CARBON DIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS RELATED THERETO
A system comprises an injection well in communication with an underground reservoir that is at a first temperature and that contains a native fluid, a production well in communication with the reservoir, and a supply system providing a non-water based working fluid to the injection well at a second temperature lower than the first temperature. Exposure of the working fluid to the first temperatures heats the working fluid to a third temperature that is higher than the second temperature. At least a portion of the working fluid at the third temperature enters the production well and is produced from the reservoir as a production fluid. An energy recovery apparatus in fluid communication with the production well converts energy contained in the production fluid to electricity, heat, or a combinations thereof.
This application is a continuation of U.S. patent application Ser. No. 13/800,720, filed on Mar. 13, 2013, which claims the benefit of priority to U.S. Provisional Patent Application Ser. No. 61/725,270, entitled “ENHANCED CARBON-DIOXIDE BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS,” filed on Nov. 12, 2012, which applications are incorporated by reference herein in their entirety.
BACKGROUNDIn light of global climate change and in response to an increased desire to reduce dependence on foreign oil supplies, renewable energy systems, such as wind, solar and geothermal-based systems are being increasingly researched and developed. However, many such systems have only limited potential due to, for example, high costs, overall process inefficiencies, possible adverse environmental impact, and the like.
SUMMARYThis disclosure describes systems and methods for efficiently recovering geothermal heat from reservoirs by injecting a non-water based working fluid, such as carbon dioxide (CO2), into the reservoir to extract geothermal heat. The CO2 can then be produced back to the surface and a portion of the geothermal energy captured by the CO2 can be recovered by an energy recovery apparatus, such as an electricity production apparatus (e.g., an expansion device driving a generator) or a heat recovery apparatus (e.g., one or more heat exchangers for heating a second working fluid).
In particular, this disclosure describes recovering geothermal heat from reservoirs that include a native fluid including a solution comprising natural gas, and in particular methane (CH4). The CO2 can cause the CH4 to come out of solution with the native fluid such that the CH4 forms a production fluid with the CO2. The production fluid can be heated by geothermal heat and produced to the surface where at least a portion of the CH4 can be separated from the production fluid and combusted to increase the overall temperature of the production fluid before it is fed into the energy recovery apparatus. Such a system and method can utilize the chemical properties of CO2 to extract CH4 from the reservoir, and then can use the chemical energy stored in a portion of the CH4 to supplement the geothermal energy captured by the production fluid. The recovery of methane from the reservoir and subsequent combustion of a portion of the methane to boost production fluid temperature or pressure, or both, can increase the overall system efficiency and the overall power produced compared to geothermal capture alone. The methane capture and use of the systems and methods of the present disclosure can allow for economically viable recovery of geothermal energy from low-temperature reservoirs (e.g., down to about 15° C., or, in some situations, down to about 10° C.). The systems and methods of the present invention can, therefore, open up reservoirs for geothermal exploitation that heretofore had been economically difficult or impossible to achieve.
The present disclosure describes a system comprising one or more injection wells for accessing one or more underground reservoirs, the one or more reservoirs being at one or more first temperatures and containing at least one native fluid, the native fluid including a solution comprising methane, each of the one or more injection wells having an injection well reservoir opening in fluid communication with at least one of the one or more reservoirs. The system further includes one or more production wells, each having a production well reservoir opening in fluid communication with at least one of the one or more reservoirs. A working-fluid supply system provides a non-water based working fluid to the one or more injection wells at a second temperature lower than the first temperatures. Exposure of the non-water based working fluid to the native fluid causes at least a portion of the methane to come out of solution with the native fluid to form a production fluid of at least a portion of the non-water based working fluid and the portion of the methane. Exposure of the mixture to the first temperatures heats the production fluid to a third temperature that is higher than the second temperature, wherein the production fluid is capable of entering one or more of the production well reservoir openings. The system also includes an energy recovery apparatus in fluid communication with the one or more productions wells, wherein energy contained in the production fluid can be converted to electricity, heat, or a combination thereof, in the energy recovery apparatus.
The present disclosure also describes a method comprising introducing a non-water based working fluid at a first temperature through one or more injection wells to one or more underground reservoirs containing at least one native fluid, the native fluid including a solution comprising methane, wherein the one or more reservoirs are at one or more second temperatures that are greater than the first temperature, exposing the non-water based working fluid to the native fluid so that at least a portion of the methane comes out of solution with the native fluid to form a production fluid of at least a portion of the non-water based working fluid and the portion of the methane, exposing the production fluid to the second temperature to heat the production fluid to a third temperature that is greater than the first temperature, producing the production fluid through one or more production wells, and extracting energy from the production fluid.
These and other examples and features of the present systems and methods will be set forth in part in the following Detailed Description. This Summary is intended to provide an overview of the present subject matter, and is not intended to provide an exclusive or exhaustive explanation. The Detailed Description below is included to provide further information about the present systems and methods.
In the following detailed description, reference is made to the accompanying drawings that form a part hereof, and in which is shown by way of illustration, specific examples in which the invention may be practiced. These examples are described in sufficient detail to enable those skilled in the art to practice the invention, and it is to be understood that other embodiments may be utilized. It is also to be understood that structural, procedural, chemical and system changes can be made without departing from the spirit and scope of the present invention. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the present invention is defined by the appended claims and their equivalents.
The present disclosure describes geothermal energy recovery systems and methods using a non-water based working fluid, such as carbon dioxide (CO2) for the recovery of geothermal energy. The geothermal energy recovery systems and methods can include aspects of the example systems and methods disclosed in U.S. Published Application No. US2012-0001429 to Saar, et al., entitled “CARBON DIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS RELATED THERETO,” and U.S. patent application Ser. No. 13/554,868 to Saar et al., entitled “CARBON DIOXIDE-BASED GEOTHERMAL ENERGY GENERATION SYSTEMS AND METHODS RELATED THERETO,” filed on Jul. 20, 2012, both of which are hereby incorporated by reference herein in their entireties. As described in these applications, a carbon dioxide working fluid can travel through the reservoir as a gas plume such that the system in the applications are referred to as Carbon Dioxide (or CO2) Plume Geothermal (“CPG”) systems.
The present disclosure also describes feeding the non-water based working fluid to a reservoir that contains a native fluid comprising a solution including methane. For example, the reservoir can comprise a deep brine aquifer comprising a brine solution with natural gas (the natural gas comprising generally about 97% methane or more) dissolved in the brine solution. Because “natural gas,” as it is used herein, is generally at least about 97 wt % methane or more, the remainder of this disclosure will refer to it as “methane” for the sake of brevity. It will be understood by a person of ordinary skill in the art that “methane” can refer to other gaseous hydrocarbons that can be included in natural gas, such as ethane, propane, and higher order alkanes. The injection of a carbon dioxide working fluid into the brine aquifer can cause a portion of the CO2 to dissolve into the brine solution, which can force a substantial portion of the dissolved methane out of solution. The released methane can combine with the remaining CO2 to form a production fluid in the form of a gaseous plume similar to the CO2 plumes in the CPG systems. In addition, a zone of a mixture of brine solution with dissolved or free-phase methane plus CO2 can form between the native brine solution and the zone of CO2 combined with methane. The fluid comprising brine, methane, and/or CO2 can also form a production fluid, in addition to the production fluid that is similar to a CO2 plume formed in a CPG system. As described in more detail below, a portion of the methane recovered from the brine aquifer can be combusted to increase the temperature or the pressure, or both, of the production fluid prior to recovering energy from the production fluid, such as by passing the production fluid through an expansion device that powers a generator to produce electricity. The remainder of the methane present in the production fluid can either be separated out and sold, or it can be re-injected into the reservoir to provide for further production and use in the energy recover system. The use of recovered methane to boost the economic efficiency of the system can be referred to herein as methane-enhanced CO2 Plume Geothermal (“ME-CPG”) systems.
Alternatively, the reservoir can include an oil or natural gas field where the oil or natural gas hydrocarbons have been partially recovered using conventional recovery methods. The oil or natural gas hydrocarbons can be recovered via the injection of carbon dioxide or other recovery fluids into the field in order to release a portion of the hydrocarbons from the reservoir. This process can be referred to as “enhanced oil recovery” (EOR) (described in more detail below). The production fluid from an EOR field can include the CO2 working fluid, methane and other natural gas components, other higher order hydrocarbons, and brine. As with the brine aquifer reservoir described above, a portion of the methane recovered from the EOR field can be used to increase the temperature, the pressure, or both of the production fluid before further energy recovery is conducted. The EOR hydrocarbons can be separated from the production fluid and sold. A portion of the separated hydrocarbons can also be combusted to heat the working fluid or increase the working fluid's pressure prior to energy recovery.
The systems of this disclosure can include components or aspects where considerable heat is generated—heat that typically is lost to the atmosphere. For example, both EOR and CPG systems can include one or more compressors for the CO2 so that the CO2 can be injected back into the reservoir for further oil or natural gas recovery, geothermal heat recovery, or CO2 sequestration. The compressors can generate considerable heat, on the order of 400 to 450 kilojoules (kJ) per kilogram (kg) of CO2 compressed for each stage of compression, depending on the type of compressor system used. EOR systems can also generate considerable heat during the separation of the oil and natural gas hydrocarbons from the production fluid, for example if a portion of the methane or other produced fluid is combusted to heat the production fluid in order to improve separation efficiency.
In some examples, the geothermal energy recovery system and the EOR system (if present) can be co-located with another facility type, e.g., a power plant or an ethanol or biofuel production facility. For example, the co-located facility can be the initial source of CO2 that is compressed and injected into the reservoir for the recovery of geothermal heat, methane, and/or other hydrocarbons. The co-located facility can also typically produce considerable waste heat. In addition, for a co-located biofuel production facility, such as an ethanol plant, a portion of the biofuel produced at the plant can be combusted to increase the temperature of a working fluid or production fluid or to increase the pressure of the working fluid, or both, prior to energy recovery from the working fluid or production fluid. Similarly, biofuel or other from an off-site third party can be obtained and transported to the geothermal recovery system and combusted to increase the temperature of a working fluid or production fluid or to increase the pressure of the working fluid, or both.
In some examples, the systems and methods of the present disclosure can include a heat recovery system for recovering waste heat generated by some other aspect of the system or method, such as waste heat from the CO2 compressors, the EOR separation system, or a co-located facility. The waste heat recovered by the heat recovery system can also be used to increase the temperature, the pressure, or both of the production fluid before it is fed into the energy recovery system (e.g., the expansion device and generator). Waste heat capture with a heat recovery system can increase the efficiency of the geothermal energy recovery system and method similar to the enhancement provided by recovered methane combustion in the ME-CPG system. The capture of waste heat to boost the economic efficiency of the system can be referred to herein as waste heat-enhanced CO2 Plume Geothermal (“WHE-CPG”) systems. It will be appreciated that both ME-CPG and WHE-CPG can be used in the same system.
Conventional Geothermal Energy TechnologyGeothermal energy is heat energy generated and stored within the earth (or any other planet), which can be “mined” for various uses, including to produce electricity, for direct use, or for ground-source heat pumps. Geothermal energy sources can be relatively constant with heat energy replenished on human time scales after being “mined.” Geothermal energy also can require no storage other than the earth.
Potential uses of conventional geothermal energy are generally temperature dependent, with cascading systems utilizing a single geothermal resource for multiple purposes. Water-based geothermal systems that use water as a working fluid (e.g., conventional water-based enhanced geothermal systems (EGS) and conventional non-EGS water-based) can require very high temperatures. For example, electricity generation at water-based geothermal power plants typically requires temperatures in excess of 165° C. Direct uses, such as aquaculture, greenhouse, industrial and agricultural processes, resorts, space and district heating (wells to structures) from such systems can utilize more moderate temperatures of about 38 to 165° C. when water is the subsurface geothermal working fluid. Residential and commercial building ground-source heat pumps from water-based geothermal systems, which may use a secondary heat exchange fluid (e.g., isobutene) in order to transfer geothermal heat energy from the ground for use, can generally require temperatures between about 4 and 38° C.
DefinitionsThe terms “subterranean” or “subsurface” or “underground,” as used herein, can refer to locations and/or geological formations beneath the Earth's surface.
The term “in situ,” as used herein, can refer to a natural or original position or place of a geologic feature which may be above ground or underground, such that it is located in a place where it was originally formed or deposited by nature and has remained substantially undisturbed over time, such that it is in substantially the same original condition. A 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 situ” 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 situ” 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. In contrast, 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.
The term “large-scale hydrofracturing,” as used herein, can refer 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. Pat. 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. 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.
The term “rock,” as used herein, can refer 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.” Various types of 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.
The term “sediment,” as used herein, can refer 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.
The term “soil,” as used herein, can refer 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.
The term “fluid,” as used herein, can refer to a liquid, gas, or combination thereof, or a fluid that exists above the critical point, e.g., a supercritical fluid. A fluid is capable of flowing, expanding, and 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, CO2, magma, noble gases, or any combination thereof.
The term “native fluid,” as used herein, can refer to a fluid which is resident in a rock formation or sediment formation prior to the implementation of the systems or methods of the present disclosure. 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 previously-present in the rock or sediment formation and thus constitute a native fluid in this case.
The term “working fluid,” as used herein, can refer to a fluid which is not native to a rock formation or sediment formation and that is used by the systems or methods of the present disclosure for some purpose. A working fluid can undergo a phase change from a gas to a liquid (energy source), a liquid to gas (refrigerant), or can become part of a solution (e.g., by dissolving into a native fluid). A “working fluid” in a machine or in a closed loop system can be the pressurized gas or liquid which actuates the machine. Water is used as a working fluid in conventional (e.g., water-based) heat engine systems. Non-water based working fluids can include, but are not limited to, ammonia, sulfur dioxide, carbon dioxide, and non-halogenated hydrocarbons such as methane. A working fluid can include a fluid in a supercritical state. Different working fluids can have different thermodynamic and fluid-dynamic properties, resulting in different power conversion efficiencies.
The term “pore space” as used herein, can refer to any space not occupied by a solid (rock or mineral). Pore space can be the space formed between grains 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 can evolve over time due to changes in solid space volume or size (which can come from chemical reactions, deformations, etc.). A space can be filled with fluid and still be deemed to be “pore space.”
The term “CO2 plume” as used herein, can refer to a large-scale (e.g., meters to several kilometers to tens of kilometers across) CO2 presence within subsurface pore spaces. Within a CO2 plume, a significant percentage of fluid in the pore space can be CO2. The CO2 plume can include other fluids, such as native methane or other hydrocarbons, which can be collected and carried by the CO2 plume as it travels through a reservoir. For example, a CO2 plume can include a substantial percentage (e.g., as much as 20 wt. %) methane that has been desorbed from a saline aquifer (as described in more detail below). A CO2 plume can also include a substantial portion of native hydrocarbons, (e.g., up to 90 wt % hydrocarbons or more), and can still be considered a “CO2 plume” within the meaning of the present disclosure. A CO2 plume can contain a substantial portion, e.g., as much as 70% by volume, or more, of a native fluid such as brine or hydrocarbons extracted from a reservoir. The brine or other native fluid can be immobile or only minimally mobile and, therefore, generally considered in the art to be residually trapped.
The term “reservoir” or “storage rock formation” or “storage sediment formation,” as used herein, can refer to a formation comprising one or more of rock, sediment, and soil that can be capable of receiving and storing an amount of fluid substantially “permanently” as that term is understood in the geological arts.
The term “geothermal heat flow,” as used herein, can refer to any kind of heat transfer in the subsurface and can include one or more of conductive heat transfer, advective heat transfer (also referred to as convective heat transfer), and radiative heat transfer (although radiative heat transfer can typically be negligible in the subsurface). A “low” heat flow generally can be considered to be less than about 50 milliwatts per square meter. A “moderate” heat flow generally can be considered to be at least about 50 to about 80 milliwatts per square meter. A “high” heat flow generally can be considered to be greater than 80 milliwatts per square meter.
The term “injection well,” as used herein, can refer to a well or borehole, which can be cased (e.g., lined) or uncased, and which can contain one or more pipes through which a fluid can flow (typically in a downward direction) for purposes of releasing that fluid into the subsurface at some depth.
The term “production well,” as used herein, can refer to a well or borehole, which can be cased (e.g., lined) or uncased, and which can contain one or more pipes through which a fluid can flow (typically in an upward direction) for purposes of bringing fluids up from the subsurface up to the Earth's surface or near the surface. A production well can exist in the same borehole as an injection well.
The term “enhanced geothermal system” (EGS), as used herein, can refer to a system in which a manmade (e.g., artificial) reservoir is created, usually by means of large-scale hydrofracturing of the subsurface, e.g., by inducing fractures to create space which can contain significant amounts of fluid. Such artificial reservoirs typically can be much smaller than natural reservoirs.
The term “enhanced oil recovery” (EOR) (also referred to as “improved oil recovery,” “tertiary recovery,” or “quaternary recovery”), as used herein, 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 fluid, 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.
The term “conventional water-based geothermal system,” as used herein, can refer to a geothermal system that uses water as a working fluid. A conventional water-based geothermal approach can be used in natural reservoir systems or in hydrofractured (e.g., EGS) systems.
The term “conventional CO2-based EGS,” as used herein, can refer to a conventional EGS system that uses carbon dioxide as the working fluid.
The term “waste heat,” as used herein, can refer to heat energy generated by a system or unit operation that typically is allowed to dissipate to the environment rather than being used for some other purpose within the system or method.
Enhanced CPG SystemsIn an example, the working fluid 12 is a non-water based working fluid 12, such as carbon dioxide (CO2). For the sake of brevity, the remainder of this disclosure will describe the working fluid 12 as CO2 working fluid 12. However, as described above, the working fluid 12 can comprise other suitable compounds capable of absorbing thermal energy from its surroundings, and further releasing the thermal energy as described herein. Other examples of non-water based working fluids 12 can include, but are not limited to, ammonia, sulfur dioxide, or non-halogenated hydrocarbons such as methane.
The CO2 working fluid 12 can be provided from a CO2 source 18, such as a waste stream from a facility that produces CO2, such as via combustion. Examples of facilities that can be a CO2 source 18 include power plants, such as a fossil fuel power plants (e.g., coal plant, natural gas plant, and the like), a plant capable of producing fuel, such as biofuel (e.g., ethanol plant), or an industrial plant, such as a cement manufacturer, steel manufacturer, and the like. The CO2 source 18 can also be natural geologic CO2 produced from a geologic formation. In an example, the CO2 can be transported from a remote CO2 source 18 via any suitable means, (e.g., a pipeline or via various transportation means, such as a truck, ship, or railroad). In another example, the facility that provides the CO2 source 18 can be co-located with the geothermal recovery system 10, such as a co-located power plant, biofuel plant, or industrial plant. As described in more detail below, a co-located facility can provide for synergies allowing for more efficient operation of the co-located facility and of the geothermal energy recovery.
In an example, the system 10 can be located at a site (e.g., in a position) configured to provide access to a target formation. The target formation can comprise a caprock 8 located above a reservoir 1, as shown in
A top layer 9 can be located above the caprock 8 and the reservoir 1. The top layer 9 can comprise any number of layers and types of natural deposits or formations. For example, the top layer 9 can comprise one or more features such as one or more reservoirs (e.g., the reservoir 1 or a different reservoir) or one or more caprocks (e.g., the caprock 8) having the features as described herein. The top layer 9 can additionally or alternatively comprise additional areas suitable for injection of the working fluid, such as the CO2 working fluid 12. In an example, the top layer 9 additionally or alternatively further comprises any type of rocks, including rocks or sediments in layers, rock or sediment formations, and the like, or any combinations thereof. The top layer 9 can additionally or alternatively comprise a top layer or layers of sediment or soil of varying depths. The permeability and porosity of the top layer 9 can vary widely, as long as drilling can be performed to insert the injection well 14 and production well 28, as described below.
The top layer 9 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 9 can further have a wide range of depths (e.g., “thickness”) sufficient to ensure the working fluid introduced into the reservoir 1 can remain in the desired state, such as a supercritical state. In an example, the depth of the top layer 9 is at least 100 meters (m) or more, and can be up to one (1) kilometer (km) or more, such as up to three (3) km, four (4) km, five (5) km, for example, up to 10 km or over 15 km including any range there between, below the Earth's surface (e.g., below or within a given topography in an area, which may or may not be exposed to the atmosphere). In most examples, however, it is expected that the target formations will be 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, which can include the reservoir 1, a caprock 8, and a top layer 9, 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. In an example, the target formation is a sedimentary basin having a substantially bowl or convex shape. In other examples, the target formation can have another shape, such as the substantially dome or concave shape, although the present disclosure is not limited to the shapes described or depicted in the figures. In some examples, the target formation is lower than the lowest freshwater aquifer, but this may not always be the case. The target formation can comprise a brine or water aquifer or a brine or water-filled rock formation (e.g., reservoir 1) that includes a native fluid 2. The native fluid 2 can be inhibited or prevented from escaping upwardly, for example due to the presence of the caprock 8. The target formation can also 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. In an example, the target formation is a reservoir containing one or more of natural gas, oil, native CO2, fresh water, or brine.
In an example, CO2, such as the CO2 working fluid 12 shown in
If present, the caprock, such as the caprock 8 shown in
The thickness of the caprock 8 can vary, but is generally substantially less than the thickness of the top layer 9. In an example, the top layer 9 has a thickness on the order of 10, or 10 to 100, up to 1000 times the thickness of the caprock 8, further including any range there between, although the systems and methods of the present disclosure are not so limited. In an example, the thickness of the caprock 8 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 8 can comprise more than one caprock layer, such that multiple caprocks can be present which partially or completely cover one another and can act jointly as a caprock 8 to prevent or reduce upward leakage of the working fluid from the reservoir 1.
The reservoir 1 can be one or more natural underground rock reservoirs capable of containing fluids. For example, the reservoir 1 can be a previously-created manmade reservoir or a portion of a previously-created manmade reservoir, such as, for example, shale formations remaining from shale fracturing for hydrocarbon removal. The reservoir 1 can also be capable of storing carbon dioxide on a permanent or substantially permanent basis, as this term is understood in the art. In some examples, the reservoir 1 is sufficiently porous and permeable to be able to sequester fluids, such as carbon dioxide, and to receive and retain geothermal heat 6. In contrast to conventional geothermal systems, such as enhanced geothermal systems using a water-based working fluid, there is no requirement that the reservoir 1 be a hot dry rock reservoir, as that term is understood in the art, although, as noted herein, such a reservoir can optionally be used.
The reservoir 1 can be sufficiently permeable to allow multidirectional routes for dispersion or flow of fluid at relatively high rates, including lateral dispersion or flow. The caprock 8 above the reservoir 1, if present, can further enhance the dispersion capabilities of the reservoir 1. In an example, the porosity of the reservoir 1 can range from between about two (2) % to about 50% or greater, such as up to about 60%.
The reservoir 1 can be sufficiently permeable to allow fluids to flow relatively easily, e.g., at a rate of about 0.1 to about 50 liters/minute (L/min) or higher, such as up to several thousand L/min. In an example, the reservoir 1 has a permeability of about 10−16 m2 to about 10−9 m2, or greater, such as up to about 10−6 m2.
In an example, the reservoir 1 has a porosity of at least about two (2) % and a permeability of at least about 10−5 m2, with the caprock 8 having a maximum permeability of about 10−16 m2.
The reservoir 1 can have any suitable natural temperature. In an example, the natural temperature of the reservoir 1 is at least about 40° C., although natural temperatures below 40° C. can be sufficient, such as down to 30° C. or 20° C., further including down to 10° C., including any range there between. The ability to economically recover geothermal energy from a reservoir 1 having a natural temperature as low as 10° C., as described below, demonstrates a substantial advantage of the methane-enhanced geothermal recovery systems of the present disclosure over systems that use CO2 alone for geothermal recovery, such as CPG systems described above. Natural temperatures greater than 90° C. can also be present, with the highest temperature limited only by the amount of geothermal heat 6 provided and the ability of the reservoir 1 to capture and retain the geothermal heat 6. For example, it is possible that temperatures greater than about 300° C. can be present in the reservoir 1.
A specific desired natural temperature can be obtained by varying the depth of the injection well 14 or the production well 28, or both. In an example, higher natural temperatures can be obtained by increasing the depth of the injection well 14, with or without increasing the depth of the production well 28. The overall size of the reservoir 1 can also vary.
The geothermal heat 6 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. As a result, as compared to conventional systems using water as the working fluid, the systems described herein can operate in a wider range of locations, including low and moderate geothermal heat flow regions. The methane-enhanced and waste-heat enhanced systems of the present disclosure can also operate a wider range of locations than systems that merely use a CO2 working fluid to recover geothermal energy, including at lower heat flow rates than the CO2 geothermal-only systems. Also in contrast to conventional water-based systems which can be operated in areas containing little natural water (e.g., the American Southwest), thus requiring importation of water, the novel systems described herein do not rely on water as the working fluid, and thus do not import water for use as a working fluid. It is to be understood, that areas having medium or low geothermal heat flow rates can also be used.
In some examples, the CO2 working fluid from the CO2 source 18 can be compressed to an elevated pressure in a compressor 20. In an example, the compressed CO2 can be cooled in a cooling unit 22 because cooling the CO2 working fluid 12 prior to injection into the injection well 14 can be advantageous by improving injectability of the CO2. Most fluids, including CO2, are denser when they are cooler than when they are warmer, such that a relatively cold column of CO2 in the injection well 14 can compress itself more than a relatively hot column of CO2. Therefore, a relatively cold and relatively low pressure CO2 working fluid 12 at the surface can have the same pressure at the bottom of the injection well 14 as a relatively hot and relatively high pressure CO2 working fluid 12 fed to the injection well 14. A pump (not shown) can optionally be included downstream of the cooling unit 22 either before the CO2 working fluid 12 enters the injection well 14 or within the injection well 14.
Although the CO2 from the CO2 source 18 can, in some examples, be used “as is,” in other examples, further processing of the CO2 from the CO2 source 18 can be performed prior to introducing the CO2 to the compressor 20, the cooling unit 22, or the injection well 14. For example, some waste streams can require dewatering or drying, or both. In an example, the CO2 from the CO2 source 18 can be stored on site or off site for a period of time. In an example, the cold CO2 that is fed from the cooling unit 22 into the injection well 14 as the CO2 working fluid 12 is a saturated liquid or supercritical CO2.
As shown in
As mentioned above, in an example the native fluid 2 can comprise a brine, such as what can be present in a deep saline aquifer 1. In an example, a saline aquifer 1 can be present proximate to a hydrocarbon field such that a portion of the methane and other gaseous hydrocarbons, such as ethane and propane, can dissolve into the brine 2 within the aquifer 1. Although many alkane compounds can dissolve in brine, methane has the highest solubility compared to higher-order alkanes (e.g., ethane, propane, butane, etc.). Therefore, while other alkanes can be dissolved into solution in the brine 2, the present disclosure will describe the systems and methods herein as being with respect to dissolved methane. In an example, the composition of methane dissolved in the brine 2 can be from about 0.1 wt % to about 5 wt %/o methane. Such a low percentage of methane generally makes the methane, by itself, uneconomical to mine. For example, the cost to extract dilute methane dissolved in a saline aquifer would generally be achieved by pumping the brine to the surface and extracting the methane. The energy requirement to pump the brine to the surface can cost considerably more than the actual value of the methane that is extracted.
Carbon dioxide is known to have a higher solubility in brine than methane and other alkanes, such that when the CO2 working fluid 12 is injected into the aquifer 1, the CO2 will preferentially dissolve into the brine 2 and force at least a portion of the methane 4 out of solution. The dissolution of the methane 4 can create a zone of relatively high concentration of methane in front of the advancing CO2 plume 24.
As the production fluid 26 moves through the reservoir 2, it can become heated by geothermal heat 6 that is present in or is supplied to the reservoir 120. The geothermal heat 6 can raise the temperature of one or more components of the production fluid 26, raise the pressure of one or more components of the production fluid 26, or both. For example, the geothermal heat 6 can raise the temperature of the CO2 working fluid 12, the released methane 4, or both, raise the pressure of the CO2 working fluid 12, the released methane 4, or both, or raise both the temperature and the pressure of the CO2 working fluid 12 or the released methane 4, or both, within the production fluid 26. For example, the temperature of the production fluid 26 as it enters the production well opening 30 can be higher than the temperature of the CO2 working fluid 12 as it exits the injection well opening 16.
Upon its release at the injection well reservoir opening 16, the relatively cool CO2 working fluid 12 can permeate through the reservoir 1 forming the CO2 plume 24. Upon exposure to the temperatures present in the reservoir 1 (which are higher than the temperature of the cold CO2 working fluid 12), the cold CO2 working fluid 12 absorbs heat from the reservoir 1, thus causing an upwardly-migrating CO2 plume 24, which, in an example, can be laterally advected due to non-zero groundwater flow velocities within the reservoir 1. In an example, lateral migration occurs additionally or alternatively due to the CO2 plume 24 spreading, as additional CO2 exits the production well 28. In an example, the CO2 working fluid 12, in the form of the CO2 plume 24 or the production fluid 26, can form a continuous or substantially continuous connected stream from the injection well opening 16 to the production well opening 30.
The CO2 plume 24 can migrate, can be transported (such as in a closed loop system as described herein), or can flow or spreads towards the production well 28, entering a production well reservoir opening 30 as a relatively hot production fluid 26, e.g., a fluid having a temperature greater than the temperature of the cold CO2 working fluid 12 at the injection well opening 16. The CO2 plume 24 can move at any suitable rate in a substantially horizontal manner across the reservoir 1. In an example, the CO2 plume 24 can move at a rate of from about 0.1 to about one (1) m per day, inclusive, such as from about 0.4 to about 0.6 m/day, inclusive, although the systems and methods of the present disclosure are not so limited.
In another example, the reservoir 1 can comprise a hydrocarbon field, such as a reservoir that is part of an oil or natural gas field. The oil or natural gas reservoir 1 can be partially depleted by conventional hydrocarbon recovery methods. In such a case, if the CO2 working fluid can serve to assist in oil or hydrocarbon recovery through enhanced oil recovery (EOR). An EOR system can be set up similar to the system described above for a brine saline aquifer, e.g., with a CO2 source 18 providing the CO2 working fluid that can be injected into the reservoir 1 using a compressor 20 and, in some examples, a cooling unit 22. Therefore,
In an EOR-type system, methane 4 and other hydrocarbon gasses can be in a solution within the native fluid 2, such as by being dissolved or complexed with other hydrocarbons in the native fluid 2, or the methane 4 can be physically stored within the reservoir 1, such as within pores of the rock formation that forms the reservoir 1. The native fluid 2 can also comprise at least one hydrocarbon to be recovered, such as oil, natural gas, or both. The CO2 working fluid 12 can be injected through the one or more injection wells 14 and into the reservoir 1, where the CO2 working fluid 12 can interact with the native fluid 2, and in particular can interact with the at least one hydrocarbon of the native fluid 2, to form at least one production fluid 26. The interaction between the CO2 working fluid 12 and the native fluid 2 can improve the mobility of the hydrocarbons in the resulting production fluid 26 to improve extraction of the hydrocarbons from the reservoir 2. The production fluid 26 can be pushed toward one or more production wells 28, where it can be returned at or near the surface.
In an example, water or other fluids can be injected into the reservoir in addition to the CO2 or other non-water based working fluid 12. For example, a Water Alternating Gas (“WAG”) method can be used where the CO2 working fluid 12 and a water-containing working fluid are alternated, with the CO2 working fluid 12 acting to improve mobility of the hydrocarbons, and the water-containing working fluid pushing the CO2 and hydrocarbon production fluid 26 toward one or more production well openings 30 and up the one or more production wells 28. Further description of EOR and WAG is including in National Energy Technology Laboratory (NETL), “Carbon Dioxide Enhanced Oil Recovery,” (available at http://www.netl.doe.gov/technologies/oil-gas/publications/EP/small_CO2_eor_primer.pdf) (March 2010) which is incorporated herein by reference in its entirety.
In the case of an EOR-type method, the production fluid 26 can include at least a portion of the CO2 working fluid 12 and at least a portion of the hydrocarbons that had been part of the native fluid 2. The production fluid 26 can also include other native fluids that can be present in the reservoir 1, such as a brine solution, and other injected fluids, such as a water-containing working fluid. In an example, the production fluid 26 can include a non-water based working fluid (e.g., CO2) 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 26 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 26 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 50 wt %, inclusive, of other native fluids or other injected fluids.
Depending on the composition of the native fluid in the reservoir 1 and the specifics of the particular EOR operation, the production fluid 26 can have a “high” percentage of CO2 from the working fluid, e.g., between about 66 wt % and about 99 wt % CO2, inclusive, a “low” percentage of CO2 from the working fluid, e.g., between 1 wt % and about 33 wt % CO2, inclusive, or any range of CO2 content in between, such as a “medium” percentage of the CO2 working fluid, e.g., between about 33 wt % and about 66 wt % CO2, inclusive. In some examples, the percentage of CO2 in the production fluid can be very low, such as from 1 wt % to 9 wt %, inclusive, for example from 2 wt % to 5 wt %, inclusive.
In the case of a CO2 working fluid 12, the CO2 can be partially or fully miscible with the hydrocarbons so that the CO2 working fluid 12 and the hydrocarbons form a homogenous or substantially homogenous solution of CO2 and hydrocarbon. Alternatively, the CO2 working fluid 12 can be fully or substantially immiscible so that the CO2 only partially dissolves, or substantially does not dissolve in the hydrocarbons so that the CO2 and the hydrocarbons in the production fluid 141 are produced as separate immiscible or substantially immiscible fluids. The CO2 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 1 so that the hydrocarbons can more easily separate from the rock formation of the reservoir 1 or be more easily driven toward the production well opening 30, or both.
The production fluid 26 can be carried up through the reservoir 2, such as by or in conjunction with a CO2 plume 24. The production fluid 26 can also be formed as a zone of mobilized hydrocarbons and CO2 that can be similar to a plume, but not necessarily. In an example where a water-containing working fluid is used, such as in a WAG process (described above), the one or more production fluids 26 can include alternating zones of mobilized hydrocarbons with CO2 and zones of water-containing working fluid. As the production fluid 26 moves through the reservoir 2, it can become heated by geothermal heat 6 that is present in or is supplied to the reservoir 1. The geothermal heat 6 can raise the temperature of one or more components of the production fluid 26, raise the pressure of one or more components of the production fluid 26, or both. For example, the geothermal heat 6 can raise the temperature of at least one of the CO2 working fluid 12, the methane 4 released from the native fluid 2, or other hydrocarbons released from the native fluid 2, raise the pressure of at least one of the CO2 working fluid 12, the methane 4 released from the native fluid 2, or other hydrocarbons released from the native fluid 2, or raise both the temperature and the pressure of at least one of the CO2 working fluid 12, the methane 4 released from the native fluid 2, or other hydrocarbons released from the native fluid 2. For example, the temperature of the production fluid 26 as it enters the production well opening 30 can be higher than the temperature of the CO2 working fluid 12 as it exits the injection well opening 16.
The dissolving of at least a portion of the CO2 working fluid 12 into a brine working fluid 2 can provide for CO2 sequestering, e.g., to store CO2 that has been produced in a power plant, a biofuel plant, or an industrial plant in order to reduce CO2 emissions into the atmosphere. Similarly, a portion of the CO2 working fluid 12 can be sequestered into an oil or hydrocarbon reservoir 1 when the CO2 working fluid 12 is being used for EOR.
Whether the native fluid 2 comprises a fluid with dissolved methane, such as a brine, or a hydrocarbon fluid, such as oil or natural gas in an EOR field, the production fluid 26 can be brought to the surface via the one or more production wells 28 so that energy can be recovered via an energy recovery system 32. In an example, shown in
The system 10 can include a pump or compressor (not shown) at the surface, e.g., essentially immediately downstream of the production well 28, and upstream of the energy recovery system 32, in order to boost the pressure of the production fluid 26. The increased pressure from this pump or compressor can allow the production fluid 26 to effectively and efficiently produce power when the production fluid 36 is run through the expansion device 36. A pump or compressor in this location, e.g. upstream of the energy recovery system 26, can be particular effective for a reservoir 1 comprising a saline aquifer with native CO2 in the native fluid 2, because the production fluid 26 can be produced at pressures that are too low to cost-effectively produce electricity 42 from the expansion device 36 and the generator 40. Waste heat off this pump or compressor can be harvested, as described in more detail below, for supplementing power production. Alternatively, a pump or compressor can be added to the system essentially immediately upstream of the injection well 14 before reinjection the CO2 into the reservoir 1 as part of the working fluid 12.
The expansion device 36 can comprise any suitable type of expansion device 36 known in the art, such as a turbine, although the present disclosure is not so limited. In contrast to conventional water-based geothermal systems which produce low pressure steam at high volumetric flow rates, the use of a conventional turbine in higher pressure CO2 geothermal energy systems and methods described herein, is an option, rather than a requirement
In an example, the expansion device 36 comprises one or more piston-cylinder devices. The expansion device 36 can be one or more scroll, screw or rotary compressors designed to run in reverse as engines. The expansion device 36 can comprise a single expansion device 36, or a plurality of expansion devices 36. Multiple expansion devices 36 can run in parallel, with one or more first expansion devices 36 running pumps or compressors directly and one or more second expansion devices 36 producing electric power for sale. The generator 40 can be any suitable generator known in the art, to produce electricity 42. In an example, the components of the production fluid 26 can comprise primarily or substantially all of lower density gases so that the expansion device 36 can be a direct turbine. Relatively low-density gaseous or supercritical fluids can provide relatively higher energy efficiency, and thus produce relatively 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, such as CO2 and methane, through a direct turbine 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.
As described above, the native fluid 2 in the reservoir 2 can comprise methane 4, such as methane 4 within solution in the native fluid 2. As further described above, the injection of the CO2 working fluid 12 can cause at least a portion of the methane 4 to come out of solution with the native fluid 2 and be brought up to the surface with the CO2 working fluid 12 as a production fluid 26. The system and method of the present disclosure can be configured to take advantage of the methane 4 that is produced to the surface in order to improve the efficiency of the geothermal energy recovery by recovering another form of energy from the reservoir 1—namely, a portion of the chemical energy stored in the methane 4.
As shown in
After combustion in the heater 48, the methane 46 is converted into CO2 and water vapor in an exhaust stream 56. In an example, at least a portion of the CO2 in the exhaust stream 56 can be captured by a CO2 capture system 58. In an example, the CO2 capture system 58 can comprise an absorber through which an absorbing material can flow, such as an absorbing solution comprising one or more amines, and a regenerator that can strip CO2 from the amine solution. The outputs from the CO2 capture system 58 can include a CO2-rich stream 60 and a vented gas 62 (e.g., water vapor and other non-absorbed compounds). If desired, the vented gas 62 can be further treated. The CO2 output stream 60 can be fed back into the reservoir 1, such as by compressing the CO2 output stream 60 in a compressor, which can be the same compressor 20 as is used to compress the CO2 from the CO2 source 18, as shown in
In another example, rather than heating the production fluid 26 with a heater 48, the separated methane 46 can be combusted in a conventional gas turbine or gas engine (not shown) to produce electricity from the turbine or engine. The combustion of the methane 46 in the gas turbine or the engine can produce substantial waste heat in the form of hot combustion gases (e.g., CO2 and steam) and hot engine or turbine cooling jacket fluid. The waste heat can be added to the production fluid 26, such as via a heat exchanger. This configuration can, in some cases, lead to higher energy conversion efficiency then directly heating the production fluid 26 in a heater 48.
In some examples, a portion of the separated methane 46 can be split off from the methane stream 46 and stored or sold as a methane product 47. However, in some situations, it may be inefficient or uneconomical to sell a portion of the separated methane 46 rather than combusting all of the methane 46 to boost the temperature or pressure of a working fluid or production fluid. The reason for this is because the most likely end point for sold methane is a natural gas power plant where it will be burned to produce electricity. As described above, the separated methane 46 combusted in the heater 48 is used to heat a working fluid or production fluid, which in turn can be sent through an energy recovery system 32 to generate electricity 42. However, the sold methane 47 can lose some economic efficiency due to transportation costs to bring the methane 47 to the outside power plant. Burning methane in a power plant can also be less efficient than the energy recovery system 32 because power plants do not also incorporate geothermal energy recovery. Moreover, natural gas power plants typically employ steam turbines, which can be considerably less efficient than direct turbines using supercritical CO2 as the working fluid or CO2 and methane as a production fluid. In addition, the majority of natural gas power plants are not equipped for CO2 capture so that the methane 47 delivered to these power plants will likely contribute to CO2 emissions. In contrast, the energy recovery systems 32 of the present disclosure can also be configured with a CO2 capture system 58, as described above, to capture any CO2 formed by the heater 48. Thus, the systems of the present disclosure can provide for reduced CO2 emissions to the atmosphere. Even if the outside power plant were to have CO2 capturing capabilities, the systems and methods of the present disclosure can provide for more efficient reduction of emissions because the CO2 capture system and geologic storage of CO2 can be co-located with the geothermal energy recovery system, reducing or eliminating the need for transportation systems necessary to reduce or prevent emissions from natural gas power plants.
The heater 48 can be positioned upstream of the expansion device 36, as shown in
In some examples, the separation system 44 can cool or depressurize the production fluid in order to achieve the separation of the methane 46 (described in more detail below). Therefore, in an example, the methane separation system 44 is downstream of the expansion device 36 such that the cooled production fluid 52 is fed into the separation system 44. By separating the methane 46 from the production fluid 52 downstream of the expansion device 36, the system can prevent or reduce the loss of geothermal energy during the separation of the methane 46 from the production fluid 52.
In an example, the methane separation system 44 can comprise one or more membranes that are configured to selectively allow the passage of one or more components within the production fluid 52 through the membrane while preventing or impeding the passage of one or more other components within the production fluid 52 through the membrane. For example, the membrane can be selectively permeable between CO2 and methane, so that the CO2 can pass substantially unimpeded through the membrane, while a portion of the methane 46 is prevented from passing through the membrane, or vice versa. In an example, the pressure difference across the membrane can be controlled, which can control the percentage of methane that can be removed from the production fluid 52 in order to control the amount of methane in the separated methane stream 46.
It has been found that even if only a small percentage of the methane is separated from the production fluid can provide for substantial increases in energy recovery from the energy recovery system 32. In an example, the production fluid contains about 5 wt % methane, and about 10 wt % to about 30 wt % of this can be separated out and combusted, which can provide for an increase in the production of electricity 42 of from about 75% to 1000% above the electricity that can be produced from the geothermal energy collected by the production fluid alone. Moreover, separating only a small portion of the methane from the production fluid can ensure that a substantial amount of methane is still present in the production fluid before it is re-injected back into the reservoir 1 (described in more detail below). The presence of methane in the re-injected production fluid can ensure that methane is present in the reservoir to be extracted over time such that there is a generally always a portion of methane that can be brought to the surface with the production fluid 26.
The use of the separated methane 46 can allow for economically viable geothermal energy recovery from reservoirs having lower temperatures than can be achieved through simply extracting the thermal energy from the production fluid 26. For example, a CO2 plume 24 is used to collect geothermal energy, with no combustion of produced methane or any other heat-recovery methods (such as those described below), the recovery of geothermal energy from the reservoir may only be economically efficient at temperatures down to between about 30° C. and about 50° C., and in most cases only down to about 60° C. However, with the use of the methane separation system 44 and the methane combustion heater 48, economically viable recovery of geothermal energy can be achieved down to a reservoir temperature of about 10° C. to about 25° C., depending on the percentage of methane that can be produced from the reservoir 1, the reservoir depth and temperature, and the local ambient temperature.
As noted above, the system 10 of the present disclosure can be used for geothermal energy capture, as described herein, and can also be used for sequestering CO2 within the rock formation or native fluid 2 within the reservoir 1. Therefore, in some examples, at least a portion of the CO2 working fluid 12 can be stored permanently or semi-permanently within the reservoir 1, such that a replacement supply of CO2 can be required in order to continue operation of the system. The capture of the CO2 output stream 60 from the exhaust stream 56 can provide for a substantial portion of the make-up CO2 required. In an example, the CO2 output stream 60 from the CO2 capture system 58 can provide all or substantially all of the CO2 required to make up for CO2 that is sequestered within the reservoir 1.
Each of the binary systems 66, 78, 92 of
In the example of
As with the heater 48 in
The methane separation system 44, 96 can separate the methane stream 46, 98, as described above, and can leave a final production fluid 108 that can comprise CO2 and methane. The final production fluid 108 can also include other compounds, such as oil and gas compounds from an EOR reservoir or entrained brine solution from a saline aquifer, that can be further separated from the final production fluid 108 and sold as separate products, or the other compounds can be injected back into the reservoir 1 or into another reservoir. In an example, further cooling of the final production fluid 108 can be needed such that the final production fluid 108 is sent through a cooling unit, such as a cooling tower to further cool the production fluid before re-injecting the production fluid back into the reservoir. In an example, the final production fluid 108 can be cooled with the same cooling unit 22 that can cool compressed CO2 coming of the compressor 20. The systems of
Alternatively, the other compounds, such as oil and gas compounds or brine solution, can be separated from the production fluid 26 after it is produced from the production well 28 but before the energy recovery system 32, 66, 78, 92. In such a case, the production fluid 26 can be separated into various component streams, such as a CO2 and methane stream, a hydrocarbon stream, and a brine stream. Each of the components streams will include geothermal heat extracted from the reservoir 1. Therefore, thermal energy can be extracted from each stream with a separate energy recovery system, such as an expansion device and generator, as described above with respect to
The physical and thermodynamic properties of CO2 and methane, which can be the two primary components in the production fluid 26, can allow for the final production fluid 108 to be re-injected into the reservoir 1 via the injection well 14 without the need for an injection pump. In other words, the system 10 can be configured so that the CO2 working fluid 12/production fluid 26, 108 can form a thermosiphon as it circulates through the reservoir 1, to the surface via the production well 28, through the energy recovery system 32, 66, 78, 92, and back into the injection well 14.
In the case of CO2 and methane, a thermosiphon can be formed due to the expansion properties of the gases as they are heated in the reservoir 1. In an example, a relatively cold and compressed CO2 working fluid 12 (which can include methane within the re-injected final production fluid 108) is injected into the injection well 14, forming a long column of cold fluid. As the depth into the well is increased, the fluid at a particular point within the injection well becomes more and more compressed, until the CO2 working fluid exits the injection well 14 as a heavy, dense fluid from the injection well opening 16. As described above, at least a portion of the CO2 working fluid 12 can form a CO2 plume 24 (which can include re-injected methane, un-dissolved methane 4, and other compounds from the native fluid 2). The CO2 plume 24 can form a connected link between the injection well opening 16 and the production well opening 30. As the CO2 plume 24 moves through the reservoir 1, it can be heated by the geothermal heat 6 within or flowing into the reservoir 1. Both CO2 and methane expand substantially as they are heated, e.g., on the order of about a 100% expansion per 100° C. for CO2 and about a 20% expansion per 50° C. for methane.
The limited space in the reservoir 1 for expansion can cause the CO2 plume 24 to become more and more compressed as it moves through the reservoir 1 from the injection well 14 to the production well 28. This effect can partially offset the pressure loss due to Darcy flow as the CO2, methane, and other fluids move through the reservoir. Therefore, once the CO2 plume 24 reaches the production well opening 30 as the production fluid 26, it is a relatively hot relative to the CO2 working fluid 12 at the injection well opening 16, and has a pressure loss between the injection well opening 16 and the production well opening 30 that is smaller than would be expected from an identical reservoir using other working fluids, such as water or brine. As the production fluid 26 moves up the production well 28, it expands or becomes less dense (e.g., because there is less and less gas on top of the production fluid 26 as it moves up the production well 28), but still is at a relatively hot temperature and a relatively high pressure. In an example, the production fluid 26 expands less as it moves up the production well 28 than the CO2 working fluid 12 compresses as it moves down the injection well 14.
The injection well 14, production well 28, and the various components of the energy recovery system 32, 66, 78, 92 can be configured so that a thermosiphon can form between the production well 28 and the injection well 14 so that the final production fluid 108 can be re-injected into the injection well 14 without the use of a separate pump (as shown in
A thermosiphon or thermosiphon-like system, as described above, can provide efficiency advantages over systems using other working fluids. For example, the formation of a CO2 and/or methane thermosiphon can reduce or minimize parasitic power loses, such as those that can occur due to fluid injection or production pumps. Such parasitic power loses from pumps or compressors can account for as much as 30% or more of the gross power generated in geothermal systems using other working fluids, such as a water-based geothermal recovery system. The ability to provide for a thermosiphon can be a particular advantage for a CO2 working fluid 12 and the methane that can be included in the production fluid 26 over other working fluids, particularly water-based geothermal systems where a thermosiphon is impossible, practically speaking.
The presence of a pump or compressor essentially immediately downstream of the production well 28, as described above, does not prevent the function of a thermosiphon or thermosiphon-like operation of the system. Rather, the pump or compressor can merely improve efficiency of the power production in the energy recovery system 32, 66, 78, 92. A pump or compressor upstream of the energy recovery system 32, 66, 78, 92 can be desirable when the produced CO2 temperature is very low, e.g., temperatures that are far lower than conventional geothermal can economically support, such as temperatures less than about 75° C.). The pump or compressor may be economically viable when supplemental heat, either waste heat or heat from combusted fuel, is added to the production fluid 26 between the upstream pump or compressor and energy recovery system 32, 66, 78, 92.
The residual saturation of the brine native fluid 2 in the reservoir 1 can affect the lifespan of methane production from the system. As used herein, the term “residual saturation” can refer to the fraction of the reservoir pore space that remains occupied by the brine or water native fluid 2 after the CO2 working fluid 12 is injected into the reservoir 1 to form the CO2 plume 24. The residual brine or water native fluid 2 can include dissolved methane 4, and this methane 4 can diffuse out of solution over time and be carried or pushed by the CO2 plume 24. The residual water or brine native fluid 2 can also prevent circulation of the CO2 working fluid 12 through the portions of the reservoir 1 that are occupied by the residual native fluid 2 while still permitting exchange of geothermal heat 6 from the reservoir 1 and residual native fluid 2 to the CO2 working fluid 12. Thus, the residual saturation of the brine native fluid 2 can, in practice, increase the percentage of the reservoir 1 that is occupied by a given volume of the CO2 working fluid 12. Therefore, the residual native fluid 2 can, in essence, increase the volume of the rock formation in the reservoir 1 that is contacted by the CO2 working fluid 12, which in turn can increase the amount of geothermal energy that can be captured by the CO2 working fluid 12. Moreover, the methane 4 that is released from solution from the residual brine or water means that the reservoir 1 can continue to produce methane while increasing the volume of the rock formation that is contacted by the CO2 working fluid 12, thus increasing the methane production and the geothermal energy recovery efficiency of the system. For this reason, residual saturation can provide a substantial feature of the methane-enhanced systems of the present disclosure.
As described above, when the CO2 working fluid 12 is injected into the reservoir 1 where methane 4 and other alkanes are in a solution in the native fluid 2, the CO2 can cause a portion of the methane 4 to come out of solution where the methane can interact with the advancing CO2 plume 24. The release of the methane 4 from the solution can result in the formation of a zone of high methane concentration in front of the advancing CO2 plume 24.
The first production wells 28A, which can also be referred to herein as “CO2 production wells 28A,” can include a production fluid comprising CO2 and a small portion of methane. The production fluid from the CO2 production wells 28A can be processed in substantially the same manners as described above with respect to the production fluid 26 in
The second production wells 28B, which can also be referred to herein as “methane production wells 28B,” can produce a combination of methane and brine solution from the reservoir 1. The production fluid from the methane production wells 28B can also include some CO2 and, in some examples, other native fluids, such as hydrocarbons from an EOR reservoir. Because the openings 30B to the methane production wells 28B are designed to be within the high-concentration methane zone 34 within the reservoir 1, the produced fluid from the methane production wells is expected to be primarily methane, with brine solution also comprising a sizable portion of the production fluid.
The separate recovery of the production fluid from the CO2 plume 24 (primary CO2 with a small portion of methane) from the CO2 production wells 28A and from the high-concentration methane zone 34 (primarily methane with a small portion of brine) from the methane production wells 28B can provide for more controlled extraction of methane and CO2 and for maximum methane extraction from the reservoir 1. However, as will be appreciated by a person of ordinary skill in the art, as the CO2 plume 24 expands within the reservoir 1, the high-concentration methane zone 34 can move past the methane production wells 28B. Therefore, a staged approach for the placement and drilling of the production wells 28 can be used to continue to provide for the separate production of CO2 from CO2 production wells 28A and of methane from methane production wells 28B.
A CO2 working fluid can be injected into the injection well 114, as described above, so that a CO2 plume forms within the underground reservoir. As further described above, the CO2 working fluid can cause methane to come out of solution such that a zone of high methane concentration forms in front of the CO2 plume. The CO2 production wells 116A can be positioned relative to the injection well 114 so that a CO2 production well opening is located within the CO2 plume during an initial operating period after start up. The methane production wells 116B can be positioned relative to the injection well 114 so that a methane production well opening is located within the zone of high methane concentration during an initial operating period after start up. In an example, the CO2 production wells 116A are spaced from the injection well 114 at about 100 m to about 2000 m. Each methane production well 116B can be spaced another 10 m to about 1000 m from a corresponding CO2 production well 116A.
As the CO2 working fluid is added to the reservoir from a CO2 source, from circulating CO2, or from CO2 capture off the methane combustion heater, the CO2 plume will grow over time. After an initial operating period, the CO2 plume will reach the methane production wells 116B and the zone of high methane concentration will be pushed beyond the first methane production wells 116B. At such time, a second set of production wells can be drilled, such as a second pair of arc CO2 production wells 118A and a second pair of arc methane production wells 118B. In the example shown in
As the CO2 plume continues to grow, the CO2 plume can reach the methane production wells 118B such that additional production wells may be drilled. For example, a third set of production wells, such as third CO2 production wells 122A and third methane production wells 122B can be drilled. In an example, the third production wells (e.g., CO2 production wells 122A and methane production wells 122B) can be positioned along the first axis (e.g., the same axis as the first production wells 118A, 118B), or can be positioned along another axis with respect to the injection well 114. In an example, each third CO2 production well 122A can be spaced from a corresponding first CO2 production well 116A by approximately the same spacing as the first CO2 production well 116A is spaced from the injection well 114, e.g., at about 100 m to about 2000 m. Each third methane production well 122B can be spaced from a corresponding third CO2 production well 122A at about 10 m to about 1000 m.
As noted above, the primary components from the methane production wells 28B, 116B, 118B are expected to be methane and brine solution, which will generally be in separate phases at the surface (e.g., gaseous methane and liquid brine solution). Therefore, separation of methane from the production fluid of the methane production wells 28B, 116B, 118B can be relatively easy and inexpensive. A portion of the methane from the methane production wells 28B, 116B, 118B can be added to the combustion heater, along with any methane separated from the CO2 production wells 28A, 116A, 118A, to supplement the geothermal energy recovered by an energy recovery system. A portion of the methane from the methane production wells 28B, 116B, 118B can also be stored or re-injected into the reservoir to ensure methane availability over the lifespan of the reservoir, wherein the re-injected methane can later be produced with CO2, separated, and combusted to supplement geothermal energy recovery from the reservoir.
Any CO2 that is produced from the methane production wells 28B, 116B, 118B can be sent through the energy recovery system, if the temperature and/or pressure of the CO2 from the methane production wells 28B, 116B, 118B is sufficiently high. Alternatively, the CO2 produced form the methane production wells 28B, 116B, 118B can be compressed, such as in compressor 20, and injected into the injection wells 14, 114, 120 along with the CO2 working fluid 12.
Any brine or other liquid produced from either the CO2 production wells 28A, 116A, 118A or the methane production wells 28B, 116B, 118B can be processed with an energy recovery device, such as an expansion device, a binary energy recovery system, or a heat exchanger, to recover geothermal energy that has been absorbed by the brine or other liquids. In most examples, unless the brine has a sufficiently high temperature, heat can be recovered from a brine solution only through a binary power system, such as an organic Rankine cycle (ORC) or a Kalina cycle. If the temperature of the brine solution is at least about 165° C., and preferably at least about 200° C., then a direct flash or dual-flash power system can be employed. In certain examples, it may be desirable to combust a portion of the methane extracted from the reservoir 1 in order to boost the temperature of the brine solution in addition to increasing the temperature and/or the pressure of the CO2 production fluid. However, in general, water-based power systems are less efficient than gas-based power systems, and particularly CO2-based power systems. In some examples, after geothermal heat has been extracted from the brine solution, the brine system can be disposed of, such as by injecting the brine solution into the reservoir 1 or another geological formation, or the brine solution can be used for another purpose within the system, such as a cooling medium within the cooling unit 22. Alternatively, the brine solution can be processed to extract useful minerals or to provide fresh water.
In order to maximize methane production and ensure methane is available for the lifespan of the system, careful and staged CO2 plume development can be employed. A single geologic reservoir that is capable of supporting CO2 injection and sequestration can, for instance, have multiple sublayers that can preferentially permit CO2 flow. Sublayers can be distinguished by permeability and porosity. Sublayers that favorably support CO2 injection via relatively high permeability or porosity, or both, can be near-vertically separated from sublayers of lower permeability, porosity, or both. Such sublayers that support or retard CO2 flow can alternate in any order in a near-vertical stack, where “near-vertical,” as used herein, can refer to the geologic layers and sublayers being substantially horizontally oriented, or only inclined from horizontal by from zero to a few degrees in deep naturally permeable and porous formations. Such sublayering is common in deep permeable formations. The sublayer can allow CO2 injection and production to begin in one sublayer and then proceed to others, e.g. by perforating and completing the injection wells, or the production wells, or both, for the CO2 plume (which can include methane plume, as described above) in one sublayer, and with a methane high-concentration zone, in another sublayer as each sublayer matures. In such a way, a long-term methane supply for operation of the geothermal energy recovery system can more readily be achieved.
The examples described above with respect to
As discussed above, the production fluid 26 being produced from the reservoir 1 can have a percentage of methane included within the production fluid 26, e.g., from 1 wt % to 10 wt % or more, such as about 5 wt % methane and 95 wt % CO2. It has been surprisingly found that the inclusion of even a small percentage of methane in the production fluid 26 can have a demonstrable improvement in system efficiency compared to a produced fluid that is substantially all CO2, as in a CPG geothermal recovery system.
Each of the phase diagram cycles in
As can be seen from the comparison of
In addition, the amount of heat energy that needs to be removed in the cooling unit 22 (represented by the enthalpy change between points 5 and 1 in
As demonstrated by
As noted above, in some examples, the reservoir into which the CO2 working fluid is injected, e.g., reservoir 1 in
The complex produced fluid from an EOR field, which can generally comprise a combination of CO2, hydrocarbons, and water or brine, can either be separated before or after geothermal heat energy extraction. The heat extraction apparatuses, generally either a direct or a binary power system, that are employed in an EOR setting can be chosen on a site-specific basis according to produced fluid temperature, pressure, and composition conditions.
In an example, the systems required for EOR operations can be powered by electricity. The electricity requirements of an EOR system can be substantially greater than the requirements for a CO2 plume geothermal system or a CO2 geothermal system including methane combustion to supplement the geothermal energy recovery. The electricity for EOR operations can be purchased from the grid or through the use of on-site gas turbines fueled by purchased or locally-produced methane. In the case of produced methane, power production efficiency and total power produced can be increased through the use of the methane-enhanced geothermal recovery systems described above. The increased efficiency of the methane-enhanced systems can be achieved with little or no increase in cost for the site operator because geothermal and gas combustion energy are combined. Moreover, the overall power costs for an EOR system that is supplemented with methane-enhanced geothermal energy recovery can be decreased because the power produced onsite can be produced from all available energy types, e.g., geothermal and gas chemical.
One or more components of the geothermal energy recovery system or other co-located systems, such as an EOR recovery system, can include an operation or equipment that can generate considerable heat. Often, heat generated by these systems, operations, or equipment are allowed to dissipate to the atmosphere such that the heat energy is essentially wasted. This kind of heat is referred to herein as “waste heat.”
An example of waste heat that can occur at or near a geothermal energy recovery system can include heat generated by a CO2 compressor. As noted above, CO2 working fluid 12 from a CO2 source 18 can be pressurized in a compressor 20 before it is injected into the injection well 14. Similarly, the CO2 that is formed during combustion of the separated methane 46 to increase the temperature or pressure of the production fluid 26 and the captured can also be compressed with a compressor 20 and injected into the injection well 14. Also, in an enhanced oil recovery (EOR) system, CO2 can be produced from the reservoir 1 and separated from the production fluid 26. The produced CO2 can be compressed and re-injected back into the reservoir 1. It is understood in the art that CO2 compressors, such as those used in EOR systems or for the compression of CO2 for injection into a reservoir, such as for CO2 sequestration, can generate a considerable amount of heat. In an example, a CO2 compressor for the injection of CO2 into the reservoir 1 can generate 50 to 1500 kJ of heat energy per kg of CO2 compressed, such as 200 to 600 kJ of heat energy per kg of CO2 compressed, for example 400 to 450 kJ of heat energy per kg of CO2 compressed.
Another example of a source of waste heat can occur in an EOR system. As described above, a production fluid from an EOR field can include CO2, brine or other native liquids, and hydrocarbons from the oil or gas reservoir. The different components of the production fluid can be separated, either before the geothermal energy is recovered or after. One method for separating hydrocarbons from the other fluids in the production fluid can include burning a portion of the methane or other hydrocarbons that are produced within a separation vessel, which in turn heats the production fluid. The increased temperature of the production fluid can improve separation of liquid hydrocarbons from CO2, natural gas, and brine. However, the heating to improve separation results in a stream of hot liquid hydrocarbons, hot brine, hot CO2 and natural gas, or any combination thereof, that have conventionally simply been allowed to cool by dissipating the heat to the atmosphere.
Still another example of a source of waste heat can occur with a facility that includes the geothermal energy recovery systems of the present disclosure co-located with another type of facility that produces excess heat. For example, if the geothermal energy recovery facility is co-located with an ethanol or other biofuel production plant. A co-located ethanol or biofuel plant can be desirable because such plants generally produce CO2 waste streams during production that can be captured and used as the CO2 source for the geothermal energy recovery systems of the present disclosure. Other examples of waste heat sources from other facilities include, but are not limited to, fermentation tanks in biofuel facilities, furnaces in industrial facilities such as cement manufacturing plants, cooling units in fossil fuel power plants, and the heat energy produced at a flare, such as a methane or natural gas flare. Moreover, the CO2 generated by ethanol and biofuel plants are typically relatively clean CO2 streams that can be captured at a lower cost than CO2 from fossil fuel power plants. Capturing and injecting the CO2 from the ethanol or biofuel plant can require the use of a CO2 compressor, which, as noted above, can generate considerable waste heat.
The above examples of waste heat are intended to be merely exemplary of the sources of waste heat that may be typical or advantageous when co-located with geothermal energy recovery. The above examples are not intended to be limiting, and a person of ordinary skill in the art can readily determine whether other waste heat sources can be used to supplement geothermal energy recovery, as described below.
The reservoir 138 can include a native fluid 142 that can include methane 144 in solution within the native fluid 142. In an example, the native fluid 142 can include oil or other hydrocarbons or brine within an EOR reservoir 138. The CO2 working fluid 136 can form a CO2 plume 146 within the reservoir 138 that can comprise CO2 from the working fluid 136, a portion of the methane 144 that is released from solution within the native fluid 142, hydrocarbons from the native fluid 142 that are released due to the injection of the CO2 working fluid 136, and other native fluids such as brine or water (discussed in more detail above). All of these components can form a production fluid 148 that is produced to the surface via a production well 150. In short, the system 130 can be configured as an enhanced oil recovery (EOR) system. As described above, the system 130 can include several subsystems for energy recovery or conversion that supplements geothermal energy recovery by increasing the energy that is available to an energy recovery system.
The production fluid 148 can be fed into a separation system 152 that can separate the production fluid 148 into its various components. In an example, the separation system 152 can separate the production fluid 148 into a gaseous CO2 and methane stream 154, a liquid brine or water stream 156, and a liquid hydrocarbon stream 158. As described above, in some methods separation can be aided in the separation system 152 by heating the production fluid 148 to high temperatures to more efficiently separate the liquid hydrocarbons 158 from the other components, which can result in all three of the product streams 154, 156, and 158 from the separation system 152 being at a high temperature, such as about 30° C. to about 120° C., for example about 50° C. to about 80° C.
The heat energy created in the separation system 152 had conventionally been allowed to dissipate to the atmosphere as waste heat. The example system 130 of
In one example, the separation system 152 may not produce a considerable amount of waste heat, e.g., where liquid hydrocarbon separation can be achieved without further heating. In such a case, the heat exchangers 162 can be configured to only absorb the geothermal energy that has been absorbed by the production fluid 148 (and which is present in the separate product streams 154, 156, 158). Alternatively, a single heat exchanger can be positioned upstream or downstream of the separation system 152 to absorb the geothermal heat energy.
At least a portion of the cooled CO2/methane stream 154 can be pressurized by a compressor 164 for re-injection back into the reservoir 138 through the injection well 140. The cooled brine or water stream 156 can be put into brine storage 166, such as within water or brine tanks or by being injected into a geological formation. At least a portion of the cooled liquid hydrocarbon stream 158 can be sold as a hydrocarbon product 168.
The secondary working fluid 160 can circulate to other parts of the system 130 in order to absorb other heat energy that might otherwise be dissipated to the atmosphere. As described above, the CO2/methane compressor 164 can generate considerable heat energy, e.g., about 400 kJ to about 450 kJ per kg of CO2 and methane being compressed for each stage of compression. In an example, the secondary working fluid 160 can be circulated to the compressor 164 in order to recover a portion of the waste heat energy. In an example, a heat exchanger (not shown) can be placed on the CO2/methane stream 154 immediately downstream of the compressor 164 to transfer heat energy from the hot CO2/methane stream 154 to the secondary working fluid 160. In another example, the compressor 164 can be configured so that the secondary working fluid 160 flows around or through the compressor 164, e.g., through a cooling jacket on the compressor 164, to absorb heat from the compressor 164. Moreover, heat can be absorbed from the outlet of the compressor (e.g., immediately downstream of the compressor), or heat can be absorbed after one or more stages (e.g., from an intercooler) of the compressor.
In an example, the compressor 164 produces more heat energy than the heat energy produced in the separation system 152. For this reason, the circuit of the secondary working fluid 160 can be configured to first recover the heat energy from the separation system 152 (via the heat exchangers 162), and then to recover heat energy from the compressor 164.
As discussed above with respect to
A portion of the liquid hydrocarbons can be split off from the liquid hydrocarbon stream 158 to be combusted in a heater to further heat the secondary working fluid 160. In the example shown in
Alternatively, as described above, rather than heating the secondary working fluid 160 with a heater 174, the separated methane 172 and the liquid hydrocarbons 176 can be combusted in a conventional gas turbine or gas engine (not shown) to produce electricity from the turbine or engine. The combustion of the hydrocarbon fuel, e.g., the methane 172 and the liquid hydrocarbons 176 in the gas turbine or the engine can produce substantial waste heat in the form of hot combustion gases (e.g., CO2 and steam) and hot engine or turbine cooling jacket fluid. The waste heat can be added to the working fluid 160, such as via a heat exchanger. This configuration can, in some cases, lead to higher energy conversion efficiency then directly heating the working fluid 160 in a heater 174.
The byproducts of the combustion heater 174 can comprise CO2, which can be captured and compressed for re-injection into the reservoir 138, similar to the CO2 capture system 58 described above with respect to
After the secondary working fluid 160 has recovered heat from each heat source (e.g., waste heat from the separation system 152 or the compressor 164, or both, and heat from combustion of separated methane 172 or separated liquid hydrocarbons 176 in a combustion heater 174 (if present)), the secondary working fluid 160 can be fed into an energy recovery system 180 that can convert energy in the secondary working fluid 160 to another form, such as electricity 182 or direct-use heat. In the example shown in
As is further described above, a separate facility, such as a power plant, a biofuel plant, or an industrial plant can be co-located with the geothermal energy recovery system of the present disclosure. Waste heat from such a co-located facility can be recovered using heat exchangers and a working fluid, such as the secondary working fluid 160, that is pumped between the co-located facility and the geothermal energy recovery system, or the production fluid 148 or one or more of its constituent components can be pumped over to the co-located facility so that the waste heat can be transferred directly to the production fluid or the constituent component or components.
Alternative ConfigurationsIn an example, another combustible fuel, such as natural gas, biomass, or a biofuel (e.g., ethanol or diesel produced from biological sources), can be obtained from a third party outside of the geothermal energy recovery system. In another example, the other fuel can be produced at a co-located facility, such as a co-located ethanol or other biofuel production facility. The other fuel can be used to boost total power production of the geothermal energy recovery system, e.g., by combusting the outside fuel to increase the temperature, the pressure, or both, of the CO2 based working fluid. For example, if a geothermal energy recovery facility has been operating for a long period of time such that the amount of methane that is being produced from the reservoir is low, then the outside fuel can be used to supplement or replace the now-defunct methane production. The geothermal heat recovered with the CO2-based working fluid and the outside fuel source can combine in much the same fashion as CO2-based energy recovery and combusted produced methane, to increase the overall efficiency of conversion energy to electricity and to produce more electricity than either system could provide alone. In some examples, it may be more economical to purchase natural gas (mainly CH4), or other fuels, from a third party rather than relying on, or solely relying on, separated CH4 from the production fluid. For example, if the cost of natural gas is cheaper than the cost of separation. In an example, the fuel used in the combustion heater can comprise solely natural gas or other outside fuel, such as outside natural gas or fuel purchased from a third party, rather than using any separated CH4 produced from the reservoir.
In another example, site development considerations may favor immediate production of the methane within the reservoir, rather than long-term steady production of the methane. For example, rather than ensure gradual methane production over the life of a site, it can be better operated by producing the maximum methane that can be extracted beginning immediately with the onset of CO2 injection and continuing while the CO2 plume is established. The produced methane can be sold or stored onsite, such as in methane storage tanks or within a geologic formation separate from the reservoir into which the CO2 working fluid is injected. In the case of sold methane, a portion of the methane can be purchased back over time to supply the system as needed. In the case of stored methane, the methane can be removed from storage over time to supply the system. Immediate production of the methane can be economically favorable in circumstances when the well or wells that for methane or brine production can be repurposed for CO2 circulation without the need for separate methane and CO2 wells. The economic advantages of repurposing the methane or brine production wells for CO2 circulation can be balanced with the added costs for methane storage (e.g., storage tanks or systems for storing the methane in a geological formation).
The EOR facility 206 can separate a production gas stream 210, which can include CO2, CH4, and other gaseous hydrocarbons, and water and other hydrocarbons 211 from the production fluid 202. The system 200 can include a compressor or pump 212 downstream of the EOR facility 206 for increasing the pressure of the production gas stream 210 before recovering energy from the production gas stream 210. In particular, the compressor or pump 212 may be desired if the output pressure of the production gas stream 210 from the EOR facility 206 has a relatively low output pressure. The compressor or pump 212 can also compress the production gas stream 210 to desired injection conditions so that after energy recovery, the production gas stream 210 can be injected back into the reservoir via an injection well 214.
The compressor or pump 212 can increase the overall efficiency of the system. Surprisingly, it has been found that increasing the pressure of the production gas stream 210, such as with the compressor or pump 212, can increase the efficiency of the system by more than the amount of energy required to compress the production gas stream 210. Waste heat 216 from the compressor or pump 212 can be recovered by the system 200, as described in more detail above and below.
After the compressor or pump 212, if present, the production gas stream 210 can be fed through an energy recovery apparatus that can be similar to the methods described above, e.g., but first heating the production gas stream 210 in a heater 218, such as by combusting one or more fuels 219 in the heater 218, such as separated CH4, hydrocarbon fuel from the EOR operation, or other supplied fuel such as supplemental CH4, or via the recovery of waste heat in a heat exchanger/heater 218, to increase the temperature, increase the pressure, or both, of the production gas stream 210. Alternatively, the one or more fuels 219 can be combusted in a conventional gas turbine or gas engine (not shown) to produce electricity from the turbine or engine, and waste heat (in the form of hot combustion gases and hot cooling jacket fluid) from the turbine or engine can be added to the production gas stream 210, such as via a heat exchanger, rather than directly heating the production gas fluid 210 with a heater 218.
The heated or pressurized production gas stream 210 can be fed through a primary energy-recovery system 220 to produce electricity 222 directly from the production gas stream 210, such as one or more of a turbine, a generator, or an energy-recovery loop such as a Rankine power cycle, an organic Rankine cycle (ORC), or a Kalina cycle. A description of several examples of primary energy-recovery systems are described above with respect to
The system 200 of
The secondary working fluid 226 can be heated, via a heat exchanger 228, with the hot production gas stream 210 after it has been fed through the primary generator or turbine system 220. The heated secondary working fluid 226 can then be fed into a secondary turbine or generator 230 to produce additional electricity 232. After passing through the secondary turbine and generator 230, the secondary working fluid 226 can be cooled in a cooling unit 234, and the pressure of the secondary working fluid 226 can be increased with a pump or compressor 236 to increase the pressure of the working fluid 226 before starting the cycle over and heating the working fluid 226, such as with the hot, low pressure production gas stream 210 in the heat exchanger 228.
Depending on the temperature of the production gas stream 210 immediately downstream of the primary energy-recovery system 220, the secondary energy-recovery loop 224 can comprise a supercritical cycle, a transcritical cycle, a subcritical cycle, or a subcritical with superheater cycle.
The secondary energy-recovery loop 224 can provide for energy recovery from relatively lower-temperature sources. Therefore, additional low-temperature heating sources can be applied to further heat the secondary working fluid 226 beyond just using the hot production gas stream 210. The additional heating from lower-temperature sources can include geothermal energy recovery via a heat exchanger 238 that uses the production fluid 202 substantially immediately after being produced from the production well 204 to heat the secondary working fluid 226. The secondary working fluid 226 can also be further heated in a waste-heat heat exchanger 240 heated by waste heat from other parts of the system 200. Waste heat sources that can be particularly useful in the secondary energy-recovery loop 224 can include waste heat 208 from the EOR facility 206 and waste heat 216 from the pump or compressor 212.
It would be difficult to recover heat energy from the relatively lower-temperature energy sources described above using the primary energy-recovery system 220 because the CO2, CH4, and other gases in the production gas stream 210 coming out of the EOR facility 206 or the pump or compressor 212 can be relatively hot. In contrast, for at least portions of the secondary energy-recovery loop 224, the secondary working fluid 226 can be relatively cool, particular after the cooling unit 234 but before heating the secondary working fluid 226 in the heat exchanger 228 with the hot production gas stream 210.
The secondary working fluid 226 can also be further heated by a high-temperature energy source, such as by combusting one or more fuels 244, such as separated CH4, other hydrocarbons from the EOR facility 206, or other fuels (such as purchased CH4), in a secondary combustion heater 242. In an example, the secondary combustion heater 242 operates at a higher temperature than the hot production gas stream 210, so that the secondary heater 242 is placed downstream of the heat exchanger 228 as the last source of heat added to the secondary working fluid 226 in the secondary energy-recovery loop 224. The secondary energy-recovery loop system 200 of
Additional energy recovery loops, e.g., a tertiary loop, a quaternary loop, and so on, can be included in the system 200. For example, the hot secondary working fluid 226 coming out of the secondary turbine or generator 230 can be used to heat a tertiary working fluid in a tertiary energy-recovery loop, and so on.
Similar to the system 200 of
Like the system 200 of
The system 250 can also include a recuperator heat exchanger 260 to recover heat energy from the hot production gas stream 210 downstream of the heater 252 and the primary energy-recovery system 256. The recuperator heat exchanger 260 uses the relatively high temperature of the production gas stream 210 downstream of the primary energy-recovery system 256 to increase the temperature of the inlet flow of the production gas stream 210 before it enters the heater 252 and the primary energy-recovery system 256, thus increasing the overall efficiency of the system 250 compared to a system that did not include a recuperator heat exchanger. The recuperator heat exchanger system 250 of
After recovering energy from the production gas stream 210, such as via the secondary energy-recovery loop 224, as in
A direct CO2 turbine may be used after the compressor that is required in all CO2-EOR operations. This configuration may require inclusion of a pump/compressor before the turbine (preferably before the methane heater and waste heat capture unit, as well) if the existing EOR compressor has an insufficient output pressure. A pump could, alternatively, be included after the cooling unit—this configuration may be preferable, since the cold liquid/supercritical stream could relatively easily be recompressed to required injection conditions. Note that the presence of a pump after the power system is defined in the application in some cases, but the case of a direct turbine after the compressor is not explicitly specified.
EXAMPLESThe invention will be further described by reference to the following examples, which are offered to further illustrate various embodiments of the present invention. It should be understood, however, that many variations and modifications may be made while remaining within the scope of the present invention. The Examples include numerical modeling of electricity production from various working fluids or production fluids. The modeling was created using Matlab, sold by The MathWorks Inc., Natick, Mass., USA, together with the National Institute of Standards and Technology (NIST) Reference Fluid Thermodynamic and Transport Properties Database (REFPROP), Version 9.0.
Example 1The modeling assumed a reservoir depth of 1500 m, a flow rate of the production fluid of 200 kg/s, that the production fluid is 99 wt % CO2 and 1 wt % methane, that 2.0 kg/s of the methane is separated and combusted to boost the temperature, the pressure, or both of the production fluid. The expansion device and generator are assumed to have a power system efficiency of 50% of the Carnot efficiency.
As shown in
The modeling for this example assumed a reservoir depth of 1500 m, a flow rate of the production fluid of 100 kg/s. The production fluid is assumed to be 20 wt % CO2, 1 wt % CH4, and the remainder liquid hydrocarbons and brine. The flow rate of methane separated from the production fluid and combusted is assumed to be 0.5 kg/s. The energy recovery system for the EOR system is assumed to be a binary system with a secondary working fluid such that energy recovery is less efficient than the direct turbine system that can be used for Examples 1 and 2. Therefore, the energy recovery system is assumed to have a power system efficiency of 33% of the Carnot efficiency. The waste heat is generated by a high ratio (10:1) compressor with heat capture only off the final stage of compression, with no heat capture of any compressor intercoolers. Therefore, additional heat capture from the compressor beyond that shown in
As shown in
Various combinations of compressor stages can be used to capture waste heat for supplementing geothermal energy recovery.
A first data line 370 in
For each of the data lines 370, 372, 374, 376, the CO2-based working fluid is assumed to leave the EOR facility, including CO2 compressors, at 2000 psia (about 13.8 MPa) and 300° F. (about 149° C.), which is a moderate CO2 injection pressure and a reasonable pre-cooling compressor outlet temperature. The CO2 mass flow rate is shown for 100 kg/second (data lines 370 and 374) and 75 kg/second (data lines 372 and 376), which are consistent with a moderately-sized CO2 EOR facility. Parasitic energy requirements of the compressors or pumps within the system are accounted for in the results, but the compressor power required by the EOR facility to raise CO2 pressure from separation to injection conditions is not included because the facility requires this energy regardless of whether an enhanced CPG system is included. Either the primary energy-recovery or the secondary energy-recovery loop can be used to gather the geothermal and, if applicable, waste heat.
Each of the data lines 370, 372, 374, and 376 also includes an assumption of geothermal heat input in the system, the reservoir is assumed to be a relatively low temperature EOR field with moderate oil and water production (6000 barrels/day of each constituent). Geothermal energy is extracted from the combined CO2, hydrocarbon, and water production stream, cooling the stream from 57° C. (about 135° F.) to ambient conditions. A conservative estimate of 75% of the geothermal energy is assumed to be transferred to the enhanced CPG power system.
As can be seen in
The above Detailed Description is intended to be illustrative, and not restrictive. For example, the above-described examples (or one or more elements thereof) can be used in combination with each other. Other embodiments can be used, such as by one of ordinary skill in the art upon reviewing the above description. Also, various features or elements can be grouped together to streamline the disclosure. This should not be interpreted as intending that an unclaimed disclosed feature is essential to any claim. Rather, inventive subject matter can lie in less than all features of a particular disclosed embodiment. Thus, the following claims are hereby incorporated into the Detailed Description, with each claim standing on its own as a separate embodiment. The scope of the invention should be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled.
In the event of inconsistent usages between this document and any documents so incorporated by reference, the usage in this document controls.
In this document, the terms “a” or “an” are used, as is common in patent documents, to include one or more than one, independent of any other instances or usages of “at least one” or “one or more.” In this document, the term “or” is used to refer to a nonexclusive or, such that “A or B” includes “A but not B,” “B but not A,” and “A and B,” unless otherwise indicated. In this document, the terms “including” and “in which” are used as the plain-English equivalents of the respective terms “comprising” and “wherein.” Also, in the following claims, the terms “including” and “comprising” are open-ended, that is, a system, device, article, composition, formulation, or process that includes elements in addition to those listed after such a term in a claim are still deemed to fall within the scope of that claim. Moreover, in the following claims, the terms “first,” “second,” and “third,” etc. are used merely as labels, and are not intended to impose numerical requirements on their objects.
Method examples described herein can be machine or computer-implemented, at least in part. Some examples can include a computer-readable medium or machine-readable medium encoded with instructions operable to configure an electronic device to perform methods or method steps as described in the above examples. An implementation of such methods or method steps can include code, such as microcode, assembly language code, a higher-level language code, or the like. Such code can include computer readable instructions for performing various methods. The code may form portions of computer program products. Further, in an example, the code can be tangibly stored on one or more volatile, non-transitory, or non-volatile tangible computer-readable media, such as during execution or at other times. Examples of these tangible computer-readable media can include, but are not limited to, hard disks, removable magnetic disks, removable optical disks (e.g., compact disks and digital video disks), magnetic cassettes, memory cards or sticks, random access memories (RAMs), read only memories (ROMs), and the like.
The Abstract is provided to comply with 37 C.F.R. § 1.72(b), to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
Claims
1. A system comprising:
- one or more injection wells for accessing one or more underground reservoirs, the one or more reservoirs being at one or more first temperatures and containing at least one native fluid, each of the one or more injection wells having an injection well reservoir opening in fluid communication with one of the one or more reservoirs;
- one or more production wells each having a production well reservoir opening in fluid communication with one of the one or more reservoirs;
- a working-fluid supply system for providing a non-water based working fluid to the one or more injection wells at a second temperature lower than the one or more first temperatures,
- wherein the working-fluid supply system, the one or more injection wells, and the one or more production wells are configured to store at least a first portion of the non-water based working fluid in the one or more reservoirs for a specified period of time,
- wherein exposure of the working fluid to the one or more first temperatures heats the working fluid to a third temperature that is higher than the second temperature, wherein at least a second portion of the working fluid that is at the third temperature enters the one or more production well reservoir openings and is produced from the one or more reservoirs via the one or more production well to provide a production fluid; and
- an energy recovery apparatus in fluid communication with the one or more productions wells, wherein energy contained in the production fluid is converted to electricity, heat, or a combination thereof, in the energy recovery apparatus.
2. The system of claim 1, wherein the at least one native fluid includes a solution comprising methane,
- wherein exposure of the non-water based working fluid to the at least one native fluid causes methane to come out of the solution with the native fluid such that the production fluid comprises methane that had come out of the solution, and
- wherein the energy recovery apparatus comprises at least one separation apparatus that separates at least a portion of the methane from the production fluid.
3. The system of claim 2, wherein the energy recovery apparatus further comprises a heater that combusts at least a portion of the separated methane and heats the production fluid to a fourth temperature that is higher than the third temperature to provide a heated production fluid.
4. The system of claim 1, wherein the energy recovery apparatus further comprises at least one of: one or more electricity-generating devices; one or more heat exchangers; or a combination thereof to convert energy contained in the production fluid to electricity, heat energy, or a combination thereof.
5. The system of claim 1, wherein the energy recovery apparatus comprises at least one heat recovery apparatus for recovering heat from at least a first portion of the production fluid to heat a second portion of the production fluid.
6. The system of claim 1, wherein the at least one native fluid further comprises at least one hydrocarbon, wherein the production fluid comprises at least a portion of the at least one hydrocarbon, and wherein the energy recovery apparatus further comprises:
- one or more separation units to separate the at least one hydrocarbon from the production fluid; and
- a heat recovery apparatus configured to recover heat energy from at least one of the one or more separation units, the separated at least one hydrocarbon, or the separated production fluid.
7. The system of claim 1, wherein the one or more reservoirs comprise a brine aquifer and the at least one native fluid comprises a brine with methane dissolved in the brine.
8. The system of claim 1, wherein the reservoir comprises a partially-depleted oil or natural gas field and the at least one native fluid comprises at least one hydrocarbon.
9. The system of claim 1, wherein the non-water based working fluid is carbon dioxide.
10. The system of claim 1, wherein the specified period of time is a temporary period of time, a semi-permanent period of time, a substantially permanent period of time, or a permanent period of time.
11. The system of claim 1, wherein the production fluid comprises from 0.01 wt % to 99 wt % of the non-water based working fluid.
12. A system comprising:
- one or more injection wells for accessing one or more underground reservoirs, the one or more reservoirs being at one or more first temperatures, each of the one or more injection wells having an injection well reservoir opening in fluid communication with at least one of the one or more reservoirs;
- one or more production wells each having a production well reservoir opening in fluid communication with at least one of the one or more reservoirs;
- a working-fluid supply system for providing a non-water based working fluid to the one or more injection wells at a second temperature,
- wherein exposure of the non-water based working fluid to the one or more first temperatures results in heat energy being exchanged between the non-water based working fluid and the one or more reservoirs to provide a production fluid at a third temperature, wherein at least a portion of the production fluid at the third temperature enters the production well reservoir opening and is produced from the reservoir via the one or more production wells to provide a produced fluid; and
- an energy recovery apparatus in fluid communication with the one or more production wells, the energy recovery apparatus including equipment that generates waste heat and at least one heat recovery apparatus configured to recover at least a portion of the waste heat from the equipment and uses the recovered portion of the waste heat to heat the produced fluid to a fourth temperature that is higher than the third temperature to provide a heated produced fluid.
13. The system of claim 12, wherein the equipment that generates waste heat comprise at least one of: a compressor for compressing at least a portion of the produced fluid or the working fluid; a pump for moving at least a portion of the produced fluid or the working fluid; an expansion device or generator for electricity generation; an enhanced oil recovery system; a co-located facility.
14. The system of claim 13, wherein the co-located facility comprises a fuel production facility or a power plant.
15. The system of claim 14, wherein the fuel production facility comprises an ethanol production facility or a biofuel production facility.
16. The system of claim 12, wherein the energy recovery apparatus further comprises at least one of: one or more electricity-generating devices; one or more heat exchangers; or a combination thereof to convert energy contained in the heated produced fluid to electricity, heat energy, or a combination thereof.
17. The system of claim 12, wherein the reservoir comprises a brine aquifer.
18. The system of claim 12, wherein the reservoir comprises a partially-depleted oil or natural gas field and the native fluid comprises at least one hydrocarbon.
19. The system of claim 12, wherein the non-water based working fluid is carbon dioxide.
20. The system of claim 12, wherein the production fluid comprises from 0.01 wt % to 99 wt % of the non-water based working fluid.
Type: Application
Filed: Dec 7, 2017
Publication Date: Apr 19, 2018
Inventor: Jimmy Bryan Randolph (Minneapolis, MN)
Application Number: 15/835,276
