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Kafe 바로가기국가/구분 | United States(US) Patent 등록 |
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국제특허분류(IPC7판) |
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출원번호 | US-0841496 (2001-04-24) |
발명자 / 주소 |
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출원인 / 주소 |
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인용정보 | 피인용 횟수 : 208 인용 특허 : 338 |
A hydrocarbon containing formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, 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. H
A hydrocarbon containing formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, 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 used to heat the formation. The heat sources may be positioned within the formation in a pattern. The pattern may be a repeating pattern of triangles.
1. A method of treating a hydrocarbon containing formation in situ, comprising:providing heat from heaters to a portion of the formation, wherein three of the heaters are located in the formation in a triangular unit, and wherein a plurality of triangular units are repeated over an area of the forma
1. A method of treating a hydrocarbon containing formation in situ, comprising:providing heat from heaters to a portion of the formation, wherein three of the heaters are located in the formation in a triangular unit, and wherein a plurality of triangular units are repeated over an area of the formation to form a repetitive pattern of units; and producing fluid from production wells, wherein a ratio of heaters to production wells is greater than approximately 5. 2. The method of claim 1, wherein the production wells are located in the formation in units of production wells, and wherein a unit of production wells comprises a triangular pattern.3. The method of claim 1, further comprising introducing fluids into the formation through injection wells, and wherein the injection wells are located in the formation in units of injection wells, and wherein a unit of injection wells comprises a triangular pattern.4. The method of claim 1, wherein the production wells are arranged in the formation in a pattern of triangular units, introducing fluid into the formation through injection wells, wherein the injection wells are arranged in the formation in a pattern of triangular units, and wherein a spacing between production wells of a triangular unit of production wells is different than a spacing between injection wells of a triangular unit of injection wells.5. The method of claim 1, further comprising obtaining data pertaining to formation conditions from monitoring wells, wherein the monitoring wells are located in the formation in a repeating pattern of triangular units.6. The method of claim 1, wherein the plurality of triangular units comprises a first unit adjacent to a second unit, and wherein an orientation of first unit is inverted with respect to the second unit.7. The method of claim 1, wherein a distance between each of the heaters in a triangular unit of heaters varies by less than about 20%.8. The method of claim 1, wherein a distance between each heater in a triangular unit of heaters is approximately equal.9. The method of claim 1, wherein providing heat from the heaters establishes a substantially uniform temperature distribution in the portion.10. The method of claim 9, wherein a difference between a highest temperature in the portion and a lowest temperature in the portion comprises less than about 200° C. when the lowest temperature is at or above a minimum pyrolysis temperature.11. The method of claim 1, wherein a temperature at an outer lateral boundary of a triangular unit and a temperature at a center of the triangular unit are approximately equal.12. The method of claim 1, wherein a temperature at an outer lateral boundary of a triangular unit and a temperature at a center of the triangular unit increase substantially linearly after an initial period of time, and wherein the initial period of time is less than approximately 3 months.13. The method of claim 1, wherein providing heat from the heaters to the portion of the formation comprises:heating a selected volume (V) of the hydrocarbon containing formation with the heaters, wherein the formation has an average heat capacity (Cν), and wherein heat from the heaters pyrolyzes at least some hydrocarbons in the selected volume of the formation; and wherein heating energy/day (Pwr) provided to the selected volume is equal to or less than h*V*Cν*ρB, wherein ρB is formation bulk density, and wherein an average heating rate (h) of the selected volume is about 10° C./day. 14. The method of claim 1, wherein at least one of the heaters comprises an electrical heater.15. The method of claim 1, wherein at least one of the heaters comprises a surface burner.16. The method of claim 1, wherein at least one of the heaters comprises a flameless distributed combustor.17. The method of claim 1, wherein at least one of the heaters comprises a natural distributed combustor.18. The method of claim 1, further comprising controlling a temperature in at least a majority of the portion, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.19. The method of claim 1, further comprising controlling the heat such that an average heating rate of the portion is less than about 1.0° C. per day when the average temperature is in a range from about 270° C. to about 400° C.20. The method of claim 1, wherein providing heat from heaters to the portion of the formation comprises transferring heat substantially by conduction.21. The method of claim 1, wherein providing heat from the heaters to the portion of the formation increases a thermal conductivity of the portion to greater than about 0.5 W/m ° C.22. The method of claim 1, wherein the fluid comprises an API gravity of at least 25°.23. The method of claim 1, wherein the fluid comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.24. The method of claim 1, wherein the fluid 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 0.15.25. The method of claim 1, wherein the fluid 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 fluid 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 fluid comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.28. The method of claim 1, wherein the fluid 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.29. The method of claim 1, wherein the fluid 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 fluid 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 fluid comprises condensable hydrocarbons, and wherein less than about 0.1% by weight of the condensable hydrocarbons are asphaltenes.32. The method of claim 1, wherein the fluid 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 fluid comprises a non-condensable component, wherein the non-condensable component comprises molecular hydrogen, 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 fluid 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 fluid comprises ammonia, and wherein the ammonia is used to produce fertilizer.36. The method of claim 1, wherein the fluid comprises a mixture of hydrocarbon fluids and H2, wherein a partial pressure of H2 in the mixture is greater than about 2.0 bars absolute.37. The method of claim 1, further comprising altering a pressure in the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.38. The method of claim 1, further comprising recirculating a portion of hydrogen from the fluid into the formation.39. The method of claim 1, further comprising:providing hydrogen (H2) to the portion to hydrogenate hydrocarbons in the portion of the formation; and heating a portion of the part of the formation with heat from hydrogenation. 40. The method of claim 1, further comprising:producing hydrogen (H2) from the formation; and hydrogenating a portion of condensable hydrocarbons produced from the formation with at least a portion of the produced hydrogen. 41. The method of claim 1, further comprising allowing the heat to transfer from the heaters to a part of the formation increases a permeability of a majority of the part to greater than about 100 millidarcy.42. The method of claim 1, further comprising allowing the heat to transfer from the heaters to a part of the formation increases a permeability of a majority of the part such that the permeability of the majority of the part is substantially uniform.43. The method of claim 1, further comprising controlling the heat from the heaters to yield greater than about 60% by weight of condensable hydrocarbons, as measured by the Fisher Assay.44. The method of claim 1, wherein at least about 7 heaters are disposed in the formation for each production well.45. The method of claim 44, wherein at least about 20 heaters are disposed in the formation for each production well.46. A method of treating a hydrocarbon containing formation in situ, comprising:providing heat from heaters to a portion of the formation, wherein three of the heaters are located in the formation in a triangular unit, wherein a plurality of triangular units are repeated over an area of the formation to form a repetitive pattern of units; introducing fluid into the formation through injection wells, wherein the injection wells are arranged in the formation in a pattern of triangular units; producing fluid from production wells, wherein the production wells are arranged in the formation in a pattern of triangular units; and wherein a spacing between production wells of a triangular unit of production wells is different than a spacing between injection wells of a triangular unit of injection wells. 47. The method of claim 46, wherein at least 7 heaters are disposed in the formation for each production well.48. The method of claim 46, wherein at least 20 heaters are disposed in the formation for each production well.49. The method of claim 46, further comprising producing H2 from the formation, and hydrogenating a portion of condensable hydrocarbons produced from the formation with produced hydrogen.50. The method of claim 46, wherein a distance between each of the heaters in a triangular unit of heaters varies by less than about 20%.51. A method of treating a hydrocarbon containing formation in situ, comprising:providing heat from heaters to a portion of the formation, wherein three of the heaters are located in the formation in a triangular unit, and wherein a plurality of triangular units are repeated over an area of the formation to form a repetitive pattern of units; and wherein at least one of the heaters comprises a natural distributed combustor. 52. The method of claim 51, wherein at least about 7 heaters are disposed in the formation for each production well.53. The method of claim 51, wherein at least about 20 heaters are disposed in the formation for each production well.54. The method of claim 51, further comprising providing H2 to the formation to hydrogenate hydrocarbons in the part of the formation.55. The method of claim 51, further comprising producing H2 from the formation, and hydrogenating a portion of condensable hydrocarbons produced from the formation with produced hydrogen.56. The method of claim 51, wherein a distance between each of the heaters in a triangular unit of heaters varies by less than about 20%.
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