US3498381A - Method for injection of hot fluids into an underground formation - Google Patents

Method for injection of hot fluids into an underground formation Download PDF

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US3498381A
US3498381A US747726A US3498381DA US3498381A US 3498381 A US3498381 A US 3498381A US 747726 A US747726 A US 747726A US 3498381D A US3498381D A US 3498381DA US 3498381 A US3498381 A US 3498381A
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fluid
hot
injected
steam
injection
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Robert C Earlougher Jr
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Marathon Oil Co
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
    • E21B36/003—Insulating arrangements

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  • This invention concerns theA use of a hot fluid such as steamfor the recovery of crude oil from subterranean formations.
  • Steam fiooding is a well Iknown,.important method forrecovering petroleum. But, unfortunately, steam fiooding has oftentimes ⁇ proved to be uneconomic because of the inefficiency of the process. For instance, a problem which has. caused-considerable concern involves trying yto reduce heat losses of the linjected hot fluid to improve the overall thermal efiiciency of the Operation. Specifically, Ait is important that the steam injected into the formation has sufficient latentheat to vtransfer to the crude oil to improveqits mobility for recovery purposes.
  • Applicant has discovered ⁇ a process to improve the thermal eficiency of a hot -fluid oil recovery process by limiting heat losses to the well casing and adjacent formation and, in so doing, transferring a substantially greater percentage of the enthalpy or hot fluid potential to the subterranean formation.
  • This invention embodies two or more concentric tubing strings within a well casing.
  • Two preferred embodiments of injection methods are hereinafter more fully described .as the preferred embodiments of this invention, but in general the hot fluid such as steam is injected into a first tubing string which is in fluid communication with a sub terranean oil-bearing formation (herein also termed formation).
  • a second tubing string is partitioned from the formation by a packer or other means so that a second fluid, cool with respect to the first injected fluid, is injected into the outer tubing-casing annulus and returned to the surface through the second tubing. In returning to the surface, the second fluid is in contact with the first tubing string, and as a result, absorbs heat (Le.
  • the recovered second injected fluid ⁇ will be substantially hotter than when previously injected.
  • y heat losses from the injected hot uid are transferred tothe second fiuid.
  • This recovered second fiuid is utilized by Vfurther heating it to obtain a hot fluid suitable for injection into the subterranean formation.
  • FIGURE l BRIEF DESCRIPTION OF THE DRAWINGS PREFERRED EMBODIMENTS OE THE INVENTION
  • injecting hot fluid into a subterranean oil-bearing formation is preferably carried out utilizing two tubing strings and well casing as illustrated in FIGURE l. It is understood that in FIGURES 1 and 2 even though the cool uid is shown to be injected through the casing-tubing annulus 54, and returned via an inner tubing, it is equally conceivable that the reverse directions may be employed. With two tubing strings Within a well casing, there are a total of four combinations of fluid flow, two for each of the embodiments in FIGURES 1 and 2.
  • tubing strings and well casing theymay be generically described as conduits without devating vfrom the intended scope of the invention.
  • steam is generated in ⁇ steam generator 30, fed by make-up water controlled ⁇ by valve 72 and returned second injected fluid controlled by valve 10, transferred through valve 12 and then flowed through conduit 32 under pressure, the pressure being indicated by pressure valve 28.
  • Conduit 32 is connected to first injection tubing string 2 so that the steam Will travel into the j subterranean oil-bearingrformation and then through perforations 20.
  • conventional methods of steam iiooding sweep the reservoir of oil to at least one production well where the oil is recovered.
  • the injected hot uid is steam as embodied in this figure, however, other economical drive fluids may be utilized so long as they possess the required latent heat to effectively sweep the reservoir of oil.
  • the temperature is preferably from about 300 to about 700 F. and more preferably from about 380 to about 570 F.
  • the quality of the steam will preferably be from about 50 to about 100%.
  • Ihe injection rates will preferably be from about 2,000 to about 25,000 lb./hr., and more preferably from about 8,000 to about 20,000 1b./ hr.
  • hot uids examples include hot water, superheated steam, and like materials, and any of'the foregoing with compatible additives such as corrosion inhibito, surfactants, bactericides, etc.
  • the steam injection pressure will be a function of the conditions of the particular reservoir, i.e. depth and permeability of the formation, volume of the reservoir to be swept, diameter of the injection tubing string, output of the steam generator, rate of sweeping, etc.
  • injection pressures include preferably from about 70 to about 3000 p.s.i.a. and more, and more preferably from about 200 to about 1200 p.s.i.a.
  • a cool fluid with respect to the steam, is injected concurrently with respect to the steam into conduit 34 through valve 8 into the annulus formed by second tubing string 6 and well casing 4.
  • the annular tubing strings are preferably concentric and are partitioned 4from formation 16 and interior l64 of tubing string 2 by packer 18.
  • the second tubing string l6 and tubing string 2 form annulus 62 which is in uid communication with annulus 54. This allows the cool fluid injected in annulus 54 to travel down annulus 54 and up annulus y62.
  • the communication between the two annuli is effected by leaving a space below second tubing string 6 and packer 18.
  • the injected cool fluid is preferably water at about ambient temperature.
  • This cool fluid may contain additives compatible with the fluid, examples include corrosion inhibitors, surfactants, etc. as desired.
  • Cool uid in annulus 62 is iiowing countercurrently to steam traveling through tubing 2; as a result, the enthalpy of the cool iiuid increases as heat transfers from the steam. Near the y top of annulus 62, the cool uid has obtained its highest the steam generator is obvious since less heat will have to be provided to the hotter cool fluid to elevate its temperature to a suitable level to produce steam in steam generator 30. This improves the economics of the operation.
  • casing 4 is cemented in place with either bonded or nonbonded cement 14.
  • Tubing string 2 may also be insulated to insure proper heat transfer between the cool uid and the steam. Again, the amount and type of insulation 22 to be used is dependent upon the parameters of the particular system.
  • FIGURE 2 illustrates two tubing strings within well casing 4. Steam is generated as in FIGURE 1 in steam generator 30 and sent through the annular region 52 of tubing string ⁇ 60 by opening valve 40.
  • Tubing string 60 is in lluid communication with the subterranean oil-bearing formation via annular spacing 52 and perforated holes 20 within casing 4.
  • Packer 18 partitions 0r Substantially isolates the annular region 54 between casing 4 and tubing string 60.
  • Annular space 54 is in uid communication with steam generator 30 via second tubing string '66 via special tubing shoe S8. As the cool fluid is injected through conduit 68 via valve 44, it traverses the annular region 54, connecting shoe 58, and returns to the surface through space 56 within tube y66.
  • Tubing shoe 58 comprises a plurality of pipelike connections between annular region 54 and tubing interior 516. It is important that the cool fluid in annular region 54 be solely in uid communication with region 56 via passages 58.
  • the hot fluid injection tubing string ⁇ 60 may be insulated from the circulating cool fluid by insulation 2-2.
  • the desirability of insulating and the extent of insulation tol be effected is dependent on the particular parameters of the reservoir and injection well system. It should also be apparent that the rate of injection of cool fluid will determine how hot the returned hotter cool fluid will be. The injection rate should be determined so that minimum heat loss to the entire system will occur.
  • a well of preferably less than 3000 ft. and more preferably less than 1000 ft. in depth will most efficiently be run, at a cool fluid injection rate of from about 2,000 to about 25,000 and more preferably from about 8,000 to about 20,000 lb./hr.
  • a casing and packer are set in an injection well at a depth of 492 feet.
  • the inner diameter of the casing is 5.299 inches and the outer diameter is 6.000 inches.
  • a first tubing string is inserted and centrally disposed Within the casing and has an inner diameter of 1.880 inches, roughness 0.00065 inch, and an outer diameter of 1.995 inches.
  • the insulation diameter of the first tubing string is 3.000 inches and the thermal conductivity of the insulation is 3.0 B.t.u./ (hr. ft. F.) and the thermal conductivity of the pipe is 26.5 B.t.u./ (hr. ft. F.).
  • the second tubing string having an inner diameter of 3.958 inches and an outer diameter of 4.500 inches is placed concentric with the first tubing string, and also has a thermal conductivity of 26.5 B.t.u./ (hr. ft. F.).
  • the thermal conductivity of the earth surrounding the well bore is 1.4 B.t.u./ (hr. ft. F.) and the thermal-diifusivity of the earth s 0.04 ft2/hr.
  • the geothermal temperature at the surface is 60 F. and the geothermal temperature gradient is 0.0207" lF./ft. Eighty percent quality steam at 5l8.2 F. is injected at a rate of 18,500 lb./hr.
  • mi fBased on natural gas as fuel at $0.30/m.c.f, u B.t.u.]

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  • Physics & Mathematics (AREA)
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Description

March 3, 1970 R c EARLouGHER, JR 3,498,331
METHOD FOR INJECTION OF HOT FLUIDS INTO AN UNDERGROUND FORMATION 2 Sheets-Sheet 1 Filed July 25, 1968 /NVE/VTO? ROBERT C. EARLOUGHER, JR.
ATTORNEY March 3, 1970 R. c. EARLOUGHER. JR 3,498,381
METHOD FOR INJECTION OF HOT FLUIDS INTO AN UNDERGROUND FORMATION Filed July 25, 1968 2 Sheets-Sheet 2 MO f, Dun/ /NVEA/'O? ROBERT C. EARLOUGHER, JR.
United States Patent 3,498,381 METHOD FOR INJECTION OF HOT FLUIDS INTO AN UNDERGROUND FORMATION Robert C. Earlougher, Jr., Littleton, Colo., assignor to Marathon Oil Company, Findlay, Ohio, a corporation of Ohio Filed July 25, 1968, Ser. No. 747,726
. Int. Cl. E21b 43/24 U.S. Cl. 166-303 j 12 Claims ABSTRACT OF THE DISCLOSURE The thermal efiiciency of a hot fluidk injection system for the recovery of hydrocarbons from subterranean oil-bearing formations is improved by inserting two or. more con` centric tubular strings within a casing wherein hot fluids are injected into a first tubing string-which is in uid communication with the oil-bearingformation, and a second tubing and the annular space between the well casing and the outer tubing is partitioned from the oil-bearing formation by a packer or other means so that acool iuid may be injected into theouter tubing-casing annulus and returned to the surface through the second tubing. As the cool fluid approaches the surface through the second tubing string its enthalpy is increased by heat transfer from the hot injected uids through the first tubing string. r The cool fluid circulation system described above serves to insulate the injected hot fluids fromtthe formation as well as. act as a preheater of fluids for the production of -hot fluids on. the surface.
` BACKGROUND OF THE INVENTION This invention concerns theA use of a hot fluid such as steamfor the recovery of crude oil from subterranean formations. Steam fiooding is a well Iknown,.important method forrecovering petroleum. But, unfortunately, steam fiooding has oftentimes `proved to be uneconomic because of the inefficiency of the process. For instance, a problem which has. caused-considerable concern involves trying yto reduce heat losses of the linjected hot fluid to improve the overall thermal efiiciency of the Operation. Specifically, Ait is important that the steam injected into the formation has sufficient latentheat to vtransfer to the crude oil to improveqits mobility for recovery purposes. -j Previous processes'for steam injection have had such high attendant heat losses between the -injection point at the surface and the subterranean formation thatmuch of the latent heat of the-steam 'has been transferred to the formation through the well casing en route to the oilbearing formation.-For instance, steam when pumped into a formation through an` injection well can lose about 20% of its heat content by the time ,it has descended approximately 2000 feet. In some deep well systems, the steam may lose practically all -of its latent heat. Thus, the re-l sulting injected fluid may be hot water rather than steam. Also, thermal stresses etc. are imparted to the casing by high temperatures of the fluid and this can cause failure of the casing which may necessitate its replacement. Furthermore, the hot casing loses heat tothe cooler formation. These are some of the problems which traditional steam flooding techniques present.- Y
Applicant has discovered `a process to improve the thermal eficiency of a hot -fluid oil recovery process by limiting heat losses to the well casing and adjacent formation and, in so doing, transferring a substantially greater percentage of the enthalpy or hot fluid potential to the subterranean formation.
3,498,381 Patented Mar. 3, 1970 ICC SUMMARY OF THE INVENTION This process is essentially an improved hot fluid injection oil recovery process wherein the improvement lies in the increased thermal efficiency of the injection system. Specifically, excessive heat losses to the formation by heat transfer through the well casing from the hot injected fluid are obviated. More specifically, the heat content, i.e. original enthalpy of the steam generated at the surface is retained to a much higher degree so that a larger heat input can be effected in the subterranean oil-bearing formation.
vThis invention embodies two or more concentric tubing strings within a well casing. Two preferred embodiments of injection methods are hereinafter more fully described .as the preferred embodiments of this invention, but in general the hot fluid such as steam is injected into a first tubing string which is in fluid communication with a sub terranean oil-bearing formation (herein also termed formation). A second tubing string is partitioned from the formation by a packer or other means so that a second fluid, cool with respect to the first injected fluid, is injected into the outer tubing-casing annulus and returned to the surface through the second tubing. In returning to the surface, the second fluid is in contact with the first tubing string, and as a result, absorbs heat (Le. increases in enthalpy) from the hot fiuid through the tubing wall. Thus, the recovered second injected fluid `will be substantially hotter than when previously injected. As a result,y heat losses from the injected hot uid are transferred tothe second fiuid. This recovered second fiuid is utilized by Vfurther heating it to obtain a hot fluid suitable for injection into the subterranean formation.
BRIEF DESCRIPTION OF THE DRAWINGS PREFERRED EMBODIMENTS OE THE INVENTION Injecting hot fluid into a subterranean oil-bearing formation is preferably carried out utilizing two tubing strings and well casing as illustrated in FIGURE l. It is understood that in FIGURES 1 and 2 even though the cool uid is shown to be injected through the casing-tubing annulus 54, and returned via an inner tubing, it is equally conceivable that the reverse directions may be employed. With two tubing strings Within a well casing, there are a total of four combinations of fluid flow, two for each of the embodiments in FIGURES 1 and 2.
Although the herein mentioned apparatuses utilized for injectionand recovery of fluids are referred to, inter alia,v
as tubing strings and well casing, theymay be generically described as conduits without devating vfrom the intended scope of the invention.
In FIGURE 1, steam is generated in` steam generator 30, fed by make-up water controlled `by valve 72 and returned second injected fluid controlled by valve 10, transferred through valve 12 and then flowed through conduit 32 under pressure, the pressure being indicated by pressure valve 28. Conduit 32 is connected to first injection tubing string 2 so that the steam Will travel into the j subterranean oil-bearingrformation and then through perforations 20. Hereafter, conventional methods of steam iiooding sweep the reservoir of oil to at least one production well where the oil is recovered. Preferably, the injected hot uid is steam as embodied in this figure, however, other economical drive fluids may be utilized so long as they possess the required latent heat to effectively sweep the reservoir of oil. For saturated steam the temperature is preferably from about 300 to about 700 F. and more preferably from about 380 to about 570 F. The quality of the steam will preferably be from about 50 to about 100%. Ihe injection rates will preferably be from about 2,000 to about 25,000 lb./hr., and more preferably from about 8,000 to about 20,000 1b./ hr.
Examples of other useful hot uids include hot water, superheated steam, and like materials, and any of'the foregoing with compatible additives such as corrosion inhibito, surfactants, bactericides, etc. The steam injection pressure will be a function of the conditions of the particular reservoir, i.e. depth and permeability of the formation, volume of the reservoir to be swept, diameter of the injection tubing string, output of the steam generator, rate of sweeping, etc. Examples of injection pressures include preferably from about 70 to about 3000 p.s.i.a. and more, and more preferably from about 200 to about 1200 p.s.i.a.
In FIGURE 1, a cool fluid, with respect to the steam, is injected concurrently with respect to the steam into conduit 34 through valve 8 into the annulus formed by second tubing string 6 and well casing 4. The annular tubing strings are preferably concentric and are partitioned 4from formation 16 and interior l64 of tubing string 2 by packer 18. The second tubing string l6 and tubing string 2 form annulus 62 which is in uid communication with annulus 54. This allows the cool fluid injected in annulus 54 to travel down annulus 54 and up annulus y62. The communication between the two annuli is effected by leaving a space below second tubing string 6 and packer 18.
The injected cool fluid is preferably water at about ambient temperature. This cool fluid may contain additives compatible with the fluid, examples include corrosion inhibitors, surfactants, etc. as desired. Cool uid in annulus 62 is iiowing countercurrently to steam traveling through tubing 2; as a result, the enthalpy of the cool iiuid increases as heat transfers from the steam. Near the y top of annulus 62, the cool uid has obtained its highest the steam generator is obvious since less heat will have to be provided to the hotter cool fluid to elevate its temperature to a suitable level to produce steam in steam generator 30. This improves the economics of the operation.
Preferably, casing 4 is cemented in place with either bonded or nonbonded cement 14. Tubing string 2 may also be insulated to insure proper heat transfer between the cool uid and the steam. Again, the amount and type of insulation 22 to be used is dependent upon the parameters of the particular system.
FIGURE 2 illustrates two tubing strings within well casing 4. Steam is generated as in FIGURE 1 in steam generator 30 and sent through the annular region 52 of tubing string `60 by opening valve 40. Tubing string 60 is in lluid communication with the subterranean oil-bearing formation via annular spacing 52 and perforated holes 20 within casing 4. Packer 18 partitions 0r Substantially isolates the annular region 54 between casing 4 and tubing string 60. Annular space 54 is in uid communication with steam generator 30 via second tubing string '66 via special tubing shoe S8. As the cool fluid is injected through conduit 68 via valve 44, it traverses the annular region 54, connecting shoe 58, and returns to the surface through space 56 within tube y66. The cool fluid becomes much hotter `by heat transfer from the steam in adjacent annular region 52. Opening valve 42 allows the yhotter cool fluid to be recycled to steam generator 30. Any excess hotter cool uid may be exited as desired by opening valve 70. Tubing shoe 58 comprises a plurality of pipelike connections between annular region 54 and tubing interior 516. It is important that the cool fluid in annular region 54 be solely in uid communication with region 56 via passages 58.
As in the previous embodiment of FIGURE l, the hot fluid injection tubing string `60 may be insulated from the circulating cool fluid by insulation 2-2. The desirability of insulating and the extent of insulation tol be effected is dependent on the particular parameters of the reservoir and injection well system. It should also be apparent that the rate of injection of cool fluid will determine how hot the returned hotter cool fluid will be. The injection rate should be determined so that minimum heat loss to the entire system will occur. Generally, for the purposes of this invention, a well of preferably less than 3000 ft. and more preferably less than 1000 ft. in depth will most efficiently be run, at a cool fluid injection rate of from about 2,000 to about 25,000 and more preferably from about 8,000 to about 20,000 lb./hr.
There are many parameters of operation in injection well systems that the person skilled in the art will take EXAMPLE A casing and packer are set in an injection well at a depth of 492 feet. The inner diameter of the casing is 5.299 inches and the outer diameter is 6.000 inches. A first tubing string is inserted and centrally disposed Within the casing and has an inner diameter of 1.880 inches, roughness 0.00065 inch, and an outer diameter of 1.995 inches. The insulation diameter of the first tubing string is 3.000 inches and the thermal conductivity of the insulation is 3.0 B.t.u./ (hr. ft. F.) and the thermal conductivity of the pipe is 26.5 B.t.u./ (hr. ft. F.). The second tubing string having an inner diameter of 3.958 inches and an outer diameter of 4.500 inches is placed concentric with the first tubing string, and also has a thermal conductivity of 26.5 B.t.u./ (hr. ft. F.). The thermal conductivity of the earth surrounding the well bore is 1.4 B.t.u./ (hr. ft. F.) and the thermal-diifusivity of the earth s 0.04 ft2/hr. The geothermal temperature at the surface is 60 F. and the geothermal temperature gradient is 0.0207" lF./ft. Eighty percent quality steam at 5l8.2 F. is injected at a rate of 18,500 lb./hr. andat a pressure of 800 p.s.i.a. into the first tubing string. The heat injected at the surface is 1,061 B`.t.u./lb. Into the annulus between the well casing and the second tubing string, coolant water is injected at a rate of 18,500 lb./hr., circulated around the bottom of the pipe, and produced up through the annulus between the rst and second tubing strings Where at the surface its temperature is calculated to be 164 F. It is then fed to the steam generator as feed water. After one year from start ofY injection,
the following heat loss and eiciency calculations are obtained:
Cost of heat entering formation, 2 $/million B.t.u. 0.375 Eiciency of process-percent of energy supplied to boiler which is injected 80.0
1Assumes 80% eiclency of boiler, 3% heat loss in hot Water from Well to boiler.
mi: fBased on natural gas as fuel at $0.30/m.c.f, u B.t.u.]
It should be understood that the invention is capable of a variety of modifications and variations which will be made apparent to those skilled in the art` Such are to be included within the scope of this invention as dened in the specification and appended claims.
What is claimed is:
1. In a process for the recovery of hydrocarbons from an oil-bearing subterranean formation wherein a hot uid is injected through a well into the formation to facilitate movement and recovery of the formation hydrocarbons, the improvement of increasing the overall thermalefficiency of the recovery process comprising in combination the steps of:
(a) injecting through a iirst conduit in said Well the hot fluid into the subterranean formation,
(b) injecting downwardly into said well concurrently through a, second conduit in said well a second uid relatively cool with respect to the hot uid, said hot fluid and said second iluid partitioned from each other below the surface,
(c) recovering the second uid by owing said second uid upwardly through a third conduit in said well, said third conduit being positioned in heat transfer relationship to said first conduit, whereby the second recovered uid obtains an increase in enthalpy due to heat transfer from the. hot uid, and
(d) incorporating at least a portion of said second recovered uid with the hot uid.
2. The process of claim 1 wherein the` iirst injected uid is selected from the group consisting of hot water, steam, and superheated steam.
3. The process of claim 1 wherein the second injected uid is water.
4. The process of claim 1 wherein the first conduit is interior to the second and third conduits.
5. The process of claim 1 wherein the first conduit is interior to the second conduit and exterior to the third conduit.
6. The process of claim 1 wherein the first conduit is variably insulated from the second injected fluid so as to maintain the desired heat transfer between the injected hot uid and the second injected uid.
7. An improved process for the recovery of hydrocarbons from an oil-bearing subterranean formation wherein a hot fluid is injected through a well into the formation to facilitate movement and recovery of the formation hydrocarbons, the improvement comprising increasing the overall thermal-efficiency of the process comprising in combination the steps of:
(a) injecting through a first conduit in said well the hot uid into the subterranean formation,
(b) injecting concurrently through a second conduit in said well a second fluid relatively cool with respect to the hot uid, said hot fluid and said second fluid partitioned from each other below the surface,
(c) recovering said second fluid by owing said second fluid upwardly through a third conduit in said well, said third conduit being positioned in heat transfer relationship to said first conduit, whereby the recovered second fluid obtains an increase in enthalpy due to heat transfer from the second hot uid,
(d) and recycling the recovered second fluid to a hot liuid generation apparatus to be regeneratedr as the hot fluid to be injected through the rst conduit.
8. The process of claim 7 wherein the first injected iiuid is selected from the group consisting of hot water, steam, and superheated steam.
9. The process of claim 7 wherein the second injected liuid is water.
10. The process of claim 7 wherein the first conduit is interior to the second and third conduits.
11. The process of claim 7 wherein the first conduit is interior to the second conduit and exterior to the third conduit.
12. The process of claim 7 wherein the lirst conduit is variably insulated from the second injected uid so as to maintain the desired heat transfer between the injected hot fluid and the second injected uid.
References Cited UNITED STATES PATENTS 895,612 8/1908 Baker 166-57 3,142,336 7/1964 Doscher 166-57 X 3,294,167 12/1966 Vogel 166-272 CHARLES E. OCONNELL, Primary Examiner IAN A. CALVERT, Assistant Examiner U.S. Cl. X.R. 166--57
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Cited By (34)

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US3613792A (en) * 1969-12-11 1971-10-19 British Petroleum Co Oil well and method for production of oil through permafrost zone
US3685583A (en) * 1970-04-13 1972-08-22 Raymond Int Inc Permafrost insulation
US3703929A (en) * 1970-11-06 1972-11-28 Union Oil Co Well for transporting hot fluids through a permafrost zone
US3804163A (en) * 1972-06-08 1974-04-16 Sun Oil Co Catalytic wellbore heater
US3837401A (en) * 1972-02-28 1974-09-24 Texaco Inc Hot fluid injection into hydrocarbon reservoirs
US3897826A (en) * 1972-07-24 1975-08-05 Chevron Res Method for well workover operations
US3938592A (en) * 1970-03-23 1976-02-17 Ivan Timofeevich Aladiev Rock-exploitation method based on thermodynamic cycles utilizing in-situ energy source
US3952802A (en) * 1974-12-11 1976-04-27 In Situ Technology, Inc. Method and apparatus for in situ gasification of coal and the commercial products derived therefrom
US4022280A (en) * 1976-05-17 1977-05-10 Stoddard Xerxes T Thermal recovery of hydrocarbons by washing an underground sand
US4062405A (en) * 1976-11-22 1977-12-13 Continental Oil Company Method of treating oil-bearing formations using molten sulfur insulating packer fluid
US4220202A (en) * 1970-03-23 1980-09-02 Aladiev Ivan T Apparatus for realization of rock exploitation method based on thermodynamic cycles utilizing in situ energy source
US4378846A (en) * 1980-12-15 1983-04-05 Brock Kurtis B Enhanced oil recovery apparatus and method
EP0109288A2 (en) * 1982-11-12 1984-05-23 The Babcock & Wilcox Company Heating oil in wells and generating steam from well water
US4678039A (en) * 1986-01-30 1987-07-07 Worldtech Atlantis Inc. Method and apparatus for secondary and tertiary recovery of hydrocarbons
US5040605A (en) * 1990-06-29 1991-08-20 Union Oil Company Of California Oil recovery method and apparatus
US20050103497A1 (en) * 2003-11-17 2005-05-19 Michel Gondouin Downhole flow control apparatus, super-insulated tubulars and surface tools for producing heavy oil by steam injection methods from multi-lateral wells located in cold environments
EP2310471A1 (en) * 2008-07-28 2011-04-20 Forbes Oil And Gas Pty Ltd Apparatus for liquefaction of carbonaceous material
US8955591B1 (en) 2010-05-13 2015-02-17 Future Energy, Llc Methods and systems for delivery of thermal energy
US20150211336A1 (en) * 2014-01-29 2015-07-30 Harris Corporation Hydrocarbon resource heating system including common mode choke assembly and related methods
US9200505B2 (en) 2010-08-18 2015-12-01 Future Energy, Llc Methods and systems for enhanced delivery of thermal energy for horizontal wellbores
CN106121617A (en) * 2016-08-24 2016-11-16 中为(上海)能源技术有限公司 Waste heat recovery product well system and operational approach for coal underground gasifying technology
CN110630172A (en) * 2018-06-21 2019-12-31 中国石油化工股份有限公司 Frozen soil layer drilling heat-resistant anti-melting device
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US20230304705A1 (en) * 2022-02-28 2023-09-28 EnhancedGEO Holdings, LLC Geothermal power from superhot geothermal fluid and magma reservoirs
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CN110630172A (en) * 2018-06-21 2019-12-31 中国石油化工股份有限公司 Frozen soil layer drilling heat-resistant anti-melting device
EP3959418A4 (en) * 2019-04-26 2023-01-04 General Energy Recovery Inc. Apparatus, method and wellbore installation to mitigate heat damage to well components during high temperature fluid injection
US12055023B2 (en) 2019-04-26 2024-08-06 General Energy Recovery Inc. Apparatus, method and wellbore installation to mitigate heat damage to well components during high temperature fluid injection
US11841172B2 (en) 2022-02-28 2023-12-12 EnhancedGEO Holdings, LLC Geothermal power from superhot geothermal fluid and magma reservoirs
US11852383B2 (en) 2022-02-28 2023-12-26 EnhancedGEO Holdings, LLC Geothermal power from superhot geothermal fluid and magma reservoirs
US12055131B2 (en) 2022-02-28 2024-08-06 EnhancedGEO Holdings, LLC Geothermal power from superhot geothermal fluid and magma reservoirs
US20230304705A1 (en) * 2022-02-28 2023-09-28 EnhancedGEO Holdings, LLC Geothermal power from superhot geothermal fluid and magma reservoirs
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US11918967B1 (en) 2022-09-09 2024-03-05 EnhancedGEO Holdings, LLC System and method for magma-driven thermochemical processes
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