Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3675715 A
Publication typeGrant
Publication dateJul 11, 1972
Filing dateDec 30, 1970
Priority dateDec 30, 1970
Publication numberUS 3675715 A, US 3675715A, US-A-3675715, US3675715 A, US3675715A
InventorsSpeller Frank N Jr
Original AssigneeForrester A Clark
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Processes for secondarily recovering oil
US 3675715 A
Abstract
A secondary recovery process for oil wet sands using underground combustion to produce a makeup effluent gas containing carbon dioxide. The effluent gas is mixed with a wet casing head gas enriched by ethane plus hydrocarbons and the mixture is injected into the reservoir at relatively low pressures to promote oil flow toward a production well. The enriched injected gas mixture reduces the oil's adhesion to the sand and promotes oil flow. The production well is maintained under a vacuum pressure so as to pull the injected mixture through the formation. The mixture is recovered and reinjected. The production well vacuum pulls ethane plus hydrocarbons from the oil at the formation face to enrich the casinghead gas.
Images(1)
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

United States Patent Speller, Jr.

[451 July 11, 1972 [54] PROCESSES FOR SECONDARILY RECOVERIN G OIL [72] Inventor: Frank N. Speller, Jr., Tyler, Tex.

[73] Assignee: Forrester A. Clark, Boston, Mass.

[22] Filed: Dec. 30, 1970 211 App]. No.: 102,824

[52] U.S.Cl ..166/256,166/266, 166/272 [51] lnt.Cl. 2lb43/24 [58] FieldofSearch ..166/256, 257, 258, 261,272, 166/266 [56] References Cited UNITED STATES PATENTS 2,584,605 2/1952 Merriam ..166/258 3,163,215 12/1964 Stratton... ..166/258 3,358,756 12/1967 Vogel ..166/272 3,586,377 6/1971 Ellington ..l66/272 3,599,714 8/197] Messman .l66/258 Primary Examiner-James A. Leppink Attorney--Mann, Brown, McWilliams & Bradway [57] ABSTRACT A secondary recovery process for oil wet sands using underground combustion to produce a makeup effluent gas containing carbon dioxide. The effluent gas is mixed with a wet casing head gas enriched by ethane plus hydrocarbons and the mixture is injected into the reservoir at relatively low pressures to promote oil flow toward a production well. The enriched injected gas mixture reduces the oil's adhesion to the sand and promotes oil flow. The production well is maintained under a vacuum pressure so as to pull the injected mixture through the fonnation. The mixture is recovered and reinjected. The production well vacuum pulls ethane plus hydrocarbons from the oil at the formation face to enrich the casinghead gas.

6Claims,1DrawingFigure PROCESSES FOR SECONDARILY RECOVERING OIL The present invention is directed to improvements in processes for secondary recovery of oil.

A number of secondary recovery processes for the recovery of oil from oil bearing sands are known. In the past water flooding techniques have been utilized in order to drive oil towards a producing well. Fire flood processes are also known in which combustion is initiated underground in order to create pressure while reducing viscosity of oil and adhesion of oil to the reservoir sand to thereby promote flow of the oil toward a producing well. In some cases carbon dioxide with or without hydrocarbon gases has been utilized in connection with water flood processes to promote flow of oil towards a recovery well. It has also been known to utilize butane, propane, and equivalent hydrocarbon gases under relatively high pressures, for example, exceeding 2,000 psi in a water or gas mixture for driving oil from the oil bearing sands to a producing well. Air injection processes which produce oxidation without ignition and low pressure gas injection techniques have also been proposed in secondary recovery processes.

Water flooding techniques can be economically effective in the case of water wet sands. However, in the case of oil wet sands the water flooding technique is usually ineffective to free the oil from the formation and drive it to a producing well with satisfactory economy. The term oil wet sands" as used herein is intended to refer to those sands in which oil is found on the face of the sands and in formations having an absence of formation water. Use of carbon dioxide in water flooding techniques increases equipment corrosion to the extent that the economies of the overall operation may be unsatisfactory. Fire flood techniques are satisfactory in some cases with oil wet sands but in some cases a fire flood operation is not economical, because of the extent and intensity of burning necessary to produce a given amount of oil. The use of injected gas mixtures at high pressures has the disadvantage that the gases so used then become quite dense or may become liquid at the high pressures, with the result that the high pressures utilized with gas injected mixtures usually require plugging of those wells of the field which are not operative in the process in order to maintain the high pressures and to avoid contamination of the atmosphere. Air injection is sometimes satisfactory but this process does not reduce oil adhesion as much as fire flood or carbon dioxide processes. Low pressure gas injection can be satisfactory to promote oil flow in some cases, but the low pressures may not be sufficient to drive oil to a production well in some formations and the gas supply may not be sufficient for production.

With the foregoing in mind, the present invention is directed to a new and improved process for secondary recovery of oil from formations having oil wet sands, and in those instances where a casing head gas which is rich in ethane plus, hydrocarbon or the equivalent is present in suitable quantities at the site of the recovery operation.

The major purposes of the invention are to provide a method for secondary recovery of oil from oil wet sands while utilizing relatively low working pressures for gas injection with the result that over a prolonged period of time plugging of the wells not actually involved in the operation and in the field being worked is unnecessary; and in such a way that pollution of the surrounding atmosphere is avoided, all while increasing the recovery of oil at an overall cost less than that which can be obtained with known fire flood, or a water flood, carbon dioxide, air injection or gas injection processes.

These and other purposes will appear from time to time in the course of the ensuing specification and claims when taken in conjunction with the accompanying drawing, in which:

FIG. 1 is a diagram of the process constituting the present invention.

In accordance with the present invention, combustion is initiated underground in accordance with known fire flood techniques. The combustion, however, is not initiated for the main purpose of driving oil towards a recovery well but rather for the purpose of producing an effluent gas containing carbon dioxide and other constituents which are then mixed with a wet casing head gas and reinjected for the purpose of promoting flow of oil towards a producing well. Oil and injected gas are then separately recovered from the producing well, whereupon the recovered part of the injected gas can be recycled.

As shown in FIG. 1, for example, the numeral 10 designates a thermal injection well in which a suitable compressor or the like 11 delivers air to the bottom of the well for the purpose of controlling the combustion. The combustion may be initiated by means of any known system for initiating a fire flood operation. A fire flood as designated generally at 12 produces heat and pressures which are effective in driving the products of combustion and some oil toward an effluent well generally designated at 13. Temperatures at the flame front may be 600 F. or greater. The casing of effluent well 13 is maintained at or near atmospheric pressure and the products of combustion from the fire in the form of effluent gases pass up the casing 14 of the well. Some oil may be driven to the oil inlet of well 13 and this oil may be recovered through the tubing 15 within the well.

Pumping facilities (not shown) may be utilized to withdraw the oil through the tubing 15.

The oxygen in the air pumped underground to the fire is converted to an equivalent volume of CO and this conversion may be as much as percent efficient. Heat from the fire volatilizes light components of the oil in the immediate vicinity and the volatilized components are in the form of rich vapors until they partially condense as they are driven away from the burn area. Some of the partially condensed components then go into solution with other fonnation oil and others go into the mixture of the combustion gas. The recovered vapors usually include an ethane plus component; thus the effluent gas is a mixture enriched by ethane, heavier hydrocarbons and carbon dioxide for reinjection.

The heavier hydrocarbons are butane, propane, etc. The term ethane plus as used herein refers to the heavier hydrocarbons in a gas and designates the ethane and heavier hydrocarbons in the gas.

Since the main purposes of the thermal injection well is not to drive oil towards the well 13 but rather to produce an enriched product of combustion gas, the volume of oxygen or air supplied to the injection well 10 may be considerably lower than that used in normal fire flood processes. In normal fire flood processes the intention is to create an intensity of burning such as to produce temperatures and pressures which cause maximum oil flow. Nonetheless, in the process of this in vention, any oil recovered from the effluent well 13 is of value and helps to pay for the cost of operation.

It should be understood that one or more effluent wells 13 may be utilized. They may be advantageously situated in surrounding relation to the thermal injection well 10. It should also be understood that control of the underground combustion in processes of this type is effected through the air supply control. By shutting off the air supply, the combustion may be extinguished eventually. The degree of combustion may also be increased by increasing air supply.

In accordance with the invention, the air supply is controlled so as to produce carbon dioxide in the effluent mixture of gases on the order of 16 to 25 percent by volume of the total effluent gas mixture. The following Table No. I shows typical gaseous mixtures by volume in five effluent gas wells surrounding a thermal injection well:

1n further accordance with the invention, a wet casing head gas, which is available from producing wells at the field being operated, is utilized for mixture with the effluent gas and for reinjection into the formation. Casing head gas is that gas normally present in the casing of a well and which is sometimes recovered for sale or other use. It normally has little or no carbon dioxide therein. The casing head gas is mixed with the effluent gas from the well 13. Suitable piping connections pass the mixture to a compressor 17. Suitable valves and controls, diagrammatically indicated at 18 and 19, may be used to control the relative volumes of the two gases in the mixture before delivery to the compressor 17. Compressor 17 delivers the mixture to a second injection well 20. Producing wells are diagrammatically represented at 21. The wells 21 are the source of the casing head gas.

The producing wells 21 surround the gas injection well 20. Oil is pumped from the production wells 21 through the tubing of the wells to conveniently located stock tanks. Gas is recovered from these wells by pulling a vacuum on the casing of the wells which causes the gas to be separated from the oil at the formation face and be conducted up the casing and then passed to the compressor 17 for injection. The vacuum on the casing of the production wells 21 is on the order of 5 to 7.5 psi or l0-15 inches mercury vacuum. The vacuum which is maintained on the casing of each production well has the effect of pulling ethane plus hydrocarbons out of the oil at the point of separation, thereby enriching the gas and making it into what may be termed a wet casing head gas. The invention contemplates a casing head gas of this type which contains an average of 6 gallons or more, per thousand cubic feet of gas, of 26 lb. Reid vapor pressure at 70 F., gasoline content which is in a vapor phase in the gas.

The mixture injected into the well 20 thus has a beneficial carbon dioxide component which results mostly from the effluent gas as well as a beneficial ethane plus component.

Approximately one quarter of the gas mixture injected into the formation from the injection well 20 is lost from various causes such as a portion of it going into solution with unproduced oil while another portion repressurizes the formation and maintains it under pressure. The remaining part of the injected gas mixture, together with some gas components from the recovered oil as aforementioned, is recovered at the formation face by the casings of the production wells. The effluent gas, in addition to supplying the beneficial effect of CO as well as some ethane plus component to the gas mixture, acts as a source of makeup gas to maintain a total volume of gas mixture injected per day. The carbon dioxide component in the mixture is believed to act in a manner equivalent to the ethane plus hydrocarbons in enriching the gas for oil recovery purposes.

In cold weather some of the gas from the producing wells may condense into liquid drops which may be caught in sur- .face drips or traps in the piping leading to the compressor blank.

The control of the gas mixture is maintained so that there is a greater amount of ethane plus component in the gas by volume than the carbon dioxide.

In a typical example, the casing head gas is mixed with the relatively dry effluent gas in the proportion of three parts of casing head gas and one part of effluent gas by volume, while each injection well receives 50-150 MCF of the gas mixture per day. The actual total volume of gas injected per well per day will depend upon the thickness of the sand layer in the formation. Usually, an injected volume of 50 to 100 MCF of the mixture per well per day is a practical working volume. Preferably the mixture is such that there are on the order of two parts of ethane plus to one part of carbon dioxide in the mixture. The ethane plus component in the mixture is on the order of 20 to 35 percent of the total mixture by volume, while the carbon dioxide is on the order of 10 to percent of the total mixture by volume. The actual percentage of ethane plus gas component in the casing head gas as well as the actual percentage of carbon dioxide in the effluent gas will vary from time to time. The gases are analyzed periodically and the valves controlled to control the relative amounts of carbon dioxide and ethane plus in the mixture supplied to the compressor 17 in the amounts stated.

It may be noted that the casing head gas or the efl'luent gas is not suitable for injection at high pressures because of the tendency of the ethane plus and carbon dioxide components to liquefy at high pressure. However, the compressor 17 is operated at relatively low pressures. These low pressures are on the order of lbs. psi for delivery into the gas injection well diagrammatically represented at 20 in the drawings. The actual injection pressure may vary somewhat but the pressure developed by the compressor 17 as well as the temperature of the injected gas mixture should be such that the mixture is injected in a gaseous state. Injection well 20 is located with sufficient proximity to the production well or wells 21 so that the injected gas mixture drives the oil in the reservoir toward the production well where it may be withdrawn through the pipe 22 of the well. Suitable pumping facilities (such as rod pumps) may be used to withdraw the oil. The vacuum together with the injection pressure creates a push-pull" effect and serves to drive and pull the gas through the oil in the reservoir between the second injection well 20 and the production well 21. The vacuum also pulls from the oil hydrocarbons heavier than ethane. The withdrawn gas is then delivered through suitable piping 23 and valve controls 24 for recycling through compressor 17 to the second injection well 20. The withdrawn gas is mixed with the efiluent gas as may be necessary to maintain the injection mixture in the volumetric proportion stated and in the total volume per day as stated. A typical gas analysis withdrawn from five production wells is shown in the following table II.

The components shown in Table [1 illustrate the component parts of the mixture which is pulled through the formation together with some components which are added to the mixture from the oil in the formation from time to time. The carbon dioxide content is due primarily to that which results from the added effluent gas while the ethane plus components are due for the most part to the gas originally within the formation being worked.

The process is relatively inexpensive because the gas materials used are available at the site and because the low pressures require less expensive compressor operation than that required in high pressure techniques. Use of the process enables continuous use of gas native to the formation. The corrosive effect of CO is minimized because the process is intended for oil wet sands rather than water wet sands. The volume of combustion air supplied may be less than that in normal fire flood processes.

The process recovers oil more efficiently than other processes because of the tendency of the enrichers (carbon dioxide and ethane plus hydrocarbons) to partially go into solution with oil in the formation, thereby reducing the oils adhesion to the sand grains and making the oil susceptible to being swept by the low pressure injected gas to a producing well bore.

1 claim:

1. The method of secondary recovery of oil from a reservoir having oil wet sands including the steps of producing a fire flood in a reservoir adjacent a thermal injection well, withdrawing products of combustion from the flood so formed through a second well, mixing the products of combustion with wet casing head gas containing ethane plus gas, with the resultant mixture having on the order of 20 to 35 percent ethane plus gas by volume, injecting the gas mixture thus formed into a second injection well in proximity to one or more production wells in the reservoir, withdrawing the injected gas from the production well, withdrawing oil from the production well, and recycling the withdrawn gas to the second injection well.

2. The method of claim 1 wherein the combustion is controlled and the mixture of casing head gas with the products of combustion is controlled so that the injected gas mixture has on the order of approximately two parts ethane plus to approximately one part of carbon dioxide.

3. The method of claim 2 wherein the gas mixture injected in the second injection well is on the order of 50,000 to 150,000 MCF per day.

4. The method of claim 1 characterized by and including the r step of additionally withdrawing oil from the second well.

5. The method of secondary recovery of oil from a reservoir having oil wet sands including the steps of mixing an exhaust gas, containing carbon dioxide and other gases resulting from combustion of a hydrocarbon oil, with a wet casing head gas having an ethane plus gas component, controlling the relative volumes of carbon dioxide and ethane plus in the mixture so that approximately two parts ethane plus to one part carbon dioxide are present in the mixture, injecting the controlled mixture in a reservoir well at pressures and temperatures such as to maintain the mixture during injection as a gaseous phase for driving oil in the reservoir toward a production well, maintaining the production well under vacuum, and separately withdrawing oil and gas from said production well.

6. The method of claim 5 wherein the withdrawn gas is recycled through the injection well at said pressures and temperatures.

* i l II

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2584605 *Apr 14, 1948Feb 5, 1952Frederick SquiresThermal drive method for recovery of oil
US3163215 *Dec 4, 1961Dec 29, 1964Phillips Petroleum CoProducing plural subterranean strata by in situ combustion and fluid drive
US3358756 *Mar 12, 1965Dec 19, 1967Shell Oil CoMethod for in situ recovery of solid or semi-solid petroleum deposits
US3586377 *Jun 10, 1969Jun 22, 1971Atlantic Richfield CoMethod of retorting oil shale in situ
US3599714 *Sep 8, 1969Aug 17, 1971Becker Karl EMethod of recovering hydrocarbons by in situ combustion
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4005752 *Oct 16, 1975Feb 1, 1977Occidental Petroleum CorporationMethod of igniting in situ oil shale retort with fuel rich flue gas
US4008764 *Jul 11, 1975Feb 22, 1977Texaco Inc.Carrier gas vaporized solvent oil recovery method
US4078608 *Mar 23, 1977Mar 14, 1978Texaco Inc.Thermal oil recovery method
US4086960 *Feb 25, 1976May 2, 1978Haynes Charles AApparatus for hydrocarbon recovery from earth strata
US4552216 *Jun 21, 1984Nov 12, 1985Atlantic Richfield CompanyMethod of producing a stratified viscous oil reservoir
US4669542 *Nov 21, 1984Jun 2, 1987Mobil Oil CorporationSimultaneous recovery of crude from multiple zones in a reservoir
US6581684Apr 24, 2001Jun 24, 2003Shell Oil CompanyIn Situ thermal processing of a hydrocarbon containing formation to produce sulfur containing formation fluids
US6588503Apr 24, 2001Jul 8, 2003Shell Oil CompanyIn Situ thermal processing of a coal formation to control product composition
US6588504Apr 24, 2001Jul 8, 2003Shell Oil CompanyIn situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids
US6591906Apr 24, 2001Jul 15, 2003Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected oxygen content
US6591907Apr 24, 2001Jul 15, 2003Shell Oil CompanyIn situ thermal processing of a coal formation with a selected vitrinite reflectance
US6607033Apr 24, 2001Aug 19, 2003Shell Oil CompanyIn Situ thermal processing of a coal formation to produce a condensate
US6609570Apr 24, 2001Aug 26, 2003Shell Oil CompanyIn situ thermal processing of a coal formation and ammonia production
US6688387Apr 24, 2001Feb 10, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce a hydrocarbon condensate
US6698515Apr 24, 2001Mar 2, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a relatively slow heating rate
US6702016Apr 24, 2001Mar 9, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with heat sources located at an edge of a formation layer
US6708758Apr 24, 2001Mar 23, 2004Shell Oil CompanyIn situ thermal processing of a coal formation leaving one or more selected unprocessed areas
US6712135Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a coal formation in reducing environment
US6712136Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a selected production well spacing
US6712137Apr 24, 2001Mar 30, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to pyrolyze a selected percentage of hydrocarbon material
US6715546Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore
US6715547Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to form a substantially uniform, high permeability formation
US6715548Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids
US6715549Apr 24, 2001Apr 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected atomic oxygen to carbon ratio
US6719047Apr 24, 2001Apr 13, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation in a hydrogen-rich environment
US6722429Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation leaving one or more selected unprocessed areas
US6722430Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of a coal formation with a selected oxygen content and/or selected O/C ratio
US6722431Apr 24, 2001Apr 20, 2004Shell Oil CompanyIn situ thermal processing of hydrocarbons within a relatively permeable formation
US6725920Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to convert a selected amount of total organic carbon into hydrocarbon products
US6725921Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a coal formation by controlling a pressure of the formation
US6725928Apr 24, 2001Apr 27, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a distributed combustor
US6729395Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected ratio of heat sources to production wells
US6729396Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to produce hydrocarbons having a selected carbon number range
US6729397Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation with a selected vitrinite reflectance
US6729401Apr 24, 2001May 4, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation and ammonia production
US6732794Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce a mixture with a selected hydrogen content
US6732795Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to pyrolyze a selected percentage of hydrocarbon material
US6732796Apr 24, 2001May 11, 2004Shell Oil CompanyIn situ production of synthesis gas from a hydrocarbon containing formation, the synthesis gas having a selected H2 to CO ratio
US6736215Apr 24, 2001May 18, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation, in situ production of synthesis gas, and carbon dioxide sequestration
US6739393Apr 24, 2001May 25, 2004Shell Oil CompanyIn situ thermal processing of a coal formation and tuning production
US6739394 *Apr 24, 2001May 25, 2004Shell Oil CompanyProduction of synthesis gas from a hydrocarbon containing formation
US6742587Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to form a substantially uniform, relatively high permeable formation
US6742588Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce formation fluids having a relatively low olefin content
US6742589Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using repeating triangular patterns of heat sources
US6742593Apr 24, 2001Jun 1, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using heat transfer from a heat transfer fluid to heat the formation
US6745831Apr 24, 2001Jun 8, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation by controlling a pressure of the formation
US6745832Apr 24, 2001Jun 8, 2004Shell Oil CompanySitu thermal processing of a hydrocarbon containing formation to control product composition
US6745837Apr 24, 2001Jun 8, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a controlled heating rate
US6749021Apr 24, 2001Jun 15, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using a controlled heating rate
US6752210Apr 24, 2001Jun 22, 2004Shell Oil CompanyIn situ thermal processing of a coal formation using heat sources positioned within open wellbores
US6758268Apr 24, 2001Jul 6, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using a relatively slow heating rate
US6761216Apr 24, 2001Jul 13, 2004Shell Oil CompanyIn situ thermal processing of a coal formation to produce hydrocarbon fluids and synthesis gas
US6763886Apr 24, 2001Jul 20, 2004Shell Oil CompanyIn situ thermal processing of a coal formation with carbon dioxide sequestration
US6769483Apr 24, 2001Aug 3, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using conductor in conduit heat sources
US6769485Apr 24, 2001Aug 3, 2004Shell Oil CompanyIn situ production of synthesis gas from a coal formation through a heat source wellbore
US6789625Apr 24, 2001Sep 14, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation using exposed metal heat sources
US6805195Apr 24, 2001Oct 19, 2004Shell Oil CompanyIn situ thermal processing of a hydrocarbon containing formation to produce hydrocarbon fluids and synthesis gas
US7644765Oct 19, 2007Jan 12, 2010Shell Oil CompanyHeating tar sands formations while controlling pressure
US7673681Oct 19, 2007Mar 9, 2010Shell Oil CompanyTreating tar sands formations with karsted zones
US7673786Apr 20, 2007Mar 9, 2010Shell Oil CompanyWelding shield for coupling heaters
US7677310Oct 19, 2007Mar 16, 2010Shell Oil CompanyCreating and maintaining a gas cap in tar sands formations
US7677314Oct 19, 2007Mar 16, 2010Shell Oil CompanyMethod of condensing vaporized water in situ to treat tar sands formations
US7681647Oct 19, 2007Mar 23, 2010Shell Oil CompanyMethod of producing drive fluid in situ in tar sands formations
US7683296Apr 20, 2007Mar 23, 2010Shell Oil CompanyAdjusting alloy compositions for selected properties in temperature limited heaters
US7703513Oct 19, 2007Apr 27, 2010Shell Oil CompanyWax barrier for use with in situ processes for treating formations
US7717171Oct 19, 2007May 18, 2010Shell Oil CompanyMoving hydrocarbons through portions of tar sands formations with a fluid
US7730945Oct 19, 2007Jun 8, 2010Shell Oil CompanyUsing geothermal energy to heat a portion of a formation for an in situ heat treatment process
US7730946Oct 19, 2007Jun 8, 2010Shell Oil CompanyTreating tar sands formations with dolomite
US7730947Oct 19, 2007Jun 8, 2010Shell Oil CompanyCreating fluid injectivity in tar sands formations
US7735935Jun 1, 2007Jun 15, 2010Shell Oil CompanyIn situ thermal processing of an oil shale formation containing carbonate minerals
US7785427Apr 20, 2007Aug 31, 2010Shell Oil CompanyHigh strength alloys
US7793722Apr 20, 2007Sep 14, 2010Shell Oil CompanyNon-ferromagnetic overburden casing
US7798220Apr 18, 2008Sep 21, 2010Shell Oil CompanyIn situ heat treatment of a tar sands formation after drive process treatment
US7798221May 31, 2007Sep 21, 2010Shell Oil CompanyIn situ recovery from a hydrocarbon containing formation
US7831134Apr 21, 2006Nov 9, 2010Shell Oil CompanyGrouped exposed metal heaters
US7832484Apr 18, 2008Nov 16, 2010Shell Oil CompanyMolten salt as a heat transfer fluid for heating a subsurface formation
US7841401Oct 19, 2007Nov 30, 2010Shell Oil CompanyGas injection to inhibit migration during an in situ heat treatment process
US7841408Apr 18, 2008Nov 30, 2010Shell Oil CompanyIn situ heat treatment from multiple layers of a tar sands formation
US7841425Apr 18, 2008Nov 30, 2010Shell Oil CompanyDrilling subsurface wellbores with cutting structures
US7845411Oct 19, 2007Dec 7, 2010Shell Oil CompanyIn situ heat treatment process utilizing a closed loop heating system
US7849922Apr 18, 2008Dec 14, 2010Shell Oil CompanyIn situ recovery from residually heated sections in a hydrocarbon containing formation
US7860377Apr 21, 2006Dec 28, 2010Shell Oil CompanySubsurface connection methods for subsurface heaters
US7866385Apr 20, 2007Jan 11, 2011Shell Oil CompanyPower systems utilizing the heat of produced formation fluid
US7866386Oct 13, 2008Jan 11, 2011Shell Oil CompanyIn situ oxidation of subsurface formations
US7866388Oct 13, 2008Jan 11, 2011Shell Oil CompanyHigh temperature methods for forming oxidizer fuel
US7912358Apr 20, 2007Mar 22, 2011Shell Oil CompanyAlternate energy source usage for in situ heat treatment processes
US7931086Apr 18, 2008Apr 26, 2011Shell Oil CompanyHeating systems for heating subsurface formations
US7942197Apr 21, 2006May 17, 2011Shell Oil CompanyMethods and systems for producing fluid from an in situ conversion process
US7942203Jan 4, 2010May 17, 2011Shell Oil CompanyThermal processes for subsurface formations
US7950453Apr 18, 2008May 31, 2011Shell Oil CompanyDownhole burner systems and methods for heating subsurface formations
US7986869 *Apr 21, 2006Jul 26, 2011Shell Oil CompanyVarying properties along lengths of temperature limited heaters
US8220539Oct 9, 2009Jul 17, 2012Shell Oil CompanyControlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US8256512Oct 9, 2009Sep 4, 2012Shell Oil CompanyMovable heaters for treating subsurface hydrocarbon containing formations
US8261832Oct 9, 2009Sep 11, 2012Shell Oil CompanyHeating subsurface formations with fluids
US8267170Oct 9, 2009Sep 18, 2012Shell Oil CompanyOffset barrier wells in subsurface formations
US8267185Oct 9, 2009Sep 18, 2012Shell Oil CompanyCirculated heated transfer fluid systems used to treat a subsurface formation
US8281861Oct 9, 2009Oct 9, 2012Shell Oil CompanyCirculated heated transfer fluid heating of subsurface hydrocarbon formations
US8327932Apr 9, 2010Dec 11, 2012Shell Oil CompanyRecovering energy from a subsurface formation
US8353347Oct 9, 2009Jan 15, 2013Shell Oil CompanyDeployment of insulated conductors for treating subsurface formations
US8434555Apr 9, 2010May 7, 2013Shell Oil CompanyIrregular pattern treatment of a subsurface formation
US8448707May 28, 2013Shell Oil CompanyNon-conducting heater casings
US8851170Apr 9, 2010Oct 7, 2014Shell Oil CompanyHeater assisted fluid treatment of a subsurface formation
US8881806Oct 9, 2009Nov 11, 2014Shell Oil CompanySystems and methods for treating a subsurface formation with electrical conductors
US9022118Oct 9, 2009May 5, 2015Shell Oil CompanyDouble insulated heaters for treating subsurface formations
US9051829Oct 9, 2009Jun 9, 2015Shell Oil CompanyPerforated electrical conductors for treating subsurface formations
Classifications
U.S. Classification166/256, 166/266, 166/402
International ClassificationE21B43/243, E21B43/16
Cooperative ClassificationE21B43/243
European ClassificationE21B43/243