Recovering energy from a subsurface formation

• US 8,327,932 B2
• Filed: 04/09/2010
• Issued: 12/11/2012
• Est. Priority Date: 04/10/2009
• Status: Active Grant

• Current Assignee: Shell Oil Company (Shell Plc)
• Original Assignee: Shell Oil Company (Shell Plc)
• Inventors: Karanikas, John Michael, McNeil, Robert Irving III, Pollard, Richard
• Primary Examiner(s): Neuder, William P
• Application Number:
  US12/757,632
• Publication Number:
  US 20100258265A1
• Time in Patent Office: 977 Days
• Field of Search: 166/251, 166/261, 166/262
• US Class Current: 166/251.1
• CPC Class Codes: E21B 36/04 using electrical heaters
• CPC Class Codes: E21B 43/2401 by means of electricity
• CPC Class Codes: E21B 43/243 Combustion in situ
• CPC Class Codes: H05B 2214/03 Heating of hydrocarbons

Abstract

A method of recovering energy from a subsurface hydrocarbon containing formation includes introducing an oxidizing fluid in a wellbore positioned in at least a first portion of the formation. At least a portion of the first portion of the formation has been subjected to an in situ heat treatment process. The portion includes a treatment area having elevated levels of coke substantially adjacent the wellbore. The pressure in the wellbore is increased by introducing the oxidizing fluid under pressure such that the oxidizing fluid substantially permeates a majority of the treatment area and initiates a combustion process. Heat from the combustion process is allowed to transfer to fluids in the treatment area. Pressure decreases in the wellbore such that heated fluids from the portion of the formation are conveyed into the wellbore. The heated fluids are transferred to a heat exchanger configured to collect thermal energy.

Claims

1. A method of recovering energy from a subsurface hydrocarbon containing formation, comprising:

introducing an oxidizing fluid in a wellbore positioned in at least a first portion of a subsurface hydrocarbon containing formation, wherein at least a part of the first portion of the subsurface hydrocarbon containing formation has been subjected to an in situ heat treatment process prior to introduction of the oxidizing fluid, and wherein the part comprises a treatment area comprising elevated levels of coke substantially adjacent the wellbore;

increasing a pressure in the wellbore by introducing the oxidizing fluid under pressure such that the oxidizing fluid substantially permeates a majority of the treatment area and initiates a combustion process;

allowing heat from the combustion process to transfer to some of the fluids in the treatment area;

decreasing the pressure in the wellbore such that at least some heated fluids from the part of the formation are conveyed into the wellbore; and

transferring the heated fluids conveyed into the wellbore to the surface to a heat exchanger configured to collect thermal energy.

2. The method of claim 1, wherein the treatment area comprises residual hydrocarbons.

3. The method of claim 1, wherein the heated fluids comprise at least some heated oxidizing fluid.

4. The method of claim 1, wherein the heated fluids comprise at least some products from the combustion process.

5. The method of claim 1, further comprising transferring a heated heat transfer fluid from the heat exchanger to at least a second portion of the subsurface hydrocarbon containing formation.

6. The method of claim 5, wherein the heat transfer fluid comprises molten salt.

7. The method of claim 5, wherein the heat transfer fluid comprises molten metal.

8. The method of claim 5, wherein the heat transfer fluid comprises condensable hydrocarbons.

9. The method of claim 5, wherein the heat transfer fluid comprises thermally conductive gases.

10. The method of claim 9, wherein the thermally conductive gases comprise helium, carbon dioxide, steam, or mixtures thereof.

11. The method of claim 1, further comprising transferring a heated heat transfer fluid from the heat exchanger to at least a second portion of the subsurface hydrocarbon containing formation such that at least part of the second portion is heated using the heated heat transfer fluid.

12. The method of claim 1, further comprising forming at least one barrier at least partially around the treatment area substantially adjacent the wellbore, wherein the barrier is configured to inhibit oxidizing fluid introduced in the wellbore from being conveyed beyond the treatment area substantially adjacent the wellbore.

13. The method of claim 1, further comprising introducing a barrier forming fluid around the treatment area substantially adjacent the wellbore, wherein the barrier fluid is configured to solidify at or below a specified temperature range.

14. The method of claim 13, wherein the barrier forming fluid comprises a slurry.

15. The method of claim 13, wherein the barrier forming fluid comprises solids and a low volatility solvent.

16. The method of claim 13, wherein the barrier forming fluid comprises ceramics, micas, clays, or mixtures thereof.

17. The method of claim 1, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore.

18. The method of claim 1, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting a flow rate of the oxidizing fluid.

19. The method of claim 1, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting the increase in pressure.

20. The method of claim 1, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting a duration of the combustion process.

21. The method of claim 1, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by injecting steam in the wellbore.

22. The method of claim 1, further comprising conducting a cycling process, wherein the cycling process comprises repeatedly:

increasing the pressure in the wellbore using the oxidizing fluid; and

decreasing the pressure in the wellbore to remove at least some of the combustion products.

23. The method of claim 22, further comprising introducing sufficient oxidizing fluid in the wellbore such that the combustion process proceeds throughout the cycling process of the wellbore.

24. The method of claim 1, further comprising inhibiting heat loss in an overburden of at least the first portion of the subsurface hydrocarbon containing formation by insulating at least the portion of the wellbore in the overburden.

25. A method of recovering energy from a subsurface hydrocarbon containing formation, comprising:

introducing an oxidizing fluid in a wellbore positioned in at least a first portion of a subsurface hydrocarbon containing formation, wherein at least a part of the first portion of the subsurface hydrocarbon containing formation has been subjected to an in situ heat treatment process prior to introduction of the oxidizing fluid, and wherein the part comprises a treatment area comprising elevated levels of coke substantially adjacent the wellbore;

increasing a pressure in the wellbore by introducing the oxidizing fluid under pressure such that the oxidizing fluid substantially permeates a majority of the treatment area and initiates a combustion process;

allowing heat from the combustion process to transfer to fluids in the treatment area;

decreasing the pressure in the wellbore such that at least some heated fluids from the treatment area are conveyed into the wellbore; and

introducing a heat transfer fluid in the wellbore such that heat is transferred from the wellbore to the heat transfer fluid.

26. The method of claim 25, wherein the treatment area comprises residual hydrocarbons.

27. The method of claim 25, wherein the heated fluids comprise at least some heated oxidizing fluid.

28. The method of claim 25, wherein the heated fluids comprise at least some products from the combustion process.

29. The method of claim 25, further comprising transferring the heated heat transfer fluid from the wellbore to at least a second portion of the subsurface hydrocarbon containing formation.

30. The method of claim 25, further comprising transferring the heated heat transfer fluid from the wellbore to at least a second portion of the subsurface hydrocarbon containing formation such that at least a part of the second portion is heated using the heated heat transfer fluid.

31. The method of claim 25, further comprising forming a barrier at least partially around the treatment area substantially adjacent the wellbore, wherein the barrier is configured to inhibit oxidizing fluid introduced in the wellbore from being conveyed beyond the treatment area substantially adjacent the wellbore.

32. The method of claim 25, further comprising introducing a barrier forming fluid around the treatment area substantially adjacent the wellbore, wherein the barrier fluid is configured to solidify at or below a specified temperature range.

33. The method of claim 32, wherein the barrier forming fluid comprises a slurry.

34. The method of claim 32, wherein the barrier forming fluid comprises solids and a low volatility solvent.

35. The method of claim 32, wherein the barrier forming fluid comprises ceramics, micas, clays, or mixtures thereof.

36. The method of claim 25, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore.

37. The method of claim 25, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting a flow rate of the oxidizing fluid.

38. The method of claim 25, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting the increase in pressure.

39. The method of claim 25, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by adjusting a duration of the combustion process.

40. The method of claim 25, further comprising regulating the temperature in the wellbore and/or the temperature of the treatment area substantially adjacent the wellbore by injecting steam in the wellbore.

41. The method of claim 25, further comprising conducting a cycling process, wherein the cycling process comprises repeatedly:

increasing the pressure in the wellbore using the oxidizing fluid; and

decreasing the pressure in the wellbore to remove at least some of the combustion products.

42. The method of claim 41, further comprising introducing sufficient oxidizing fluid in the wellbore such that the combustion process proceeds throughout the cycling process of the wellbore.

43. The method of claim 25, further comprising inhibiting heat loss in an overburden of at least the first portion of the subsurface hydrocarbon containing formation by insulating at least the portion of the wellbore in the overburden.

44. The method of claim 25, wherein the heat transfer fluid comprises molten salt.

45. The method of claim 25, wherein the heat transfer fluid comprises molten metal.

46. The method of claim 25, wherein the heat transfer fluid comprises condensable hydrocarbons.

47. The method of claim 25, wherein the heat transfer fluid comprises thermally conductive gases.

48. The method of claim 47, wherein the thermally conductive gases comprise helium, carbon dioxide, steam, or mixtures thereof.