodiments, temperature limited heaters allow for substantially uniform heating of the formation. In some embodiments, temperature limited heaters are able to heat the formation more efficiently by operating at a higher average heat output along the entire length of the heater. The temperature limited heater operates at the higher average heat output along the entire length of the heater because power to the heater does not have to be reduced to the entire heater, as is the case with typical constant wattage heaters, if a temperature along any point of the heater exceeds, or is about to exceed, a maximum operating temperature of the heater. Heat output from portions of a temperature limited heater approaching a Curie temperature and/or the phase transformation temperature range of the heater automatically reduces without controlled adjustment of the time-varying current applied to the heater. The heat output automatically reduces due to changes in electrical properties (for example, electrical resistance) of portions of the temperature limited heater. Thus, more power is supplied by the temperature limited heater during a greater portion of a heating process.
[0707] In certain embodiments, the system including temperature limited heaters initially provides a first heat output and then provides a reduced (second heat output) heat output, near, at, or above the Curie temperature and/or the phase transformation temperature range of an electrically resistive portion of the heater when the temperature limited heater is energized by a time-varying current. The first heat output is the heat output at temperatures below which the temperature limited heater begins to self-limit. In some embodiments, the first heat output is the heat output at a temperature about 50 C, about 75 C, about 100 C, or about 125 C below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic material in the temperature limited heater.
[0708] The temperature limited heater may be energized by time-varying current (alternating current or modulated direct current) supplied at the wellhead. The wellhead may include a power source and other components (for example, modulation components, transformers, and/or capacitors) used in supplying power to the temperature limited heater. The temperature limited heater may be one of many heaters used to heat a portion of the formation.
[0709] In certain embodiments, the temperature limited heater includes a conductor that operates as a skin effect or proximity effect heater when time-varying current is applied to the conductor.
The skin effect limits the depth of current penetration into the interior of the conductor. For WO 2008/051495 , PCT/US2007/022376 ferromagnetic materials, the skin effect is dominated by the magnetic permeability of the conductor. The relative magnetic permeability of ferromagnetic materials is typically between and 1000 (for example, the relative magnetic permeability of ferromagnetic materials is typically at least 10 and may be at least 50, 100, 500, 1000 or greater). As the temperature of the ferromagnetic material is raised above the Curie temperature, or the phase transformation temperature range, and/or as the applied electrical current is increased, the magnetic permeability of the ferromagnetic material decreases substantially and the skin depth expands rapidly (for example, the skin depth expands as the inverse square root of the magnetic permeability). The reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the conductor near, at, or above the Curie temperature, the phase transformation temperature range, and/or as the applied electrical current is increased. When the temperature limited heater is powered by a substantially constant current source, portions of the heater that approach, reach, or are above the Curie temperature and/or the phase transformation temperature range may have reduced heat dissipation. Sections of the temperature limited heater that are not at or near the Curie temperature and/or the phase transformation temperature range may be dominated by skin effect heating that allows the heater to have high heat dissipation due to a higher resistive load.
[0710] Curie temperature heaters have been used in soldering equipment, heaters for medical applications, and heating elements for ovens (for example, pizza ovens). Some of these uses are disclosed in U.S. Patent Nos. 5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732 to Yagnik et al. U.S. Patent No. 4,849,611 to Whitney et al.
describes a plurality of discrete, spaced-apart heating units including a reactive component, a resistive heating component, and a temperature responsive component.
[0711] An advantage of using the temperature limited heater to heat hydrocarbons in the formation is that the conductor is chosen to have a Curie temperature and/or a phase transformation temperature range in a desired range of temperature operation.
Operation within the desired operating temperature range allows substantial heat injection into the formation while maintaining the temperature of the temperature limited heater, and other equipment, below design limit temperatures. Design limit temperatures are temperatures at which properties such as corrosion, creep, and/or deformation are adversely affected. The temperature limiting properties of the temperature limited heater inhibit overheating,or burnout of the heater adjacent to low thermal conductivity "hot spots" in the formation. In some embodiments, the temperature limited heater is able to lower or control heat output and/or withstand heat at temperatures above 25 C, 37 C, 100 C, 250 C, 500 C, 700 C, 800 C, 900 C, or higher up to 1131 C, depending on the materials used in the heater.
[0712] The temperature limited heater allows for more heat injection into the formation than constant wattage heaters because the energy input into the temperature limited heater does not have to be limited to accommodate low thermal conductivity regions adjacent to the heater. For example, in Green River oil shale there is a difference of at least a factor of 3 in the thermal conductivity of the lowest richness oil shale layers and the highest richness oil shale layers.
When heating such a formation, substantially more heat is transferred to the formation with the temperature limited heater than with the conventional heater that is limited by the temperature at low thermal conductivity layers. The heat output along the entire length of the conventional heater needs to accommodate the low thermal conductivity layers so that the heater does not overheat at the low thermal conductivity layers and burn out. The heat output adjacent to the low thermal conductivity layers that are at high temperature will reduce for the temperature limited heater, but the remaining portions of the temperature limited heater that are not at high temperature will still provide high heat output. Because heaters for heating hydrocarbon formations typically have long lengths (for example, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10 km), the majority of the length of the temperature limited heater may be operating below the Curie temperature and/or the phase transformation temperature range while only a few portions are at or near the Curie temperature and/or the phase transformation temperature range of the temperature limited heater.
[0713] The use of temperature limited heaters allows for efficient transfer of heat to the formation. Efficient transfer of heat allows for reduction in time needed to heat the formation to a desired temperature. For example, in Green River oil shale, pyrolysis typically requires 9.5 years to 10 years of heating when using a 12 m heater well spacing with conventional constant wattage heaters. For the same heater spacing, temperature limited heaters may allow a larger average heat output while maintaining heater equipment temperatures below equipment design limit temperatures. Pyrolysis in the formation may occur at an earlier time with the larger average heat output provided by temperature limited heaters than the lower average heat output provided by constant wattage heaters. For example, in Green River oil shale, pyrolysis may occur in 5 years using temperature limited heaters with a 12 m heater well spacing. Temperature limited heaters counteract hot spots due to inaccurate well spacing or drilling where heater wells come too close together. In certain embodiments, temperature limited heaters allow for increased power output over time for heater wells that have been spaced too far apart, or limit power output for heater wells that are spaced too close together. Temperature liniited heaters also supply more power in regions adjacent the overburden and underburden to compensate for temperature losses in these regions.
[07141 Temperature limited heaters may be advantageously used in many types of formations.
For example, in tar sands formations or relatively permeable formations containing heavy hydrocarbons, temperature limited heaters may be used to provide a controllable low temperature output for reducing the viscosity of fluids, mobilizing fluids, and/or enhancing the radial flow of fluids at or near the wellbore or in the formation. Temperature limited heaters may be used to inhibit excess coke formation due to overheating of the near wellbore region of the formation.
[0715] The use of temperature limited heaters, in some embodiments, eliminates or reduces the need for expensive temperature control circuitry. For example, the use of temperature limited heaters eliminates or reduces the need to perform temperature logging and/or the need to use fixed thermocouples on the heaters to monitor potential overheating at hot spots.
[0716] In certain embodiments, phase transformation (for example, crystalline phase transformation or a change in the crystal structure) of materials used in a temperature limited heater change the selected temperature at which the heater self-limits.
Ferromagnetic material used in the temperature limited heater may have a phase transformation (for example, a transformation from ferrite to austenite) that decreases the magnetic permeability of the ferromagnetic material. This reduction in magnetic permeability is similar to reduction in magnetic permeability due to the magnetic transition of the ferromagnetic material at the Curie temperature. The Curie temperature is the magnetic transition temperature of the ferrite phase of the ferromagnetic material. The reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the temperature limited heater near, at, or above the temperature of the phase transformation and/or the Curie temperature of the ferromagnetic material.
107171 The phase.transformation of the ferromagnetic material may occur over a temperature range. The temperature range of the phase transformation depends on the ferromagnetic material and may vary, for example, over a range of about 5 C to a range of about 200 C.
Because the phase transformation takes place over a temperature range, the reduction in the magnetic permeability due to the phase transformation takes place over the temperature range.
The reduction in magnetic permeability may also occur hysteretically over the temperature range of the phase transformation. In some embodiments, the phase transformation back to the lower temperature phase of the ferromagnetic material is slower than the phase transformation to the higher temperature phase (for example, the transition from austenite back to ferrite is slower than the transition from ferrite to austenite). The slower phase transformation back to the lower temperature phase may cause hysteretic operation of the heater at or near the phase transformation temperature range that allows the heater to slowly increase to higher resistance after the resistance of the heater reduces due to high temperature.
[0718] In some embodiments, the phase transformation temperature range overlaps with the reduction in the magnetic permeability when the temperature approaches the Curie temperature of the ferromagnetic material. The overlap may produce a faster drop in electrical resistance versus temperature than if the reduction in magnetic permeability is solely due to the temperature approaching the Curie temperature. The overlap may also produce hysteretic behavior of the temperature limited heater near the Curie temperature and/or in the phase transformation temperature range.
[0719] In certain embodiments, the hysteretic operation due to the phase transformation is a smoother transition than the reduction in magnetic permeability due to magnetic transition at the Curie temperature. The smoother transition may be easier to control (for example, electrical control using a process control device that interacts with the power supply) than the sharper transition at the Curie temperature. In some embodiments, the Curie temperature is located inside the phase transformation range for selected metallurgies used in temperature limited heaters. This phenomenon provides temperature limited heaters with the smooth transition properties of the phase transformation in addition to a sharp and definite transition due to the reduction in magnetic properties at the Curie temperature. Such temperature limited heaters may be easy to control (due to the phase transformation) while providing finite temperature limits (due to the sharp Curie temperature transition). Using the phase transformation temperature range instead of and/or in addition to the Curie temperature in temperature limited heaters increases the number and range of metallurgies that may be used for temperature limited heaters.
[0720] In certain embodiments, alloy additions are made to the ferromagnetic material to adjust the temperature range of the phase transformation. For example, adding carbon to the ferromagnetic material may increase the phase transformation temperature range and lower the onset temperature of the phase transformation. Adding titanium to the ferromagnetic material may increase the onset temperature of the phase transformation and decrease the phase transformation temperature range. Alloy compositions may be adjusted to provide desired Curie temperature and phase transformation properties for the ferromagnetic material. The alloy composition of the ferromagnetic material may be chosen based on desired properties for the ferromagnetic material (such as, but not limited to, magnetic permeability transition temperature or temperature range, resistance versus temperature profile, or power output).
Addition of titanium may allow higher Curie temperatures to be obtained when adding cobalt to 410 stainless steel by raising the ferrite to austenite phase transformation temperature range to a temperature range that is above, or well above, the Curie temperature of the ferromagnetic material.

[0721] In some embodiments, temperature limited heaters are more economical to manufacture or make than standard heaters. Typical ferromagnetic materials include iron, carbon steel, or ferritic stainless steel. Such materials are inexpensive as compared to nickel-based heating alloys (such as nichrome, KanthalTM (Bulten-Kanthal AB, Sweden), and/or LOHMTM
(Driver-Harris Company, Harrison, New Jersey, U.S.A.)) typically used in insulated conductor (mineral insulated cable) heaters. In one embodiment of the temperature limited heater, the temperature limited heater is manufactured in continuous lengths as an insulated conductor heater to lower costs and improve reliability.
[0722] In some embodiments, the temperature limited heater is placed in the heater well using a coiled tubing rig. A heater that can be coiled on a spool may be manufactured by using metal such as ferritic stainless steel (for example, 409 stainless steel) that is welded using electrical resistance welding (ERW). U.S. Patent 7,032,809 to Hopkins describes forming seam-welded pipe. To form a heater section, a metal strip from a roll is passed through a former where it is shaped into a tubular and then longitudinally welded using ERW.
107231 FIG. 36 depicts an embodiment of a device for longitudinal welding (seam-welding) of a tubular using ERW. Metal strip 474 is shaped into tubular form as it passes through ERW coil 476. Metal strip 474 is then welded into a tubular inside shield 478. As metal strip 474 is joined inside shield 478, inert gas (for example, argon or another suitable welding gas) is provided inside the forming tubular by gas inlets 480. Flushing the tubular with inert gas inhibits oxidation of the tubular as it is formed. Shield 478 may have window 482.
Window 482 allows an operator to visually inspect the welding process. Tubular 484 is formed by the welding process.
[0724] In some embodiments, a composite tubular may be formed from the seam-welded tubular. The seam-welded tubular is passed through a second former where a conductive strip (for example, a copper strip) is applied, drawn down tightly on the tubular through a die, and longitudinally welded using ERW. A sheath may be formed by longitudinally welding a support material (for example, steel such as 347H or 347HH) over the conductive strip material. The support material may be a strip rolled over the conductive strip material. An overburden section of the heater may be formed in a similar manner.

[0725] In certain embodiments, the overburden section uses a non-ferromagnetic material such as 304 stainless steel or 316 stainless steel instead of a ferromagnetic material. The heater section and overburden section may be coupled using standard techniques such as butt welding using an orbital welder. In some embodiments, the overburden section material (the non-ferromagnetic material) may be pre-welded to the ferromagnetic material before rolling. The pre-welding may eliminate the need for a separate coupling step (for example, butt welding). In an embodiment, a flexible cable (for example, a furnace cable such as a MGT
1000 furnace cable) may be pulled through the center after forming the tubular heater. An end bushing on the flexible cable may be welded to the tubular heater to provide an electrical current return path.
The tubular heater, including the flexible cable, may be coiled onto a spool before installation into a heater well. In an embodiment, the temperature limited heater is installed using the coiled tubing rig. The coiled tubing rig may place the temperature limited heater in a deformation resistant container in the formation. The deformation resistant container may be placed in the heater well using conventional methods.
[0726] Temperature limited heaters may be used for heating hydrocarbon formations including, but not limited to, oil shale formations, coal formations, tar sands formations, and formations with heavy viscous oils. Temperature limited heaters may also be used in the field of environmental remediation to vaporize or destroy soil contaminants.
Embodiments of temperature limited heaters may be used to heat fluids in a wellbore or sub-sea pipeline to inhibit deposition of paraffin or various hydrates. In some embodiments, a temperature limited heater is used for solution mining a subsurface formation (for example, an oil shale or a coal formation). In certain embodiments, a fluid (for example, molten salt) is placed in a wellbore and heated with a temperature limited heater to inhibit deformation and/or collapse of the wellbore. In some embodiments, the temperature limited heater is attached to a sucker rod in the wellbore or is part of the sucker rod itself. In some embodiments, temperature limited heaters are used to heat a near wellbore region to reduce near wellbore oil viscosity during production of high viscosity crude oils and during transport of high viscosity oils to the surface. In some embodiments, a temperature limited heater enables gas lifting of a viscous oil by lowering the viscosity of the oil without coking the oil. Temperature limited heaters may be used in sulfur transfer lines to maintain temperatures between about 110 C and about 130 C.
[0727] The ferromagnetic alloy or ferromagnetic alloys used in the temperature limited heater determine the Curie temperature of the heater. Curie temperature data for various metals is listed in "American Institute of Physics Handbook," Second Edition, McGraw-Hill, pages 5-170 through 5-176. Ferromagnetic conductors may include one or more of the ferromagnetic elements (iron, cobalt, and nickel) and/or alloys of these elements. In some embodiments, ferromagnetic conductors include iron-chromium (Fe-Cr) alloys that contain tungsten (W) (for example, HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys that contain chromium (for example, Fe-Cr alloys, Fe-Cr-W alloys, Fe-Cr-V (vanadium) alloys, and Fe-Cr-Nb (Niobium) alloys). Of the three main ferromagnetic elements, iron has a Curie temperature of approximately 770 C; cobalt (Co) has a Curie temperature of approximately 1131 C; and nickel has a Curie temperature of approximately 358 C. An iron-cobalt alloy has a Curie temperature higher than the Curie temperature of iron. For example, iron-cobalt alloy with 2%
by weight cobalt has a Curie temperature of approximately 800 C; iron-cobalt alloy with 12%
by weight cobalt has a Curie temperature of approximately 900 C; and iron-cobalt alloy with 20% by weight cobalt has a Curie temperature of approximately 950 C. Iron-nickel alloy has a Curie temperature lower than the Curie temperature of iron. For example, iron-nickel alloy with 20% by weight nickel has a Curie temperature of approximately 720 C, and iron-nickel alloy with 60% by weight nickel has a Curie temperature of approximately 560 C.
[0728] Some non-ferromagnetic elements used as alloys raise the Curie temperature of iron. For example, an iron-vanadium alloy with 5.9% by weight vanadium has a Curie temperature of approximately 815 C. Other non-ferromagnetic elements (for example, carbon, aluminum, copper, silicon, and/or chromium) may be alloyed with iron or other ferromagnetic materials to lower the Curie temperature. Non-ferromagnetic materials that raise the Curie temperature may be combined with non-ferromagnetic materials that lower the Curie temperature and alloyed with iron or other ferromagnetic materials to produce a material with a desired Curie temperature and other desired physical and/or chemical properties. In some embodiments, the Curie temperature material is a ferrite such as NiFe2O4. In other embodiments, the Curie temperature material is a binary compound such as FeNi3 or Fe3Al.
[0729] In some embodiments, the improved alloy includes carbon, cobalt, iron, manganese, silicon, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight:
about 0.1 % to about 10% cobalt; about 0.1 % carbon, about 0.5% manganese, about 0.5%
silicon, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 0.1 % to about 10% cobalt; about 0.1 % carbon, about 0.5%
manganese, about 0.5% silicon, with the balance being iron.
[0730] In some embodiments, the improved alloy includes chromium, carbon, cobalt, iron, manganese, silicon, titanium, vanadium, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight: about 5% to about 20% cobalt, about 0.1%
carbon, about 0.5% manganese, about 0.5% silicon, about 0.1% to about 2% vanadium with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12%
chromium, about 0.1% carbon, about 0.5% silicon, about 0.1 % to about 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2% vanadium, above 0% to about 1%
titanium, with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12%
chromium, about 0.1% carbon, about 0.5% silicon, about 0.1 % to about 0.5%
manganese, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1 %
carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2%
vanadium, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1%
to about 0.5%
manganese, above 0% to about 15% cobalt, above 0% to about 1% titanium, with the balance being iron. In certain embodiments, the improved alloy includes, by weight:
about 12%
chromium, about 0.1 % carbon, about 0.5% silicon, about 0.1 /a to about 0.5%
manganese, above 0% to about 15% cobalt, with the balance being iron. The addition of vanadium may allow for use of higher amounts of cobalt in the improved alloy.
[0731] Certain embodiments of temperature limited heaters may include more than one ferromagnetic material. Such embodiments are within the scope of embodiments described herein if any conditions described herein apply to at least one of the ferromagnetic materials in the temperature limited heater.
[0732] Ferromagnetic properties generally decay as the Curie temperature and/or the phase transformation temperature range is approached. The "Handbook of Electrical Heating for Industry" by C. James Erickson (IEEE Press, 1995) shows a typical curve for 1%
carbon steel (steel with 1% carbon by weight). The loss of magnetic permeability starts at temperatures above 650 C and tends to be complete when temperatures exceed 730 C. Thus, the self-limiting temperature may be somewhat below the actual Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The skin depth for current flow in 1% carbon steel is 0.132 cm at room temperature and increases to 0.445 cm at 720 C.
From 720 C to 730 C, the skin depth sharply increases to over 2.5 cm. Thus, a temperature limited heater embodiment using 1% carbon steel begins to self-limit between 650 C and 730 C.
[0733] Skin depth generally defines an effective penetration depth of time-varying current into the conductive material. In general, current density decreases exponentially with distance from an outer surface to the center along the radius of the conductor. The depth at which the current density is approximately 1/e of the surface current density is called the skin depth. For a solid lll cylindrical rod with a diameter much greater than the penetration depth, or for hollow cylinders with a wall thickness exceeding the penetration depth, the skin depth, 8, is:
(EQN. 3) 8 = 1981.5* (p/( *f))'/z;
in which: S= skin depth in inches;
p = resistivity at operating temperature (ohm-cm);
= relative magnetic permeability; and f = frequency (Hz).
EQN. 3 is obtained from "Handbook of Electrical Heating for Industry" by C.
James Erickson (IEEE Press, 1995). For most metals, resistivity (p) increases with temperature. The relative magnetic permeability generally varies with temperature and with current.
Additional equations may be used to assess the variance of magnetic permeability and/or skin depth on both temperature and/or current. The dependence of on current arises from the dependence of on the electromagnetic field.
[0734] Materials used in the temperature limited heater may be selected to provide a desired turndown ratio. Turndown ratios of at least 1.1:1, 2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperature limited heaters. Larger turndown ratios may also be used. A selected turndown ratio may depend on a number of factors including, but not limited to, the type of formation in which the temperature limited heater is located (for example, a higher turndown ratio may be used for an oil shale formation with large variations in thermal conductivity between rich and lean oil shale layers) and/or a temperature limit of materials used in the wellbore (for example, temperature limits of heater materials). In some embodiments, the turndown ratio is increased by coupling additional copper or another good electrical conductor to the ferromagnetic material (for example, adding copper to lower the resistance above the Curie temperature and/or the phase transformation temperature range).
[0735] The temperature limited heater may provide a maximum heat output (power output) below the Curie temperature and/or the phase transformation temperature range of the heater. In certain embodiments, the maximum heat output is at least 400 W/m (Watts per meter), 600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m. The temperature limited heater reduces the amount of heat output by a section of the heater when the temperature of the section of the heater approaches or is above the Curie temperature and/or the phase transformation temperature range. The reduced amount of heat may be substantially less than the heat output below the Curie temperature and/or the phase transformation temperature range. In some embodiments, the reduced amount of heat is at most 400 W/m, 200 W/m, 100 W/m or may approach 0 W/m.

[0736] In certain embodiments, the temperature limited heater operates substantially independently of the thermal load on the heater in a certain operating temperature range.
"Thermal load" is the rate that heat is transferred from a heating system to its surroundings. It is to be understood that the thermal load may vary with temperature of the surroundings and/or the thermal conductivity of the surroundings. In an embodiment, the temperature limited heater operates at or above the Curie temperature and/or the phase transformation temperature range of the temperature limited heater such that the operating temperature of the heater increases at most by 3 C, 2 C, 1.5 C, 1 C, or 0.5 C for a decrease in thermal load of 1 W/m proximate to a portion of the heater. In certain embodiments, the temperature limited heater operates in such a manner at a relatively constant current.
[0737] The AC or modulated DC resistance and/or the heat output of the temperature limited heater may decrease as the temperature approaches the Curie temperature and/or the phase transformation temperature range and decrease sharply near or above the Curie temperature due to the Curie effect and/or phase transformation effect. In certain embodiments, the value of the electrical resistance or heat output above or near the Curie temperature and/or the phase transformation temperature range is at most one-half of the value of electrical resistance or heat output at a certain point below the Curie temperature and/or the phase transformation temperature range. In some embodiments, the heat output above or near the Curie temperature and/or the phase transformation temperature range is at most 90%, 70%, 50%, 30%, 20%, 10%, or less (down to 1%) of the heat output at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30 C below the Curie temperature, 40 C
below the Curie temperature, 50 C below the Curie temperature, or 100 C
below the Curie temperature). In certain embodiments, the electrical resistance above or near the Curie temperature and/or the phase transformation temperature range decreases to 80%, 70%, 60%, 50%, or less (down to 1%) of the electrical resistance at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30 C below the Curie temperature, 40 C below the Curie temperature, 50 C below the Curie temperature, or 100 C below the Curie temperature).
[0738] In some embodiments, AC frequency is adjusted to change the skin depth of the ferromagnetic material. For example, the skin depth of 1% carbon steel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and 0.046 cm at 440 Hz. Since heater diameter is typically larger than twice the skin depth, using a higher frequency (and thus a heater with a smaller diameter) reduces heater costs. For a fixed geometry, the higher frequency results in a higher turndown ratio. The turndown ratio at a higher frequency is calculated by multiplying the turndown ratio at a lower frequency by the square root of the higher frequency divided by the lower frequency. In some embodiments, a frequency between 100 Hz and 1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used (for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, high frequencies may be used. The frequencies may be greater than 1000 Hz.
[0739] To maintain a substantially constant skin depth until the Curie temperature and/or the phase transformation temperature range of the temperature limited heater is reached, the heater may be operated at a lower frequency when the heater is cold and operated at a higher frequency when the heater is hot. Line frequency heating is generally favorable, however, because there is less need for expensive components such as power supplies, transformers, or current modulators that alter frequency. Line frequency is the frequency of a general supply of current. Line frequency is typically 60 Hz, but may be 50 Hz or another frequency depending on the source for the supply of the current. Higher frequencies may be produced using commercially available equipment such as solid state variable frequency power supplies. Transformers that convert three-phase power to single-phase power with three times the frequency are commercially available. For example, high voltage three-phase power at 60 Hz may be transformed to single-phase power at 180 Hz and at a lower voltage. Such transformers are less expensive and more energy efficient than solid state variable frequency power supplies. In certain embodiments, transformers that convert three-phase power to single-phase power are used to increase the frequency of power supplied to the temperature limited heater.
[0740] In certain embodiments, modulated DC (for example, chopped DC, waveform modulated DC, or cycled DC) may be used for providing electrical power to the temperature limited heater.
A DC modulator or DC chopper may be coupled to a DC power supply to provide an output of modulated direct current. In some embodiments, the DC power supply may include means for modulating DC. One example of a DC modulator is a DC-to-DC converter system.
DC-to-DC
converter systems are generally known in the art. DC is typically modulated or chopped into a desired waveform. Waveforms for DC modulation include, but are not limited to, square-wave, sinusoidal, deformed sinusoidal, deformed square-wave, triangular, and other regular or irregular waveforms.
[0741] The modulated DC waveform generally defines the frequency of the modulated DC.
Thus, the modulated DC waveform may be selected to provide a desired modulated DC
frequency. The shape and/or the rate of modulation (such as the rate of chopping) of the modulated DC waveform may be varied to vary the modulated DC frequency. DC may be modulated at frequencies that are higher than generally available AC
frequencies. For example, modulated DC may be provided at frequencies of at least 1000 Hz. Increasing the frequency of supplied current to higher values advantageously increases the turndown ratio of the temperature limited heater.
107421 In certain embodiments, the modulated DC waveform is adjusted or altered to vary the modulated DC frequency. The DC modulator may be able to adjust or alter the modulated DC
waveform at any time during use of the temperature limited heater and at high currents or voltages. Thus, modulated DC provided to the temperature limited heater is not limited to a single frequency or even a small set of frequency values. Waveform selection using the DC
modulator typically allows for a wide range of modulated DC frequencies and for discrete control of the modulated DC frequency. Thus, the modulated DC frequency is more easily set at a distinct value whereas AC frequency is generally limited to multiples of the line frequency.
Discrete control of the modulated DC frequency allows for more selective control over the turndown ratio of the temperature limited heater. Being able to selectively control the turndown ratio of the temperature limited heater allows for a broader range of materials to be used in designing and constructing the temperature limited heater.
[0743] In some embodiments, the modulated DC frequency or the AC frequency is adjusted to compensate for changes in properties (for example, subsurface conditions such as temperature or pressure) of the temperature limited heater during use. The modulated DC
frequency or the AC
frequency provided to the temperature limited heater is varied based on assessed downhole conditions. For example, as the temperature of the temperature limited heater in the wellbore increases, it may be advantageous to increase the frequency of the current provided to the heater, thus increasing the turndown ratio of the heater. In an embodiment, the downhole temperature of the temperature limited heater in the wellbore is assessed.
[0744] In certain embodiments, the modulated DC frequency, or the AC
frequency, is varied to adjust the turndown ratio of the temperature limited heater. The turndown ratio may be adjusted to compensate for hot spots occurring along a length of the temperature limited heater. For example, the turndown ratio is increased because the temperature limited heater is getting too hot in certain locations. In some embodiments, the modulated DC frequency, or the AC
frequency, are varied to adjust a turndown ratio without assessing a subsurface condition.
[0745] At or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic material, a relatively small change in voltage may cause a relatively large change in current to the load. The relatively small change in voltage may produce problems in the power supplied to the temperature limited heater, especially at or near the Curie temperature and/or the phase transformation temperature range. The problems include, but are not limited to, reducing the power factor, tripping a circuit breaker, and/or blowing a fuse.
In some cases, voltage changes may be caused by a change in the load of the temperature limited heater. In certain embodiments, an electrical current supply (for example, a supply of modulated DC or AC) provides a relatively constant amount of current that does not substantially vary with changes in load of the temperature limited heater. In an embodiment, the electrical current supply provides an amount of electrical current that remains within 15%, within 10%, within 5%, or within 2% of a selected constant current value when a load of the temperature limited heater changes.
[0746] Temperature limited heaters may generate an inductive load. The inductive load is due to some applied electrical current being used by the ferromagnetic material to generate a magnetic field in addition to generating a resistive heat output. As downhole temperature changes in the temperature limited heater, the inductive load of the heater changes due to changes in the ferromagnetic properties of ferromagnetic materials in the heater with temperature. The inductive load of the temperature limited heater may cause a phase shift between the current and the voltage applied to the heater.
[0747] A reduction in actual power applied to the temperature limited heater may be caused by a time lag in the current waveform (for example, the current has a phase shift relative to the voltage due to an inductive load) and/or by distortions in the current waveform (for example, distortions in the current waveform caused by introduced harmonics due to a non-linear load).
Thus, it may take more current to apply a selected amount of power due to phase shifting or waveform distortion. The ratio of actual power applied and the apparent power that would have been transmitted if the same current were in phase and undistorted is the power factor. The power factor is always less than or equal to 1. The power factor is I when there is no phase shift or distortion in the waveform.
[0748] Actual power applied to a heater due to a phase shift may be described by EQN. 4:
(EQN. 4) P = I x V x cos(0);
in which P is the actual power applied to a heater; I is the applied current;
V is the applied voltage; and 0 is the phase angle difference between voltage and current.
Other phenomena such as waveform distortion may contribute to further lowering of the power factor.
If there is no distortion in the waveform, then cos(0) is equal to the power factor.
[0749] In certain embodiments, the temperature limited heater includes an inner conductor inside an outer conductor. The inner conductor and the outer conductor are radially disposed about a central axis. The inner and outer conductors may be separated by an insulation layer. In certain embodiments, the inner and outer conductors are coupled at the bottom of the temperature limited heater. Electrical current may flow into the temperature limited heater through the inner conductor and return through the outer conductor. One or both conductors may include ferromagnetic material.
[0750] The insulation layer may comprise an electrically insulating ceramic with high thermal conductivity, such as magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. The insulating layer may be a compacted powder (for example, compacted ceramic powder). Compaction may improve thermal conductivity and provide better insulation resistance. For lower temperature applications, polymer insulation made from, for example, fluoropolymers, polyimides, polyamides, and/or polyethylenes, may be used. In some embodiments, the polymer insulation is made of perfluoroalkoxy (PFA) or polyetheretherketone (PEEKTM (Victrex Ltd, England)).
The insulating layer may be chosen to be substantially infrared transparent to aid heat transfer from the inner conductor to the outer conductor. In an embodiment, the insulating layer is transparent quartz sand. The insulation layer may be air or a non-reactive gas such as helium, nitrogen, or sulfur hexafluoride. If the insulation layer is air or a non-reactive gas, there may be insulating spacers designed to inhibit electrical contact between the inner conductor and the outer conductor. The insulating spacers may be made of, for example, high purity aluminum oxide or another thermally conducting, electrically insulating material such as silicon nitride. The insulating spacers may be a fibrous ceramic material such as NextelTM 312 (3M
Corporation, St.
Paul, Minnesota, U.S.A.), mica tape, or glass fiber. Ceramic material may be made of alumina, alumina-silicate, alumina-borosilicate, silicon nitride, boron nitride, or other materials.
[07511 The insulation layer may be flexible and/or substantially deformation tolerant. For example, if the insulation layer is a solid or compacted material that substantially fills the space between the inner and outer conductors, the temperature limited heater may be flexible and/or substantially deformation tolerant. Forces on the outer conductor can be transmitted through the insulation layer to the solid inner conductor, which may resist crushing. Such a temperature limited heater may be bent, dog-legged, and spiraled without causing the outer conductor and the inner conductor to electrically short to each other. Deformation tolerance may be important if the wellbore is likely to undergo substantial deformation during heating of the formation.
107521 In certain embodiments, an outermost layer of the temperature limited heater (for example, the outer conductor) is chosen for corrosion resistance, yield strength, and/or creep resistance. In one embodiment, austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H, 347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainless steels, or combinations thereof may be used in the outer conductor. The outermost layer may also include a clad conductor. For example, a corrosion resistant alloy such as 800H or 347H
stainless steel may be clad for corrosion protection over a ferromagnetic carbon steel tubular. If high temperature strength is not required, the outermost layer may be constructed from ferromagnetic metal with good corrosion resistance such as one of the ferritic stainless steels. In one embodiment, a ferritic alloy of 82.3% by weight iron with 17.7% by weight chromium (Curie temperature of 678 C) provides desired corrosion resistance.
[0753] The Metals Handbook, vol. 8, page 291 (American Society of Materials (ASM)) includes a graph of Curie temperature of iron-chromium alloys versus the amount of chromium in the alloys. In some temperature limited heater embodiments, a separate support rod or tubular (made from 347H stainless steel) is coupled to the temperature limited heater made from an iron-chromium alloy to provide yield strength and/or creep resistance. In certain embodiments, the support material and/or the ferromagnetic material is selected to provide a 100,000 hour creep-rupture strength of at least 20.7 MPa at 650 C. In some embodiments, the 100,000 hour creep-rupture strength is at least 13.8 MPa at 650 C or at least 6.9 MPa at 650 C. For example, 347H steel has a favorable creep-rupture strength at or above 650 C.
In some embodiments, the 100,000 hour creep-rupture strength ranges from 6.9 MPa to 41.3 MPa or more for longer heaters and/or higher earth or fluid stresses.
107541 In temperature limited heater embodiments with both an inner ferromagnetic conductor and an outer ferromagnetic conductor, the skin effect current path occurs on the outside of the inner conductor and on the inside of the outer conductor. Thus, the outside of the outer conductor may be clad with the corrosion resistant alloy, such as stainless steel, without affecting the skin effect current path on the inside of the outer conductor.
[0755] A ferromagnetic conductor with a thickness of at least the skin depth at the Curie temperature and/or the phase transformation temperature range allows a substantial decrease in resistance of the ferromagnetic material as the skin depth increases sharply near the Curie temperature and/or the phase transformation temperature range. In certain embodiments when the ferromagnetic conductor is not clad with a highly conducting material such as copper, the thickness of the conductor may be 1.5 times the skin depth near the Curie temperature and/or the phase transformation temperature range, 3 times the skin depth near the Curie temperature and/or the phase transformation temperature range, or even 10 or more times the skin depth near the Curie temperature and/or the phase transformation temperature range. If the ferromagnetic conductor is clad with copper, thickness of the ferromagnetic conductor may be substantially the same as the skin depth near the Curie temperature and/or the phase transformation temperature range. In some embodiments, the ferromagnetic conductor clad with copper has a thickness of at least three-fourths of the skin depth near the Curie temperature and/or the phase transformation temperature range.
[0756] In certain embodiments, the temperature limited heater includes a composite conductor with a ferromagnetic tubular and a non-ferromagnetic, high electrical conductivity core. The non-ferromagnetic, high electrical conductivity core reduces a required diameter of the conductor. For example, the conductor may be composite 1.19 cm diameter conductor with a core of 0.575 cm diameter copper clad with a 0.298 cm thickness of ferritic stainless steel or carbon steel surrounding the core. The core or non-ferromagnetic conductor may be copper or copper alloy. The core or non-ferromagnetic conductor may also be made of other metals that exhibit low electrical resistivity and relative magnetic permeabilities near 1(for example, substantially non-ferromagnetic materials such as aluminum and aluminum alloys, phosphor bronze, beryllium copper, and/or brass). A composite conductor allows the electrical resistance of the temperature limited heater to decrease more steeply near the Curie temperature and/or the phase transformation temperature range. As the skin depth increases near the Curie temperature and/or the phase transformation temperature range to include the copper core, the electrical resistance decreases very sharply.
[0757] The composite conductor may increase the conductivity of the temperature limited heater and/or allow the heater to operate at lower voltages. In an embodiment, the composite conductor exhibits a relatively flat resistance versus temperature profile at temperatures below a region near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor of the composite conductor. In some embodiments, the temperature limited heater exhibits a relatively flat resistance versus temperature profile between 100 C and 750 C or between 300 C and 600 C. The relatively flat resistance versus temperature profile may also be exhibited in other temperature ranges by adjusting, for example, materials and/or the configuration of materials in the temperature limited heater. In certain embodiments, the relative thickness of each material in the composite conductor is selected to produce a desired resistivity versus temperature profile for the temperature limited heater.
[0758] In certain embodiments, the relative thickness of each material in a composite conductor is selected to produce a desired resistivity versus temperature profile for a temperature limited heater. In an embodiment, the composite conductor is an inner conductor surrounded by 0.127 cm thick magnesium oxide powder as an insulator. The outer conductor may be 304H stainless steel with a wall thickness of 0.127 cm. The outside diameter of the heater may be about 1.65 cm.

[0759] A composite conductor (for example, a composite inner conductor or a composite outer conductor) may be manufactured by methods including, but not limited to, coextrusion, roll forming, tight fit tubing (for example, cooling the inner member and heating the outer member, then inserting the inner member in the outer member, followed by a drawing operation and/or allowing the system to cool), explosive or electromagnetic cladding, arc overlay welding, longitudinal strip welding, plasma powder welding, billet coextrusion, electroplating, drawing, sputtering, plasma deposition, coextrusion casting, magnetic forming, molten cylinder casting (of inner core material inside the outer or vice versa), insertion followed by welding or high temperature braising, shielded active gas welding (SAG), and/or insertion of an inner pipe in an outer pipe followed by mechanical expansion of the inner pipe by hydroforming or use of a pig to expand and swage the inner pipe against the outer pipe. In some embodiments, a ferromagnetic conductor is braided over a non-ferromagnetic conductor. In certain embodiments, composite conductors are formed using methods similar to those used for cladding (for example, cladding copper to steel). A metallurgical bond between copper cladding and base ferromagnetic material may be advantageous. Composite conductors produced by a coextrusion process that forms a good metallurgical bond (for example, a good bond between copper and 446 stainless steel) may be provided by Anomet Products, Inc.
(Shrewsbury, Massachusetts, U.S.A.).
[0760] FIGS. 37-58 depict various embodiments of temperature limited heaters.
One or more features of an embodiment of the temperature limited heater depicted in any of these figures may be combined with one or more features of other embodiments of temperature limited heaters depicted in these figures. In certain embodiments described herein, temperature limited heaters are dimensioned to operate at a frequency of 60 Hz AC. It is to be understood that dimensions of the temperature limited heater may be adjusted from those described herein to operate in a similar manner at other AC frequencies or with modulated DC current.
[0761] FIG. 37 depicts a cross-sectional representation of an embodiment of the temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section. FIGS. 38 and 39 depict transverse cross-sectional views of the embodiment shown in FIG. 37. In one embodiment, ferromagnetic section 486 is used to provide heat to hydrocarbon layers in the formation. Non-ferromagnetic section 488 is used in the overburden of the formation. Non-ferromagnetic section 488 provides little or no heat to the overburden, thus inhibiting heat losses in the overburden and improving heater efficiency.
Ferromagnetic section 486 includes a ferromagnetic material such as 409 stainless steel or 410 stainless steel.
Ferromagnetic section 486 has a thickness of 0.3 cm. Non-ferromagnetic section 488 is copper with a thickness of 0.3 cm. Inner conductor 490 is copper. Inner conductor 490 has a diameter of 0.9 cm. Electrical insulator 500 is silicon nitride, boron nitride, magnesium oxide powder, or another suitable insulator material. Electrical insulator 500 has a thickness of 0.1 cm to 0.3 cm.
[0762] FIG. 40 depicts a cross-sectional representation of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section placed inside a sheath. FIGS. 41, 42, and 43 depict transverse cross-sectional views of the embodiment shown in FIG. 40. Ferromagnetic section 486 is 410 stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section 488 is copper with a thickness of 0.6 cm. Inner conductor 490 is copper with a diameter of 0.9 cm. Outer conductor 502 includes ferromagnetic material. Outer conductor 502 provides some heat in the overburden section of the heater.
Providing some heat in the overburden inhibits condensation or refluxing of fluids in the overburden. Outer conductor 502 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cm and a thickness of 0.6 cm. Electrical insulator 500 includes compacted magnesium oxide powder with a thickness of 0.3 cm. In some embodiments, electrical insulator 500 includes silicon nitride, boron nitride, or hexagonal type boron nitride. Conductive section 504 may couple inner conductor 490 with ferromagnetic section 486 and/or outer conductor 502.
[0763] FIG. 44A and FIG. 44B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic inner conductor. Inner conductor 490 is a 1"
Schedule XXS 446 stainless steel pipe. In some embodiments, inner conductor 490 includes 409 stainless steel, 410 stainless steel, Invar 36, alloy 42-6, alloy 52, or other ferromagnetic materials. Inner conductor 490 has a diameter of 2.5 cm. Electrical insulator 500 includes compacted silicon nitride, boron nitride, or magnesium oxide powders; or polymers, Nextel ceramic fiber, mica, or glass fibers. Outer conductor 502 is copper or any other non-ferromagnetic material, such as but not limited to copper alloys, aluminum and/or aluminum alloys. Outer conductor 502 is coupled to jacket 506. Jacket 506 is 304H, 316H, or 347H
stainless steel. In this embodiment, a majority of the heat is produced in inner conductor 490.
[0764] FIG. 45A and FIG. 45B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic inner conductor and a non-ferromagnetic core.
Inner conductor 490 may be made of 446 stainless steel, 409 stainless steel, 410 stainless steel, carbon steel, Armco ingot iron, iron-cobalt alloys, or other ferromagnetic materials. Core 508 may be tightly bonded inside inner conductor 490. Core 508 is copper or other non-ferromagnetic material. In certain embodiments, core 508 is inserted as a tight fit inside inner conductor 490 before a drawing operation. In some embodiments, core 508 and inner conductor 490 are coextrusion bonded. Outer conductor 502 is 347H stainless steel. A
drawing or rolling operation to compact electrical insulator 500 (for example, compacted silicon nitride, boron nitride, or magnesium oxide powder) may ensure good electrical contact between inner conductor 490 and core 508. In this embodiment, heat is produced primarily in inner conductor 490 until the Curie temperature and/or the phase transformation temperature range is approached. Resistance then decreases sharply as current penetrates core 508.
[0765] FIG. 46A and FIG. 46B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic outer conductor. Inner conductor 490 is nickel-clad copper. Electrical insulator 500 is silicon nitride, boron nitride, or magnesium oxide. Outer conductor 502 is a I" Schedule XXS carbon steel pipe. In this embodiment, heat is produced primarily in outer conductor 502, resulting in a small temperature differential across electrical insulator 500.
[0766] FIG. 47A and FIG. 47B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic outer conductor that is clad with a corrosion resistant alloy. Inner conductor 490 is copper. Outer conductor 502 is a 1"
Schedule XXS
carbon steel pipe. Outer conductor 502 is coupled to jacket 506. Jacket 506 is made of corrosion resistant material (for example, 347H stainless steel). Jacket 506 provides protection from corrosive fluids in the wellbore (for example, sulfidizing and carburizing gases). Heat is produced primarily in outer conductor 502, resulting in a small temperature differential across electrical insulator 500.
[0767] FIG. 48A and FIG. 48B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic outer conductor. The outer conductor is clad with a conductive layer and a corrosion resistant alloy. Inner conductor 490 is copper.
Electrical insulator 500 is silicon nitride, boron nitride, or magnesium oxide. Outer conductor 502 is a I" Schedule 80 446 stainless steel pipe. Outer conductor 502 is coupled to jacket 506.
Jacket 506 is made from corrosion resistant material such as 347H stainless steel. In an embodiment, conductive layer 510 is placed between outer conductor 502 and jacket 506.
Conductive layer 510 is a copper layer. Heat is produced primarily in outer conductor 502, resulting in a small temperature differential across electrical insulator 500.
Conductive layer 510 allows a sharp decrease in the resistance of outer conductor 502 as the outer conductor approaches the Curie temperature and/or the phase transformation temperature range. Jacket 506 provides protection from corrosive fluids in the wellbore.
[0768] In some embodiments, the conductor (for example, an inner conductor, an outer conductor, or a ferromagnetic conductor) is the composite conductor that includes two or more different materials. In certain embodiments, the composite conductor includes two or more ferromagnetic materials. In some embodiments, the composite ferromagnetic conductor includes two or more radially disposed materials. In certain embodiments, the composite conductor includes a ferromagnetic conductor and a non-ferromagnetic conductor. In some embodiments, the composite conductor includes the ferromagnetic conductor placed over a non-ferromagnetic core. Two or more materials may be used to obtain a relatively flat electrical resistivity versus temperature profile in a temperature region below the Curie temperature, and/or the phase transformation temperature range, and/or a sharp decrease (a high turndown ratio) in the electrical resistivity at or near the Curie temperature and/or the phase transformation temperature range. In some cases, two or more materials are used to provide more than one Curie temperature and/or phase transformation temperature range for the temperature limited heater.
[0769] The composite electrical conductor may be used as the conductor in any electrical heater embodiment described herein. For example, the composite conductor may be used as the conductor in a conductor-in-conduit heater or an insulated conductor heater.
In certain embodiments, the composite conductor may be coupled to a support member such as a support conductor. The support member may be used to provide support to the composite conductor so that the composite conductor is not relied upon for strength at or near the Curie temperature and/or the phase transformation temperature range. The support member may be useful for heaters of lengths of at least 100 m. The support member may be a non-ferromagnetic member that has good high temperature creep strength. Examples of materials that are used for a support member include, but are not limited to, Haynes 625 alloy and Haynes HR120 alloy (Haynes International, Kokomo, Indiana, U.S.A.), NF709, Incoloy 800H alloy and 347HP
alloy (Allegheny Ludlum Corp., Pittsburgh, Pennsylvania, U.S.A.). In some embodiments, materials in a composite conductor are directly coupled (for example, brazed, metallurgically bonded, or swaged) to each other and/or the support member. Using a support member may reduce the need for the ferromagnetic member to provide support for the temperature limited heater, especially at or near the Curie temperature and/or the phase transformation temperature range. Thus, the temperature limited heater may be designed with more flexibility in the selection of ferromagnetic materials.
[0770] FIG. 49 depicts a cross-sectional representation of an embodiment of the composite conductor with the support member. Core 508 is surrounded by ferromagnetic conductor 512 and support member 514. In some embodiments, core 508, ferromagnetic conductor 512, and support member 514 are directly coupled (for example, brazed together or metallurgically bonded together). In one embodiment, core 508 is copper, ferromagnetic conductor 512 is 446 stainless steel, and support member 514 is 347H alloy. In certain embodiments, support member 514 is a Schedule 80 pipe. Support member 514 surrounds the composite conductor having ferromagnetic conductor 512 and core 508. Ferromagnetic conductor 512 and core 508 may be joined to form the composite conductor by, for example, a coextrusion process.
For example, the composite conductor is a 1.9 cm outside diameter 446 stainless steel ferromagnetic conductor surrounding a 0.95 cm diameter copper core.
[0771] In certain embodiments, the diameter of core 508 is adjusted relative to a constant outside diameter of ferromagnetic conductor 512 to adjust the turndown ratio of the temperature limited heater. For example, the diameter of core 508 may be increased to 1.14 cm while maintaining the outside diameter of ferromagnetic conductor 512 at 1.9 cm to increase the turndown ratio of the heater.
[0772] In some embodiments, conductors (for example, core 508 and ferromagnetic conductor 512) in the composite conductor are separated by support member 514. FIG. 50 depicts a cross-sectional representation of an embodiment of the composite conductor with support member 514 separating the conductors. In one embodiment, core 508 is copper with a diameter of 0.95 cm, support member 514 is 347H alloy with an outside diameter of 1.9 cm, and ferromagnetic conductor 512 is 446 stainless steel with an outside diameter of 2.7 cm. The support member depicted in FIG. 50 has a lower creep strength relative to the support members depicted in FIG.
49.
[0773] In certain embodiments, support member 514 is located inside the composite conductor.
FIG. 51 depicts a cross-sectional representation of an embodiment of the composite conductor surrounding support member 514. Support member 514 is made of 347H alloy.
Inner conductor 490 is copper. Ferromagnetic conductor 512 is 446 stainless steel. In one embodiment, support member 514 is 1.25 cm diameter 347H alloy, inner conductor 490 is 1.9 cm outside diameter copper, and ferromagnetic conductor 512 is 2.7 cm outside diameter 446 stainless steel. The turndown ratio is higher than the turndown ratio for the embodiments depicted in FIGS. 49, 50, and 52 for the same outside diameter, but the creep strength is lower.
[0774] In some embodiments, the thickness of inner conductor 490, which is copper, is reduced and the thickness of support member 514 is increased to increase the creep strength at the expense of reduced turndown ratio. For example, the diameter of support member 514 is increased to 1.6 cm while maintaining the outside diameter of inner conductor 490 at 1.9 cm to reduce the thickness of the conduit. This reduction in thickness of inner conductor 490 results in a decreased turndown ratio relative to the thicker inner conductor embodiment but an increased creep strength.

[0775] In one embodiment, support member 514 is a conduit (or pipe) inside inner conductor 490 and ferromagnetic conductor 512. FIG. 52 depicts a cross-sectional representation of an embodiment of the composite conductor surrounding support member 514. In one embodiment, support member 514 is 347H alloy with a 0.63 cm diameter center hole. In some embodiments, support member 514 is a preformed conduit. In certain embodiments, support member 514 is formed by having a dissolvable material (for example, copper dissolvable by nitric acid) located inside the support member during formation of the composite conductor. The dissolvable material is dissolved to form the hole after the conductor is assembled. In an embodiment, support member 514 is 347H alloy with an inside diameter of 0.63 cm and an outside diameter of 1.6 cm, inner conductor 490 is copper with an outside diameter of 1.8 cm, and ferromagnetic conductor 512 is 446 stainless steel with an outside diameter of 2.7 cm.
[07761 In certain embodiments, the composite electrical conductor is used as the conductor in the conductor-in-conduit heater. For example, the composite electrical conductor may be used as conductor 516 in FIG. 53.
[0777] FIG. 53 depicts a cross-sectional representation of an embodiment of the conductor-in-conduit heater. Conductor 516 is disposed in conduit 518. Conductor 516 is a rod or conduit of electrically conductive material. Low resistance sections 520 are present at both ends of conductor 516 to generate less heating in these sections. Low resistance section 520 is formed by having a greater cross-sectional area of conductor 516 in that section, or the sections are made of material having less resistance. In certain embodiments, low resistance section 520 includes a low resistance conductor coupled to conductor 516.
[0778] Conduit 518 is made of an electrically conductive material. Conduit 518 is disposed in opening 522 in hydrocarbon layer 460. Opening 522 has a diameter that accommodates conduit 518.
[0779] Conductor 516 may be centered in conduit 518 by centralizers 524.
Centralizers 524 electrically isolate conductor 516 from conduit 518. Centralizers 524 inhibit movement and properly locate conductor 516 in conduit 518. Centralizers 524 are made of ceramic material or a combination of ceramic and metallic materials. Centralizers 524 inhibit deformation of conductor 516 in conduit 518. Centralizers 524 are touching or spaced at intervals between approximately 0.1 m (meters) and approximately 3 m or more along conductor 516.
[0780] A second low resistance section 520 of conductor 516 may couple conductor 516 to wellhead 450, as depicted in FIG. 53. Electrical current may be applied to conductor 516 from power cable 526 through low resistance section 520 of conductor 516.
Electrical current passes from conductor 516 through sliding connector 528 to conduit 518. Conduit 518 may be electrically insulated from overburden casing 530 and from wellhead 450 to return electrical current to power cable 526. Heat may be generated in conductor 516 and conduit 518. The generated heat may radiate in conduit 518 and opening 522 to heat at least a portion of hydrocarbon layer 460.
[0781] Overburden casing 530 may be disposed in overburden 458. Overburden casing 530 is, in some embodiments, surrounded by materials (for example, reinforcing material and/or cement) that inhibit heating of overburden 458. Low resistance section 520 of conductor 516 may be placed in overburden casing 530. Low resistance section 520 of conductor 516 is made of, for example, carbon steel. Low resistance section 520 of conductor 516 may be centralized in overburden casing 530 using centralizers 524. Centralizers 524 are spaced at intervals of approximately 6 m to approximately 12 m or, for example, approximately 9 m along low resistance section 520 of conductor 516. In a heater embodiment, low resistance section 520 of conductor 516 is coupled to conductor 516 by one or more welds. In other heater embodiments, low resistance sections are threaded, threaded and welded, or otherwise coupled to the conductor. Low resistance section 520 generates little or no heat in overburden casing 530.
Packing 532 may be placed between overburden casing 530 and opening 522.
Packing 532 may be used as a cap at the junction of overburden 458 and hydrocarbon layer 460 to allow filling of materials in the annulus between overburden casing 530 and opening 522. In some embodiments, packing 532 inhibits fluid from flowing from opening 522 to surface 534.
[0782] FIG. 54 depicts a cross-sectional representation of an embodiment of a removable conductor-in-conduit heat source. Conduit 518 may be placed in opening 522 through overburden 458 such that a gap remains between the conduit and overburden casing 530. Fluids may be removed from opening 522 through the gap between conduit 518 and overburden casing 530. Fluids may be removed from the gap through conduit 536. Conduit 518 and components of the heat source included in the conduit that are coupled to wellhead 450 may be removed from opening 522 as a single unit. The heat source may be removed as a single unit to be repaired, replaced, and/or used in another portion of the formation.
[0783] For a temperature limited heater in which the ferromagnetic conductor provides a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range, a majority of the current flows through material with highly non-linear functions of magnetic field (H) versus magnetic induction (B).
These non-linear functions may cause strong inductive effects and distortion that lead to decreased power factor in the temperature limited heater at temperatures below the Curie temperature and/or the phase transformation temperature range. These effects may render the electrical power supply to the temperature limited heater difficult to control and may result in additional current flow through surface and/or overburden power supply conductors. Expensive and/or difficult to implement control systems such as variable capacitors or modulated power supplies may be used to compensate for these effects and to control temperature limited heaters where the majority of the resistive heat output is provided by current flow through the ferromagnetic material.
[0784] In certain temperature limited heater embodiments, the ferromagnetic conductor confines a majority of the flow of electrical current to an electrical conductor coupled to the ferromagnetic conductor when the temperature limited heater is below or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
The electrical conductor may be a sheath, jacket, support member, corrosion resistant member, or other electrically resistive member. In some embodiments, the ferromagnetic conductor confines a majority of the flow of electrical current to the electrical conductor positioned between an outermost layer and the ferromagnetic conductor. The ferromagnetic conductor is located in the cross section of the temperature limited heater such that the magnetic properties of the ferromagnetic conductor at or below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor confine the majority of the flow of electrical current to the electrical conductor. The majority of the flow of electrical current is confined to the electrical conductor due to the skin effect of the ferromagnetic conductor. Thus, the majority of the current is flowing through material with substantially linear resistive properties throughout most of the operating range of the heater.
[0785] In certain embodiments, the ferromagnetic conductor and the electrical conductor are located in the cross section of the temperature limited heater so that the skin effect of the ferromagnetic material limits the penetration depth of electrical current in the electrical conductor and the ferromagnetic conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
Thus, the electrical conductor provides a majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. In certain embodiments, the dimensions of the electrical conductor may be chosen to provide desired heat output characteristics.
[0786] Because the majority of the current flows through the electrical conductor below the Curie temperature and/or the phase transformation temperature range, the temperature limited heater has a resistance versus temperature profile that at least partially reflects the resistance versus temperature profile of the material in the electrical conductor. Thus, the resistance versus temperature profile of the temperature limited heater is substantially linear below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor if the material in the electrical conductor has a substantially linear resistance versus temperature profile. For example, the temperature limited heater in which the majority of the current flows in the electrical conductor below the Curie temperature and/or the phase transformation temperature range may have a resistance versus temperature profile similar to the profile shown in FIG. 260. The resistance of the temperature limited heater has little or no dependence on the current flowing through the heater until the temperature nears the Curie temperature and/or the phase transformation temperature range. The majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range.
[0787] Resistance versus temperature profiles for temperature limited heaters in which the majority of the current flows in the electrical conductor also tend to exhibit sharper reductions in resistance near or at the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. For example, the reduction in resistance shown in FIG. 260 is sharper than the reduction in resistance shown in FIG. 246. The sharper reductions in resistance near or at the Curie temperature and/or the phase transformation temperature range are easier to control than more gradual resistance reductions near the Curie temperature and/or the phase transformation temperature range because little current is flowing through the ferromagnetic material.
[0788] In certain embodiments, the material and/or the dimensions of the material in the electrical conductor are selected so that the temperature limited heater has a desired resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
[0789] Temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range are easier to predict and/or control.
Behavior of temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range may be predicted by, for example, its resistance versus temperature profile and/or its power factor versus temperature profile. Resistance versus temperature profiles and/or power factor versus temperature profiles may be assessed or predicted by, for example, experimental measurements that assess the behavior of the temperature limited heater, analytical equations that assess or predict the behavior of the temperature limited heater, and/or simulations that assess or predict the behavior of the temperature limited heater.
[0790] In certain embodiments, assessed or predicted behavior of the temperature limited heater is used to control the temperature limited heater. The temperature limited heater may be controlled based on measurements (assessments) of the resistance and/or the power factor during operation of the heater. In some embodiments, the power, or current, supplied to the temperature limited heater is controlled based on assessment of the resistance and/or the power factor of the heater during operation of the heater and the comparison of this assessment versus the predicted behavior of the heater. In certain embodiments, the temperature limited heater is controlled without measurement of the temperature of the heater or a temperature near the heater. Controlling the temperature limited heater without temperature measurement eliminates operating costs associated with downhole temperature measurement. Controlling the temperature limited heater based on assessment of the resistance and/or the power factor of the heater also reduces the time for making adjustments in the power or current supplied to the heater compared to controlling the heater based on measured temperature.
[0791] As the temperature of the temperature limited heater approaches or exceeds the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor, reduction in the ferromagnetic properties of the ferromagnetic conductor allows electrical current to flow through a greater portion of the electrically conducting cross section of the temperature limited heater. Thus, the electrical resistance of the temperature limited heater is reduced and the temperature limited heater automatically provides reduced heat output at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. In certain embodiments, a highly electrically conductive member is coupled to the ferromagnetic conductor and the electrical conductor to reduce the electrical resistance of the temperature limited heater at or above the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The highly electrically conductive member may be an inner conductor, a core, or another conductive member of copper, aluminum, nickel, or alloys thereof.
[0792] The ferromagnetic conductor that confines the majority of the flow of electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range may have a relatively small cross section compared to the ferromagnetic conductor in temperature limited heaters that use the ferromagnetic conductor to provide the majority of resistive heat output up to or near the Curie temperature and/or the phase transformation temperature range. A temperature limited heater that uses the electrical conductor to provide a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range has low magnetic inductance at temperatures below the Curie temperature and/or the phase transformation temperature range because less current is flowing through the ferromagnetic conductor as compared to the temperature limited heater where the majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range is provided by the ferromagnetic material.
Magnetic field (H) at radius (r) of the ferromagnetic conductor is proportional to the current (I) flowing through the ferromagnetic conductor and the core divided by the radius, or:
(EQN. 5) H oc I/r.

Since only a portion of the current flows through the ferromagnetic conductor for a temperature limited heater that uses the outer conductor to provide a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range, the magnetic field of the temperature limited heater may be significantly smaller than the magnetic field of the temperature limited heater where the majority of the current flows through the ferromagnetic material. The relative magnetic permeability ( ) may be large for small magnetic fields.
[07931 The skin depth (S) of the ferromagnetic conductor is inversely proportional to the square root of the relative magnetic permeability ( ):
(EQN. 6) S a (1/ )'.
Increasing the relative magnetic permeability decreases the skin depth of the ferromagnetic conductor. However, because only a portion of the current flows through the ferromagnetic conductor for temperatures below the Curie temperature and/or the phase transformation temperature range, the radius (or thickness) of the ferromagnetic conductor may be decreased for ferromagnetic materials with large relative magnetic permeabilities to compensate for the decreased skin depth while still allowing the skin effect to limit the penetration depth of the electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. The radius (thickness) of the ferromagnetic conductor may be between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm depending on the relative magnetic permeability of the ferromagnetic conductor. Decreasing the thickness of the ferromagnetic conductor decreases costs of manufacturing the temperature limited heater, as the cost of ferromagnetic material tends to be a significant portion of the cost of the temperature limited heater. Increasing the relative magnetic permeability of the ferromagnetic conductor provides a higher turndown ratio and a sharper decrease in electrical resistance for the temperature limited heater at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.

[0794] Ferromagnetic materials (such as purified iron or iron-cobalt alloys) with high relative magnetic permeabilities (for example, at least 200, at least 1000, at least I
x 104, or at least I X
105) and/or high Curie temperatures (for example, at least 600 C, at least 700 C, or at least 800 C) tend to have less corrosion resistance and/or less mechanical strength at high temperatures.
The electrical conductor may provide corrosion resistance and/or high mechanical strength at high temperatures for the temperature limited heater. Thus, the ferromagnetic conductor may be chosen primarily for its ferromagnetic properties.
[0795] Confining the majority of the flow of electrical current to the electrical conductor below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor reduces variations in the power factor. Because only a portion of the electrical current flows through the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range, the non-linear ferromagnetic properties of the ferromagnetic conductor have little or no effect on the power factor of the temperature limited heater, except at or near the Curie temperature and/or the phase transformation temperature range. Even at or near the Curie temperature and/or the phase transformation temperature range, the effect on the power factor is reduced compared to temperature limited heaters in which the ferromagnetic conductor provides a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range. Thus, there is less or no need for external compensation (for example, variable capacitors or waveform modification) to adjust for changes in the inductive load of the temperature limited heater to maintain a relatively high power factor.
[0796] In certain embodiments, the temperature limited heater, which confines the majority of the flow of electrical current to the electrical conductor below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor, maintains the power factor above 0.85, above 0.9, or above 0.95 during use of the heater. Any reduction in the power factor occurs only in sections of the temperature limited heater at temperatures near the Curie temperature and/or the phase transformation temperature range. Most sections of the temperature limited heater are typically not at or near the Curie temperature and/or the phase transformation temperature range during use. These sections have a high power factor that approaches 1 The power factor for the entire temperature limited heater is maintained above 0.85, above 0.9, or above 0.95 during use of the heater even if some sections of the heater have power factors below 0.85.

[0797] Maintaining high power factors allows for less expensive power supplies and/or control devices such as solid state power supplies or SCRs (silicon controlled rectifiers). These devices may fail to operate properly if the power factor varies by too large an amount because of inductive loads. With the power factors maintained at high values; however, these devices may be used to provide power to the temperature limited heater. Solid state power supplies have the advantage of allowing fine tuning and controlled adjustment of the power supplied to the temperature limited heater.
[0798] In some embodiments, transformers are used to provide power to the temperature limited heater. Multiple voltage taps may be made into the transformer to provide power to the temperature limited heater. Multiple voltage taps allows the current supplied to switch back and forth between the multiple voltages. This maintains the current within a range bound by the multiple voltage taps.
[0799] The highly electrically conductive member, or inner conductor, increases the turndown ratio of the temperature limited heater. In certain embodiments, thickness of the highly electrically conductive member is increased to increase the turndown ratio of the temperature limited heater. In some embodiments, the thickness of the electrical conductor is reduced to increase the turndown ratio of the temperature limited heater. In certain embodiments, the turndown ratio of the temperature limited heater is between 1.1 and 10, between 2 and 8, or between 3 and 6 (for example, the turndown ratio is at least 1.1, at least 2, or at least 3).
[0800] FIG. 55 depicts an embodiment of a temperature limited heater in which the support member provides a majority of the heat output below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. Core 508 is an inner.
conductor of the temperature limited heater. In certain embodiments, core 508 is a highly electrically conductive material.such as copper or aluminum. In some embodiments, core 508 is a copper alloy that provides mechanical strength and good electrically conductivity such as a dispersion strengthened copper. In one embodiment, core 508 is Glidcop (SCM
Metal Products, Inc., Research Triangle Park, North Carolina, U.S.A.). Ferromagnetic conductor 512 is a thin layer of ferromagnetic material between electrical conductor 538 and core 508. In certain embodiments, electrical conductor 538 is also support member 514. In certain embodiments, ferromagnetic conductor 512 is iron or an iron alloy. In some embodiments, ferromagnetic conductor 512 includes ferromagnetic material with a high relative magnetic permeability. For example, ferromagnetic conductor 512 may be purified iron such as Armco ingot iron (AK Steel Ltd., United Kingdom). Iron with some impurities typically has a relative magnetic permeability on the order of 400. Purifying the iron by annealing the iron in hydrogen gas (HZ) at 1450 C increases the relative magnetic permeability of the iron.
Increasing the relative magnetic permeability of ferromagnetic conductor 512 allows the thickness of the ferromagnetic conductor to be reduced. For example, the thickness of unpurified iron may be approximately 4.5 mm while the thickness of the purified iron is approximately 0.76 mm.
[0801] In certain embodiments, electrical conductor 538 provides support for ferromagnetic conductor 512 and the temperature limited heater. Electrical conductor 538 may be made of a material that provides good mechanical strength at temperatures near or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512.
In certain embodiments, electrical conductor 538 is a corrosion resistant member. Electrical conductor 538 (support member 514) may provide support for ferromagnetic conductor 512 and corrosion resistance. Electrical conductor 538 is made from a material that provides desired electrically resistive heat output at temperatures up to and/or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512.
[0802] In an embodiment, electrical conductor 538 is 347H stainless steel. In some embodiments, electrical conductor 538 is another electrically conductive, good mechanical strength, corrosion resistant material. For example, electrical conductor 538 may be 304H, 316F1, 347HH, NF709, Incoloy 800H alloy (Inco Alloys International, Huntington, West Virginia, U.S.A.), Haynes HR120 alloy, or Inconel 617 alloy.
[0803] In some embodiments, electrical conductor 538 (support member 514) includes different alloys in different portions of the temperature limited heater. For example, a lower portion of electrical conductor 538 (support member 514) is 347H stainless steel and an upper portion of the electrical conductor (support member) is NF709. In certain embodiments, different alloys are used in different portions of the electrical conductor (support member) to increase the mechanical strength of the electrical conductor (support member) while maintaining desired heating properties for the temperature limited heater.
[0804] In some embodiments, ferromagnetic conductor 512 includes different ferromagnetic conductors in different portions of the temperature limited heater. Different ferromagnetic conductors may be used in different portions of the temperature limited heater to vary the Curie temperature and/or the phase transformation temperature range and, thus, the maximum operating temperature in the different portions. In some embodiments, the Curie temperature and/or the phase transformation temperature range in an upper portion of the temperature limited heater is lower than the Curie temperature and/or the phase transformation temperature range in a lower portion of the heater. The lower Curie,temperature and/or the phase transformation temperature range in the upper portion increases the creep-rupture strength lifetime in the upper portion of the heater.
[0805] In the embodiment depicted in FIG. 55, ferromagnetic conductor 512, electrical conductor 538, and core 508 are dimensioned so that the skin depth of the ferromagnetic conductor limits the penetration depth of the majority of the flow of electrical current to the support member when the temperature is below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. Thus, electrical conductor 538 provides a majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. In certain embodiments, the temperature limited heater depicted in FIG. 55 is smaller (for example, an outside diameter of 3 cm, 2.9 cm, 2.5 cm, or less) than other temperature limited heaters that do not use electrical conductor 538 to provide the majority of electrically resistive heat output.
The temperature limited heater depicted in FIG. 55 may be smaller because ferromagnetic conductor 512 is thin as compared to the size of the ferromagnetic conductor needed for a temperature limited heater in which the majority of the resistive heat output is provided by the ferromagnetic conductor.
[0806] In some embodiments, the support member and the corrosion resistant member are different members in the temperature limited heater. FIGS. 56 and 57 depict embodiments of temperature limited heaters in which the jacket provides a majority of the heat output below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. In these embodiments, electrical conductor 538 is jacket 506.
Electrical conductor 538, ferromagnetic conductor 512, support member 514, and core 508 (in FIG.
56) or inner conductor 490 (in FIG. 57) are dimensioned so that the skin depth of the ferromagnetic conductor limits the penetration depth of the majority of the flow of electrical current to the thickness of the jacket. In certain embodiments, electrical conductor 538 is a material that is corrosion resistant and provides electrically resistive heat output below the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. For example, electrical conductor 538 is 825 stainless steel or 347H stainless steel. In some embodiments, electrical conductor 538 has a small thickness (for example, on the order of 0.5 mm).
108071 In FIG. 56, core 508 is highly electrically conductive material such as copper or aluminum. Support member 514 is 347H stainless steel or another material with good mechanical strength at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512.

[0808] In FIG. 57, support member 514 is the core of the temperature limited heater and is 347H
stainless steel or another material with good mechanical strength at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 5 12.
Inner conductor 490 is highly electrically conductive material such as copper or aluminum.
[0809] In certain embodiments, the materials and design of the temperature limited heater are chosen to allow use of the heater at high temperatures (for example, above 850 C). FIG. 58 depicts a high temperature embodiment of the temperature limited heater. The heater depicted in FIG. 58 operates as a conductor-in-conduit heater with the majority of heat being generated in conduit 518. The conductor-in-conduit heater may provide a higher heat output because the majority of heat is generated in conduit 518 rather than conductor 516. Having the heat generated in conduit 518 reduces heat losses associated with transferring heat between the conduit and conductor 516.
[0810] Core 508 and conductive layer 510 are copper. In some embodiments, core 508 and conductive layer 510 are nickel if the operating temperatures is to be near or above the melting point of copper. Support members 514 are electrically conductive materials with good mechanical strength at high temperatures. Materials for support members 514 that withstand at least a maximum temperature of about 870 C may be, but are not limited to, MO-RE alloys (Duraloy Technologies, Inc. (Scottdale, Pennsylvania, U.S.A.)), CF8C+
(Metaltek Intl.
(Waukesha, Wisconsin, U.S.A.)), or Inconel 617 alloy. Materials for support members 514 that withstand at least a maximum temperature of about 980 C include, but are not limited to, Incoloy Alloy MA 956. Support member 514 in conduit 518 provides mechanical support for the conduit. Support member 514 in conductor 516 provides mechanical support for core 508.
[0811] Electrical conductor 538 is a thin corrosion resistant material. In certain embodiments, electrical conductor 538 is 347H, 617, 625, or 800H stainless steel.
Ferromagnetic conductor 512 is a high Curie temperature ferromagnetic material such as iron-cobalt alloy (for example, a 15% by weight cobalt, iron-cobalt alloy).
[0812] In certain embodiments, electrical conductor 538 provides the majority of heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512.
Conductive layer 510 increases the turndown ratio of the temperature limited heater.
[0813] For long vertical temperature limited heaters (for example, heaters at least 300 m, at least 500 m, or at least 1 km in length), the hanging stress becomes important in the selection of materials for the temperature limited heater. Without the proper selection of material, the support member may not have sufficient mechanical strength (for example, creep-rupture strength) to support the weight of the temperature limited heater at the operating temperatures of the heater. FIG. 59 depicts hanging stress (ksi (kilopounds per square inch)) versus outside diameter (in.) for the temperature Iirnited heater shown in FIG. 55 with 347H
as the support member. /The hanging stress was assessed with the support member outside a 0.5" copper core and a 0.75" outside diameter carbon steel ferromagnetic conductor. This assessment assumes the support member bears the entire load of the heater and that the heater length is 1000 ft.
(about 305 m). As shown in FIG. 59, increasing the thickness of the support member decreases the hanging stress on the support member. Decreasing the hanging stress on the support member allows the temperature limited heater to operate at higher temperatures.
[0814] In certain embodiments, materials for the support member are varied to increase the maximum allowable hanging stress at operating temperatures of the temperature limited heater and, thus, increase the maximum operating temperature of the temperature limited heater.
Altering the materials of the support member affects the heat output of the temperature limited heater below the Curie temperature and/or the phase transformation temperature range because changing the materials changes the resistance versus temperature profile of the support member.
In certain embodiments, the support member is made of more than one material along the length of the heater so that the temperature limited heater maintains desired operating properties (for example, resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range) as much as possible while providing sufficient mechanical properties to support the heater.
[0815] FIG. 60 depicts hanging stress (ksi) versus temperature ( F) for several materials and varying outside diameters for the temperature limited heaters. Curve 540 is for 347H stainless steel. Curve 542 is for Incoloy alloy 800H. Curve 544 is for Haynes HR120 alloy. Curve 546 is for NF709. Each of the curves includes four points that represent various outside diameters of the support member. The point with the highest stress for each curve corresponds to outside diameter of 1.05". The point with the second highest stress for each curve corresponds to outside diameter of 1. 15". The point with the second lowest stress for each curve corresponds to outside diameter of 1.25". The point with the lowest stress for each curve corresponds to outside diameter of 1.315". As shown in FIG. 60, increasing the strength and/or outside diameter of the material and the support member increases the maximum operating temperature of the temperature limited heater.
108161 FIGS. 61, 62, 63, and 64 depict examples of embodiments for temperature limited heaters able to provide desired heat output and mechanical strength for operating temperatures up to about 770 C for 30,000 hrs. creep-rupture lifetime. The depicted temperature limited heaters have lengths of 1000 ft, copper cores of 0.5" diameter, and iron ferromagnetic conductors with outside diameters of 0.765". In FIG. 61, the support member in heater portion 548 is 347H stainless steel. The support member in heater portion 550 is Incoloy alloy 800H.
Portion 548 has a length of 750 ft. and portion 550 has a length of 250 ft.
The outside diameter of the support member is 1.315". In FIG. 62, the support member in heater portion 548 is 347H
stainless steel. The support member in heater portion 550 is Incoloy alloy 800H. The support member in heater portion 552 is Haynes HR120 alloy. Portion 548 has a length of 650 ft., portion 550 has a length of 300 ft., and portion 552 has a length of 50 ft.
The outside diameter of the support member is 1.15". In FIG. 63, the support member in heater portion 548 is 347H
stainless steel. The support member in heater portion 550 is lncoloy alloy 800H. The support member in heater portion 552 is Haynes HR120 alloy. Portion 548 has a length of 550 ft., portion 550 has a length of 250 ft., and portion 552 has a length of 200 ft.
The outside diameter of the support member is 1.05".
[08171 In some embodiments, a transition section is used between sections of the heater. For example, if one or more portions of the heater have varying Curie temperatures and/or phase transformation temperature ranges, a transition section may be used between portions to provide strength that compensates for the differences in temperatures in the portions.
FIG. 64 depicts another example of an embodiment of a temperature limited heater able to provide desired heat output and mechanical strength. The support member in heater portion 548 is 347H stainless steel. The support member in heater portion 550 is NF709. The support member in heater portion 552 is 347H. Portion 548 has a length of 550 ft. and a Curie temperature of 843 C, portion 550 has a length of 250 ft. and a Curie temperature of 843 C, and portion 552 has a length of 180 ft. and a Curie temperature of 770 C. Transition section 554 has a length of 20 ft., a Curie temperature of 770 C, and the support member is NF709.
[0818] The materials of the support member along the length of the temperature limited heater may be varied to achieve a variety of desired operating properties. The choice of the materials of the temperature limited heater is adjusted depending on a desired use of the temperature limited heater. TABLE 2 lists examples of materials that may be used for the support member.
The table provides the hanging stresses (6) of the support members and the maximum operating temperatures of the temperature limited heaters for several different outside diameters (OD) of the support member. The core diameter and the outside diameter of the iron ferromagnetic conductor in each case are 0.5" and 0.765", respectively.

Material OD = 1.05" OD = 1.15" OD = 1.25" OD = 1.315"

a(ksi) T a(ksi) T a(ksi) T( F) a(ksi) T( F) ( F) ( F) 347H stainless 7.55 1310 6.33 1340 5.63 1360 5.31 1370 steel lncoloy alloy 7.55 1337 6.33 1378 5.63 1400 5.31 1420 Haynes HR120 7.57 1450 6.36 1492 5.65 1520 5.34 1540 alloy HA230 7.91 1475 6.69 1510 5.99 1530 5.67 1540 Haynes alloy 556 7.65 1458 6.43 1492 5.72 1512 5.41 1520 NF709 7.57 1440 6.36 1480 5.65 1502 5.34 1512 [0819] In certain embodiments, one or more portions of the temperature limited heater have varying outside diameters and/or materials to provide desired properties for the heater. FIGS. 65 and 66 depict examples of embodiments for temperature limited heaters that vary the diameter and/or materials of the support member along the length of the heaters to provide desired operating properties and sufficient mechanical properties (for example, creep-rupture strength properties) for operating temperatures up to about 834 C for 30,000 hrs., heater lengths of 850 ft, a copper core diameter of 0.5", and an iron-cobalt (6% by weight cobalt) ferromagnetic conductor outside diameter of 0.75". In FIG. 65, portion 548 is 347H stainless steel with a length of 300 ft and an outside diameter of 1.15". Portion 550 is NF709 with a length of 400 ft and an outside diameter of 1.15". Portion 552 is NF709 with a length of 150 ft and an outside diameter of 1.25". In FIG. 66, portion 548 is 347H stainless steel with a length of 300 ft and an outside diameter of 1.15". Portion 550 is 347H stainless steel with a length of 100 ft and an outside diameter of 1.20". Portion 552 is NF709 with a length of 350 ft and an outside diameter of 1.20". Portion 556 is NF709 with a length of 100 ft and an outside diameter of 1.25".
[0820] In certain embodiments, one or more portions of the temperature limited heater have varying dimensions and/or varying materials to provide different power outputs along the length of the heater. More or less power output may be provided by varying the selected temperature (for example, the Curie temperature and/or the phase transformation temperature range) of the temperature limited heater by using different ferromagnetic materials along its length and/or by varying the electrical resistance of the heater by using different dimensions in the heat generating member along the length of the heater. Different power outputs along the length of the temperature limited heater may be needed to compensate for different thermal properties in the formation adjacent to the heater. For example, an oil shale formation may have different water-filled porosities, dawsonite compositions, and/or nahcolite compositions at different depths in the formation. Portions of the formation with higher water-filled porosities, higher dawsonite compositions, and/or higher nahcolite compositions may need more power input than portions with lower water-filled porosities, lower dawsonite compositions, and/or lower nahcolite compositions to achieve a similar heating rate. Power output may be varied along the length of the heater so that the portions of the formation with different properties (such as water-filled porosities, dawsonite compositions, and/or nahcolite compositions) are heated at approximately the same heating rate.
[0821] In certain embodiments, portions of the temperature limited heater have different selected self-limiting temperatures (for example, Curie temperatures and/or phase transformation temperature ranges), materials, and/or dimensions to compensate for varying thermal properties of the formation along the length of the heater. For example, Curie temperatures, phase transformation temperature ranges, support member materials, and/or dimensions of the portions of the heaters depicted in FIGS. 61-66 may be varied to provide varying power outputs and/or operating temperatures along the length of the heater.
[0822] As one example, in an embodiment of the temperature limited heater depicted in FIG. 61, portion 550 may be used to heat portions of the formation that, on average, have higher water-filled porosities, dawsonite compositions, and/or nahcolite compositions than portions of the formation heated by portion 548. Portion 550 may provide less power output than portion 548 to compensate for the differing thermal properties of the different portions of the formation so that the entire formation is heated at an approximately constant heating rate.
Portion 550 may require less power output because, for example, portion 550 is used to heat portions of the formation with low water-filled porosities and/or little or no dawsonite. In one embodiment, portion 550 has a Curie temperature of 770 C (pure iron) and portion 548 has a Curie temperature of 843 C (iron with added cobalt). Such an embodiment may provide more power output from portion 548 so that the temperature lag between the two portions is reduced.
Adjusting the Curie temperature of portions of the heater adjusts the selected temperature at which the heater self-limits. In some embodiments, the dimensions of portion 550 are adjusted to further reduce the temperature lag so that the formation is heated at an approximately constant heating rate throughout the formation. Dimensions of the heater may be adjusted to adjust the heating rate of one or more portions of the heater. For example, the thickness of an outer conductor in portion 550 may be increased relative to the ferromagnetic member and/or the core of the heater so that the portion has a higher electrical resistance and the portion provides a higher power output below the Curie temperature of the portion.
[0823] Reducing the temperature lag between different portions of the formation may reduce the overall time needed to bring the formation to a desired temperature. Reducing the time needed to bring the formation to the desired temperature reduces heating costs and produces desirable production fluids more quickly.
[0824] Temperature limited heaters with varying Curie temperatures and/or phase transformation temperature ranges may also have varying support member materials to provide mechanical strength for the heater (for example, to compensate for hanging stress of the heater and/or provide sufficient creep-rupture strength properties). For example, in the embodiment of the temperature limited heater depicted in FIG. 64, portions 548 and 550 have a Curie temperature of 843 C. Portion 548 has a support member made of 347H stainless steel. Portion 550 has a support member made of NF709. Portion 552 has a Curie temperature of 770 C and a support member made of 347H stainless steel. Transition section 554 has a Curie temperature of 770 C and a support member made of NF709. Transition section 554 may be short in length compared to portions 548, 550, and 552. Transition section 554 may be placed between portions 550 and 552 to compensate for the temperature and material differences between the portions.
For example, transition section 554 may be used to compensate for differences in creep properties between portions 550 and 552.
[0825] Such a substantially vertical temperature limited heater may have less expensive, lower strength materials in portion 552 because of the lower Curie temperature in this portion of the heater. For example, 347H stainless steel may be used for the support member because of the lower maximum operating temperature of portion 552 as compared to portion 550.
Portion 550 may require more expensive, higher strength material because of the higher operating temperature of portion 550 due to the higher Curie temperature in this portion.
[0826] In some embodiments, a relatively thin conductive layer is used to provide the majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor. Such a temperature limited heater may be used as the heating member in an insulated conductor heater. The heating member of the insulated conductor heater may be located inside a sheath with an insulation layer between the sheath and the heating member.
[0827] FIGS. 67A and 67B depict cross-sectional representations of an embodiment of the insulated conductor heater with the temperature limited heater as the heating member. Insulated conductor 558 includes core 508, ferromagnetic conductor 512, inner conductor 490, electrical insulator 500, and jacket 506. Core 508 is a copper core. Ferromagnetic conductor 512 is, for example, iron or an iron alloy.
[0828] Inner conductor 490 is a relatively thin conductive layer of non-ferromagnetic material with a higher electrical conductivity than ferromagnetic conductor 512. In certain embodiments, inner conductor 490 is copper. Inner conductor 490 may be a copper alloy.
Copper alloys typically have a flatter resistance versus temperature profile than pure copper. A flatter resistance versus temperature profile may provide less variation in the heat output as a function of temperature up to the Curie temperature and/or the phase transformation temperature range.
In some embodiments, inner conductor 490 is copper with 6% by weight nickel (for example, CuNi6 or LOHMTM). In some embodiments, inner conductor 490 is CuNi l OFe1 Mn alloy.
Below the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512, the magnetic properties of the ferromagnetic conductor confine the majority of the flow of electrical current to inner conductor 490. Thus, inner conductor 490 provides the majority of the resistive heat output of insulated conductor 558 below the Curie temperature and/or the phase transformation temperature range.
108291 In certain embodiments, inner conductor 490 is dimensioned, along with core 508 and ferromagnetic conductor 512, so that the inner conductor provides a desired amount of heat output and a desired turndown ratio. For example, inner conductor 490 may have a cross-sectional area that is around 2 or 3 times less than the cross-sectional area of core 508.
Typically, inner conductor 490 has to have a relatively small cross-sectional area to provide a desired heat output if the inner conductor is copper or copper alloy. In an embodiment with copper inner conductor 490, core 508 has a diameter of 0.66 cm, ferromagnetic conductor 512 has an outside diameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.03 cm, electrical insulator 500 has an outside diameter of 1.53 cm, and jacket 506 has an outside diameter of 1.79 cm. In an embodiment with a CuNi6 inner conductor 490, core 508 has a diameter of 0.66 cm, ferromagnetic conductor 512 has an outside diameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.12 cm, electrical insulator 500 has an outside diameter of 1.63 cm, and jacket 506 has an outside diameter of 1.88 cm. Such insulated conductors are typically smaller and cheaper to manufacture than insulated conductors that do not use the thin inner conductor to provide the majority of heat output below the Curie temperature and/or the phase transformation temperature range.
[0830] Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 500 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 500 includes beads of silicon nitride.
[0831] In certain embodiments, a small layer of material is placed between electrical insulator 500 and inner conductor 490 to inhibit copper from migrating into the electrical insulator at higher temperatures. For example, the small layer of nickel (for example, about 0.5 mm of nickel) may be placed between electrical insulator 500 and inner conductor 490.
[0832] Jacket 506 is made of a corrosion resistant material such as, but not limited to, 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel. In some embodiments, jacket 506 provides some mechanical strength for insulated conductor 558 at or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 512. In certain embodiments, jacket 506 is not used to conduct electrical current.
[0833] In certain embodiments of temperature limited heaters, three temperature limited heaters are coupled together in a three-phase wye configuration. Coupling three temperature limited heaters together in the three-phase wye configuration lowers the current in each of the individual temperature limited heaters because the current is split between the three individual heaters.
Lowering the current in each individual temperature limited heater allows each heater to have a small diameter. The lower currents allow for higher relative magnetic permeabilities in each of the individual temperature limited heaters and, thus, higher turndown ratios.
In addition, there may be no return current needed for each of the individual temperature limited heaters. Thus, the turndown ratio remains higher for each of the individual temperature limited heaters than if each temperature limited heater had its own return current path.
[0834] In the three-phase wye configuration, individual temperature limited heaters may be coupled together by shorting the sheaths, jackets, or canisters of each of the individual temperature limited heaters to the electrically conductive sections (the conductors providing heat) at their terminating ends (for example, the ends of the heaters at the bottom of a heater wellbore). In some embodiments, the sheaths, jackets, canisters, and/or electrically conductive sections are coupled to a support member that supports the temperature limited heaters in the wellbore.
[0835] FIG. 68A depicts an embodiment for installing and coupling heaters in a wellbore. The embodiment in FIG. 68A depicts insulated conductor heaters being installed into the wellbore.
Other types of heaters, such as conductor-in-conduit heaters, may also be installed in the wellbore using the embodiment depicted. Also, in FIG. 68A, two insulated conductors 558 are shown while a third insulated conductor is not seen from the view depicted.
Typically, three insulated conductors 558 would be coupled to support member 560, as shown in FIG. 68B. In an embodiment, support member 560 is a thick walled 347H pipe. In some embodiments, thermocouples or other temperature sensors are placed inside support member 560. The three insulated conductors may be coupled in a three-phase wye configuration.
[0836] In FIG. 68A, insulated conductors 558 are coiled on coiled tubing rigs 562. As insulated conductors 558 are uncoiled from rigs 562, the insulated conductors are coupled to support member 560. In certain embodiments, insulated conductors 558 are simultaneously uncoiled and/or simultaneously coupled to support member 560. Insulated conductors 558 may be coupled to support member 560 using metal (for example, 304 stainless steel or Inconel alloys) straps 564. In some embodiments, insulated conductors 558 are coupled to support member 560 using other types of fasteners such as buckles, wire holders, or snaps.
Support member 560 along with insulated conductors 558 are installed into opening 522. In some embodiments, insulated conductors 558 are coupled together without the use of a support member. For example, one or more straps 564 may be used to couple insulated conductors 558 together.
[0837] Insulated conductors 558 may be electrically coupled to each other at a lower end of the insulated conductors. In a three-phase wye configuration, insulated conductors 558 operate without a current return path. In certain embodiments, insulated conductors 558 are electrically coupled to each other in contactor section 566. In section 566, sheaths, jackets, canisters, and/or electrically conductive sections are electrically coupled to each other and/or to support member 560 so that insulated conductors 558 are electrically coupled in the section.
108381 In certain embodiments, the sheaths of insulated conductors 558 are shorted to the conductors of the insulated conductors. FIG. 68C depicts an embodiment of insulated conductor 558 with the sheath shorted to the conductors. Sheath 506 is electrically coupled to core 508, ferromagnetic conductor 512, and inner conductor 490 using termination 568.
Termination 568 may be a metal strip or a metal plate at the lower end of insulated conductor 558. For example, termination 568 may be a copper plate coupled to sheath 506, core 508, ferromagnetic conductor 512, and inner conductor 490 so that they are shorted together. In some embodiments, termination 568 is welded or brazed to sheath 506, core 508, ferromagnetic conductor 512, and inner conductor 490.
108391 The sheaths of individual insulated conductors 558 may be shorted together to electrically couple the conductors of the insulated conductors, depicted in FIGS. 68A and 68B.
In some embodiments, the sheaths may be shorted together because the sheaths are in physical contact with each other. For example, the sheaths may in physical contact if the sheaths are strapped together by straps 564. In some embodiments, the lower ends of the sheaths are physically coupled (for example, welded) at the surface of opening 522 before insulated conductors 558 are installed into the opening.
[0840] In certain embodiments, coupling multiple heaters (for example, insulated conductor, or mineral insulated conductor, heaters) to a single power source, such as a transformer, is advantageous. Coupling multiple heaters to a single transformer may result in using fewer transformers to power heaters used for a treatment area as compared to using individual transformers for each heater. Using fewer transformers reduces surface congestion and allows easier access to the heaters and surface components. Using fewer transformers reduces capital costs associated with providing power to the treatment area. In some embodiments, at least 4, at least 5, at least 10, at least 25 heaters, at least 35 heaters, or at least 45 heaters are powered by a single transformer. Additionally, powering multiple heaters (in different heater wells) from the single transformer may reduce overburden losses because of reduced voltage and/or phase differences between each of the heater wells powered by the single transformer. Powering multiple heaters from the single transformer may inhibit current imbalances between the heaters because the heaters are coupled to the single transformer.
[0841] In order to provide power to multiple heaters using the single transformer, the transformer may have to provide power at higher voltages to carry the current to each of the heaters effectively. In certain embodiments, the heaters are floating (ungrounded) heaters in the formation. Floating the heaters allows the heaters to operate at higher voltages. In some embodiments, the transformer provides power output of at least about 3 kV, at least about 4 kV, at least about 5 kV, or at least about 6 kV.
[0842] FIG. 69 depicts a top view representation of heater 716 with three insulated conductors 558 in conduit 536. Heater 716 includes three insulated conductors 558 in conduit 536. Heater 716 may be located in a heater well in the subsurface formation. Conduit 536 may be a sheath, jacket, or other enclosure around insulated conductors 558. Each insulated conductor 558 includes core 508, electrical insulator 500, and jacket 506. Insulated conductors 558 may be mineral insulated conductors with core 508 being a copper alloy (for example, a copper-nickel alloy such as Alloy 180), electrical insulator 500 being magnesium oxide, and jacket 506 being Incoloy 825, copper, or stainless steel (for example 347H stainless steel).
In some embodiments, jacket 506 includes non-work hardenable metals so that the jacket is annealable.
[0843] In some embodiments, core 508 and/or jacket 506 include ferromagnetic materials. In some embodiments, one or more insulated conductors 558 are temperature limited heaters. In certain embodiments, the overburden portion of insulated conductors 558 include high electrical conductivity materials in core 508 (for example, pure copper or copper alloys such as copper with 3% silicon at a weld joint) so that the overburden portions of the insulated conductors provide little or no heat output. In certain embodiments, conduit 536 includes non-corrosive materials and/or high strength materials such as stainless steel. In one embodiment, conduit 536 is 347H stainless steel.
[0844] Insulated conductors 558 may be coupled to the single transformer in a three-phase configuration (for example, a three-phase wye configuration). Each insulated conductor 558 may be coupled to one phase of the single transformer. In certain embodiments, the single transformer is also coupled to a plurality of identical heaters 716 in other heater wells in the formation (for example, the single transformer may couple to 40 heaters or more 716 in the formation). In some embodiments, the single transformer couples to at least 4, at least 5, at least 10, at least 15, or at least 25 additional heaters in the formation.
[0845] FIG. 70 depicts an embodiment of three-phase wye transformer 728 coupled to a plurality of heaters 716. For simplicity in the drawing, only four heaters 716 are shown in FIG.
70. It is to be understood that several more heaters may be coupled to the transformer 728. As shown in FIG. 70, each leg (each insulated conductor) of each heater is coupled to one phase of transformer 728 and current returned to the neutral or ground of the transformer (for example, returned through conductor 2024 depicted in FIGS. 69 and 71).
108461 Electrical insulator 500' may be located inside conduit 536 to electrically insulate insulated conductors 558 from the conduit. In certain embodiments, electrical insulator 500' is magnesium oxide (for example, compacted magnesium oxide). In some embodiments, electrical insulator 500' is silicon nitride (for example, silicon nitride blocks).
Electrical insulator 500' electrically insulates insulated conductors 558 from conduit 536 so that at high operating voltages (for example, 3 kV or higher), there is no arcing between the conductors and the conduit. In some embodiments, electrical insulator 500' inside conduit 536 has at least the thickness of electrical insulators 500 in insulated conductors 558. The increased thickness of insulation in heater 716 (from electrical insulators 500 and/or electrical insulator 500') inhibits and may prevent current leakage into the formation from the heater. In some embodiments, electrical insulator 500' spatially locates insulated conductors 558 inside conduit 536.
[0847] Return conductor 2024 may be electrically coupled to the ends of insulated conductors 558 (as shown in FIG. 71) arid return current from the ends of the insulated conductors to the transformer on the surface of the formation. Return conductor 2024 may include high electrical conductivity materials such as pure copper, nickel, copper alloys, or combinations thereof so that the return conductor provides little or no heat output. In some embodiments, return conductor 2024 is a tubular (for example, a stainless steel tubular) that allows an optical fiber to be placed inside the tubular and used for temperature measurement. In some embodiments, return conductor 2024 is a small insulated conductor (for example, small mineral insulated conductor). Return conductor 2024 may be coupled to the neutral or ground leg of the transformer in a three-phase wye configuration. Thus, insulated conductors 558 are electrically isolated from conduit 536 and the formation. Using return conductor 2024 to return current to the surface may make coupling the heater to a wellhead easier. In some embodiments, current is returned using one or more of jackets 506, depicted in FIG. 69. One or more jackets 506 may be coupled to cores 508 at the end of the heaters and return current to the neutral of the three-phase wye transformer.
[0848] FIG. 71 depicts a side view representation of the end section of three insulated conductors 558 in conduit 536. The end section is the section of the heaters the furthest away from (distal from) the surface of the formation. The end section includes contactor section 566 coupled to conduit 536. In some embodiments, contactor section 566 is welded or brazed to conduit 536. Termination 568 is located in contactor section 566. Termination 568 is electrically coupled to insulated conductors 558 and return conductor 2024.
Termination 568 electrically couples the cores of insulated conductors 558 to the return conductor 2024 at the ends of the heaters.
108491 In certain embodiments, heater 716, depicted in FIGS. 69 and 71, includes an overburden section using copper as the core of the insulated conductors. The copper in the overburden section may be the same diameter as the cores used in the heating section of the heater. The copper in the overburden section may also have a larger diameter than the cores in the heating section of the heater. Increasing the size of the copper in the overburden section may decrease losses in the overburden section of the heater.
[0850] Heaters that include three insulated conductors 558 in conduit 536, as depicted in FIGS.
69 and 71, may be made in a multiple step process. In some embodiments, the multiple step process is performed at the site of the formation or treatment area. In some embodiments, the multiple step process is performed at a remote manufacturing site away from the formation. The finished heater is then transported to the treatment area.
108511 Insulated conductors 558 may be pre-assembled prior to the bundling either on site or at a remote location. Insulated conductors 558 and return conductor 2024 may be positioned on spools. A machine may draw insulated conductors 558 and return conductor 2024 from the spools at a selected rate. Preformed blocks of insulation material may be positioned around return conductor 2024 and insulated conductors 558. In an embodiment, two blocks are positioned around return conductor 2024 and three blocks are positioned around insulated conductors 558 to form electrical insulator 500'. The insulated conductors and return conductor may be drawn or pushed into a plate of conduit material that has been rolled into a tubular shape.
The edges of the plate may be pressed together and welded (for example, by laser welding).
After forming conduit 536 around electrical insulator 500', the bundle of insulated conductors 558, and return conductor 2024, the conduit may be compacted against the electrical insulator 2024 so that all of the components of the heater are pressed together into a compact and tightly fitting form. During the compaction, the electrical insulator may flow and fill any gaps inside the heater.
108521 In some embodiments, heater 716 (which includes conduit 536 around electrical insulator 500' and the bundle of insulated conductors 558 and return conductor 2024) is inserted into a coiled tubing tubular that is placed in a wellbore in the formation.
The coiled tubing tubular may be left in place in the formation (left in during heating of the formation) or removed from the formation after installation of the heater. The coiled tubing tubular may allow for easier installation of heater 716 into the wellbore.
[0853] In some embodiments, one or more components of heater 716 are varied (for example, removed, moved, or replaced) while the operation of the heater remains substantially identical.
FIG. 72 depicts one alternative embodiment of heater 716 with three insulated cores 508 in conduit 536. In this embodiment, electrical insulator 500' surrounds cores 508 and return conductor 2024 in conduit 536. Cores 508 are located in conduit 536 without electrical insulator 500 and jacket 506 surrounding the cores. Cores 508 are coupled to the single transformer in a three-phase wye configuration with each core 508 coupled to one phase of the transformer.
Return conductor 2024 is electrically coupled to the ends of cores 508 and returns current from the ends of the cores to the transformer on the surface of the formation.
[0854] FIG. 73 depicts another alternative embodiment of heater 716 with three insulated conductors 558 and insulated return conductor in conduit 536. In this embodiment, return conductor 2024 is an insulated conductor with core 508, electrical insulator 500, and jacket 506.
Return conductor 2024 and insulated conductors 558 are located in conduit 536 are surrounded by electrical insulator 500 and conduit 536. Return conductor 2024 an