WO2014205163A1 - Procédé de récupération assistée de pétrole utilisant la capture de dioxyde de carbone - Google Patents

Procédé de récupération assistée de pétrole utilisant la capture de dioxyde de carbone Download PDF

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Publication number
WO2014205163A1
WO2014205163A1 PCT/US2014/043086 US2014043086W WO2014205163A1 WO 2014205163 A1 WO2014205163 A1 WO 2014205163A1 US 2014043086 W US2014043086 W US 2014043086W WO 2014205163 A1 WO2014205163 A1 WO 2014205163A1
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Prior art keywords
steam
carbon dioxide
pressure range
capture system
passing
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PCT/US2014/043086
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English (en)
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Michael J. Lewis
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Individual
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Individual
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Priority claimed from US13/921,411 external-priority patent/US20130341924A1/en
Application filed by Individual filed Critical Individual
Priority to MX2015017408A priority Critical patent/MX2015017408A/es
Publication of WO2014205163A1 publication Critical patent/WO2014205163A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K23/00—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
    • F01K23/02—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled
    • F01K23/06—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle
    • F01K23/064—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle in combination with an industrial process, e.g. chemical, metallurgical
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K23/00—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
    • F01K23/02—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled
    • F01K23/06—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle
    • F01K23/10—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle with exhaust fluid of one cycle heating the fluid in another cycle
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
    • Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells

Definitions

  • the present invention relates to carbon dioxide injection for tertiary hydrocarbon recovery. More particularly, the present invention the relates to portable carbon dioxide generators that can be used for producing the carbon dioxide gas for injection into a hydrocarbon-bearing formation. The present invention also relates to systems and methods whereby steam of different pressures can be utilized to enhance the efficiency of the enhanced recovery process.
  • Gas injection is one of the most common tertiary techniques.
  • carbon dioxide injection into depleted oil wells has received considerable attention owing to its ability to mix with crude oil. Since the crude oil is miscible with carbon dioxide, the injection of carbon dioxide renders the oil substantially less viscous and more readily extractable.
  • Carbon dioxide in quantities sufficiently large enough for commercial exploitation generally has come from three sources.
  • One such source is the naturally occurring underground supply of carbon dioxide in areas such as Colorado, Wyoming, Mississippi, and other areas.
  • a second source is that resulting from by-products of the operation of a primary process, such as the manufacture of ammonia or a hydrogen reformer.
  • a third source is found in the exhaust gases from burning of various hydrocarbon fuels.
  • One of the largest problems that is faced by carbon dioxide users is the problem of transportation from the place of production to the point of use.
  • U.S. Patent No.4,499,946 issued on February 19, 1985 to Martin et al., provides a portable, above-ground system and process for generating combustion gases and for injecting the purified nitrogen and carbon dioxide at controlled temperatures into a subterranean formation so as to enhance the recovery thereof.
  • the system includes a high-pressure combustion reactor for sufficient generation of combustion gases at the required rates and at pressures up to about 8000 p.s.i. and temperatures up to about 4500 °F.
  • the reactor is water-jacketed but lined with refractory material to minimize soot formation.
  • U.S. Patent No. 4,741,398, issued on May 3, 1988 to F. L. Goldsberry shows a hydraulic accumulator-compressor vessel using geothermal brine under pressure as a piston to compress carbon dioxide-rich gas. This is used in a system having a plurality of gas separators in tandem to recover pipeline quality gas from geothermal brine.
  • a first high pressure separator feeds gas to a membrane separator which separates low pressure waste gas from high pressure quality gas.
  • a second separator produces low pressure waste gas. Waste gas from both separators is combined and fed into the vessel through a port at the top as the vessel is drained for another compression cycle.
  • U.S. Patent No. 4,824,447 issued on April 25, 1989 to F. L. Goldsberry, describes an enhanced oil recovery system which produces pipeline quality gas by using a high pressure separator/heat exchanger and a membrane separator. Waste gas is recovered from both the membrane separator and a low pressure separator in tandem with the high pressure separator. Liquid hydrocarbons are skimmed off the top of geothermal brine in the low pressure separator. High pressure brine from the geothermal well is used to drive a turbine/generator set before recovering waste gas in the first separator. Another turbine/generator set is provided in a supercritical binary power plant that uses propane as a working fluid in a closed cycle and uses exhaust heat from the combustion engine and geothermal energy of the brine in the separator/heat exchanger to heat the propane.
  • This system includes an internal combustion engine that drives an electrical generator.
  • a waste heat recovery unit is provided through which hot exhaust gases from the engine are passed to recover thermal energy in a usable form.
  • a means is provided for conveying exhaust gases coming out of the waste heat recovery unit to a recovery unit where the carbon dioxide is extracted and made available as a saleable byproduct.
  • U.S. Patent No. 7,753,972 issued on July 13, 2010 to Zubrin et al., discloses a portable renewable energy system for enhanced oil recovery. This is a truck mobile system that reforms biomass into carbon dioxide and hydrogen. The gases are separated. The carbon dioxide is sequestered underground for enhanced oil recovery and the hydrogen used to generate several megawatts of carbon-free electricity.
  • U.S. Patent Publication No. 2008/0283247 shows a portable, modular apparatus for recovering oil from an oil well and generating electric power.
  • This system includes a chassis to support a fuel reformer, a gas separator, a power generator, and/or a compressor.
  • the fuel reformer module is adapted to react a fuel source with water to generate a driver gas including a mixture of carbon dioxide gas and hydrogen gas.
  • the gas separator module is operatively coupled to the reformer module and is adapted to separate at least a portion of the hydrogen gas from the rest of the driver gas.
  • the power generator module is operatively coupled to the gas separator module and is adapted to generate electric power using a portion of the separated hydrogen gas.
  • the compressor module is operatively connected to the reformer module and is adapted to compress a portion of the driver gas and to eject the driver gas at high pressure into the oil well for enhanced oil recovery.
  • U.S. Patent Publication No. 2009/0236093 shows a method for extracting petroleum by using reformed gases.
  • This method includes reforming a fuel source by reaction with water to generate driver gas and injecting the driver gas into the oil well.
  • the reforming operation includes causing the combustion of a combustible material with ambient oxygen for the release of energy.
  • a reforming reaction fuel and water is heated with the energy released from this heating process. This is at a temperature above that required for the reforming reaction in which the fuel and water sources are reformed into driver gas.
  • U.S. Patent Publication No. 2010/0314136 published on December 16, 2010 to Zubrin et al, discloses an in-situ apparatus for generating carbon dioxide gas at an oil site for use in enhanced oil recovery.
  • the apparatus includes a steam generator adapted to boil and superheat water to generate a source of superheated steam, as well as a source of essentially pure oxygen.
  • the apparatus also includes a steam reformer adapted to react a carbonaceous material with the superheated steam and the pure oxygen, in an absence of air, to generate a driver gas made up of primarily carbon dioxide gas and hydrogen.
  • a separator is adapted to separate at least a portion of the carbon dioxide gas from the rest of the driver gas to generate a carbon dioxide-rich driver gas and a hydrogen-rich fuel gas.
  • a compressor is used for compressing the carbon dioxide-rich driver gas for use in enhanced oil recovery.
  • U.S. Patent Publication No. 2011/0067410 published on March 24, 2011 to Zubrin et al, teaches a reformation power plant that generates clean electricity from carbonaceous material and high pressure carbon dioxide.
  • the reformation power plant utilizes a reformation process that reforms carbonaceous fuel with super-heated steam into a high-pressure gaseous mixture that is rich in carbon dioxide and hydrogen. This high-pressure gas exchanges excess heat with the incoming steam from a boiler and continues onward to a condenser. Once cooled, the high-pressure gas goes through a methanol separator, after which the carbon dioxide-rich gas is sequestered underground or is re-used. The remaining hydrogen-rich gas is combusted through a gas turbine.
  • the gas turbine provides power to a generator and also regenerative heat for the boiler.
  • the generator converts mechanical energy into electricity, which is transferred to the electric grid.
  • the present invention is a process for enhanced oil recovery from a well in which the process includes the steps of: (1) producing steam in at least a first pressure range and a second pressure range; (2) passing the steam of the first pressure range to a steam turbine so as to produce power therefrom; (3) passing the steam of the second pressure range to an amine capture system such that carbon dioxide is delivered therefrom; and (4) injecting the carbon dioxide from the amine capture system into a well for enhanced oil recovery.
  • the step of producing steam further includes producing steam in a third pressure range.
  • the third pressure range is passed to an absorption chiller so as to cool a liquid therein.
  • the steam of the first pressure range has a pressure range greater than the pressure of the steam of the second pressure range.
  • the pressure of the steam is of the second pressure range is greater than the pressure of the steam in the third pressure range.
  • the first pressure range will have a pressure greater than 500 p.s.i.g.
  • the steam of the second pressure range will have a pressure of between 150 and 200 p.s.i.g.
  • the steam of the third pressure range will be less than 25 p.s.i.g.
  • the steam of the second pressure range can be used of variety of purposes.
  • the steam of the second pressure range can be passed to a dehydration unit so as to dry the natural gas passing therethrough.
  • the steam of the second pressure range can be passed to a heater treater. Initially, oil and water are pumped from the well into the heater treater. The pumped oil and water are heated in the heater treater with the passed steam of the second pressure range. Water is separated from the pumped oil and water in the heater treater.
  • the step of producing steam includes the steps of operating a heat recovery steam generator so as to produce the steam and to produce an exhaust.
  • the exhaust is delivered the exhaust to the amine capture system.
  • the carbon dioxide is separated from the exhaust by the amine capture system.
  • the energy is initially produced by a combustion turbine.
  • the combustion turbine is operated so as to provide power to the heat recovery steam generator.
  • the step of injecting the carbon dioxide includes the steps of compressing the carbon dioxide to a pressure of up to 2000 p.s.i.g. The compressed carbon dioxide is injected into the well.
  • the use of the combustion turbine in conjunction with the heat recovery steam generator provides power for sale and use in the project and steam for additional power.
  • the heat recovery steam generator allows for the generation of steam at various steam pressures.
  • the heat recovery steam generator will generate steam in at least two, and most likely, three different pressure ranges.
  • the high pressure steam (in excess of 500 p.s.i.g.) will be utilized to generate additional power through the use of a condensing steam turbine.
  • the turbine condenses the steam that is produced and is used to generate additional power.
  • the steam is converted back to water for reintroduction to the heat recovery steam generator. This serves to generate additional power without the necessity of the large volumes of water required in many installations, or the capital costs and electrical requirements of the air cooling.
  • the medium pressure steam (approximately 150 - 200 p.s.i.g.) will be utilized to provide the heat of the regeneration of the enhanced amine in the carbon dioxide capture system as well as for the regeneration of glycol in the gas dehydration system.
  • the medium pressure steam can also be used for the regeneration of the standard amine in the facility that is used to separate recycle gas coming from the oil field into its natural gas and carbon dioxide components.
  • the low pressure steam (up to approximately 25 p.s.i.g.) will be used to provide the heat required for the absorption chillers that are used to cool turbine inlet air and to cool the regenerated enhanced amine and normal amine before injection into the respective contactor vessels.
  • a portion of this steam, or possibly even hot water being returned from the absorption chillers, will be utilized to heat the inlet oil and water in the heater-treater on the inlet side of the central oil field production facilities. If optimization would indicate that a portion of the steam can provide all or a portion of the refrigeration for the natural gas processing, then the steam can be utilized as part of the natural gas liquids separation facility.
  • the enhanced oil recovery projects are long term developments. Typically, they would require carbon dioxide for many years. The production outcomes are predictable.
  • An oil field central processing facility has to be in service for the same period of time and would require two externally provided inputs, heat and power. Given the reservoir and oil characteristics, a reservoir simulation model can be created and the outputs of that model can be utilized to design the central facility equipment. Through the use of the heat from the combustion turbine, the overall efficiency of the process is greatly improved.
  • a standard oil field central processing facility will have a gas flame-driven heat source for the amine plant, the heater-treater and the gas dehydrator. Each of these pieces of equipment has its own safety and emissions issues.
  • the integrated design of the present invention allows a single source of heat and emissions to be the combustion turbine. In this facility, the insulated steam and return lines will travel to and from each individual piece of equipment taking heat and returning water to the process with minimal losses.
  • the integrated process of the present invention provides an effective method of generating carbon dioxide for enhanced oil recovery directly at an oil field location while, at the same time, providing all the necessary heat and power required to run all of the associated oil field processes in the most efficient manner possible.
  • FIGURE 1 is a block diagram showing the process of the enhanced oil recovery of the present invention.
  • the process 10 for enhanced oil recovery includes a combustion turbine 12, a heat recovery steam generator 14, amine capture systems 16 and 18, and a compressor 20.
  • the combustion turbine 12 is a natural gas-powered combustion turbine which utilizes natural gas as the fuel source.
  • the combustion turbine 12 includes a generator suitable for generating electrical energy.
  • the combustion turbine 12 is connected by line 22 to the electrical grid or to suitable batteries. As such, the electrical energy produced by the combustion turbine 12 can be connected to the electrical grid so that electrical energy from the combustion turbine 12 can be sold to the utilities.
  • the combustion turbine 12 is connected to a natural gas pipeline 24 and/or to the natural gas line 26 which emanates from the process 10.
  • Inlet air to the combustion turbine 12 is provided along inlet air line 28.
  • the inlet air passing through line 28 is delivered to an inlet air chiller 30.
  • the inlet air chiller cools the inlet to a cooler temperature so that the output of the combustion turbine 12 remains more constant.
  • the inlet air chiller 30 will serve to cool the inlet air to approximately 60°F prior to passing to the combustion turbine 12.
  • the inlet air 30 will sit above the turbine. As such, water will fall out from the inlet air chiller 30. This chilled water can then be provided to the thermal storage 32 or for other make-up water needs.
  • the exhaust from the combustion turbine 12 is delivered to the heat recovery steam generator 14.
  • the heat recovery steam generator 14 causes the hot exhaust 34 from the combustion turbine 12 to pass therethrough such that the heat recovery steam generator 14 will extract residual heat from the hot exhaust 34 and produce steam for the process of the present invention.
  • the heat recovery steam generator 14 will also lower the exhaust temperature before the exhaust gases pass into the amine capture systems 16 and/ or 18.
  • the heat recovery steam generator 14 will produce a great deal of steam.
  • the heat recovery steam generator 14 will produce steam of a first pressure range, a second pressure range, and a third pressure range.
  • Line 36 shows the steam output from the heat recovery steam generator 14. It can be seen that the steam of the first pressure range 38 will pass to a condensing steam turbine 40.
  • the first pressure range of the steam passing from line 36 into line 38 will be greater than 500 p.s.i.g. As such, the steam will have sufficient power so as to properly operate the condensing steam turbine.
  • the steam turbine 40 is a device that extracts thermal energy from pressurized steam and uses it to carry out mechanical work on a rotating output shaft. Since the steam turbine 40 utilizes rotary motion, it is particularly suited to be used to drive an electrical generator.
  • the steam turbine is in the form of a heat engine that derives most of its improvement in thermodynamic efficiency through the use of multiple stages in the expansion of the steam.
  • the electrical power for the process 10 of the present invention can be provided as an output 42 of the condensing steam turbine.
  • the steam 38 of the first pressure range is returned back to the heat recovery steam generator 14 along line 44 as water.
  • the heat recovery steam generator 14 also passes the steam along line 36 so as to produce steam of a second pressure so as to be delivered along line 46.
  • the steam of the second pressure, as passed along line 46 will be in the range of between 150 p.s.i.g. and 200 p.s.i.g. Suitable valving systems, known in the art, can serve to properly deliver the desired pressure of steam along the respective lines.
  • the steam of the second pressure range can be utilized for a variety of purposes.
  • the steam passing along line 46 can then pass to line for delivery to the amine capture system 16.
  • the amine capture system 16 is a Fluor Econamine FG Unit.
  • the Fluor Econamine FG Unit which forms the amine capture system 16 is an amine-based technology for a large-scale, post-combustion carbon dioxide capture.
  • the Econamine FG Plus technology is one of the first and one of the most widely applied commercial solutions that has been proven in operating environments to remove carbon dioxide from high oxygen content flue gases.
  • the amine capture system 16 utilizes a solvent formulation that is specially designed to recover carbon dioxide from low-pressure, oxygen-containing streams, such as boilers and reformer stack gas and gas-turbine flue-gas streams.
  • the carbon dioxide recovered by the amine capture system 16 can be tailored to meet the end user's specifications.
  • the amine capture system 16 utilizes a particular type of amine that captures carbon dioxide without degrading in the presence or oxygen.
  • the steam passing along 18 is used to provide heat.
  • the amine will enter the contactor tower and trickle downward while the exhaust gases flow upwardly. As such, the amine will contact the exhaust gases and retain the carbon dioxide.
  • the amine and carbon dioxide is then delivered to a boiler (heated by the steam 48) such that the carbon dioxide will boil out of the amine then be delivered outwardly along line 50 in the system 10. Exhaust gases pass from the amine capture system 16 along line 52.
  • the exhaust from the heat recovery steam generator 14 is passed along line 54 to a blower 56.
  • the blower 56 is in the nature of a fan. As such, the exhaust 56 can provide further heat for the amine capture system 16.
  • the exhaust, as passed by the blower 56, will contain additional carbon dioxide that can be removed through the use of the amine capture system 16.
  • the higher velocity exhaust gas from line 58 is delivered by blower 56 along line 58 as an input into the amine capture system 16.
  • the steam of the second pressure can further be delivered along lines 60 and 62 to the amine capture system 18.
  • the amine capture system 18 is a membrane separator or a standard amine contactor.
  • the membrane separator or standard amine contactor as used as part of the amine capture system 18 serves to remove the carbon dioxide from the natural gas and carbon dioxide mixture as passes as an input along 64 to the amine capture system 18.
  • the carbon dioxide output is passed along line 66 to the compressor 20.
  • the amine capture system 18 serves to receive the solution containing carbon dioxide.
  • the steam from the heat recovery steam generator 14 is delivered along lines 60 and 62 as heat to the amine capture system 18. As such, this heat is used so as to strip the carbon dioxide from the solution.
  • the low pressure carbon dioxide will pass outwardly of the amine capture system 18 along line 66 to the carbon dioxide compressor 20.
  • the carbon dioxide that passes along line 66 is a low-pressure, high-purity carbon dioxide.
  • the amine capture system 18 utilizes the steam of the second pressure range, as passed along line 48, directly to the amine capture system 18. Additionally, the amine capture system 18 can also utilize steam that is produced from the amine capture system 16. As such, the steam that is part of the output of the amine capture system 16 can be further utilized within the system 10 of the present invention.
  • the steam of the second pressure can also be used to facilitate the drying of the natural gas and carbon dioxide that has been produced from the well.
  • steam of the second pressure range passes along line 68 into the dehydration unit 70.
  • the dehydration unit 70 utilizes triethylene glycol to remove water from the mixture of carbon dioxide and natural gas that passes as an input along line 72 to the dehydration unit 70.
  • the dehydration unit 70 takes the water out of the carbon dioxide and natural gas mixture. As such, only a dry gas mixture of the natural gas and carbon dioxide will pass along line 64 as an input to the amine capture system 18.
  • the steam of the second pressure can further pass along line 74 as a steam input to the heater treater 76.
  • the heater treater 76 is a vessel that is commonly used in the oil field.
  • the heater treater 76 receives an oil and water mixture from line 78 from a bulk separator 80.
  • the heater treater 76 can further receive oil and water along line 82 from the test separator 84.
  • the heater treater 76 will contain a mixture of oil and water therein. In normal application, water will settle within the heater treater while oil will flow toward the top.
  • the temperature of the oil and water mixture within the heater treater 76 is elevated. As such, this will enhance the separation process.
  • water will pass outwardly of the heater treater 76 along line 86 for disposal.
  • the natural gas and carbon dioxide will flow outwardly of the heater treater 76 along line 88 to a compressor 90.
  • the crude oil that is separated from the water in heater treater 76 is passed along line 92 to crude storage vessel 94.
  • the crude oil that is received within the storage vessel 94 can be provided as a salable product along line 96.
  • the compressor 90 receives the mixture of natural gas and carbon dioxide from the heater treater 76 and builds up the pressure of the gas.
  • natural gas and carbon dioxide will have a pressure of approximately 75 p.s.i.g. from the field.
  • the compressor 90 will enhance the pressure of the natural gas and carbon dioxide mixture to between 600 and 700 p.s.i. As such, the compressed mixture of natural gas and carbon dioxide can flow into the dehydration unit 70 along line 72.
  • the bulk separator 80 receives production fluids from the well along line 100.
  • the production well fluids will typically include natural gas, carbon dioxide, water and oil.
  • the bulk separator 80 serves to pass the separated natural gas and carbon dioxide mixture along line 102 for delivery to the compressor 90 and/or into the line 88 from the heater treater 76.
  • the oil and water mixture from the bulk separator 80 passes along line 78 as an input to the vessel at the heater treater 76.
  • the water from the bulk separator will pass along line 104 for disposal.
  • the test separator 84 receives production fluid along line 106.
  • the test separator operates on each well separately.
  • the test separator 84 can determine how much carbon dioxide is associated with the oil.
  • the test separator 84 will then pass the oil and water mixture the heater treater 76 along line 82.
  • the test separator 84 will further transmit the produced water along line 108 for disposal.
  • the natural gas and carbon dioxide mixture from the test separator 84 is delivered along line 110 to the compressor 90. As such, the natural gas and carbon dioxide mixture from the heater treater 76, from the bulk separator 80, and from the test separator 84 will flow for use in the system 10 of the present invention.
  • the amine capture system 18 serves to separate the carbon dioxide from the natural gas.
  • the carbon dioxide will flow outwardly of the amine capture system 18 along line 66 to the compressor 20.
  • the natural gas as separated from the carbon dioxide, will flow along line 110 to a natural gas processing system 112.
  • the natural gas processing system 112 utilizes refrigeration so as to separate the various components of the natural gas.
  • the methane and ethane will flow outwardly of the natural gas processing system 112 along line 114.
  • the methane or ethane that passes along line 114 can be delivered to the natural gas pipeline 116.
  • the natural gas that passes in the line 114 can be utilized as the fuel for the combustion turbine 12. As such, this natural gas would flow along line 118 as a fuel input to the combustion turbine 12.
  • the natural gas processing system 112 will further pass natural gas liquids along line 120 to a natural gas liquid storage and loadout facility 122.
  • the natural gas liquids can include propane and butane. As such, the gas will need to be pressurized for delivery.
  • any natural gas liquids that are in the natural gas storage and loadout facility 122 can be delivered along line 124 for sale.
  • the natural gas processing system 112 can deliver pentanes and hexanes along line 126 for mixture with the crude passing in line 92. As such, these heavy natural gas components can be delivered as part of the crude product from the system 10.
  • the heat recovery steam generator 14 further produces steam of a third pressure range.
  • This third pressure range will be in the order of less than 25 p.s.i.g.
  • the steam of the second pressure range is delivered along line 128 to an absorption chiller 130.
  • the cooling provided by the absorption chiller 130 can also be provided by a mechanical refrigeration unit.
  • the steam passing in line 128 is used to provide the energy to the absorption chiller 130.
  • the absorption chiller 130 can produce chilled water for delivery to the thermal storage 32 along line 132.
  • the absorption chiller 130 will receive water, for chilling, along line 134 from the thermal storage 32.
  • the thermal storage 32 is in the nature of a tank. Typically, the water within the tank of the thermal storage 32 will contain glycol so as to avoid any freezing. The glycol will facilitate the ability to cool the water on a hot day while keeping the water from freezing on extremely cold days. The thermal storage 32 will further level out the refrigeration load of the system. Ultimately, warm water from the thermal storage 32 will pass for cooling to the absorption chiller 130. The thermal storage 32 serves to deliver chilled water along line 136 to the inlet air chiller 30, to the amine capture system 16, to the amine capture system 18 and to the compressor 20. Ultimately, after the chilled water has been utilized by these components, the water will return along line 138 back to the thermal storage 32. It is also possible that the chilled water flowing from the thermal storage 32 can also be used to facilitate the refrigeration of the natural gas in the natural gas processing system 112.
  • the compressor 20 serves to deliver the compressed carbon dioxide along line 140 to the well.
  • the carbon dioxide that is compressed by the compressor 20 is received from the amine capture system 18.
  • the compressor 20 will serve to compress the carbon dioxide to a pressure of approximately 2000 p.s.i.g. As such, this compressed carbon dioxide can be utilized for tertiary oil recovery in the well.

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  • Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Treating Waste Gases (AREA)
  • Gas Separation By Absorption (AREA)
  • Carbon And Carbon Compounds (AREA)

Abstract

L'invention porte sur un procédé de récupération assistée de pétrole, comprenant les étapes consistant à produire de la vapeur à une pression dans au moins une première plage de pression et une deuxième plage de pression, faire passer la vapeur à une pression dans la première plage de pression vers une turbine à vapeur (40) afin de produire de l'énergie électrique à partir de cette dernière, faire passer la vapeur à une pression dans la deuxième plage de pression vers un système de capture à amine (16) de façon à ce que du dioxyde de carbone soit libéré de ce dernier et injecter le dioxyde de carbone provenant du système de capture à amine dans un puits (140) de récupération assistée de pétrole. De la vapeur à une pression dans une troisième plage de pression peut être amenée à passer dans un refroidisseur par absorption (130) afin d'y refroidir un liquide. La première plage de pression est supérieure à la deuxième plage de pression.
PCT/US2014/043086 2013-06-19 2014-06-19 Procédé de récupération assistée de pétrole utilisant la capture de dioxyde de carbone Ceased WO2014205163A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
MX2015017408A MX2015017408A (es) 2013-06-19 2014-06-19 Proceso para recuperacion mejorada de petroleo usando captura de dioxido de carbono.

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/921,411 2013-06-19
US13/921,411 US20130341924A1 (en) 2011-08-08 2013-06-19 Process for enhanced oil recovery using capture of carbon dioxide

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WO2014205163A1 true WO2014205163A1 (fr) 2014-12-24

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