Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore Number:7,147,057 from the United States Patent and Trademark Office (PTO) owispatent Systems and methods are provided for treating a wellbore using a loop system to heat oil in a subterranean formation contacted by the wellbore. The loop system comprises a loop that conveys a fluid (e.g., steam) down the wellbore via a injection conduit and returns fluid (e.g., condensate) from the wellbore via a return conduit. A portion of the fluid in the loop system may be injected into the subterranean formation using one or more valves disposed in the loop system. Alternatively, only heat and not fluid may be transferred from the loop system into the subterranean formation. The fluid returned from the wellbore may be re-heated and re-conveyed by the loop system into the wellbore. Heating the oil residing in the subterranean formation reduces the viscosity of the oil so that it may be recovered more easily.<H distributing, conveying, Loop, systems, an, 7147057.html, Patent, pto, 7147057

Title: Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore

Abstract: Systems and methods are provided for treating a wellbore using a loop system to heat oil in a subterranean formation contacted by the wellbore. The loop system comprises a loop that conveys a fluid (e.g., steam) down the wellbore via a injection conduit and returns fluid (e.g., condensate) from the wellbore via a return conduit. A portion of the fluid in the loop system may be injected into the subterranean formation using one or more valves disposed in the loop system. Alternatively, only heat and not fluid may be transferred from the loop system into the subterranean formation. The fluid returned from the wellbore may be re-heated and re-conveyed by the loop system into the wellbore. Heating the oil residing in the subterranean formation reduces the viscosity of the oil so that it may be recovered more easily.

Patent Number: 7,147,057 Issued on 12/12/2006 to Steele, et al.

Inventors: Steele; David Joe (Irving, TX), McGlothen; Jody R. (Waxahachie, TX), Bayh, III; Russell Irving (Carrollton, TX)
Assignee: Halliburton Energy Services, Inc. (Houston, TX)

Appl. No.: 10/680,901

Filed: October 6, 2003

Current U.S. Class: 166/303 ; 166/302; 166/50

Current International Class: E21B 43/24 (20060101)

Field of Search: 166/302,303,305.1,272.6,272.7,272.1,50,52,57

References Cited [Referenced By]

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Primary Examiner: Dang; Hoang
Attorney, Agent or Firm: Carroll; Rodney

Claims

What is claimed is:

1. A method of servicing a wellbore, comprising: using a loop system to heat oil in a subterranean formation contacted by the wellbore, wherein the loop system conveys steam down the wellbore, wherein the loop system comprises a closed loop that circulates the steam through a conduit disposed in the wellbore such that heat is transferred from the steam to the subterranean formation, and wherein the steam is circulated through the loop system until the steam is substantially absent of condensate, and then the loop system is switched from the closed loop to an open loop in which at least a portion of the steam is injected into the subterranean formation.

2. The method of claim 1, wherein the loop system returns fluid from the wellbore.

3. The method of claim 2, wherein the fluid comprises condensate, steam, or combinations thereof.

4. The method of claim 1, further comprising injecting at least a portion of the steam from the loop system into the subterranean formation.

5. The method of claim 4, wherein another material is injected into the subterranean formation before, after, or concurrent with injecting the steam.

6. The method of claim 5, wherein the another material is recovered from the subterranean formation prior to being injected therein.

7. The method of claim 5, wherein the another material comprises an oil-soluble fluid.

8. The method of claim 1, wherein the steam is injected from the loop system into the subterranean formation until a predetermined temperature is achieved at a location in the wellbore.

9. The method of claim 1, wherein the loop system comprises one or more valves for controlling the injection of the steam into the subterranean formation.

10. The method of claim 9, wherein the loop system can automatically or manually be switched from a closed loop system in which all of the valves are closed to an injection system in which the valves are regulated to control the flow of the steam into the subterranean formation.

11. The method of claim 9, wherein the valve comprises a thermally-controlled valve, a pressure-activated valve, a spring loaded-control valve, a surface-controlled valve, a hydraulically-controlled valve, a fiber optic-controlled valve, a sub-surface controlled valve, a manual valve, or combinations thereof.

12. The method of claim 8, wherein the loop system comprises one or more thermally-controlled valves for regulating the flow of the steam into the subterranean formation.

13. The method of claim 9, wherein the one or more valves correspond to one or more heating zones in the subterranean formation such that the steam may be selectively injected into the heating zones.

14. The method of claim 13, wherein the one or more heating zones are isolated from each other by one or more isolation packers.

15. The method of claim 12, wherein the one or more thermally-controlled valves correspond to one or more heating zones in the subterranean formation such that the steam may be selectively injected into the heating zones.

16. The method of claim 15, wherein each thermally-controlled valve controls the injection of the steam into the subterranean formation in response to the temperature corresponding to the heating zone.

17. The method of claim 16, wherein the control results in the injection of about saturated steam.

18. The method of claim 1, further comprising recovering oil from the subterranean formation.

19. The method of claim 16, further comprising recovering oil from the subterranean formation.

20. The method of claim 18, wherein the recovery of oil and the condensate are simultaneous.

21. The method of claim 18, wherein the recovery of oil and the condensate are sequential.

22. The method of claim 1, further comprising reheating the condensate to form a portion of the steam.

23. The method of claim 18, wherein the oil and the condensate are recovered from a common wellbore.

24. The method of claim 18, wherein the oil and the condensate are recovered from different wellbores.

25. The method of claim 18, wherein the oil and condensate are recovered from a multilateral wellbore.

26. The method of claim 18, wherein the oil and the condensate are recovered from a SAGD wellbore.

27. The method of claim 19, wherein the oil and the condensate are recovered from a SAGD wellbore.

28. The method of claim 1, wherein the subterranean formation comprises oil and tar sands.

29. The method of claim 1, further comprising passing a chemical into the loop system for reducing contaminants therein.

30. The method of claim 1, wherein the steam loop comprises a steam boiler coupled to a steam injection conduit coupled to a condensate recovery conduit.

31. The method of claim 30, wherein the steam boiler is fired from hydrocarbons recovered from the wellbore.

32. The method of claim 30, wherein the steam loop further comprises one or more control valves in the steam injection conduit.

33. The method of claim 32, wherein the control valve comprises a thermally-controlled valve, a pressure-activated valve, a spring loaded-control valve, a surface-controlled valve, a hydraulically-controlled valve, a fiber optic-controlled valve, a sub-surface controlled valve, a manual valve, or combinations thereof.

34. The method of claim 30, further comprising a steam trap disposed between the steam injection conduit and the condensate recovery conduit.

35. The method of claim 30, further comprising a condensate pump disposed within the condensate recovery conduit.

36. The method of claim 35, further comprising a flash tank disposed within the condensate recovery conduit.

37. The method of claim 30, wherein the wellbore is a multilateral wellbore.

38. The method of claim 30, wherein the wellbore is an SAGD wellbore.

39. The method of claim 38, wherein the steam boiler is fired from hydrocarbons recovered from the wellbore.

40. The method of claim 30, further comprising means for recovering oil from the wellbore.

41. The method of claim 40, wherein the means for recovering oil comprises an oil recovery conduit.

42. The method of claim 41, wherein the steam injection conduit, the condensate recovery conduit, or both are disposed within the oil recovery conduit.

43. The method of claim 42, wherein the wellbore is an SAGD wellbore.

44. The method of claim 42, wherein the steam injection conduit and the condensate recovery conduit are arranged in a concentric configuration.

45. The method of claim 30, wherein the wellbore contacts a subterranean formation comprising oil and tar sands.

46. The method of claim 32, wherein the steam loop is capable of being automatically or manually switched from a closed loop system in which all of the control valves are closed to an injection system in which the control valves are regulated to control the flow of the steam into the subterranean formation.

47. The method of claim 32, wherein the one or more valves correspond to one or more heating zones in the subterranean formation such that the steam may be selectively injected into the heating zones.

48. The method of claim 47, wherein the one or more heating zones are isolated from each other by one or more isolation packers.

49. The method of claim 32, wherein one or more control valves are disposed in the oil recovery conduit.

50. The method of claim 1 further comprising: injecting fluid into the subterranean formation contacted by the wellbore for heating the subterranean formation, wherein the wellbore comprises a plurality of heating zones.

51. The method of claim 50, further comprising using a plurality of control valves disposed in the wellbore to regulate the flow of the fluid into the wellbore, wherein the valves correspond to the heating zones such that the fluid may be selectively injected into the heating zones.

52. The method of claim 51, wherein one or more of the control valves are thermally controlled.

53. The method of claim 50, wherein the heating zones are isolated from each other by isolation packers.

54. The method of claim 50, wherein the fluid comprises steam, heated water, or combinations thereof.

55. The method of claim 1 wherein the steam loop comprises a delivery conduit for injecting fluid into the subterranean formation penetrated by the wellbore, wherein the delivery conduit comprises a plurality of heating zones that correspond to heating zones in the wellbore.

56. The method of claim 55, wherein the heating zones are isolated by isolation packers.

57. The method of claim 55, further comprising control valves in the delivery conduit that correspond to the heating zones for selectively injecting the fluid into the respective heating zones.

58. The method of claim 1 further comprising: using the loop system disposed in the wellbore to controllably release fluid into the subterranean formation contacted by the wellbore for heating the subterranean formation.

59. The method of claim 58, wherein the fluid comprises steam, heated water, or combinations thereof.

60. The method of claim 58, further comprising using the loop system to return the same or different fluid from the wellbore.

61. The method of claim 59, wherein the loop system comprises one or more control valves for controlling the injection of the fluid into the subterranean formation.

62. The method of claim 61, wherein one or more of the control valves are thermally controlled.

63. The method of claim 61, wherein the loop system can be automatically or manually switched from a closed loop system in which all of the control valves are closed to an injection system in which one or more of the control valves are regulated open to control the flow of the fluid into the subterranean formation.

64. The method of claim 1 wherein the loop system is capable of controllably releasing fluid into the subterranean formation contacted by the wellbore for heating the subterranean formation.

65. The method of claim 64, wherein the fluid comprises steam, heated water, or combinations thereof.

66. The method of claim 64, wherein the loop system comprises one or more control valves for controlling the release of the fluid into the subterranean formation.

67. The method of claim 66, wherein one or more of the control valves are thermally controlled.

68. The method of claim 66, wherein the loop system is capable of being automatically or manually switched from a closed loop system in which all of the control valves are closed to an injection system in which one or more of the control valves are regulated open to control the flow of the fluid into the subterranean formation.

69. The method of claim 1 wherein the heat reduces the viscosity of the oil, thereby allowing the oil to flow by natural forces into a second wellbore.

70. The method of claim 69 wherein the natural force is gravity.

71. The method of claim 30 wherein the heat reduces the viscosity of hydrocarbons, thereby allowing the hydrocarbons to flow by natural forces into a second wellbore.

72. The method of claim 71 wherein the natural force is gravity.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The subject matter of this patent application is related to the commonly owned U.S. patent application Ser. No. 10/681,020 entitled "Thermally-Controlled Valves and Methods of Using the Same in a Well Bore," filed on Oct. 6, 2003 and incorporated by reference herein.

FIELD OF THE INVENTION

This invention generally relates to the production of oil. More specifically, the invention relates to methods of using a loop system to convey and distribute thermal energy into a wellbore for the stimulation of the production of oil in an adjacent subterranean formation.

BACKGROUND OF THE INVENTION

Many reservoirs containing vast quantities of oil have been discovered in subterranean formations; however, the recovery of oil from some subterranean formations has been very difficult due to the relatively high viscosity of the oil and/or the presence of viscous tar sands in the formations. In particular, when a production well is drilled into a subterranean formation to recover oil residing therein, often little or no oil flows into the production well even if a natural or artificially induced pressure differential exits between the formation and the well. To overcome this problem, various thermal recovery techniques have been used to decrease the viscosity of the oil and/or the tar sands, thereby making the recovery of the oil easier.

One such thermal recovery technique utilizes steam to thermally stimulate viscous oil production by injecting steam into a wellbore to heat an adjacent subterranean formation. Typically, the highest demand placed on the boiler that produces the steam is at start-up when the wellhead, the casing, the tubing used to convey the steam into the wellbore, and the earth surrounding the wellbore have to be heated to the boiling point of water. Until the temperature of these elements reach the boiling point of water, at least a portion of the steam produced by the boiler condenses, reducing the quality of the steam being injected into the wellbore. The condensate present in the steam being injected into the wellbore acts as an insulator and slows down the heat transfer from the steam to the wellbore, the subterranean formation, and ultimately, the oil. As such, the oil might not be heated adequately to stimulate production of the oil. In addition, the condensate might cause water logging to occur.

Further, the steam is typically injected such that it is not evenly distributed throughout the well bore, resulting in a temperature gradient along the well bore. Areas that are hotter and colder than others, i.e., hot spots and cold spots, thus undesirably form in the subterranean formation. The cold spots lead to the formation of pockets of oil that remain immobile. Further, the hot spots allow the steam to break through the formation and pass directly to the production well, creating a path of least resistance for the flow of steam to the production well. Consequently, the steam bypasses a large portion of the oil residing in the formation, and thus fails to heat and mobilize the oil.

A need therefore exists to reduce the amount of condensate in the steam being injected into a subterranean formation and thereby improve the production of oil from the subterranean formation. It is also desirable to reduce the amount of hot spots and cold spots in the subterranean formation.

SUMMARY OF THE INVENTION

According to some embodiments, methods of treating a wellbore comprise using a loop system to heat oil in a subterranean formation contacted by the wellbore. The loop system conveys steam down the wellbore and returns condensate from the wellbore. A portion of the steam in the loop system may be injected into the subterranean formation using one or more injection devices, such as a thermally-controlled valve (TCV), disposed in the loop system. Alternatively, only heat and not steam may be transferred from a closed loop system into the subterranean formation. The condensate returned from the wellbore may be re-heated to form a portion of the steam being conveyed by the loop system into the wellbore. Heating the oil residing in the subterranean formation reduces the viscosity of the oil so that it may be recovered more easily. The oil and the condensate may be produced from a common wellbore or from different wellbores.

In some embodiments, a system for treating a wellbore comprises a steam loop disposed within the wellbore. The steam loop comprises a steam boiler coupled to a steam injection conduit coupled to a condensate recovery conduit. The steam loop may also comprise one or more injection devices, such as TCV's, in the steam injection conduit. The system for treating the wellbore may further include an oil recovery conduit for recovering oil from the wellbore. The steam loop and the oil recovery conduit may be disposed in a concurrent wellbore or in different wellbores such as steam-assisted gravity drainage (SAGD) wellbores.

In additional embodiments, methods of servicing a wellbore comprise injecting fluid into a subterranean formation contacted by the wellbore for heating the subterranean formation, wherein the wellbore comprises a plurality of heating zones.

In yet more embodiments, methods of servicing a wellbore comprise using a loop system disposed in the wellbore to controllably release fluid into a subterranean formation contacted by the wellbore for heating the subterranean formation.

DESCRIPTION OF THE DRAWINGS

The invention, together with further advantages thereof, may best be understood by reference to the following description taken in conjunction with the accompanying drawings in which:

FIG. 1A depicts an embodiment of a loop system that conveys steam into a multilateral wellbore and returns condensate from the wellbore, wherein the loop system is disposed above an oil production system.

FIG. 1B depicts a detailed view of a heating zone in the loop system shown in FIG. 1A.

FIG. 2A depicts another embodiment of a loop system that conveys steam into a monolateral wellbore and returns condensate from the wellbore, wherein the loop system is co-disposed with an oil production system.

FIG. 2B depicts a detailed view of a portion of the loop system shown in FIG. 2A.

FIG. 3A depicts another embodiment of a portion of the loop system originally depicted in FIG. 1A, wherein a steam delivery conduit and a condensate recovery conduit are arranged in a concentric configuration.

FIG. 3B depicts another embodiment of a portion of the loop system originally depicted in FIG. 2A, wherein a steam delivery conduit, a condensate recovery conduit, and an oil recovery conduit are arranged in a concentric configuration.

FIG. 4 depicts an embodiment of a steam loop that may be used in the embodiments shown in FIG. 1A and FIG. 2A.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

As used herein, a "loop system" is defined as a structural conveyance (e.g., piping, conduit, tubing, etc.) forming a flow loop and circulating material therein. In an embodiment, the loop system coveys material downhole and return all or a portion of the material back to the surface. In an embodiment, a loop system may be used in a well bore for conveying steam into a wellbore and for returning condensate from the wellbore. The steam in the wellbore heats oil in a subterranean formation contacted by the wellbore, thereby reducing the viscosity of the oil so that it may be recovered more easily. The loop system comprises a steam loop disposed in the wellbore that includes a steam boiler coupled to a steam injection conduit coupled to a condensate recovery conduit. The steam loop may optionally comprise control valves and/or injection devices for controlling the injection of the steam into the subterranean formation. When control valves are disposed in the steam loop, the loop system can automatically and/or manually be switched from a closed loop system in which some or all of the valves are closed (and thus all or substantially all of the material, e.g., water in the form of steam and/or condensate, is circulated and returned to the surface) to an injection system in which the valves are regulated to control the flow of the steam into the subterranean formation. It is understood that "subterranean formation" encompasses both areas below exposed earth or areas below earth covered by water such as sea or ocean water.

In some embodiments, the steam loop may be employed to convey (e.g., circulate and/or inject) steam into the well bore and to recover condensate from the well bore concurrent with the production of oil. In alternative embodiments, a "huff and puff" operation may be utilized in which the steam loop conveys steam into the wellbore in sequence with the production of oil. As such, heat can be transferred into the subterranean formation and oil can be recovered from the formation in different cycles. Other chemicals as deemed appropriate by those skilled in the art may also be injected into the wellbore simultaneously with or alternating with the cycling of the steam into the wellbore. It is understood that the steam used to heat the oil in the subterranean formation may be replaced with or supplemented by other heating fluids such as diesel oil, gas oil, molten sodium, and synthetic heat transfer fluids, e.g., THERMINOL 59 heat transfer fluid which is commercially available from Solutia, Inc., MARLOTHERM heat transfer fluid which is commercially available from Condea Vista Co., and SYLTHERM and DOWTHERM heat transfer fluids which are commercially available from The Dow Chemical Company.

FIG. 1A illustrates an embodiment of a loop system for conveying steam into a wellbore and returning condensate from the well bore. As shown in FIG. 1A, the loop system may be employed in a multilateral configuration comprising SAGD wellbores. In this configuration, two lateral SAGD wellbores extend from a main wellbore and are arranged one above the other. Alternatively, the loop system may be employed in SAGD wellbores having an injector wellbore independent from a production wellbore. The SAGD wellbores may be arranged in parallel in various orientations such as vertically, slanted (useful at shallow depths), or horizontally, and they may be spaced sufficiently apart to allow heat flux from one to the other.

The system shown in FIG. 1A comprises a steam boiler 10 coupled to a steam loop 12 that runs from the surface of the earth and down into an upper lateral SAGD wellbore 14 that penetrates a subterranean formation 16. The steam boiler 10 is shown above the surface of the earth; however, it may alternatively be disposed underground in wellbore 14 or in a laterally enclosed space such as a depressed silo. When steam boiler 10 is disposed underground, water may be pumped down to boiler 10, and a surface heater or boiler may be used to pre-heat the water before conveying it to boiler 10. The steam boiler 10 may be any known steam boiler such as an electrical fired boiler to which electricity is supplied or an oil or natural gas fired boiler. In an alternative embodiment, steam boiler 10 may be replaced with a heater when a heating transfer medium other than steam, e.g., water, antifreeze, and/or sodium, is conveyed into wellbore 14.

The steam loop 12 further includes a steam injection conduit 13 connected to a condensate recovery conduit 15 in which a condensate pump, e.g., a downhole steam-driven pump, is disposed (not shown).

Optionally, one or more valves 20 may be disposed in steam loop 12 for injecting steam into well bore 14 such that the steam can migrate into subterranean formation 16 to heat the oil and/or tar sand therein. Each valve 20 may be disposed in separate isolated heating zones of well bore 14 as defined by isolation packers 18. The valves 20 are capable of selectively controlling the flow of steam into corresponding heating zones of subterranean formation 16 such that a uniform temperature profile may be obtained across subterranean formation 16. Consequently, the formation of hot spots and cold spots in subterranean formation 16 are avoided. Examples of suitable valves for use in steam loop 12 include, but are not limited to, thermally-controlled valves, pressure-activated valves, spring loaded-control valves, surface-controlled valves (e.g., an electrically-driven/controlled/operated valve, a hydraulically-driven/controlled/operated valve, and a fiber optic-controlled/actuated/operated valve), sub-surface controlled valves (a tool may be lowered in the wellbore to shift the valve's position), manual valves, and combinations thereof. Additional disclosure related to thermally-controlled valves and methods of using them in a wellbore can be found in the copending patent application entitled "Thermally-Controlled Valves and Methods of Using the Same in a Well Bore," filed concurrently herewith.

As depicted in FIG. 1A, the loop system described above may also include a means for recovering oil from subterranean formation 16. This means for recovering oil may comprise an oil recovery conduit 24 disposed in a lower wellbore 22, for example, in a lower multilateral SAGD wellbore that penetrates subterranean formation 16. The oil recovery conduit 24 may be coupled to an oil tank 28 located above the surface of the earth or underground near the surface of the earth. The oil recovery conduit 24 comprises a pump 26 for displacing the oil from wellbore 22 to oil tank 28. Examples of suitable pumps for conveying the oil from wellbore 22 include, but are not limited to, progressive cavity pumps, jet pumps, and gas-lift, steam-powered pumps. Although not shown, various pieces of equipment may be disposed in oil recovery conduit 24 for treating the produced oil before storing it in oil tank 28. For instance, the produced oil usually contains a mixture of oil, condensate, sand, etc. Before the oil is stored, it may be treated by the use of chemicals, heat, settling tanks, etc. to let the sand fall out. Examples of equipment that may be employed for this treatment include a heater, a treater, a heater/treater, and a free-water knockout tank, all of which are known to those skilled in the art. Also, a downhole auger that may be employed to produce the sand that usually accompanies the oil and thereby prevent a production well from "sanding up" is disclosed in U.S. patent application Ser. No. 2003/0155113 A1, published Aug. 21, 2003 and entitled "Production Tool," which is incorporated by reference herein in its entirety.

In addition, the heat generated by the produced oil may be recovered via a heat exchanger, for example, by circulating the oil through coils of steel tubing that are immersed in a tank of water or other fluid. Further, the water being fed to boiler 10 may be pumped through another set of coils. The heat is transferred from the produced fluid into the tank water and then to the feed water coils to help heat up the feed water. Transferring the heat from the produced oil to the feed water in this manner increases the efficiency of the loop system by reducing the amount of heat that boiler 10 must produce to convert the feed water into steam. It is understood that various pieces of equipment also may be disposed in steam loop 12, wellbores 14 and 22, and subterranean formation 16 as deemed appropriate by one skilled in the art.

Although not shown, one or more valves optionally may be disposed in oil recovery conduit 24 for regulating the production of fluids from wellbore 22. Moreover, valves may be disposed in isolated heating zones of wellbore 22 as defined by isolation packers 18 and/or 29 (see FIG. 1B). The valves are capable of selectively preventing the flow of steam into oil recovery conduit 24 so that the heat from the injected steam remains in wellbore 22 and subterranean formation 16. Consequently, the heat energy remains in subterranean formation 16, which reduces the amount of energy (e.g. electricity or natural gas) required to heat boiler 10. Examples of suitable valves for use in oil recovery conduit 24 include, but are not limited to, steam traps, thermally-controlled valves, pressure-activated valves, spring loaded control valves, surface controlled valves (e.g., an electrically-driven/controlled/operated valve, a hydraulically-driven/controlled/operated valve, and a fiber optic-controlled/actuated/operated valve), sub-surface controlled valves (a tool may be lowered in the wellbore to shift the valve's position), and combinations thereof. Additional information related to the use of such valves can be found in the copending TCV application referenced previously.

Isolations packers 18 may also be arranged in wellbore 14 and/or wellbore 22 to isolate different heating zones therein. The isolation packers 18 may comprise, for example, ethylene propylene diene monomer (EPDM), perfluoroelastomer (FFKM) materials such as KALREZ perfluoroelastomer available from DuPont de Nemours & Co., CHEMRAZ perfluoroelastomer available from Greene Tweed & Co., PERLAST perfluoroelastomer available from Precision Polymer Engineering Ltd., and ISOLAST perfluoroelastomer available from John Crane Inc., polyetheretherketone (PEEK), and polyetherketoneketone (PEKK).

FIG. 1B illustrates a detailed view of an isolated heating zone in the loop system shown in FIG. 1A. As shown, dual tubing/casing isolation packers 18a may surround steam injection conduit 13 and condensate recovery conduit 15, thereby forming seals between those conduits and against the inside wall of a casing 30a (or a slotted liner, screen, the wellbore, etc.) that supports subterranean formation 16 and prevents it from collapsing into wellbore 14. The isolation packers 18a prevent steam from passing from one heating zone to another, allowing the steam to be transferred to corresponding heating zones of formation 16. The isolation packers 18a thus serve to ensure that heat is more evenly distributed throughout formation 16. Thus, isolation packers 18a create a heating zone in subterranean formation 16 that extends from wellbore 14 (the steam injection wellbore) to wellbore 22 (oil production wellbore) and from the top to the bottom of the oil reservoir in subterranean formation 16. In addition, isolation packers 18a prevent steam and other fluids (e.g., heated oil) from flowing in the annulus (or gap) between steam injection conduit 13, oil recovery conduit 24, and the inside of casing 30a. Isolation packers 18b also may surround oil recovery conduit 24, thereby forming a seal between that conduit and the inside wall of a casing 30b (or a slotted liner, a screen, the wellbore, etc.) that supports formation 16 and prevents it from collapsing into wellbore 22. The casing 30b may have holes (or slots, screens, etc.) to permit the flow of oil into oil production conduit 24. The isolation packers 18b prevent steam and other fluids (e.g., heated oil) from flowing in the annulus between oil recovery conduit 24 and the inside of casing 30B. Additional external casing packers 29, which may be inflated with cement, drilling mud, etc., may form a seal between the outside of casing 30a and the wall of wellbore 14 and between the outside of casing 30b and the wall of wellbore 22. Sealing the space between the outside wall of casings 30a and 30b and the wall of the wellbores 14 and 22, respectively, is necessary to prevent steam and other fluids such as heated oil from flowing from one heating zone (depicted by the Heat Zone Boundary lines) to another.

Turning back to FIG. 1A, using the loop system comprises first supplying water to steam boiler 10 to form steam having a relatively high temperature and high pressure, followed by conveying the steam produced in boiler 10 into upper wellbore 14 using steam loop 12. The steam passes from steam boiler 10 into wellbore 14 through steam injection conduit 13. Initially, the earth surrounding wellbore 14, steam injection conduit 13, valves 20, and any other structures disposed in wellbore 14 are below the temperature of the steam. As such, a portion of the steam condenses as it flows through steam injection conduit 13. The steam and the condensate may be re-circulated in steam loop 12 until a desired event occurs, e.g., the temperature of wellbore 14 is heated to at least the boiling point of water (i.e., 212.degree. F. at atmospheric pressure). Further, the steam may be re-circulated until it is saturated or superheated such that it contains the optimum amount of heat. In an embodiment, steam loop 12 is operated during this time as a closed loop system by closing all of the valves 20. In another embodiment, all of the valves except the one farthest from the surface remain closed until a desired event occurs. Then that valve closes, and the rest of the valves open. In this embodiment, a single tubing string could be used to convey the steam downhole to the one open valve, and the wellbore casing/liner could be used to convey condensate back to the surface. The condensate could be cleaned and reused by re-heating it using a heat exchanger and/or an inexpensive boiler. Using a single tubing string may be less expensive than using multiple tubing strings with packers therebetween. Recirculating the condensate and waiting until a desired event has occurred before injecting steam into the wellbore conserves energy and thus reduces the operation costs of the loop system, such as the cost of water and fuel for the boiler. In addition, this method prevents the injection of excessive water into the formation that would eventually be produced and thus would have to be separated from the oil for disposal or re-use.

The steam loop 12 may be switched from a closed loop mode to an injection mode manually or automatically (i.e, when valves 20 are thermally-controlled valves) in response to measured or sensed parameters. For example, a downhole temperature, a temperature of the steam/condensate in wellbore 14, a temperature of the produced oil, and/or the amount of condensate could be measured, and valves 20 could be adjusted in response to such measurements. Various methods may be employed to take the measurements. For example, a fiber optic line may be run into wellbore 14 before steam injection begins. The fiber optic line has the capability of reading the temperature along every single inch of wellbore 14. In addition, hydraulic or electrical lines could be run into wellbore 14 for sensing temperatures therein. Another method may involve measuring the slight change in pH between the steam and the condensate to determine whether the steam is condensing such that the fuel consumption of boiler 10 can be controlled. A control loop (e.g., intelligent well completions or smart wells) may be utilized to implement the switching of steam loop 12 from a closed loop mode to an injection mode and vice versa.

In the injection mode, near-saturated steam may be selectively injected into the heating zones of subterranean formation 16 by controlling valves 20. Valves 20 may regulate the flow of steam into wellbore 14 based on the temperature in the corresponding heating zones of subterranean formation 16. That is, valves 20 may open or increase the flow of steam into corresponding heating zones when the temperature in those heating zones is lower than desired. However, valves 20 may close or reduce the flow of steam into corresponding heating zones when the temperature in those zones is higher than desired. The opening and closing of valves 20 may be automated or manual in response to measured or sensed parameters as described above. As such, valves 20 can be controlled to achieve a substantially uniform temperature distribution across subterranean formation 16 such that all or a substantial portion of the oil in formation 16 is heated. In an embodiment, valves 20 comprise TCV's that automatically regulate flow in response to the temperature in a given heating zone. Additional details regarding such an embodiment are disclosed in the copending TCV application referenced previously.

Further, valves 20 may comprise steam traps that allow the steam to flow into wellbore 14 while inhibiting the flow of condensate into wellbore 14. Instead, the condensate may be returned from wellbore 14 back to steam boiler 10 via condensate return conduit 15, allowing it to be re-heated to form a portion of the steam flowing into wellbore 14. The condensate may contain dissolved solids that are naturally present in the water being fed to steam boiler 10. Any scale that forms on the inside of steam injection conduit 13 and condensate return conduit 15 may be flushed from steam loop 12 by reversing the flow of the steam and condensate in steam loop 12. Other methods of scale inhibition and removal known to those skilled in the art may be used too.

Removing the condensate from steam injection conduit 13 such that it is not released with the steam into wellbore 14 reduces the possibility of experiencing water logging and improves the quality of the steam. However, after steam has been injected into wellbore 14 for some time, the area near wellbore 14 may become water logged due to a variety of reasons such as temporary shutdown of the boiler for maintenance. To overcome this problem, the loop system may be switched to the closed loop mode, wherein injection valves are closed and steam is circulated rather than injected as described in detail below. The steam may be heated to a superheated state such that a vast amount of heat is transferred into the water logged area, causing the fluids therein to become superheated and expand deep into subterranean formation 16. Other means known to those skilled in the art may also be employed to overcome the water logging problem.

The quality of the steam injected into wellbore 14 can be adjusted by controlling the steam pressure and temperature of the entire system, or the quality of the steam injected into each heating zone of subterranean formation 16 may be adjusted by changing the temperature and pressure set points of the control valves 20. Injecting a higher quality steam into wellbore 14 often provides for better heat transfer from the steam to the oil in subterranean formation 16. Further, the steam has enough stored heat to convert a portion of the condensed steam and/or flash near wellbore 14 into steam. Therefore, the amount of heat transferred from the steam to the oil in subterranean formation 16 is sufficient to render the oil mobile.

According to alternative embodiments, steam loop 12 is a closed loop that releases thermal energy but not mass into wellbore 14. The steam loop 12 either contains no control valves, or the control valves 20 are closed such that steam cannot be injected into wellbore 14. As the steam passes through steam injection conduit 13, heat may be transferred from the steam into the different zones of wellbore 14 and is further transferred into corresponding heating zones of subterranean formation 16.

In response to being heated by the steam circulated into wellbore 14, the oil residing in the adjacent subterranean formation 16 becomes less viscous such that gravity pulls it down to the lower wellbore 22 where it can be produced. Also, any tar sand present in subterranean formation becomes less viscous, allowing oil to flow into lower wellbore 22. The oil that migrates into wellbore 22 may be recovered by pumping it through oil recovery conduit 24 to oil tank 28. Optionally, released deposits such as sand may also be removed from subterranean formation 16 by pumping the deposits from wellbore 22 via oil recovery conduit 24 along with the oil. The deposits may be separated from the oil in the manner described previously.

FIG. 2A illustrates another embodiment of a loop system similar to the one depicted in FIG. 1A except that the oil and the condensate are recovered in a common well bore. The system comprises a steam boiler 30 coupled to a steam loop 32 that runs from the surface of the earth down into wellbore 34 that penetrates a subterranean formation 36. The steam boiler 30 is shown above the surface of the earth; however, it may alternatively be disposed underground in wellbore 34 or in a laterally enclosed space such as a depressed silo. When steam boiler 30 is disposed underground, water may be pumped down to boiler 30, and a surface heater or boiler may be used to pre-heat the water before conveying it to boiler 30. The steam boiler 30 may be any known steam boiler such as an electrical fired boiler to which electricity is supplied or an oil or natural gas fired boiler. As in the embodiment shown in FIG. 1A, steam boiler 30 may be replaced with a heater.

The steam loop 32 may include a steam injection conduit 31 connected to a condensate recovery conduit 33. In addition to steam loop 32, an oil recovery conduit 42 for recovering oil from subterranean formation 36 extends from an oil tank 46 down into wellbore 34. The oil tank 46 may be disposed above or below the surface of the earth. If steam boiler 30 is disposed in wellbore 34, the water being fed to boiler 30 may be pre-heated by the oil being produced in wellbore 34. As shown, oil recovery conduit 42 may be interposed between steam injection conduit 31 and condensate recovery unit 33. It is understood that other configurations of steam loop 32 and oil recovery conduit 42 than those depicted in FIG. 2 may be employed. For example, a concentric conduit configuration, a multiple conduit configuration, and so forth may be used. A pump 44 may be disposed in oil recovery conduit 42 for displacing oil from wellbore 34 to oil tank 46. Examples of suitable pumps for conveying the oil from wellbore 34 include, but are not limited to, progressive cavity pumps, jet pumps, and gas-lift, steam-powered pumps. Although not shown, a pump, e.g., a steam powered condensate pump, also may be disposed in condensate recovery conduit 33. Like in the embodiment shown in FIG. 1, various types of equipment may be disposed in steam loop 32, oil recovery conduit 42, wellbore 34, and subterranean 36. Also, the produced oil may be hot, and it may be cooled using a heat exchanger as described in the previous embodiment.

Optionally, one or more valves 40 may be disposed in steam loop 32 for injecting steam into wellbore 34 such that the steam can migrate into subterranean formation 36 to heat the oil and/or tar sand therein. The valves 40 may be disposed in isolated heating zones of wellbore 34 as defined by isolation packers 38. The valves 40 are capable of selectively controlling the flow of steam into corresponding heating zones of subterranean formation 36 such that a more uniform temperature profile may be obtained across subterranean formation 36. Consequently, the formation of hot spots and cold spots in subterranean formation 36 are reduced. Additionally, one or more valves 40 may be disposed in oil recovery conduit 42 for regulating the production of fluids from wellbore 34. The valves 40 may be disposed in isolated heating zones of wellbore 34, as defined by isolation packers 38 and/or 39. The valves 40 are capable of selectively preventing the flow of steam into oil recovery conduit 42 so that the heat from the injected steam remains in wellbore 34 and subterranean formation 36. Consequently, the heat energy remains in the subterranean formation 36, thus reducing the amount of energy (e.g. electricity or natural gas) required to heat boiler 30. Examples of suitable valves for use in steam loop 32 and oil recovery conduit 42 include, but are not limited to, thermally-controlled valves, pressure-activated valves, spring loaded control valves, surface controlled valves (e.g., an electrically-driven/controlled/operated valve, a hydraulically-driven/controlled/operated valve, and a fiber optic-controlled/actuated/operated valve), sub-surface controlled valves (a tool may be lowered in the wellbore to shift the valve's position), and combinations thereof. Additional disclosure related to thermally-controlled valves and methods of using them in a wellbore can be found in the previously referenced copending TCV patent application.

Isolations packers 38 may also be arranged in wellbore 34 to isolate different heating zones of the wellbore. The isolation packers 38 may comprise, for example, ethylene propylene diene monomer (EPDM), perfluoroelastomer (FFKM) materials such as KALREZ perfluoroelastomer available from DuPont de Nemours & Co., CHEMRAZ perfluoroelastomer available from Greene Tweed & Co., PERLAST perfluoroelastomer available from Precision Polymer Engineering Ltd., and ISOLAST perfluoroelastomer available from John Crane Inc., polyetheretherketone (PEEK), and polyetherketoneketone (PEKK).

FIG. 2B illustrates a detailed view of an isolat