Method for regenerating solvent and sequestering carbon dioxide

Abstract

Embodiments of the present disclosure relate to methods for subterranean regeneration of CO2-philic solvents and sequestration of carbon dioxide. The method may include the step of exposing a CO2-philic solvent to a CO2-containing gas to allow the CO2-philic solvent to adsorb a portion of carbon dioxide in the CO2-containing gas, thereby producing a CO2-containing solution. The CO2-containing solution may be supplied to one or more porous rock fractures through one or more injection conduits. The CO2-containing solution may be heated by heat provided by the one or more rock fractures to release at least a portion of the adsorbed carbon dioxide into the one or more rock fractures to regenerate the CO2-philic solvent. At least a portion of the released carbon dioxide may be sequestered in the porous rock fracture.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of U.S. application serial number: 17 / 814,142, filed on July 21, 2022, which is incorporated herein by reference in its entirety. Background Art Technical Field

[0003]

[0013] Embodiments described herein relate generally to carbon dioxide sequestration, and more particularly to methods for subsurface regeneration of solvents and sequestration of carbon dioxide. Technical Background

[0005] The observed warming of the Earth's climate, which is primarily attributed to carbon dioxide emissions from human activities, is one of the biggest problems facing the Earth. It is predicted that the growing energy demand will continue to maintain a high demand for fossil fuel-based energy production. Therefore, methods are needed throughout the world to reduce emissions from fossil fuel-based energy production. Capturing and sequestering carbon dioxide gas released by fossil fuel-based energy production has been proposed as a possible solution. However, conventional carbon capture technology is energy intensive because the CO2-philic solvent used to capture the carbon dioxide gas needs to be heated to release the carbon dioxide, and this heating can require a large amount of energy. In addition, in order to store the captured carbon dioxide, the carbon dioxide gas must often be compressed, which is also an energy intensive method. The energy used to power conventional carbon capture technology is usually provided by burning additional fossil fuels, which increases the cost of energy production and produces more carbon dioxide. Therefore, a carbon capture method that does not require the burning of additional fossil fuels and reduces energy requirements is needed. Summary of the invention

[0006] Embodiments of the present disclosure meet this need for carbon capture technology, which may not require the burning of additional fossil fuels and may reduce energy requirements. It has been found that by releasing carbon dioxide directly from a CO2-loving solvent into one or more porous rock fractures for sequestration, and using the heat present in the underground rock fractures to regenerate the CO2-loving solvent, the amount of additional fossil fuels burned to power carbon capture and sequestration can be reduced. For example, by eliminating the need to compress carbon dioxide gas and regenerating the CO2-loving solvent by using geothermal energy instead of using energy generated by burning fossil fuels.

[0007] According to one or more embodiments of the present disclosure, a method for underground regeneration of a CO2-friendly solvent and sequestration of carbon dioxide is provided. The method may include exposing a CO2-friendly solvent to a CO2-containing gas in an adsorber to allow the CO2-friendly solvent to adsorb at least a portion of the carbon dioxide in the CO2-containing gas, thereby producing a CO2-containing solution. The method may further include supplying a CO2-containing solution to one or more porous rock fractures through one or more injection pipes that are fluidly connected to one or more porous rock fractures, and heating the CO2-containing solution by heat provided by one or more rock fractures, so as to release at least a portion of the adsorbed carbon dioxide into one or more rock fractures, thereby regenerating the CO2-friendly solvent. The method may further include adsorbing or chemically reacting the released carbon dioxide in a porous rock near the fracture, and sealing at least a portion of the released carbon dioxide in one or more rock fractures. The method may further include transporting a regenerated CO2-friendly solvent from one or more porous rock fractures through one or more production pipelines.

[0008] It should be understood that both the foregoing general description and the following detailed description describe various embodiments and are intended to provide an overview or framework for understanding the nature and characteristics of the subject matter claimed. Additional features and advantages of the embodiments will be set forth in the detailed description, and in part, will be apparent to those of ordinary skill in the art from the description, including the drawings and claims, or recognized by practicing the described embodiments. The accompanying drawings are included to provide a further understanding of the embodiments, and together with the detailed description, are used to explain the principles and operation of the subject matter claimed. However, the embodiments depicted in the drawings are illustrative and exemplary in nature and are not intended to limit the subject matter claimed.

[0009] BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The following detailed description may be better understood when read in conjunction with the following drawings, in which:

[0011] Figure 1 is a schematic diagram of a carbon sequestration system suitable for use with embodiments of the present disclosure.

[0012] Figure 2 is a schematic diagram of an alternative carbon sequestration system suitable for use with embodiments of the present disclosure.

[0013] Figure 3 is a graph showing the relative permeability of carbon dioxide gas and solvent as a function of gas saturation. DETAILED DESCRIPTION

[0014] The present disclosure generally relates to a method for underground regeneration of a CO2-friendly solvent and sequestration of carbon dioxide. The method may generally include exposing a CO2-friendly solvent to a CO2-containing gas in an adsorber to allow the CO2-friendly solvent to adsorb at least a portion of the carbon dioxide in the CO2-containing gas, thereby producing a CO2-containing solution. The method may further include supplying a CO2-containing solution to one or more porous rock fractures through one or more injection conduits that are fluidly connected to one or more porous rock fractures. The method may also include heating a CO2-containing solution by heat provided by one or more rock fractures so as to release at least a portion of the adsorbed carbon dioxide into one or more rock fractures, thereby regenerating the CO2-friendly solvent. The method may also include sealing at least a portion of the released carbon dioxide in one or more porous rock fractures by adsorbing the released carbon dioxide or chemically reacting the released carbon dioxide with porous rock fractures and porous rocks near the fractures, and transporting the regenerated CO2-friendly solvent from one or more porous rock fractures through one or more production pipelines.

[0015] As used throughout this disclosure, the term "CO2-philic solvent" refers to a solvent that can reversibly adsorb CO2 and then release the adsorbed CO2 when heated. The CO2-philic solvent can be any suitable solvent that reversibly adsorbs CO2. For example, the CO2-philic solvent can be an aqueous solution of one or more of monoethanolamine, diethanolamine, triethanolamine, 2-amino-2-methyl-1-propanol, piperazine, diglycolamine, glycinates, sarcosinates, lithium carbonate, sodium carbonate, or potassium carbonate.

[0016] As used throughout this disclosure, the term "gas containing CO2" refers to any gas or gas mixture containing carbon dioxide. The gas containing CO2 may include other gas components. For example, the gas containing CO2 may include CO2 and one or more of gaseous hydrocarbons, H2S, SO2, N2, Ar, water vapor, and O2.

[0017] As used throughout this disclosure, the term "flue gas" refers to any gaseous emission from a suitable emission source. For example, flue gas may include emissions from vehicles, fossil fuel power plants, cement plants, or any other suitable industrial or non-industrial emission source.

[0018] As used throughout this disclosure, the term "porous rock formation" refers to any rock formation with the ability to store CO2 in physical form or react with carbon dioxide to form stable carbonates. Porous rock formations can include mafic rocks. The term "mafic" generally describes silicate minerals or igneous rocks rich in magnesium and iron. Mafic minerals can be darker in color, and rock-forming mafic minerals include olivine, pyroxene, amphibole and biotite. Examples of mafic rocks include basalt, diabase and gabbro. Examples of ultramafic rocks include dunite, peridotite and pyroxenite. Chemically, mafic and ultramafic rocks can be rich in iron, magnesium and calcium. Porous rock formations containing mafic rocks can react components of the injection stream with components of the mafic rock in situ to precipitate and store the components of the injection stream in the formation. In some embodiments, the mafic rock comprises basaltic rock. In some embodiments, CO2 may be stored in the formation as an adsorbate in porous rock, or dissolved in fluids contained in the formation, such as water (brine) or hydrocarbons.

[0019] As used throughout this disclosure, the term "porous rock fracture" refers to any fracture within a porous rock formation that is large enough to receive a CO2-philic solvent. Porous rock fractures may be naturally formed, or they may be artificially created. For example, by methods such as hydraulic fracturing.

[0020] As used throughout this disclosure, the term "wellbore" refers to a wellbore in a formation that is capable of receiving injection of water, other aqueous solutions, or other liquids or gases. A wellbore may be vertical, horizontal, or positioned at any angle within a formation. A wellbore forms a path that allows fluids and equipment to pass between the surface and the formation.

[0021] As used throughout this disclosure, the term "injection conduit" refers to any suitable passage in fluid communication with one or more porous rock formations, wherein fluid can flow from the injection conduit into the one or more porous rock formations. The injection conduit may include a pipe, tubular, perforation, or any other structure that can transport a fluid into one or more porous rock formations.

[0022] As used throughout this disclosure, the term "production conduit" refers to any suitable passage in fluid communication with one or more porous rock formations, wherein fluid can flow from the one or more porous rock formations into the production conduit. The production conduit may include pipes, tubulars, perforations, or any other structure that can transport fluids into one or more porous rock formations.

[0023] Reference now Figure 1, schematically depicts an example system 100 that may be suitable for the methods described herein. The system 100 generally includes: an adsorber 102, an injection conduit 104 in fluid communication with the adsorber 102 and one or more porous rock fractures 106, and a production conduit 108 in fluid communication with the one or more porous rock fractures 106. In one or more embodiments, the CO2-philic solvent can be contacted with a CO2-containing gas in a countercurrent or cocurrent manner within the adsorber 102 to form a CO2-containing solution. As used throughout this disclosure, the term "cocurrent" refers to a flow pattern in which the gas flows in a direction similar to the flow of the solvent. As used throughout this disclosure, the term "countercurrent" refers to a flow pattern in which the gas flows in a direction different from the flow of the solvent. The CO2-containing solution can be moved from the adsorber 102 to the one or more porous rock fractures 106 via the injection conduit 104. The CO2-containing solution can be heated by contacting a porous rock adjacent to the one or more porous rock fractures 106 to release the CO2 gas and produce a regenerated CO2-philic solvent. In one or more embodiments, the released CO2 gas can be adsorbed by the porous rock formation 106 or react with the porous rock formation 106 to form stable carbonates. The regenerated CO2-philic solvent can leave one or more porous rock fractures 106 through a production pipeline. In one or more embodiments, the production pipeline 108 can be in fluid communication with the adsorber 102, and the CO2-philic solvent can be returned to the adsorber 102 from the porous rock formation 106 through the production pipeline 108, so that the CO2-philic solvent can circulate between one or more porous rock fractures 106 and the adsorber 102. In one or more embodiments, a purifier (not shown) can be added upstream of the adsorber to purify sulfur oxides or nitrogen oxides of the CO2-containing gas. In one or more embodiments, the injection pipeline 104 can be an injection well. In one or more embodiments, the production pipeline 108 can be a production well.

[0024] Still reference Figure 1 In one or more embodiments, the solution containing CO2 may experience a pressure loss when entering the fracture because the pressure of the surrounding fracture 106 may be lower than the pressure within the injection pipe 104. At higher temperatures and / or lower pressures, the carbon dioxide dissolved in the solution containing CO2 may become less soluble and may come out of the solution as gaseous carbon dioxide. The released carbon dioxide gas may form a gas zone in the upper portion of the fracture 106. Without being bound by theory, it is believed that allowing carbon dioxide to come out of the solution as gaseous carbon dioxide in one or more porous rock fractures may increase the rate at which carbon dioxide is sequestered in one or more porous rock fractures.

[0025] In one or more embodiments, the porous rock including one or more porous rock fractures can be permeable so that carbon dioxide gas or liquid solvent can enter the pores of the porous rock. In some embodiments, the relative permeabilities of carbon dioxide gas and liquid solvent can be such that the permeability of carbon dioxide gas is much higher than the permeability of solvent. Without being bound by theory, it is believed that when the permeability of carbon dioxide is significantly greater than the permeability of solvent, less solvent enters the pores of the porous rock than if the permeability of carbon dioxide is not as high relative to the permeability of solvent. The solvent entering the pores of the porous rock can prevent the sequestration of carbon dioxide because the carbon dioxide gas may not be able to enter the rock pores filled with solvent. In addition, the solvent entering the pores may be trapped, resulting in solvent loss, and the solvent may need to be replaced, thereby increasing the costs associated with carbon dioxide sequestration.

[0026] In embodiments where the porous rock fractures are sufficiently permeable to allow the liquid solvent to enter the pores of the porous rock, it may be necessary to change the permeability of the porous rock to reduce the amount of solvent allowed to penetrate the rock. This can be achieved by increasing the gas saturation of the fractures. Injecting a gas prior to injecting the CO2-containing solvent can increase the gas saturation of the fractures. The injected gas can be CO2, nitrogen, air, or any other suitable gas. Figure 3 As shown, as the gas saturation increases, the relative permeability of carbon dioxide gas increases accordingly, while the relative permeability of solvent decreases accordingly. Without being bound by theory, it is believed that by increasing the gas saturation of one or more fractures, less solvent can be allowed to penetrate into the porous rock in one or more porous rock fractures, which can reduce the amount of solvent trapped in the pores of the porous rock and increase the rate at which carbon dioxide gas is sequestered as more gas is allowed to enter the pores of the porous rock.

[0027] As described herein, in one or more embodiments, the released carbon dioxide can react with porous rock fractures to form stable carbonates. For example, the released carbon dioxide can react with calcium oxide or magnesium oxide in porous rock fractures to form calcium carbonate or magnesium carbonate. Without being bound by theory, it is believed that the formation of stable carbonates by the reaction between carbon dioxide and porous rock in one or more porous rock fractures can allow carbon dioxide gas to be sealed in one or more porous rock fractures, while reducing the possibility of the sealed carbon dioxide being released back into the atmosphere compared to other carbon sequestration methods (e.g., methods that do not form stable carbonates).

[0028] In one or more embodiments, the one or more porous rock fractures may be natural rock fractures. As used in the present disclosure, the term "natural rock fracture" refers to a rock fracture that already exists within a rock and is not formed by human action. In one or more embodiments, the one or more porous rock fractures may be hydraulic fractures or engineered fractures. As used in the present disclosure, the term "hydraulic fracture or engineered fracture" refers to a rock fracture formed by artificial means (e.g., by hydraulic fracturing).

[0029] In one or more embodiments, the CO2-containing gas can contain 0.04 wt% to 70 wt% carbon dioxide. For example, the CO2-containing gas can contain the following amounts of carbon dioxide: 0.04 wt% to 60 wt%, 0.04 wt% to 50 wt%, 0.04 wt% to 40 wt%, 0.04 volume % to 30 volume%, 0.04 volume % to 20 volume%, 0.04 volume % to 10 volume%, 0.04 volume % to 1.0 volume%, 0.04 volume % to 0.5 volume%, 0.5 volume % to 60 volume%, 0.5 volume % to 50 volume%, 0.5 volume % to 40 volume%, 0.5 volume % to 30 volume%, 0.5 volume % to 20 volume%, 0.5 volume % to 10 volume%, 0.5 volume % to 1.0 volume%, 1.0 volume % to 60 volume%, 1.0 volume % to 50% by volume, 1.0% to 40% by volume, 1.0% to 30% by volume, 1.0% to 20% by volume, 1.0% to 10% by volume, 10% to 60% by volume, 10% to 50% by volume, 10% to 40% by volume, 10% to 30% by volume, 10% to 20% by volume, 20% to 60% by volume, 20% to 50% by volume, 20% to 40% by volume, 20% to 30% by volume, 30% to 60% by volume, 30% to 50% by volume, 30% to 40% by volume, 40% to 60% by volume, 40% to 50% by volume, 50% to 60% by volume, or any combination of these scopes. In one or more embodiments, the gas containing CO can be flue gas. For example, the gas containing CO can be the flue gas produced by a fossil fuel power plant.

[0030] In one or more embodiments, the method may further include purging the flue gas of sulfur oxides or nitrogen oxides upstream of the adsorber. In some embodiments, the flue gas may be purified to reduce the amount of sulfur oxides and nitrogen oxides to an amount of 1 ppm to 10 ppm. For example, the flue gas may be purified to reduce the amount of sulfur oxides and nitrogen oxides to the following amounts: 1 ppm to 9 ppm, 1 ppm to 8 ppm, 1 ppm to 7 ppm, 1 ppm to 6 ppm, 1 ppm to 5 ppm, 1 ppm to 4 ppm, 1 ppm to 3 ppm, 1 ppm to 2 ppm, 2 ppm to 10 ppm, 2 ppm to 9 ppm, 2 ppm to 8 ppm, 2 ppm to 7 ppm, 2 ppm to 6 ppm, 2 ppm to 5 ppm, 2 ppm to 4 ppm, 2 ppm to 3 ppm, 3 ppm to 10 ppm, 3 ppm to 9 ppm, 3 ppm to 8 ppm, 3 ppm to 7 ppm, 3 ppm to 6 ppm, 3 ...3 ppm, The CO2 absorption range of the present invention is 100-100ppm, ...

[0031] In one or more embodiments, the CO2-philic solvent can be an aqueous solution containing 5.0 wt% to 75 wt% of one or more CO2-philic species. For example, the CO2-philic solvent can contain the following amounts of one or more CO2-philic species: 5.0 wt% to 70 wt%, 5.0 wt% to 60 wt%, 5.0 wt% to 50 wt%, 5.0 wt% to 40 wt%, 5.0 wt% to 30 wt%, 5.0 wt% to 20 wt%, 5.0 wt% to 10 wt%, 10 wt% to 75 wt%, 10 wt% to 70 wt%, 10 wt% to 60 wt%, 10 wt% to 50 wt%, 10 wt% to 40 wt%, 10 wt% to 30 wt%, 10 wt% to 20 wt%, 20 wt% to 75 wt%, 20 wt% to 7 ... % to 60 wt %, 20 wt % to 50 wt %, 20 wt % to 40 wt %, 20 wt % to 30 wt %, 30 wt % to 75 wt %, 30 wt % to 70 wt %, 30 wt % to 60 wt %, 30 wt % to 50 wt %, 30 wt % to 40 wt %, 40 wt % to 75 wt %, 40 wt % to 70 wt %, 40 wt % to 60 wt %, 40 wt % to 50 wt %, 50 wt % to 75 wt %, 50 wt % to 70 wt %, 50 wt % to 60 wt %, 60 wt % to 75 wt %, 60 wt % to 70 wt %, 70 wt % to 75 wt %, or any combination of these ranges.

[0032] In one or more embodiments, the CO2-philic substance may include one or more amines, alkali carbonates, or amino acids. In some embodiments, the CO2-philic substance may include amines but not alkali carbonates or amino acids; the CO2-philic substance may only include alkali carbonates but not amines or amino acids; or the CO2-philic substance may only include amino acids but not amines or alkali carbonates. In one or more embodiments, the one or more amines may be one or more primary amines, secondary amines, or tertiary amines. In some embodiments, the one or more CO2-philic substances may include one or more of monoethanolamine, diethanolamine, triethanolamine, 2-amino-2-methyl-1-propanol, piperazine, diglycolamine, glycinates, sarcosinates, lithium carbonate, sodium carbonate, or potassium carbonate.

[0033] In one or more embodiments, the CO2-philic solvent can include 0.0 wt% to 15 wt% of a co-solvent. For example, the CO2-philic solvent can include the following amounts of a co-solvent: 0.0 wt% to 12.5 wt%, 0.0 wt% to 10 wt%, 0.0 wt% to 7.5 wt%, 0.0 wt% to 5 wt%, 0.0 wt% to 2.5 wt%, 0.0 wt% to 1.0 wt%, 0.0 wt% to 0.5 wt%, 0.5 wt% to 15 wt%, 0.5 wt% to 12.5 wt%, 0.5 wt% to 10 wt%, 0.5 wt% to 7.5 wt%, 0.5 wt% to 5 wt%, 0.5 wt% to 2.5 wt%, 0.5 wt% to 1.0 wt%, 1.0 wt% to 15 wt%, 1.0 wt% to 12.5 wt%, 1.0 wt% to 10 wt%, % to 15 wt %, 5.0 wt % to 12.5 wt %, 5.0 wt % to 10 wt %, 5.0 wt % to 7.5 wt %, 7.5 wt % to 15 wt %, 7.5 wt % to 12.5 wt %, 7.5 wt % to 10 wt %, 10 wt % to 15 wt %, 10 wt % to 12.5 wt %, 12.5 wt % to 15 wt %, or any combination of these ranges. In some embodiments, the cosolvent can be one or more fatty alcohols. For example, the co-solvent can be one or more of methanol, ethanol, propanol, isopropanol, butanol, isobutanol, ethylene glycol, trimethylene glycol, 1,5-pentanediol, isobutylene glycol, or glycerol.

[0034] As described herein, in one or more embodiments, the CO2-containing solution can be heated by heat from one or more rock fractures to release at least a portion of the adsorbed carbon dioxide, thereby regenerating the CO2-philic solvent. In some embodiments, the one or more rock fractures can heat the CO2-containing solution to a temperature of 90°C to 200°C. For example, the one or more rock fractures can heat the CO2-containing solution to the following temperatures: 90°C to 190°C, 90°C to 180°C, 90°C to 170°C, 90°C to 160°C, 90°C to 150°C, 90°C to 140°C, 90°C to 130°C, 90°C to 120°C, 90°C to 110°C, 90°C to 100°C, 100°C to 200°C, 100°C to 190°C, 100°C to 180°C, 100°C to 170°C, 100°C to 160°C, 100℃ to 150℃, 100℃ to 140℃, 100℃ to 130℃, 100℃ to 120℃, 100℃ to 110℃, 110℃ to 200℃, 110℃ to 190℃, 110℃ to 180℃, 110℃ to 170℃, 110℃ to 160℃, 110℃ to 150℃, 110℃ to 140℃, 110℃ to 130℃, 110℃ to 120℃, 120℃ to 200℃, 120℃ to 190℃, 120℃ to 180℃, 120℃ to 170℃, 120℃ to 160℃, 120℃ to 150℃, 120℃ to 140℃, 120℃ to 130℃, 130℃ to 200℃, 130℃ to 190℃, 130℃ to 180℃, 130℃ to 170℃, 130℃ to 160℃, 130℃ to 150℃, 130℃ to 140℃, 140℃ to 200℃, 140℃ to 190℃, 140℃ to 180℃, 140℃ to 170℃, 140℃ to 160℃, 140°C to 150°C, 150°C to 200°C, 150°C to 190°C, 150°C to 180°C, 150°C to 170°C, 150°C to 160°C, 160°C to 200°C, 160°C to 190°C, 160°C to 180°C, 160°C to 170, 170°C to 200°C, 170°C to 190°C, 170°C to 180°C, 180°C to 200°C, 180°C to 190°C, 190°C to 200°C, or any combination of these ranges.

[0035] In one or more embodiments, the one or more porous rock fractures can have an internal pressure of 100 psi to 35,000 psi. For example, the one or more porous rock fractures can have an internal pressure of 100 psi to 30,000 psi, 100 psi to 25,000 psi, 100 psi to 20,000 psi, 100 psi to 15,000 psi, 100 psi to 10,000 psi, 100 psi to 5,000 psi, 100 psi to 2,500 psi, 100 psi to 1,000 psi, 100 psi to 500 psi, 500 psi to 35,000 psi, 500 psi to 30,000 psi, 500 psi to 25,000 psi, 500 psi to 20,000 psi, 500 psi to 15000psi, 500psi to 10000psi, 500psi to 5000psi, 500psi to 2500psi, 500psi to 1000psi, 1000psi to 35000psi, 1000psi to 30000psi, 1000psi to 25000psi, 1000psi to 20000psi, 1000psi to 15000psi, 1000psi to 10000psi, 1000psi to 5000psi, 1000psi to 2500psi, 2500psi to 35000psi, 2500psi to 30000psi si, 2500psi to 25000psi, 2500psi to 20000psi, 2500psi to 15000psi, 2500psi to 10000psi, 2500psi to 5000psi, 5000psi to 35000psi, 5000psi to 30000psi, 5000psi to 25000psi, 5000psi to 20000psi, 5000psi to 15000psi, 5000psi to 10000psi, 10000psi to 35000psi, 10000psi to 30000psi, 10000psi to 2 5000 psi, 10000 psi to 20000 psi, 10000 psi to 15000 psi, 15000 psi to 35000 psi, 15000 psi to 30000 psi, 15000 psi to 25000 psi, 15000 psi to 20000 psi, 20000 psi to 35000 psi, 20000 psi to 30000 psi, 20000 psi to 25000 psi, 25000 psi to 35000 psi, 25000 psi to 30000 psi, 30000 psi to 35000 psi, or any combination of these ranges.

[0036] In one or more embodiments, the method may further include selecting a CO2-philic substance in the CO2-philic solvent based on the conditions of the one or more porous rock fractures, wherein the CO2-philic substance is selected using one or more of pressure, temperature, or porous rock fracture type. For example, when the temperature of the one or more porous rock fractures is 90° C. to 110° C., the CO2-philic substance may include aqueous amino acids, when the temperature of the one or more rock fractures is 115° C. to 150° C., the CO2-philic substance may include aqueous amines, when the temperature of the one or more rock fractures is 130° C. to 50° C., the CO2-philic substance may include alkali carbonates, and when the temperature of the one or more rock fractures is greater than 150° C., the CO2-philic substance may be an inorganic salt such as potassium hydroxide, potassium carbonate, or sodium hydroxide.

[0037] In one or more embodiments, the injection pipeline and the production pipeline can form a single well. The production pipeline can be a production pipe, and the injection pipeline can be an injection pipe arranged annularly around the production pipe. In one or more embodiments, the injection pipe can include perforations that allow the solution containing CO2 to leave the injection pipe and enter one or more porous rock fractures. In some embodiments, the size of the perforations can be changed to control the pressure change experienced by the solution containing CO2 when leaving the injection pipe and entering one or more porous rock fractures.

[0038] In one or more embodiments, wherein the injection conduit and the production conduit form a single well, and wherein the single well can be formed by drilling into a rock formation to create a wellbore, the method can further include fracturing the rock formation to create one or more rock fractures and inserting the single well into the wellbore.

[0039] Reference now Figure 2 , schematically depicts an example system 200 that may be applicable to the methods described herein. The example system 200 may be most suitable for use in embodiments of the method in which the injection conduit and the production conduit form a single well. The system 200 and Figure 1 The system 100 of FIG. 1 is different in that the injection conduit 104 may be an injection pipe 204 and the production conduit 108 may be a production pipe 206, both of which are placed together in a single well 202. The injection pipe 204 may be annularly disposed around the production pipe 206. In some embodiments, the injection pipe may be perforated with small holes to allow the solution containing CO2 to exit the injection pipe and enter one or more porous rock fractures 106.

[0040] The embodiments herein can be used in a wide range of formation conditions. Without being bound by theory, it is believed that when one or more porous rock fractures have high permeability, it may be beneficial to reduce the residence time of the solvent within the one or more rock fractures to limit potential solvent losses. It is believed that embodiments of the present disclosure in which the production conduit and the injection conduit form a single well can have a lower solvent residence time compared to embodiments of the present disclosure in which the production conduit and the injection conduit are separate wells.

[0041] Without being bound by theory, it is believed that when one or more porous rock fractures have low permeability, increasing the residence time of the solvent within the one or more fractures may be beneficial. It is believed that by increasing the residence time of the solvent, gaseous carbon dioxide may have a better opportunity to be released from the solvent and adsorbed into the pores of the rock fractures as the solvent flows through the one or more porous rock fractures. It is also believed that embodiments of the wells of the present disclosure in which the production tubing and the injection tubing are separate may have a longer residence time of the solvent within the one or more porous rock fractures because the solvent may have to travel farther from the one or more injection tubing through the fractures before being able to exit through the one or more production tubings.

[0042] In a first aspect of the present disclosure, a method for underground regeneration of a CO2-philic solvent and sequestration of carbon dioxide may include exposing the CO2-philic solvent to a CO2-containing gas in an adsorber to allow the CO2-philic solvent to adsorb at least a portion of the carbon dioxide in the CO2-containing gas, thereby producing a CO2-containing solution. The method may also include supplying the CO2-containing solution to the one or more porous rock fractures through one or more injection pipelines that are fluidly connected to the one or more porous rock fractures. The method may also include heating the CO2-containing solution by heat provided by the one or more rock fractures to release at least a portion of the adsorbed carbon dioxide into the one or more rock fractures, thereby regenerating the CO2-philic solvent. The method may also include sequestering at least a portion of the released carbon dioxide in the one or more porous rock fractures by adsorbing carbon dioxide in the porous rock fractures or by reacting the released carbon dioxide with the porous rock fractures to form stable carbonates. The method may finally include transporting the regenerated CO2-philic solvent from the one or more porous rock fractures through one or more production pipelines.

[0043] A second aspect of the present disclosure may include the first aspect, wherein the method further comprises returning the regenerated CO2-philic solvent to the adsorber such that the CO2-philic solvent circulates between the one or more rock fractures and the adsorber.

[0044] A third aspect of the present disclosure may include any one of the above aspects, wherein the injection pipeline is an injection well, and the production pipeline is a production well.

[0045] A fourth aspect of the present disclosure may include the first aspect or the second aspect, wherein the injection pipeline and the production pipeline form a single well, the production pipeline is a production pipe, and the injection pipeline is an injection pipe annularly arranged around the production pipe.

[0046] The fifth aspect of the present disclosure may include the fourth aspect, wherein the single well is formed by drilling into a rock formation to produce a wellbore, and the method further comprises fracturing the rock formation to produce one or more rock fractures, and inserting the single well into the wellbore, wherein the single well comprises the production pipe and the injection pipe.

[0047] A sixth aspect of the present disclosure may include any one of the above aspects, wherein the CO2-containing gas contains 0.04 wt% to 70 wt% carbon dioxide.

[0048] A seventh aspect of the present disclosure may include any one of the above aspects, wherein the CO2-containing gas is flue gas.

[0049] An eighth aspect of the present disclosure may include the seventh aspect, wherein the method further comprises purifying the flue gas of one or more sulfur oxides or nitrogen oxides upstream of the adsorber.

[0050] A ninth aspect of the present disclosure may include any one of the above aspects, wherein the CO2-philic solvent is an aqueous solution comprising 5 wt % to 75 wt % of one or more CO2-philic substances and 0 wt % to 15 wt % of one or more co-solvents.

[0051] A tenth aspect of the present disclosure may include the ninth aspect, wherein the one or more co-solvents include one or more fatty alcohols.

[0052] An eleventh aspect of the present disclosure may include the ninth aspect, wherein the CO2-philic substance comprises one or more of amines, alkali metal carbonates or amino acids.

[0053] The twelfth aspect of the present disclosure may include the ninth aspect, wherein the CO2-philic substance comprises one or more of monoethanolamine, diethanolamine, triethanolamine, 2-amino-2-methyl-1-propanol, piperazine, diglycolamine, glycinates, sarcosinates, lithium carbonate, sodium carbonate or potassium carbonate.

[0054] A thirteenth aspect of the present disclosure may include any of the above aspects, wherein the one or more porous rock fractures are natural fractures.

[0055] A fourteenth aspect of the present disclosure may include any of the above aspects, wherein the one or more porous rock fractures are engineered fractures or hydraulic fractures.

[0056] A fifteenth aspect of the present disclosure may include any one of the above aspects, wherein the method further comprises selecting the CO2-philic solvent based on the conditions of the one or more porous rock fractures, wherein the CO2-philic substance is selected using one or more of pressure, temperature or porous rock fracture type.

Claims

1. A method for underground regeneration of a CO2-philic solvent and sequestration of carbon dioxide, the method comprising: exposing the CO2-philic solvent to a CO2-containing gas in an adsorber to allow the CO2-philic solvent to adsorb at least a portion of the carbon dioxide in the CO2-containing gas, thereby producing a CO2-containing solution; supplying the CO2-containing solution to the one or more porous rock fractures through one or more injection conduits in fluid communication with the one or more porous rock fractures; heating the CO2-containing solution by heat provided by one or more rock fractures to release at least a portion of the adsorbed carbon dioxide into the one or more rock fractures, thereby regenerating the CO2-philic solvent; sequestering at least a portion of the released carbon dioxide in the one or more porous rock fractures by adsorbing the carbon dioxide within the porous rock fractures or by reacting the released carbon dioxide with the porous rock fractures to form stable carbonates; and The regenerated CO2-philic solvent is transported from the one or more porous rock fractures via one or more production pipelines.

2. The method of claim 1, further comprising returning the regenerated CO2-philic solvent to the adsorber such that the CO2-philic solvent circulates between the one or more rock fractures and the adsorber.

3. The method according to any one of claims 1 or 2, wherein: The injection conduit is an injection well and the production conduit is a production well.

4. The method according to any one of claims 1 or 2, wherein: The injection pipeline and the production pipeline form a single well, the production pipeline is a production pipe, and the injection pipeline is an injection pipe annularly arranged around the production pipe.

5. The method according to claim 4, wherein: The single well is formed by drilling into a rock formation to create a wellbore, and the method further comprises: fracturing the rock formation to create one or more rock fractures; and The single well is inserted into the wellbore, wherein the single well comprises the production tubing and the injection tubing.

6. The method according to any one of claims 1 to 5, wherein: The CO2-containing gas contains 0.04 wt% to 70 wt% carbon dioxide.

7. The method according to any one of claims 1 to 6, wherein: The CO2-containing gas is flue gas.

8. The method according to claim 7, further comprising purifying the flue gas of sulfur oxides or nitrogen oxides upstream of the adsorber.

9. The method according to any one of claims 1 to 8, wherein: The CO2-philic solvent is an aqueous solution comprising: 5 to 75 wt % of one or more CO2-philic substances; and 0% to 15% by weight of one or more co-solvents.

10. The method according to claim 9, wherein: The one or more co-solvents include one or more fatty alcohols.

11. The method according to any one of claims 9 or 10, wherein: The CO2-philic substance includes one or more of amines, alkali metal carbonates or amino acids.

12. The method according to any one of claims 9 to 11, wherein the CO2-philic substance comprises one or more of monoethanolamine, diethanolamine, triethanolamine, 2-amino-2-methyl-1-propanol, piperazine, diglycolamine, glycinates, sarcosinates, lithium carbonate, sodium carbonate or potassium carbonate.

13. The method according to any one of claims 1 to 12, wherein: The one or more porous rock fractures are natural fractures.

14. The method according to any one of claims 1 to 12, wherein: The one or more porous rock fractures are engineered fractures or hydraulic fractures.

15. The method of any one of claims 1 to 14, further comprising selecting the CO2-philic solvent based on the conditions of the one or more porous rock fractures, wherein: The CO2-affinity species are selected using one or more of pressure, temperature, or porous rock fracture type.

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