EP2875089A1 - Systèmes de génération d'énergie géothermique à base de dioxyde de carbone et procédés associés à ceux-ci - Google Patents

Systèmes de génération d'énergie géothermique à base de dioxyde de carbone et procédés associés à ceux-ci

Info

Publication number
EP2875089A1
EP2875089A1 EP13745264.5A EP13745264A EP2875089A1 EP 2875089 A1 EP2875089 A1 EP 2875089A1 EP 13745264 A EP13745264 A EP 13745264A EP 2875089 A1 EP2875089 A1 EP 2875089A1
Authority
EP
European Patent Office
Prior art keywords
fluid
reservoir
working fluid
production
hydrocarbon
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP13745264.5A
Other languages
German (de)
English (en)
Inventor
Martin O. Saar
Jimmy Bryan Randolph
Thomas H. Kuehn
Kenneth Carpenter
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Heat Mining Co LLC
University of Minnesota
Original Assignee
Heat Mining Co LLC
University of Minnesota
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US13/554,868 external-priority patent/US8991510B2/en
Application filed by Heat Mining Co LLC, University of Minnesota filed Critical Heat Mining Co LLC
Publication of EP2875089A1 publication Critical patent/EP2875089A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
    • C09K8/594—Compositions used in combination with injected gas, e.g. CO2 orcarbonated gas
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/28—Dissolving minerals other than hydrocarbons, e.g. by an alkaline or acid leaching agent
    • E21B43/281—Dissolving minerals other than hydrocarbons, e.g. by an alkaline or acid leaching agent using heat
    • 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
    • F01K25/00—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for
    • F01K25/08—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours
    • F01K25/10—Plants or engines characterised by use of special working fluids, not otherwise provided for; Plants operating in closed cycles and not otherwise provided for using special vapours the vapours being cold, e.g. ammonia, carbon dioxide, ether
    • F01K25/103—Carbon dioxide
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C1/00—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid
    • F02C1/002—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid using an auxiliary fluid
    • F02C1/005—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid using an auxiliary fluid being recirculated
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C1/00—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid
    • F02C1/04—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid the working fluid being heated indirectly
    • F02C1/05—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid the working fluid being heated indirectly characterised by the type or source of heat, e.g. using nuclear or solar energy
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C1/00—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid
    • F02C1/04—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid the working fluid being heated indirectly
    • F02C1/10—Closed cycles
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F03—MACHINES OR ENGINES FOR LIQUIDS; WIND, SPRING, OR WEIGHT MOTORS; PRODUCING MECHANICAL POWER OR A REACTIVE PROPULSIVE THRUST, NOT OTHERWISE PROVIDED FOR
    • F03G—SPRING, WEIGHT, INERTIA OR LIKE MOTORS; MECHANICAL-POWER PRODUCING DEVICES OR MECHANISMS, NOT OTHERWISE PROVIDED FOR OR USING ENERGY SOURCES NOT OTHERWISE PROVIDED FOR
    • F03G7/00—Mechanical-power-producing mechanisms, not otherwise provided for or using energy sources not otherwise provided for
    • F03G7/04—Mechanical-power-producing mechanisms, not otherwise provided for or using energy sources not otherwise provided for using pressure differences or thermal differences occurring in nature
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T10/20—Geothermal collectors using underground water as working fluid; using working fluid injected directly into the ground, e.g. using injection wells and recovery wells
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F24—HEATING; RANGES; VENTILATING
    • F24T—GEOTHERMAL COLLECTORS; GEOTHERMAL SYSTEMS
    • F24T10/00—Geothermal collectors
    • F24T2010/50—Component parts, details or accessories
    • F24T2010/56—Control arrangements
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/14—Combined heat and power generation [CHP]
    • 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

  • a system comprising one or more injection wells for accessing one or more reservoirs having a first temperature, wherein the one or more reservoirs are located below one or more caprocks and are accessible without using large-scale hydrofracturing, each of the one or more injection wells having an injection well reservoir opening; one or more production wells, each having a production well reservoir opening, wherein a non-water based working fluid can be provided to the one or more injection wells at a second temperature lower than the first temperature and exposure of the non-water based working fluid to the first temperature can produce heated non-water based working fluid capable of entering each of the one or more production well reservoir openings; and an energy converting apparatus connected to each of the one or more injection wells and the one or more productions wells, wherein thermal energy contained in the heated non-water based working fluid
  • each of the one or more injection wells and each of the one or more production wells are located in the same channel and the system further comprises one or more injection pipes and one or more production pipes connected to the channel.
  • the system further comprises a non-water based working fluid source, such as carbon dioxide (e.g., supercritical carbon dioxide) obtainable from a power plant (e.g., ethanol plant or fossil-fuel based power plant) or an industrial plant.
  • a non-water based working fluid source such as carbon dioxide (e.g., supercritical carbon dioxide) obtainable from a power plant (e.g., ethanol plant or fossil-fuel based power plant) or an industrial plant.
  • the energy converting apparatus comprises one or more expansion devices and one or more generators, one or more heat exchangers or a combination thereof.
  • the one or more generators can provide electricity to an electricity provider and the system further comprises the electricity provider.
  • each of the one or more heat exchangers can provide heat to a heat provider and the system further comprises the heat provider, such as a direct use provider or a ground heat pump.
  • the system further comprises one or more cooling units fluidly connected to the one or more production wells and the one or more injection wells.
  • a method comprising accessing one or more underground reservoirs having a natural temperature, the one or more reservoirs located beneath one or more caprocks;
  • a non-water based working fluid e.g., carbon dioxide, such as supercritical carbon dioxide
  • exposing the non-water based fluid to the natural temperature to produce heated fluid exposing the non-water based fluid to the natural temperature to produce heated fluid; and extracting thermal energy from the fluid, without using large-scale hydrofracturing, is provided.
  • a non-water based working fluid e.g., carbon dioxide, such as supercritical carbon dioxide
  • the heated fluid also contains native fluid present in the one or more reservoirs.
  • the one or more caprocks each have a permeability ranging from about 10 "16 m 2 to about 0 m 2 and the one or more reservoirs each have a porosity ranging from about one (1 )% to about 50% and a permeability ranging from about 10 "16 m 2 to about 10 "6 m 2 , with each of the one or more reservoirs having a natural temperature between about -30°C and about 300 °C.
  • the thermal energy is used to produce electricity, to heat a working fluid in one or more heat exchangers, to provide condensed fluid to the one or more reservoirs, to provide cooled fluid to the one or more reservoirs, to provide shaft power to one or more pumps or compressors, or a combination thereof.
  • the electricity is produced either by providing the hot fluid to one or more expansion devices or by providing the working fluid heated in the one or more heat exchangers to the one or more expansion devices, wherein the one or more expansion devices produces shaft power to one or more generators, which, in turn, produce the electricity.
  • the working fluid heated in the one or more heat exchangers provides heat for direct use, for groundwater heat pumps, for a Rankine power cycle, or a combination thereof.
  • the method further comprises choosing the underground reservoir; transporting a non-water based working fluid source to an area proximate to the injection well; converting the non-water based working fluid source into a non-water based working fluid; and providing the heat energy to a customer.
  • FIG. 1 is a simplified schematic diagram of an example energy generation system.
  • FIG. 2 is a simplified schematic diagram of another example energy generation system.
  • FIG. 3 is a simplified schematic diagram of another example energy generation system.
  • FIG. 4 is a simplified schematic diagram of another example energy generation system according to an embodiment of the invention.
  • FIGS. 5A and 5B are simplified schematic diagrams of more example energy generation systems.
  • FIG. 6 is a cross-section of Minnesota's Rift System (MRS).
  • FIG. 8 is an illustration of a geological structure used for a numerical model of a power generation system according to an embodiment of the invention.
  • FIG. 9 is a geological model showing dimensions and solute concentration according to an embodiment of the invention.
  • FIG. 1 1 is a graph showing temperature versus distance from an injection well to a production well for a porous medium in a carbon dioxide (C0 2 ) plume geothermal (CPG) system and various fracture spacings in an enhanced geothermal system (EGS) system according to an embodiment of the invention.
  • C0 2 carbon dioxide
  • CPG plume geothermal
  • EGS enhanced geothermal system
  • FIG. 13 is a graph showing heat extraction rate versus time for a CPG system as compared to a water system according to an embodiment of the invention.
  • FIG. 14 is a graph showing density versus distance from injection well to production well for a CPG system as compared to a water system according to embodiments of the invention.
  • FIG. 15 is a graph showing Rayleigh number versus distance from injection well to production well for a CPG system as compared to a water system according to an embodiment of the invention.
  • FIG. 16 is a graph showing Prandtl number versus distance from injection well to production well for a CPG system as compared to a water system according to an embodiment of the invention.
  • novel carbon dioxide-based geothermal energy generation systems i.e., carbon plume geothermal (CPG) systems
  • CPG carbon plume geothermal
  • geothermal energy can now be provided at lower reservoir temperatures and at locations other than hot, dry rock formations, without negatively impacting the surrounding area through use of large-scale hydrofracturing.
  • Use of a carbon dioxide-based geothermal system further provides a means for sequestering and storing excess carbon dioxide, rather than having it released to the atmosphere.
  • geologic feature can be rock, mineral, sediment, reservoir, caprock and the like, or any combination thereof.
  • a geologic feature is further considered to remain "in s/fu”following minor manmade disturbances used to create and/or position components, such as channels such as injection wells and/or production wells, within, around or near the feature.
  • a feature is also considered to remain "in s/fu”following minor man-initiated disturbances, such as causing a controllable or limited amount of rock, mineral, sediment or soil to become dislodged as a result of the minor manmade or natural disturbance.
  • a feature is not considered to remain "in situ" following any type of large-scale manmade disturbances, including large-scale hydrofracturing (such as to create an artificial reservoir), or man-initiated disturbances, such as permanent deformation of a geologic feature, earthquakes and/or tremors following large-scale hydrofracturing, all of which can have a further negative impacts on groundwater flow paths, habitats and man-made structures.
  • large-scale hydrofracturing such as to create an artificial reservoir
  • man-initiated disturbances such as permanent deformation of a geologic feature, earthquakes and/or tremors following large-scale hydrofracturing, all of which can have a further negative impacts on groundwater flow paths, habitats and man-made structures.
  • large-scale hydrofracturing refers to a known method for creating or inducing artificial fractures and/or faults in a feature, such as a rock or partially consolidated sediments, typically during operation of an enhanced geothermal system (EGS). See, for example, U.S. Patent No. 3,786,858 to Potter, which employs water for hydraulic fracturing of rock to create a thermal geological reservoir from which fluid is transported to the surface.
  • EGS enhanced geothermal system
  • Large-scale hydrofracturing is known to create unintended fluid flow pathways that can result in fluid loss or "shortcutting," which in turn decreases geothermal heating efficiencies of the working fluid.
  • Large-scale hydrofracturing can also cause (micro-) seismicity and damages to natural and/or manmade structures.
  • rock refers to a relatively hard, naturally formed mineral, collection of minerals, or petrified matter.
  • a collection of rocks is commonly referred to as a "rock formation.”
  • rocks have been identified on Earth, to include, for example, igneous, metamorphic, sedimentary, and the like.
  • a rock can erode or be subject to mass wasting to become sediment and/or soil proximate to or at a distance of many miles from its original location.
  • sediment refers to a granular material eroded by forces of nature, but not yet to the point of becoming “soil.” Sediment may be found on or within the Earth's crust. A collection of sediments is commonly referred to as a “sediment formation.” Sediment is commonly unconsolidated, although “partially consolidated sediments” are often referred to simply as “sediments” and are therefore considered to be included within the definition of sediment.
  • soil refers to a granular material comprising a biologically active, porous medium. Soil is found on, or as part of, the uppermost layer of the Earth's crust and evolves through weathering of solid materials, such as consolidated rocks, sediments, glacial tills, volcanic ash, and organic matter. Although often used interchangeably with the term “dirt,” dirt is technically not biologically active.
  • fluid refers to a liquid, gas, or combination thereof, or a fluid that exists above the critical point, i.e., a supercritical fluid.
  • a fluid is capable of flowing, expanding and/or accommodating a shape of its physical surroundings.
  • a fluid can comprise a native fluid, a working fluid, or combinations thereof. Examples of fluid include, for example, air, water, brine (i.e., salty water), hydrocarbon, C0 2 , magma, noble gases, or any combination thereof.
  • native fluid refers to a fluid which is naturally resident in a rock formation or sediment formation.
  • a native fluid includes, but is not limited to, water, saline water, oil, natural gas, hydrocarbons (e.g., methane, natural gas, oil), and combinations thereof. Carbon dioxide can also be a naturally present in the rock or sediment formation and thus constitute a native fluid in this case.
  • working fluid refers to a fluid which is not native to a rock formation or sediment formation and which may undergo a phase change from a gas to a liquid (energy source) or liquid to gas (refrigerant).
  • a "working fluid" in a machine or in a closed loop system is the pressurized gas or liquid which actuates the machine.
  • a working fluid includes, but is not limited to ammonia, sulfur dioxide, carbon dioxide, and non-halogenated hydrocarbons such as methane.
  • Water is used as a working fluid in conventional (i.e., water-based) heat engine systems.
  • a working fluid includes a fluid in a supercritical state as the term is understood in the art. Different working fluids can have different thermodynamic and fluid-dynamic properties, resulting in different power conversion efficiencies.
  • Pore space refers to any space not occupied by a solid (rock or mineral). Pore space can be the space formed between grains and/or the space formed by fractures, faults, fissures, conduits, caves, or any other type of non-solid space. Pore space can be connected or unconnected and it may, or may not, evolve over time due to changes in solid space volume and/or size (which could come from reactions, deformations, etc.). A pore space is filled with fluid, as the term is understood in the art.
  • C0 2 plume refers to a large-scale (meters to several kilometers to tens of kilometers in diameter) C0 2 presence within subsurface pore spaces (as defined above, where a significant percentage of the fluid in the pore space is C0 2 .
  • reservoir or "storage rock formation” or “storage sediment formation” as used herein, refers to a rock formation and/or sediment formation capable of storing an amount of fluid substantially “permanently” as that term is understood in the geological arts.
  • geothermal heat flow refers to any kind of heat transfer in the subsurface and consists of conductive and/or advective (sometimes referred to as convective) and/or radiative heat transfer, with radiative heat transfer typically being negligible in the subsurface.
  • a "low” heat flow is generally considered to be less than about 50 milliwatts per square meter.
  • a “moderate” heat flow is generally considered to be at least about 50 to about 80 milliwatts per square meter.
  • a “high” heat flow is generally considered to be greater than 80 milliwatts per square meter.
  • injection well refers to a well or borehole which is optionally cased (i.e., lined) and which may contain one or more pipes through which a fluid flow (typically in a downwardly direction) for purposes of releasing that fluid into the subsurface at some depth.
  • An injection well may exist in the same borehole as a production well.
  • production well refers to a well or borehole which is optionally cased (i.e., lined) and which may contain one or more pipes through which a fluid can flow (typically in an upwardly direction) or purposes of bringing fluids up from the subsurface to (near) the Earth's surface.
  • a production well may exist in the same borehole as an injection well.
  • EGS enhanced geothermal system
  • EOR enhanced oil recovery
  • tertiary recovery can refer to a system or method of recovering hydrocarbons, including, by not limited to, liquid hydrocarbons such as crude oil and hydrocarbons such as natural gas that are gaseous at atmospheric pressure and temperature, from a reservoir.
  • EOR can include the injection of a gas, such as carbon dioxide, or other components into the reservoir in order to improve extraction of the hydrocarbons, such as by at least one of reducing the fluid viscosity, reducing the surface tension of the hydrocarbons, or increasing pressure in the reservoir, in order to more easily remove them from the reservoir.
  • geothermal system refers to a geothermal system that utilizes water as the (subsurface) working fluid. This could be in natural reservoir systems or in hydrofractured (i.e., EGS) systems.
  • a system 100 generates energy from a source, such as a carbon dioxide (C0 2 ) source 1 10 using a C0 2 sequestration component 1 12 and a geothermal energy production component 1 14, as shown in FIG. 1.
  • the energy generated is thermal energy (i.e., heat), although the invention is not so limited.
  • the energy produced is used to generate electricity, as shown in FIG. 1 .
  • the energy is drawn off as heat, as shown in FIG. 2.
  • the energy is used to provide electricity and heat, as shown in FIG. 3, or to provide heat to operate a separate power cycle, such as an organic Rankine cycle, as shown in FIG. 4.
  • a separate power cycle such as an organic Rankine cycle
  • the source (e.g., C0 2 source 1 10) can be any suitable fluid, including a fluid containing solids, in dissolved or non-dissolved form, capable of absorbing thermal energy from its surroundings, and further releasing the thermal energy as described herein.
  • the source may be a waste stream from a power plant, such as a fossil fuel power plant (e.g., coal plant, natural gas plant, and the like), or any type of plant capable of producing fuel, such as biofuel (e.g., ethanol plant) or any type of industrial plant, such as a cement manufacturer, steel manufacturer, and the like.
  • the fluid is further capable of being transported via any suitable means, (e.g., pipe, various transportation means, such as truck, ship or rail), over a desired distance.
  • the source such as the C0 2 source 1 10 can, in most instances, be used "as is", in some instances, further processing may be used prior to introducing the C0 2 source 1 1 0 to a compressor 132 to produce a working fluid, such as cold C0 2 138, as shown in FIG. 1 .
  • a working fluid such as cold C0 2 138
  • some waste streams may require dewatering and/or drying.
  • the C0 2 source 1 10 is stored on site or off site for a period of time.
  • the cold C0 2 138 is supercritical C0 2 .
  • the system 100 is located at a site (i.e., in a position) configured to provide access to a target formation, the target formation comprising a caprock 1 18 located above a reservoir 120 as shown in FIG. 1 .
  • the reservoir 120 has a natural temperature higher than a temperature of the working fluid. In the embodiment shown in FIG. 1 , the natural temperature in the reservoir 120 is affected by geothermal heat 124 flowing up from below.
  • a top layer 1 16 may be located above the caprock 1 18 and reservoir 120 as shown in
  • the top layer 1 16 additionally or alternatively comprises a top layer or layers of sediment and/or soil of varying depths.
  • the permeability and/or porosity of the top layer 1 16 may vary widely, as long as drilling can be performed to insert the injection well 136 and production well 160 as described below, without using large-scale hydrofracturing.
  • the top layer 1 1 6 can include a variety of geologic features, including, but not limited to, soil, sand, dirt, sediment, and the like, or combinations thereof.
  • the top layer 1 16 may further have a wide range of depths (i.e., "thickness") sufficient to ensure working fluid introduced into the reservoir 120 remains in the desired state, such as a supercritical state.
  • the depth of the top layer 1 16 is at least 100 meters (m) or more, up to one (1 ) kilometer (km), further including more than one (1 ) km, such as up to three (3) km, four (4) km, five (5) km, or more, such as up to 10 km or over 15 km including any range there between, such as one (1 ) to five (5) km, below the Earth's surface (i.e., below or within a given topography in an area, which may or may not be exposed to the atmosphere). In most embodiments, however, it is expected that the target formations are located between about 800 m and about four (4) km beneath the Earth's surface.
  • Factors that can be considered in selecting reservoir depths can also vary according to local geology (e.g. , specific rock type, geothermal heat flow rates, subsurface temperatures), access to working fluid (e.g., carbon dioxide from fossil fuel burning power plants, ethanol plants), drilling and operation costs, and sociopolitical circumstances (e.g., consumer locations, constructs, electric grid locations, and the like).
  • the target formation comprising the caprock 1 1 8 and reservoir 120, can be made up of a variety of rock types, including, but not limited to, igneous rock, metamorphic rock, limestone, sedimentary rock, crystalline rock, and combinations thereof.
  • the target formation is a sedimentary basin having a substantially bowl or convex shape as shown in FIG. 4.
  • the target formation have another shape, such as the substantially dome or concave shape as shown in FIGS. 1 -3, although the invention is not limited to the shapes depicted in FIGS. 1 -4.
  • the target formation is a saline aquifer or a saline water-filled rock formation (e.g.
  • a target formation may contain a fault which can offset the target formation or a portion of the target formation, thereby forming a geological trap, as the term is understood in the art.
  • the target formation is a reservoir containing natural gas and/or oil and/or fresh water.
  • C0 2 such as the cold C0 2 138 shown in FIG. 1
  • a reservoir 120 located at least about 0.1 km, to about 4 km deep.
  • Such a combination can minimize upward leakage of the working fluid, since additional caprocks 1 18 may be present between the reservoir 120 and the Earth's surface.
  • higher natural reservoir temperatures i.e., greater than about 70 Q C
  • higher pressures i.e., greater than about 8 Pa
  • Larger depths can also increase the likelihood of the presence of dissolved salts and other minerals in the native fluid, which may reduce the likelihood that such native fluid would otherwise be useful for drinking and irrigation applications.
  • the caprock 1 18 shown in FIG. 1 is a geologic feature having a very low permeability, i.e., below about 1 0 "16 m 2 . Such a low permeability allows the caprock 1 1 8 to essentially function as a barrier for fluid contained in the reservoir 120 below. Permeability may also be dependent, in part, on the depth (i.e., thickness) of the caprock 1 18, as well as the depth of the top layer 1 1 6 above.
  • the porosity of the caprock 1 18 can vary widely. As is known in the art, even if a rock is highly porous, if voids within the rock are not interconnected, fluids within the closed, isolated pores cannot move. Therefore, as long as the caprock 1 18 exhibits permeability sufficiently low to allow it to prevent or inhibit fluid leakage from fluid in the reservoir 120, the porosity of the caprock 1 18 is not limited.
  • the thickness of the caprock 1 1 8 can vary, but is generally substantially less than the thickness of the top layer 1 1 6.
  • the top layer 1 16 has a thickness on the order of 10, or 1 0 to 100, up to 1 000 times the thickness of the caprock 1 18, further including any range there between, although the invention is not so limited.
  • the thickness of the caprock 1 18 can vary from about one (1 ) cm up to about 1000 m or more, such as between about five (5) cm and 1000 m, such as between about one (1 ) m and about 100 m.
  • the caprock 1 18 represents more than one caprock 1 1 8, such that multiple caprocks are present which partially or completely cover one another and may act jointly as a caprock 1 1 8 to prevent or reduce upward leakage of the working fluid from the reservoir 120.
  • the reservoir 120 is a hot dry rock reservoir, as that term is understood in the art, although, as noted herein, the such a reservoir can optionally be used [0065]
  • the reservoir 120 is sufficiently permeable to allow multidirectional routes for dispersion or flow of fluid at relatively high rates, including lateral dispersion or flow.
  • the presence of the caprock 1 18 above the reservoir 120 further enhances the dispersion capabilities of the reservoir 120.
  • the porosity of the reservoir 120 ranges from between about four (4)% to about 50% or greater, such as up to about 60%.
  • the reservoir 120 is also sufficiently permeable to allow fluids to flow relatively easily, i.e., at a rate of about 0.1 to about 50 liters/minute (L/min) or higher, such as up to several thousand L/min.
  • the reservoir 120 has a permeability of about 10 "16 m 2 to about 10 "9 m 2 , or greater, such as up to about 1 0 "6 m 2 .
  • the reservoir 120 has a porosity of at least about (4) % and a permeability of at least about 10 "15 m 2 , with the caprock 1 18 having a maximum permeability of about 10 " 16 m 2 . (See also Example 1 ).
  • the reservoir 120 can have any suitable natural temperature.
  • the natural temperature of the reservoir 120 is at least about 90 Q C, although the invention is not so limited.
  • natural temperatures below 90 Q C such as down to 80 Q C or 70 Q C, further including down to 30 Q C, including any range there between, are present.
  • Natural temperatures greater than 90 Q C may also be present, with the highest temperature limited only by the amount of geothermal heat 124 provided and the ability of the reservoir 120 to capture and retain the geothermal heat 124. It is possible that temperatures greater than about 300 Q C may be present in the reservoir 120.
  • a specific desired natural temperature is obtained by varying the depth of the injection well 136 or the production well (i.e. , recovery well) 160. In one embodiment, higher natural temperatures are obtained by increasing the depth of the injection well 136, with or without increasing the depth of the production well 1 60. Unlike conventional geothermal energy systems which utilize water as the working fluid, however, the natural temperatures used to generate energy in the novel non-water based geothermal systems described herein, in amounts sufficient to produce electricity, for example, are much lower.
  • the depth of the reservoir 120 can vary as noted above. Additionally, the overall size of the reservoir 120 can also vary.
  • the geothermal heat 124 can flow at any suitable rate, including at a high rate as is present in "high geothermal heat flow regions", as the term is understood in the art.
  • Conventional water- based systems are known to require high geothermal heat flow in most instances.
  • the novel systems described herein can operate in a wider range of locations, including low and moderate geothermal heat flow regions.
  • the system 1 00 of FIG. 1 comprises a C0 2 sequestration component 1 12 and a geothermal energy production component 1 14.
  • C0 2 sequestration is accomplished by providing the C0 2 source 1 1 0 to an optional compressor 132 to produce compressed C0 2 1 1 1 (i.e., C0 2 having a temperature of about zero (0) to about 50 Q C and pressure of about three (3) to about seven (7) Pa).
  • the compressed C0 2 1 1 1 can optionally pass through a first cooling unit 134 to produce a working fluid, such as cold C0 2 138 (i.e., saturated liquid C0 2 having a temperature less than about 30 Q C and pressure of about three (3) to about seven (7) MPa), before entering the injection well 136, as shown in FIG. 1 , where it flows in a substantially downwardly direction below the Earth's surface.
  • cold C0 2 138 i.e., saturated liquid C0 2 having a temperature less than about 30 Q C and pressure of about three (3) to about seven (7) MPa
  • the cold C0 2 138 permeates the reservoir 120 forming a C0 2 plume.
  • the cold C0 2 138 Upon exposure to the temperatures present in the reservoir 120 (which are higher than the temperature of the cold C0 2 138), the cold C0 2 138 absorbs heat from the reservoir 120, thus causing an upwardly- migrating C0 2 plume 122, which, in one embodiment, may be laterally advected due to non-zero groundwater flow velocities within the reservoir 120, as shown in FIG. 1. In one embodiment, lateral migration occurs additionally or alternatively due to the C0 2 plume spreading, as additional C0 2 exits the injection well 170.
  • the C0 2 plume 122 which can further contain an amount of native fluid (partially dissolved in the C0 2 plume or included as individual bubbles or fluid pockets), migrates, is transported (such as in a closed loop system as described herein) and/or flows and/or spreads towards the production well 160, entering a production well reservoir opening 172 as hot C0 2 140 (i.e., fluid C0 2 having a temperature greater than about 30 Q C).
  • the C0 2 plume 122 can move at any suitable rate in a substantially horizontal manner across the reservoir 120.
  • the C0 2 plume 122 moves at a rate of about 0.1 to about one (1 ) m/day, such as about 0.4 to about 0.6 m/day, although the invention is not so limited.
  • the hot C0 2 140 enters an expansion device 142 to produce shaft power 144 which can be provided to a generator 146 to produce electricity 148 and to the compressor 132.
  • Warm C0 2 150 i.e., gaseous C0 2 having a temperature between about zero 0 Q and about 30 Q C and a pressure between about three (3) and about seven (7) MPa
  • the warm C0 2 150 is provided to the second cooling unit 152, where exhaust 154 (warmed air or water or water vapor) is released, while cooled C0 2 157 can be provided to the first cooling unit 134 to repeat the power cycle, after optionally passing through a pump 156.
  • the working fluid used in the carbon dioxide sequestration component 1 12 of the system 100 shown in FIG. 1 is cold C0 2 138 obtained from a C0 2 source 1 1 0. Such a working fluid can further contain entrained contaminants.
  • the working fluid useful in the substantially above-ground geothermal energy production component 1 14 of the system 100 may be any suitable secondary working fluid 250 as is understood in the art. (See FIGS. 2-4).
  • the working fluid for either the C0 2 sequestration component 1 12 or the geothermal energy production component 1 14 with a non water- based fluid i.e., any fluid which is thermodynamically more favorable than water (i.e., having a higher condensing pressure and higher vapor density at ambient temperature).
  • a non water- based fluid i.e., any fluid which is thermodynamically more favorable than water (i.e., having a higher condensing pressure and higher vapor density at ambient temperature).
  • one or more supercritical fluids are used as the working fluid for either or both components, 112 and 1 14.
  • supercritical carbon dioxide is used as the working fluid in the C0 2 sequestration component 1 12 and/or the geothermal energy production component 114.
  • Supercritical carbon dioxide has an increased density, as compared with other working fluids, such as gaseous carbon dioxide, such that a greater amount can be stored in a smaller volume, thus increasing system efficiency. Additionally, and in particular for the C0 2 sequestration component 1 12, supercritical carbon dioxide has favorable chemical properties and interaction characteristics with water (such as saline water), as is known in the art. Supercritical carbon dioxide can also be used in colder conditions, as compared with water-based geothermal systems, since it has a lower freezing point of about -55 Q C (as compared to approximately 0 Q C for water) depending on pressure.
  • a carbon dioxide-based system can be used in temperatures much lower than 0 Q C, such as down to -10 Q C or -20 Q C or -30 Q C or below, down to about -55 Q C, including any range there between.
  • the use of carbon dioxide, in one embodiment, as the working fluid in the C0 2 sequestration component 1 12 allows for sequestering of carbon dioxide.
  • the working fluid in the C0 2 sequestration component 1 12 e.g. , cold
  • C0 2 138 is released directly into the reservoir 120 where it becomes a C0 2 plume 122, which is allowed to flow through natural pores, fractures and conduits present in the reservoir 120 in the area between the injection well reservoir opening 170, where it eventually becomes hot C0 2 140, before entering a production well reservoir opening 172 of the production well 160, as shown in FIG. 1.
  • a flow pattern is referred to herein as an "open" flow cycle.
  • the working fluid can displace and/or commingle with any native fluid(s) present.
  • heat exchange between the reservoir 120 and the working fluid is facilitated and heat energy extraction is increased, as compared to a "closed" system in which the working fluid travels only through manmade pipes located in the reservoir 120 between the injection well reservoir opening 170 and the production well reservoir opening 172.
  • any fluid loss occurring in an open cycle is simply sequestered in the reservoir 120.
  • a partially open cycle is used.
  • a closed cycle is used.
  • the injection well reservoir opening 170 and the production well reservoir opening 172, the production well 160 are, in one embodiment, located at a distance sufficiently apart from one another to permit adequate heating of the cold C0 2 138 to the desired temperature.
  • the compressor 132 can comprise any suitable compressor or compressors known in the art. In one embodiment any suitable type of pump replaces the compressor 132. In one embodiment, no compressor 132 is used, such as when the C0 2 source 1 10 is provided at a sufficiently high pressure (i.e., greater than about six (6) Pa). I n one embodiment, no compressor 132 (or pump) is used and the first cooling unit 134 is a condenser which provides a saturated liquid at ambient temperature and corresponding saturation pressure (e.g., C0 2 ) for injection into the injection well 136, thus maximizing the density of the working fluid as well as the thermosyphon effect within the injection well 136.
  • a condenser which provides a saturated liquid at ambient temperature and corresponding saturation pressure (e.g., C0 2 ) for injection into the injection well 136, thus maximizing the density of the working fluid as well as the thermosyphon effect within the injection well 136.
  • the higher condensing pressure surprisingly compensates for this decreased density effect at a level sufficient to maintain the deep rock cavity (i.e., reservoir 120) pressure regardless of changing surface conditions without using a compressor 132 (or pump). Such a configuration allows for reduced start-up and operating costs.
  • Use of the first cooling unit 134 ensures that all of the carbon dioxide injected into the injection well 136 will be fluid at the same pressure and temperature, regardless of whether it comes from the C0 2 source 1 1 0 or as cooled C0 2 157 from the power cycle. Any suitable type or types of cooling unit can be used for the first cooling unit 134.
  • the first cooling unit 134 further minimizes the amount of pumping action needed to increase pressure at the injection well 136, since less power is needed to pump a liquid to a higher pressure than a gas.
  • the first cooling unit 134 also helps to maximize any natural thermosyphon effect present (i.e., passive heat exchange based on natural convection which circulates liquid), by providing the injection well 136 with cold C0 2 138 at all times, although the invention is not so limited. In one embodiment, there is no first cooling unit 134. I n one embodiment, the first cooling unit 134 is a condenser cooled by any suitable cooling means, such as with a water-antifreeze solution (e.g., glycol), with the cooling means in turn cooled by ambient air in the condenser.
  • a water-antifreeze solution e.g., glycol
  • the injection well 136 can be any suitable type of channel that allows the working fluid to move substantially downwardly. In one embodiment, the injection well 136 comprises more than one injection well. Depending on a particular site's history of heat extraction and on the geologic
  • the injection well 136 and the production well 160 comprise a single channel or shaft with two or more pipes extending there from.
  • the injection "pipe” is deeper than the production "pipe.”
  • the production well 160 can be any suitable type of channel that allows the working fluid to move substantially upwardly. I n one embodiment, the production well 160 comprises more than one production well. As with the injection well 136, patterns, depths, and C0 2 extraction rates of the production well 160 may be optimized.
  • the injection well 136 comprises more than one injection well distributed in various locations and one or more production wells 1 60 are more centrally located.
  • the ambient temperature liquid coming out of the first cooling unit 134 can be provided to the sites of the various injection wells 136 through gravity-sloped small pipes (e.g., high density, low volumetric flow rate) with little or no thermal insulation required.
  • the hot vapor, such as the hot C0 2 140 in the production well 160 is provided more directly to the geothermal energy production component 1 14, wherein pipe sizes may need to be larger to handle the higher volumetric flow rate and thermal insulation required.
  • the locations of the injection well 136 in relation to the production well 136 can be determined by any suitable means, including accessing geological data, such as from the U.S. Geological Survey pertaining to the particular target formation, and performing computer modeling, such as described in the Example section, in order to be able to predict and optimize conditions within the reservoir 120, such that, for example, the production well reservoir opening 1 72 of the production well 1 60 is at a point where the C0 2 plume 122 is at a sufficiently high temperature to become hot C0 2 140.
  • the injection well 136 and production well 160 are located at a distance sufficient to ensure that the working fluid (e.g., the cold C0 2 138) increases in temperature by at least about 10 Q C from the injection well reservoir opening 170 and the production well reservoir opening 172.
  • the working fluid e.g., the cold C0 2 138
  • Such distance can be a lateral distance, a vertical distance, or a combination thereof.
  • the roles of the injection and production wells, 136 and 160, respectively, are reversed after a period of time to improve subsurface heat exchange within the reservoir 120.
  • the injection and production wells are reversed every few months or about every one (1 ) year up to about every five (5) years or any period there between.
  • the expansion device 142 can comprise any suitable type of expansion device 142 known in the art, including any type of turbine, although the invention is not so limited.
  • any suitable type of expansion device 142 known in the art, including any type of turbine, although the invention is not so limited.
  • the use of a conventional turbine in higher pressure C0 2 geothermal energy systems and methods described herein is an option, rather than a requirement
  • the expansion device 142 is one or more piston-cylinder devices. In one embodiment, the expansion device 142 is one or more scroll, screw or rotary compressors designed to run in reverse as engines. In one embodiment, the expansion device 142 comprises more than one expansion device 142. In one embodiment, multiple expansion devices 142 run in parallel, with some running pumps or compressors directly and others producing electric power for sale.
  • the generator 146 can be any suitable generator known in the art, to produce electricity
  • the second cooling unit 152 can be any suitable type of cooling unit as is known in the art.
  • the second cooling unit 152 is a dry cooling tower in which the exhaust 154 is released to ambient air.
  • the second cooling unit 152 is a wet cooling tower in which the exhaust 154 is released into the air by also evaporating a volume of water.
  • a dry cooling tower is used during colder conditions and a wet cooling tower is used during warmer conditions. Use of a wet cooling tower during warmer conditions can increase plant efficiency, as is known in the art.
  • the pump 156 shown in FIG. 1 is also optional and may be any suitable type of pump
  • the reservoir 120 is also used as a cooling unit to cool warm C0 2 150 exiting the expansion device 142, with the appropriate piping and pumps provided as is known in the art.
  • a geothermal energy system comprising a subterranean fluid transport system comprising an ingress channel (into the reservoir) and egress channel (out of the reservoir), each of the ingress and egress channels having respective proximal ends and distal ends relative to the surface; a natural subterranean porous in situ rock formation; a working fluid, the supercritical fluid being introduced into the rock formation starting at the proximal end and moving toward the distal end of the ingress channel.
  • the fluid is withdrawn in part at the distal end of the ingress channel so as to form a subterranean fluid reservoir integral with the rock formation; and wherein the fluid is heated by the rock formation prior to transport toward the surface and proximal end 1 of the egress channel.
  • the system can comprise a compressor located in-line and integrated as part of the ingress channel to facilitate movement of the fluid toward the rock formation (i.e., reintroduction).
  • the heated plume is formed as part of the migration through the rock toward the intake at the egress channel distal end.
  • the fluid absorbs the natural geothermal heat associated with the rock formation.
  • the egress channel proximal end can be associated with a turbine and generator system, whereby electrical energy is produced and distributed to the consumer(s).
  • the heat energy can be incorporated into system for district space and water heating applications (not illustrated).
  • the subsurface-heated working fluid as a primary working fluid, can be directly introduced into a turbine assembly as part of a turbine-generator system to generate electricity.
  • a plurality of ingress channels can be employed in combination with a single egress channel.
  • a plurality of egress channels can be constructed, using a single ingress channel.
  • both a plurality of ingress channels and a plurality of egress channels can be constructed within a unitary system.
  • Arrangements using multiple systems at a land surface area using different parts of the same rock formation strata, or using separate and distinct rock formations at different depth and space parameters are contemplated.
  • an additional transport channel can be constructed for the transport of external carbon dioxide sources.
  • external carbon dioxide sources include, but are not limited to, fossil fuel power plants, ethanol plants, and the like.
  • a water removal component may be incorporated into the system.
  • the novel systems and methods described herein are constructed to permit maintenance desired for optimal operation of the system.
  • the working fluid supply channel can be structured to permit its removal for maintenance (e.g., cleaning), or intermittent removal for a period of time to create a temporary closed cyclic system.
  • the system can also be constructed to receive and accommodate multiple industrial carbon dioxide supply lines from different sources as part of the system.
  • the hot C0 2 140 passes through a heat exchanger 202 where it is used to warm a secondary working fluid 250 also cycling through the heat exchanger 202 (through the second cooling unit 152 and pump 255 as shown).
  • the heated secondary working fluid (temp > about 30 Q C) is released as heat 204, which can be used in any direct use application and/or as a ground-source heat pump, using components well known in the art.
  • a portion of the heated secondary working fluid enters the expansion device 142 to produce shaft power 144 which is provided to the compressor 132 where the cycle is repeated.
  • the hot C0 2 140 exits the heat exchanger 202 as cooled C0 2 159 (i.e., C0 2 having a temperature of two (2) and seven (7) Pa that may be condensed liquid), passing through an optional pump or compressor 156 and finally returned to the first cooling unit 134, where it may be further cooled to become cold C0 2 138, thus repeating the cycle.
  • cooled C0 2 159 i.e., C0 2 having a temperature of two (2) and seven (7) Pa that may be condensed liquid
  • the first cooling unit 134 where it may be further cooled to become cold C0 2 138, thus repeating the cycle.
  • both electricity 148 and heat 204 are produced.
  • a second cooling unit (not shown) (e.g., 152 in FIGS. 1 and 2) is used and the heat exchanger 202 as described above is also retained.
  • a novel method comprising pumping C0 2 from an emitter
  • the reservoir contains salty groundwater unlikely to be used for irrigation or consumption.
  • the reservoir may contain hydrocarbons (oil, natural gas) and the injected C0 2 is supercritical C0 2 which serves to enhance oil recovery (EOR).
  • the target formation comprises a reservoir located underneath at least one very low permeability caprock that prevents the working fluid, e.g. , supercritical C0 2 , from rising to the surface (similar to a natural gas trap).
  • the depth of the reservoir reduces the chance of C0 2 reaching the surface, as multiple other low- permeability layers are likely present above the reservoir.
  • FIGS. 5A and 5B show examples of a hydrocarbon and energy recovery system 500A
  • the system 500A, 500B can be used with a reservoir 120 that includes a native fluid 123 comprising at least one hydrocarbon to be recovered, such as oil, natural gas, or both
  • the system 500A, 500B can include a source 502 of a non-water based working fluid, such as carbon dioxide (C0 2 ).
  • the C0 2 source 502 can include a source of C0 2 , such as a power plant, an industrial plant, another production facility, or an underground source.
  • the C0 2 can be provided from an air-capture source or any other source.
  • the C0 2 can be in liquid form, gaseous form, supercritical form, or a mixture of two or more forms of C0 2
  • the C0 2 source 502 can provide C0 2 as supercritical C0 2 , for example through the use of a compressor and/or a cooling unit 503 (such as the compressor 132 and cooling unit 134 described above with respect to FIGS.
  • the C0 2 source 502 can be configured to deliver a non-water based working fluid, such as C0 2 138 (or other non-water based working fluids) to an injection well 136.
  • the injection well 136 can include an injection well opening 1 70 that is in fluid communication with the reservoir 120.
  • the C0 2 working fluid 138 can enter the reservoir 120 through the injection well opening 1 70.
  • the C0 2 working fluid 138 can interact with the native fluid 123, and in particular can interact with the at least one hydrocarbon of the native fluid 123, to form at least one production fluid 141 .
  • the interaction between the C0 2 working fluid 138 and the native fluid 123 can improve the mobility of the hydrocarbons in the resulting production fluid 141 to improve extraction of the hydrocarbons from the reservoir 120.
  • the production fluid 141 can be pushed toward one or more production wells 160, where it can be returned at or near the surface.
  • water or other fluids can be injected into the reservoir in addition to the
  • a Water Alternating Gas (“WAG”) method can be used where the C0 2 working fluid 138 and a water-containing working fluid are alternated, with the C0 2 working fluid 138 acting to improve mobility of the hydrocarbons, and the water-containing working fluid pushing the C0 2 and hydrocarbon production fluid 141 toward one or more production well openings 172 and up the production well 160.
  • WAG Water Alternating Gas
  • Further description of EOR and WAG is including in National Energy Technology Laboratory (NETL), "Carbon Dioxide Enhanced Oil Recovery,” (available at
  • the production fluid 141 can include at least a portion of the working fluid 138 and at least a portion of the hydrocarbons 123.
  • the production fluid 141 can also include other native fluids that can be present in the reservoir 120, such as a brine solution, and other injected fluids, such as a water- containing working fluid.
  • the production fluid 141 can include a non-water based working fluid (e.g. , C0 2 ) content between about 0.01 wt% and about 99 wt%, inclusive, for example between about 33 wt% and about 50 wt%, inclusive, of the non-water based working fluid.
  • the production fluid 141 can include a hydrocarbon content of between about 1 wt% and about 95 wt%, inclusive, for example between about 25 wt% and about 50 wt%, inclusive, of hydrocarbons.
  • the production fluid 141 can include a composition of other fluids, such as brine or an injected water-containing working fluid, of between about 1 wt% and about 95 wt%, inclusive, for example between about 25 wt% and about 50wt%, inclusive, of other native fluids or other injected fluids.
  • the production fluid 141 can have a "high" percentage of the C0 2 working fluid, e.g., between about 66 wt% and about 99 wt% C0 2 , inclusive, a "low” percentage of the C0 2 working fluid, e.g. , between 1 wt% and about 33 wt% C0 2 , inclusive, or any range of C0 2 content in between, such as a "medium” percentage of the C0 2 working fluid, e.g., between about 33 wt% and about 66 wt% C0 2 , inclusive.
  • the percentage of C0 2 in the working fluid can be very low, such as from 1 wt% to 9 wt%, inclusive, for example from 2 wt% to 5 wt%, inclusive.
  • the C0 2 can be partially or fully miscible with the hydrocarbons so that the C0 2 working fluid 138 and the hydrocarbons 123 form a homogenous or substantially homogenous solution of C0 2 and hydrocarbon.
  • the C0 2 working fluid 138 can be fully or substantially immiscible so that the C0 2 only partially dissolves, or substantially does not dissolve at all in the hydrocarbons so that the C0 2 and the hydrocarbons in the production fluid 141 are produced as separate immiscible or substantially immiscible fluids.
  • the C0 2 can mix with the hydrocarbons and can provide for at least one of reduced viscosity of the hydrocarbons, reduced surface tension of the hydrocarbons, increased mobility of the hydrocarbons, or increased fluid pressure in the reservoir 120 so that the hydrocarbons can more easily separate from the rock formation of the reservoir 120 or be more easily driven toward the production well opening 172, or both.
  • the production fluid 141 can be carried up through the reservoir 120, such as by or in conjunction with a C0 2 plume 122.
  • the production fluid 141 can also be formed as a zone of mobilized hydrocarbons and C0 2 that can be similar to a plume, but not necessarily.
  • the one or more production fluids 141 can include alternating zones of mobilized hydrocarbons with C0 2 and zones of water-containing working fluid. As the production fluid 141 moves through the reservoir 120, it can become heated by geothermal heat 124 that is present in or is supplied to the reservoir 120.
  • the geothermal heat 124 can raise the temperature of the production fluid 141 , raise the pressure of the production fluid 141 , or both, and in particular raise the temperature of the C0 2 working fluid 138, raise the pressure of the C0 2 working fluid 138, or both, within the production fluid 141 .
  • the temperature of the production fluid 141 as it enters the production well opening 1 72 can be higher than the temperature of the C0 2 working fluid 138 as it exits the injection well opening 1 70.
  • the heated production fluid 141 can enter one or more production wells 160, such as through a production well opening 172 to each production well 160.
  • the production fluid 141 can be returned to the surface through the one or more production wells 1 60.
  • energy can be recovered from the production fluid 141 in an energy recovery system 504A, 504B.
  • the energy recovery system 504A, 504B can include any apparatus or system configured to recover energy from a portion or all of the production fluid 141 .
  • the energy recovery system 504A, 504B can include any or all of the components described above for the electricity-generating system described above with respect to FIG. 1 , the heat-recovery system described above with respect to FIG. 2, the electricity and heat generating system with respect to FIG. 3, or the Organic Rankine Cycle (ORC) described above with respect to FIG. 4.
  • the system 500A, 500B can include a separation system 506 for separating one or more components from the production fluid 141 .
  • the production fluid 141 can include a non- water based working fluid, such as a C0 2 working fluid, for example supercritical C0 2 .
  • the production fluid 141 can also include one or more native fluids 123 from the reservoir 120, such as a brine or one or more hydrocarbons, including hydrocarbons present, for example, in the form of liquid oil such as crude oil, or natural gas, or methane.
  • the production fluid 141 can also include other injected fluids, such as a water-containing working fluid.
  • the separation system 506 can include any separation operation that is known in the art for separating components from the production fluid 141 .
  • the separation system 506 can include one or more separation operation units for separating C0 2 , from hydrocarbons, from other native fluids such as water or brine, or from injected fluids such as a water-containing working fluid.
  • the separation system 506 can also include one or more separation operation units for separating hydrocarbons from C0 2 , from other native fluids, or from other injected fluids such as a water-containing working fluid.
  • separation operation units that can be used for the separation of C0 2 , hydrocarbons, or other native fluids, include, but are not limited to: distillation units, such as one or more distillation columns; absorption units, such as one or more absorption columns; chromatography units; density separation units, such as centrifuges, cyclone separators, decanters and the like; crystallization or recrystallization units; electrophoresis units; evaporation or drying units; extraction units, such as leaching, liquid-liquid extraction, or solid-phase extraction; stripping units; and the like.
  • distillation units such as one or more distillation columns
  • absorption units such as one or more absorption columns
  • chromatography units density separation units, such as centrifuges, cyclone separators, decanters and the like
  • crystallization or recrystallization units such as centrifuges, cyclone separators, decanters and the like
  • electrophoresis units evaporation or drying units
  • extraction units such as leaching, liquid
  • the separation system 506 can be configured to separate the production fluid 141 in any way that may be desirable.
  • the separation system 506 can be configured to separate the C0 2 working fluid from the hydrocarbons, other native fluids, and any other injected fluids, while leaving the hydrocarbons and other native fluids partially or fully combined together.
  • the separation system 506 can be configured to separate the hydrocarbons from the production fluid 141 and leave the C0 2 working fluid, the other native fluids, and any other injected fluids partially or fully combined together. In an example, shown in FIGS.
  • the separation system 506 can be configured to separate the production fluid 141 into a C0 2 stream 508, a hydrocarbon stream 510, and a brine stream 512 (which can include other injected fluids such as a water-containing working fluid).
  • Each stream 508, 510, 512 can be further treated or processed after separation.
  • the C0 2 stream 508 can be fed back into the reservoir 120, such as by feeding the C0 2 stream into the compressor and/or a cooling unit 503 for reinjection back into the injection well 136, as shown in FIGS. 5A and 5B.
  • the C0 2 stream 508 can be cooled in a cooling unit and further treated to match or substantially match the pressure conditions of C0 2 coming from the C0 2 source 502, so that C0 2 from both the C0 2 stream 508 and the C0 2 source 502 can be jointly cooled and compressed in a compressor and pumped back into the reservoir 120.
  • the hydrocarbon stream 510 can be delivered to a refining system to further refine the hydrocarbons into various petroleum products.
  • the brine solution stream 512 can be sold as a product, further treated, delivered back into the reservoir 120, released at the land surface or injected into other subsurface formations, or can be disposed of otherwise.
  • the separation system 506 can be configured to be operated before, that is upstream of, the energy recovery system, or the separation system 506 can be operated after, that is downstream of, the energy recovery system.
  • FIG. 5A shows an example system 500A with the separation system 506 being positioned downstream of the energy recovery system 504A so that energy, for example in the form of heat or electricity, can be recovered from the production fluid 141 before separating the production fluid 141 into separate components.
  • the energy recovery system 504A can be configured to recover heat from the production fluid 141 in its entirety.
  • the fluid can exit the energy recovery system 504A as one or more fluids 516 that are in a cooled, and possibly expanded (e.g., lower pressure), state.
  • the cooled fluid 516 can be fed into the separation system 506.
  • the separation system 506 can then separate the cooled fluid 516 into the C0 2 stream 508, the hydrocarbon stream 510, and the brine stream 512, each of which can then be handled as described above.
  • FIG. 5B shows an example system 500B with the separation system 506 being positioned upstream of an energy recovery system 504B so that the C0 2 stream 508, the hydrocarbon stream 51 0, and the brine stream 512 can be separated before each stream is fed into the energy recovery system 504B.
  • the energy recovery system 504B can include a separate dedicated energy recovery device or devices for each stream 508, 510, 512, such as a first energy recovery device or devices 518A configured to recover energy from the C0 2 stream 508, a second energy recovery device or devices 518B configured to recover energy from the hydrocarbon stream 510, and a third energy recovery device or devices 51 8C configured to recover energy from the brine solution stream 512.
  • the production fluid 141 can include a large percentage of one component, such as up to about 99 wt% hydrocarbons, so that dedicated energy recovery device or devices for each of the remaining components (that make up part of the remaining 1 wt%) may not be practical.
  • the separation system 506 can be configured to separate out only the component with the large mass percentage, such as the hydrocarbons, and leave the other components in a combined stream.
  • the energy recovery system 504B can include only a first energy recovery device or devices configured to recover energy from the large-percentage component, and a second energy recovery device or devices for the other components. If the mass percentage of the other components is small enough, it may even be desirable to only recover energy from the large-percentage component, and to forgo energy recovery from the other components.
  • each set of the one or more dedicated energy recovery device such as one or more expansion devices and generators (e.g., turbine-generator combinations) or binary systems with heat exchangers, can be used to recover energy from the C0 2 stream 508, the hydrocarbon stream 510, and the brine solution stream 512.
  • each stream 508, 510, 512 can have its own dedicated energy recovery device or devices 518A, 518B, 518C
  • each dedicated energy recovery device or devices 518A, 51 8B, 518C can be configured for the specific stream 508, 510, 512.
  • each fluid stream can be sent through an energy recovery apparatus specifically designed for the composition of each component of the separated production fluid 141 , such as a C0 2 stream 508, a hydrocarbon stream 510, and a brine or water stream 512.
  • the energy recovery efficiency for each fluid stream can be optimized, which may be limited in the case of separation downstream of (e.g., after) energy recovery (as described above).
  • the energy recovery apparatus for liquid hydrocarbons and brine or water can be an Organic Rankine Cycle or other binary system, potentially with different secondary working fluids.
  • the energy recovery apparatus for C0 2 and gaseous hydrocarbons can be a direct turbine because the lower density of these gaseous or supercritical fluids can provide much more energy in the form of electricity than higher density fluids in liquid phase when decreasing between the same pressure levels. Passing a low density fluid through a direct turbine followed by a cooling apparatus generally can produce more electricity than extracting thermal energy to operate an Organic Rankine Cycle or other binary system, and then decreasing the pressure through a valve or turbine, when operating between the same inlet and exit conditions.
  • C0 2 in the reservoir is heated by geothermal heat present in the reservoir
  • the energy used to pump the C0 2 to the subsurface is a small fraction (e.g., substantially zero (0)% to about five (5)%) of the energy provided by the geothermal heat and may also be small in comparison to the electricity produced by the system (e.g. substantially zero (0)% to about 25%).
  • the system controller can be coupled to various sensing devices to monitor certain variables or physical phenomena, process the variables, and output control signals to control devices to take necessary actions when the variable levels exceed or drop below selected or predetermined values. Such amounts are dependent on other variables, and may be varied as desired by using the input device of the controller.
  • sensing devices may include, but are not limited to, devices for sensing temperatures, pressures and flow rates, and transducing the same into proportional electrical signals for transmission to readout or control devices may be provided for in all of the principal fluid flow lines.
  • Such a controller may be a local or remote receiver only, or a computer, such as a laptop or personal computer as is well-known in the art.
  • the controller is a personal computer having all necessary components for processing input signals and generating appropriate output signals as is understood in the art. These components can include a processor, a utility, a driver, an event queue, an application, and so forth, although the invention is not so limited.
  • the controller has a non-volatile memory comprised of a disk drive or read only memory device that stores a program to implement the above control and store appropriate values for comparison with the process variables as is well known in the art.
  • the system controller can also be programmed to ignore data from the various sensors when the operator activates certain other buttons and dials on the control panel as he/she deems necessary, such as fill override or emergency stop buttons.
  • the control panel can include indicator lights or digital displays to signal an operator as to the status of the operation. I ndicator lights can also be used to signal that a certain variable level is outside the desired range, therefore alerting the operator to the need for corrective action.
  • the corrective action is not automatic, but requires the operator (who may be located remotely and optionally controlling more than one system substantially simultaneously) to initiate corrective action either by pushing a specific button or turning a specific dial on the control panel, or by manually adjusting the appropriate valve or device.
  • a carbon dioxide injection model was designed and used to evaluate the spread of injected material over time and to determine whether the caprock 618 can effectively seal a reservoir, such as the aquifer 620 shown in FIG. 7.
  • FIG. 8 is an illustration of the target formation 600, containing the caprock 618 and aquifer 620.
  • a simulated injection well 736 can be seen within the aquifer 620. Since no deep wells exist in Minnesota to provide geometric configurations of aquifer and caprock units, the cross-section was used only to verify that the estimated rift structure was sufficiently deep for carbon dioxide storage and to estimate depths for storage units. Due to the lack of measured data, a rectangular aquifer 50 meters (m) thick (in height) and several km in length was assumed and illustrated in FIG. 8.
  • the model geology was expanded by placing a capping material, i.e., caprock 618 dimensionally equivalent to the aquifer 620, immediately above the aquifer 620.
  • the aquifer and caprock are then encased in a surrounding material that extends vertically to the ground surface with the aquifer at a depth of about 2500 m, and horizontally several kilometers beyond the aquifer and caprock (See, for example, FIG. 7).
  • the extent of surrounding material was chosen such that the upper and lower boundaries were far enough from the aquifer to realistically assume that no fluid flow occurs across the boundaries during the simulated time interval while the left and right boundaries were chosen to be sufficiently far from the modeling domain of interest to assume hydrostatic fluid pressure conditions (i.e., constant pre-injection fluid pressure conditions).
  • the surrounding unit's permeability was valued at 10 " 19 m 2 , and the pore fraction was 0.04 (i.e., 4%) based on the data provided by the GS. Fluid flow was permitted through the top and bottom of the aquifer to simulate natural conditions.
  • a solute solution of one (1 )% C0 2 was injected (the remaining content being water), with a solute weight approximately equivalent to supercritical C0 2 at a depth of 2500 m, in the center of the aquifer for a period of one year.
  • the injection rate can be varied to approximate injection of all C0 2 produced by a large (e.g., about 250 megawatt ( W) to about 1000 M ) fossil fuel-fired power plant.
  • W megawatt
  • Carbon dioxide as a solute in water was assumed for injection into a water aquifer because the solute approach simplified modeling as compared with pure carbon dioxide fluid. Future modeling may include use of pure carbon dioxide fluid.
  • CPG carbon plume geothermal
  • caprock units can be in a range from between about 0.06 to about 0.16 (i.e., about six (6)% to about 16%, respectively). Note that this range overlaps with that of the aquifer porosity. The models also indicated that porosity overlap would not be problematic for carbon dioxide storage, provided caprock permeability is several orders of magnitude lower than aquifer permeability. This preliminary study further provides support for providing a single injection well to accommodate all the carbon dioxide produced by an approximately 1 000 M coal-fired power plant using the novel systems described herein.
  • a model of various C0 2 -based geothermal systems in a naturally porous, permeable aquifer i.e., the novel C0 2 Plume Geothermal (CPG) system is compared to a conventional C0 2 -based engineered EGS and a conventional water-based (i.e., non-EGS) geothermal system.
  • CPG novel C0 2 Plume Geothermal
  • Table 2 shows details of the modeled geothermal reservoir. Table 2. Geothermal Reservoir Specifics
  • FIG. 1 1 is a graph showing temperature versus distance from the injection well to a production well for various fracture spacings in the EGS cases (the CPG system does not contain specific fractures but rather a granular porous medium). Specifically, FIG. 1 1 compares the novel CPG system (top line) with several conventional C0 2 -based EGS systems using various average fracture spacings (200m, 100m and 50m, from bottom to second from the top), thus providing a cross section through the model geometry from injection well to production well. As such, FIG. 1 1 displays a temperature
  • FIG. 12 shows a CPG system in comparison with several C0 2 -based EGS examples, showing heat energy production as a function of time.
  • the CPG system produced over 1 .75 times more heat energy than a comparable C0 2 -based EGS.
  • EGS required a much higher (more than factor of two) pressure difference between the injection well and the production well.
  • the EGS had a much greater pumping energy requirement and lower power production efficiency than the CPG systems.
  • FIG. 13 compares thermal energy extraction rates between a CPG system and a water- based regular (i.e., non-EGS, meaning a reservoir/non-hydro fractured) geothermal system, everything else being equal.
  • thermal energy extraction rates are 1 .7 to 2.7 times larger with C0 2 than water, which appears to be primarily a result of C0 2 mass flow rates being up to 5 times greater than those of water, given a fixed pressure difference between injection and production wells.
  • C0 2 energy extraction rates would be up to 1 .5 times larger than those of water.
  • C0 2 mass flow rates can be largely attributed to high C0 2 mobility (density to dynamic viscosity ratio, ⁇ / ⁇ ).
  • real-world geothermal installations typically operate on a fixed differential production pressure, as has been included in the above models.
  • FIG. 14 provides density profiles from injection well to production well, comparing C0 2 and H 2 0 cases for two different reservoir depths. These plots are applicable to both naturally porous, permeable (CPG) systems and to EGS. Use of C0 2 -based systems (lower two lines indicating different reservoir depths) compared to water-based systems (upper two curves indicating different reservoir depths) allows for a large density change in C0 2 between injection and production points.
  • thermosyphon A drop in density from injection to production wells drives fluid flow through the subsurface system, an effect known as a thermosyphon, which reduces pumping requirements, a substantial energy draw in geothermal systems.
  • the C0 2 system has much lower pumping energy requirements than a comparable water-based system.
  • Prandtl number for C0 2 water more readily diffuses momentum than heat. Hence, C0 2 more easily moves through a geothermal reservoir than water, and the increased mobility of C0 2 (see also statement about mobility of C0 2 above) ultimately leads to the improved heat energy recovery of C0 2 -based compared to water-based systems.
  • the CPG system is able to increase power production efficiency by utilizing
  • C0 2 's low freezing point. Since C0 2 does not freeze at 0 °C, unlike water, a C0 2 power cycle can use sub 0 °C condensing temperatures in its power system, increasing power production efficiency on top of efficiency improvements acquired in the geothermal reservoir.
  • Modeling of the formation of a C0 2 plume in a geologic structure will be performed. It is expected that numerical models of C0 2 injection into a brine or hydrocarbon filled geologic formation will show that a large (on the order of a kilometer in area and several tens to hundreds of meters thick), near- pure C0 2 plume can be established via displacement of the native fluid. The time period from onset of injection to C0 2 recovery at production wells is expected to be on the order of several months to two years (maximum 3 years), depending on site characteristics.
  • C0 2 native reservoir brine or hydrocarbons, and reservoir rock is useful for understanding the function and the ranges of viable parameters for CPG systems.
  • modeling of the physical responses of a natural aquifer, including pore and matrix deformation and pressure propagation will be performed.
  • CPG systems are uniquely able to make use of such geochemical behavior to enhance heat energy recovery.
  • C0 2 injected into a geologic formation will naturally rise to the top of the formation, where it will rest against/underneath the local caprock. Should exothermic reactions occur, they would impart heat to the C0 2 , which could be recovered to produce electricity as the fluid cycles through the CPG system.
  • these C0 2 -mineral reactions can be volume-increasing thereby serving to (further) seal the caprock.
  • Such reactions may not occur in the reservoir itself if the reservoir rocks/minerals/sediments are of a different composition than the caprock materials.
  • Modeling fluid flow from the geologic reservoir through the wellbores is useful for the calculation of pumping requirements and permits estimation of fluid heating or cooling in the wells. It is expected that, because of the (greater) depths and temperatures typically targeted for EGS compared to those used for CPG systems, CPG systems will result in less C0 2 cooling than C0 2 -based EGS as the heated fluid moves from the reservoir to the surface, showing further energy recovery improvements of CPG as compared to EGS.
  • the carbon dioxide-based energy generating system described herein provides a novel means for producing renewable energy, while further providing for carbon dioxide sequestration, thus providing a process with a negative carbon footprint.
  • the geothermal power plant has a negative carbon dioxide output, thus providing the first electricity-generating power scheme with a negative carbon footprint.
  • Carbon dioxide sequestration also provides added revenue to a power plant under a carbon-trading market.
  • thermodynamic, fluid dynamic, and chemical properties of this working fluid provide new ways of generating electric power in regions formerly unimaginable for this purpose, such as the eastern and mid-western parts of North American may now be considered for renewable, clean, geothermal electricity production.
  • This approach further enhances the efficiency of geothermal power plants, particularly during colder months, as compared to traditional water-based systems, thereby potentially allowing electricity production in such low heat flow regions, such as, for example, Minnesota, and other climatologically and geologically similar locations in a sustainable and highly efficient manner.
  • Such plants are also expected to be more compact than water-based versions, thereby reducing the plant's spatial and environmental footprint.
  • carbon dioxide can be cooled well below zero (0) Q C (above atmospheric pressure), such as about -55 Q C, without freezing. Carbon dioxide additionally allows the whole system to be run under pressures higher than ambient pressures. In contrast, water systems apply partial vacuums in parts of the cycle, which are prone to leaks. Additionally, the increased pressure allows for higher fluid densities, as compared to water, and thus smaller piping and other components reducing capital investment costs.
  • the system is a closed loop carbon dioxide system without a carbon dioxide sequestration component.
  • the ability to contain carbon dioxide with use of an open loop or partially open loop system further enhances the efficiency of the system and provides a means to sequester carbon dioxide from, for example, a conventional power plant.
  • some or most of the carbon dioxide e.g., from about five (5)% to about 95%, can be sequestered.
  • these same systems and methods can also be applied to providing geothermal energy to heat pumps for space heating or for direct use, as described herein. I n contrast to wind and solar power systems, geothermal systems are highly scalable and can provide base- load and dispatchable (peak) power as desired.
  • geothermal energy is a renewable energy resource and it is cheaper than coal, wind, nuclear, etc. and comparable in cost to natural gas.
  • the carbon dioxide-based geothermal energy generating system can be used to produce energy for a number of uses, including for commercial sale, process load (to operate the geothermal power or C0 2 sequestration system) and electricity generation.
  • the system is designed to generate energy in quantities sufficient to provide electricity, to provide heat for on- or off -site uses, to provide shaft power to operate the on-site equipment, or combinations thereof, and the like. In this way, the use of fossil fuels, such as natural gas, is limited, while operational costs are reduced.
  • Embodiments of the novel system and methods described herein provide, for the first time, the ability to provide electricity from a geothermal source at temperatures much lower than are required for conventional water-based geothermal systems, although higher operating temperatures may optionally be used.
  • Embodiments of the novel systems and methods described herein are efficient, economical and relatively simple in operation.
  • the process uses a production waste product (C0 2 ) that must otherwise be properly disposed of, sometimes at significant costs.
  • Various embodiments also allow an operating liability to be turned into a business asset, while simultaneously providing environmental benefits.
  • Embodiments of the invention can be employed as part of a simplified cost-effective geothermal energy system using natural state rock formations as subterranean in situ rock reservoirs. Various embodiments can also be used for subterranean carbon sequestration and permanent storage of C0 2 .
  • the use of saline aquifers and saline water-filled rock formations in one embodiment further allows water to be utilized which is unlikely to be used for consumption or irrigation.
  • Embodiments may further be part of an enhanced oil recovery (EOR) scheme and other hydrocarbon extraction methods, thereby enhancing hydrocarbon recovery (in addition to providing geothermal energy and to providing a means to sequester C0 2 ).
  • EOR enhanced oil recovery
  • the source of the carbon dioxide and carbon dioxide-based geothermal energy generating system are located on the same site or less than about one (1 ) km of each other, although the invention is not so limited.
  • the energy generation system is in close proximity to the carbon-dioxide producing source, such that energy which is generated with the system described herein is consumed partially or completely as power to the facility itself, thus eliminating the need for an elaborate and expensive piping system.
  • the energy produced with the energy generating system is piped any desired distance to be utilized in any desired manner.
  • some or all of the energy is used to power other types of manufacturing facilities and/or is sold to a local utility, and/or is used to generate electricity on-site.

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Abstract

L'invention concerne un système qui comprend un puits d'injection pour accéder à un réservoir contenant un fluide natif comprenant au moins un hydrocarbure, le réservoir étant situé en dessous d'une ou plusieurs roches couvertures, étant à une première température et étant accessible sans l'utilisation de fracturation hydraulique à grande échelle. Le système comprend de plus un puits de production en communication fluidique avec le réservoir, un appareil d'introduction configuré pour alimenter un fluide de travail à base non aqueuse à une deuxième température qui est inférieure à la première température par le puits d'injection au réservoir, le fluide de travail se mélangeant avec le fluide natif pour former un fluide de production comprenant au moins une partie de fluide de travail et au moins une partie du au moins un hydrocarbure à une troisième température qui est plus élevée que la deuxième température. Un appareil de récupération d'énergie est en communication fluidique avec le puits de production, l'énergie contenue dans le fluide de production étant convertie en électricité, chaleur ou leurs combinaisons, dans l'appareil de récupération d'énergie.
EP13745264.5A 2012-07-20 2013-07-19 Systèmes de génération d'énergie géothermique à base de dioxyde de carbone et procédés associés à ceux-ci Withdrawn EP2875089A1 (fr)

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