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Kafe 바로가기국가/구분 | United States(US) Patent 등록 |
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국제특허분류(IPC7판) |
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출원번호 | US-0841440 (2001-04-24) |
발명자 / 주소 |
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출원인 / 주소 |
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인용정보 | 피인용 횟수 : 253 인용 특허 : 255 |
A coal formation may be treated using an in situ thermal process. Hydrocarbons, H 2 , and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. Heat sources may be positione
A coal formation may be treated using an in situ thermal process. Hydrocarbons, H 2 , and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. Heat sources may be positioned within open wellbores in the formation.
1. A method of treating a coal formation in situ, comprising:providing heat from one or more heaters to at least one portion of the formation, wherein at least two of the heaters are electrical heaters disposed in one or more open wellbores in the formation;allowing the heat to transfer from at leas
1. A method of treating a coal formation in situ, comprising:providing heat from one or more heaters to at least one portion of the formation, wherein at least two of the heaters are electrical heaters disposed in one or more open wellbores in the formation;allowing the heat to transfer from at least one of the heaters to a part of the formation;maintaining a temperature in the part of the formation in a pyrolysis temperature range; andproducing a mixture from the formation. 2. The method of claim 1, wherein the one or more heaters comprise at least two heaters, and wherein superposition of heat from at least the two heaters raises a temperature of the part between the heaters to a temperature within a pyrolysis temperature range in order to pyrolyze at least some hydrocarbons in the part of the formation. 3. The method of claim 1, wherein maintaining a temperature within the part within the pyrolysis temperature range comprises maintaining the temperature between about 250° C. and about 400° C. 4. The method of claim 1, wherein at least one of the heaters is suspended in at least one of the open wellbores. 5. The method of claim 1, further comprising flowing a substantially constant amount of fluid into one of the open wellbores through one or more critical flow orifices in a tube disposed in the open wellbore proximate to one of the heaters. 6. The method of claim 1, further comprising flowing a corrosion inhibiting fluid into one of the open wellbores through a perforated tube disposed in the open wellbore. 7. The method of claim 1, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation. 8. The method of claim 1, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel. 9. The method of claim 1, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement. 10. The method of claim 1, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and at least one of the open wellbores. 11. The method of claim 1, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and inhibiting a flow of fluid between at least one of the open wellbores and the overburden casing with a packing material. 12. The method of claim 1, further comprising heating at least the one portion to pyrolyze some hydrocarbons within the part of the formation. 13. The method of claim 1, further comprising controlling a pressure and a temperature within at least a majority of the part of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure. 14. The method of claim 1, further comprising controlling pressure within at least one of the wellbores. 15. The method of claim 1, further comprising controlling pressure within at least a majority of the part of the formation with one or more valves, wherein at least one valve of the one or more valves is coupled to a wellbore of at least one of the heaters. 16. The method of claim 1, further comprising controlling pressure within at least a majority of the part of the formation with one or more valves, wherein at least one valve of the one or more valves is coupled to a production well located in the formation. 17. The method of claim 1, further comprising controlling the heat such that an average heating rat e of the part is less than about 1° C. per day during pyrolysis. 18. The method of claim 1, wherein providing heat from at least one of the heaters to at least the portion of the formation comprises:heating a selected volume (V) of the coal formation from at least one of the heaters, wherein the formation has an average heat capacity (C v ), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume is equal to or less than h*V*C v *ρ B , wherein ρ B is formation bulk density, and wherein an average heating rate of the formation (h) is about 10° C./day. 19. The method of claim 1, wherein allowing the heat to transfer from at least one of the heaters to the part comprises transferring heat substantially by conduction. 20. The method of claim 1, wherein providing heat from at least one of the heaters increases a thermal conductivity of at least a portion of the part to greater than about 0.5 W/(m ° C.). 21. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°. 22. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins. 23. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15. 24. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins. 25. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen. 26. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen. 27. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols. 28. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur. 29. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds. 30. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings. 31. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes. 32. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes. 33. The method of claim 1, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises molecular hydrogen, and wherein the molecular hydrogen is greater than about 10% by volume of the non-condensable component at 25° C. and one atmosphere absolute pressure, and wherein the molecular hydrogen is less than about 80% by volume of the non-condensable component at 25° C. and one atmosphere absolute pressure. 34. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia. 35. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer. 36. The method of claim 1, further comprising controlling a pressure within at least a majority of the part of the formation. 37. The method of claim 1, further comprising controlling a pressure within at least a majority of the part of the formation, wherein the controlled pressure is at least about 2.0 bar absolute. 38. The method of claim 1, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H 2 within the mixture greater than about 0.5 bar. 39. The method of claim 1, wherein the partial pressure of H 2 is measured when the mixture is at a production well. 40. The method of claim 1, further comprising recirculating a portion of hydrogen from the mixture into the formation. 41. The method of claim 1, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25. 42. The method of claim 1, further comprising:providing hydrogen (H 2 ) to the heated part of the formation to hydrogenate hydrocarbons within the part of the formation; andheating a portion of the part of the formation with heat from hydrogenation. 43. The method of claim 1, further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the hydrogen produced in the mixture. 44. The method of claim 1, wherein allowing the heat to transfer increases a permeability of a majority of the part to greater than about 100 millidarcy. 45. The method of claim 1, wherein allowing the heat to transfer increases a permeability of a majority of the part of the formation such that the permeability of the majority of the part of the formation is substantially uniform. 46. The method of claim 1, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay. 47. The method of claim 1, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heaters are disposed in the formation for the production well. 48. The method of claim 1, further comprising providing heat from heaters to at least the one portion of the formation, wherein the heaters are located in the formation in a unit of heaters, and wherein the unit of heaters comprises a triangular pattern. 49. The method of claim 1, further comprising providing heat from heaters to at least the one portion of the formation, wherein the heaters are located in the formation in a unit of heaters, wherein the unit of heaters comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units. 50. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream. 51. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream. 52. The method of claim 1, further comprising separating a portion of H 2 S in the mixture from the mixture. 53. The method of claim 1, further comprising separating a portion of CO 2 in the mixture from the mixture. 54. The method of claim 1, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor. 55. The method of claim 1, further comprising heating a wellbore of a production well through which the mixture is produced to inhibit condensation of the mixture within the wellbore. 56. The method of claim 1, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H 2 . 57. The method of claim 1, wherein the part is heated to a minimum pyrolysis temperature of about 270° C. 58. The method of claim 1, further comprising maintaining the pressure within the formation above about 2.0 bar absolute to inhibit production of fluids having carbon numbers above 25. 59. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bar, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons. 60. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bar, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity. 61. The method of claim 1, further comprising providing H 2 to at least a portion of the formation. 62. The method of claim 1, further comprising providing H 2 to at least a portion of the formation to hydrogenate hydrocarbons in the formation. 63. A method of treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heaters to at least one portion of the formation, wherein one or more of the heaters are electrical heaters disposed in one or more open wellbores in the formation, and wherein one or more of the heaters provide a heat output of less than about 1650 watts per meter;allowing the heat to transfer from one or more of the heaters to a pyrolysis zone of the formation;maintaining a temperature in the pyrolysis zone in a pyrolysis temperature range; andproducing a mixture from the formation. 64. The method of claim 63, wherein the pyrolysis zone comprises a selected section. 65. The method of claim 63, further comprising producing a mixture from the pyrolysis zone, wherein the mixture comprises condensable hydrocarbons having an API gravity of at least about 25°. 66. The method of claim 63, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure. 67. The method of claim 63, wherein providing heat from the heaters to at least the one portion of the formation comprises:heating a selected volume (V) of the formation from one or more of the heaters, wherein the formation has an average heat capacity (C v ), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; andwherein heating energy/day (Pwr) provided to the selected volume is equal to or less than h*V*C v *ρ B , wherein ρ B is formation bulk density, and wherein an average heating rate (h) of the selected volume is about 10° C./day. 68. The method of claim 63, further comprising providing H 2 to at least a portion of the formation. 69. The method of claim 63, further comprising providing H 2 to at least a portion of the formation of hydrogenate hydrocarbons in the formation. 70. A method of treating a coal formation in situ, comprising:providing heat from one or more heat sources to at least one portion of the formation, wherein at least two of the heat sources are electrical heaters disposed in or proximate to one or mo re open wellbores in the formation;allowing the heat to transfer from at least one of the heat sources to a part of the formation;maintaining a temperature in the part of the formation in a pyrolysis temperature range; andproducing a mixture from the formation. 71. The method of claim 70, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources raises a temperature of the part between the heat sources to a temperature within a pyrolysis temperature range in order to pyrolyze at least some hydrocarbons in the part of the formation. 72. The method of claim 70, wherein maintaining a temperature within the part within the pyrolysis temperature range comprises maintaining the temperature between about 250° C. and about 400° C. 73. The method of claim 70, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation. 74. The method of claim 70, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing comprises steel. 75. The method of claim 70, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein the overburden casing is further disposed in cement. 76. The method of claim 70, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and wherein a packing material is disposed at a junction of the overburden casing and at least one of the open wellbores. 77. The method of claim 70, further comprising coupling an overburden casing to at least one of the open wellbores, wherein the overburden casing is disposed in an overburden of the formation, and inhibiting a flow of fluid between at least one of the open wellbores and the overburden casing with a packing material. 78. The method of claim 70, further comprising controlling a pressure and a temperature within at least a majority of the part of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure. 79. The method of claim 70, further comprising controlling the heat such that an average heating rate of the part is less than about 1° C. per day during pyrolysis. 80. The method of claim 70, further comprising providing H 2 to at least a portion of the formation. 81. The method of claim 70, further comprising providing H 2 to at least a portion of the formation to hydrogenate hydrocarbons in the formation.
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