Quenching and / or sequestering process fluids within subterranean carbon-containing formations, and related systems and methods

Abstract

Disclosed herein are methods and systems for quenching a subterranean carbon-containing formation with carbon and / or sequestering carbon within a subterranean carbon-containing formation. In some embodiments, a representative coal gasification system may include (i) an injection conduit extending from a surface to a subterranean coal gasification (UCG) reaction zone of a coal seam, (ii) a production conduit extending from a first subterranean region toward the surface, and (iii) an injection well fluidly connected to a source of process fluid and extending toward a second subterranean region. The second subterranean region is laterally spaced from the first subterranean region by an adjacent formation having a higher hydraulic resistance than the first hydraulic resistance and the second hydraulic resistance.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of priority to U.S. Provisional Patent Application No. 63 / 376,434, filed on September 20, 2022, and is related to U.S. Patent Application No. 17 / 200,334, filed on March 12, 2021 (now U.S. Patent No. 11,125,069), the disclosure of which is incorporated herein by reference in its entirety. Technical Field

[0003] The present disclosure relates to quenching a subterranean carbonaceous formation with a process fluid and / or sequestering a process fluid within a subterranean carbonaceous formation. In some embodiments, the process fluid comprises carbon dioxide. Background Art

[0004] Underground coal gasification (UCG) is an industrial process in which coal or another carbonaceous mineral is used to produce product gases at underground carbonaceous formations. Typically, UCG involves supplying an oxidant to an underground carbonaceous formation and, if necessary, water and / or steam to ignite the coal and maintain the gasification process. The oxidant and possible other reagents are typically delivered to the underground carbonaceous formation via an injection well drilled from the ground. The gasification process produces product gases, which can then be brought to the surface using production wells drilled from the ground. The main product gases are hydrogen, carbon monoxide, methane, and carbon dioxide. Alternatively, the vertical shafts and associated workings of mining can be used to inject oxidants and / or produce product gases. The resulting extracted product gases can be used commercially in a variety of ways, such as as a combustion fuel for power generation or as a chemical feedstock in the production of fuels, fertilizers, or other chemical products. BRIEF DESCRIPTION OF THE DRAWINGS

[0005] Embodiments of the present disclosure will be described with reference to the accompanying drawings. However, various embodiments of the present disclosure are not limited to the arrangements shown in the accompanying drawings.

[0006] Figure 1 is a schematic cross-sectional side view of an underground coal gasification system configured in accordance with the prior art.

[0007] Figure 2 is a schematic cross-sectional isometric view of a system for using a subterranean carbonaceous formation in accordance with an embodiment of the present technology.

[0008] Figure 3 is a schematic block diagram of a system for underground coal gasification and carbon sequestration according to an embodiment of the present technology.

[0009] Figure 4 is a schematic block diagram of another system for underground coal gasification and carbon sequestration in accordance with an embodiment of the present technology.

[0010] Figure 5 is a schematic isometric view of a system for sequestering process fluids according to an embodiment of the present technology.

[0011] Figure 6 is a schematic block diagram of another system for underground coal gasification and carbon sequestration in accordance with an embodiment of the present technology.

[0012] Figure 7 is a schematic plan view of a subterranean carbonaceous formation including one or more depletion plates and active plates in accordance with an embodiment of the present technology.

[0013] Figure 8 is a schematic plan view of a subterranean carbonaceous formation including one or more depletion plates and active plates in accordance with an embodiment of the present technology.

[0014] Fig. 9 is a schematic plan view of an injection well extending through multiple zones of a subterranean carbonaceous formation in accordance with an embodiment of the present technology.

[0015] Fig. 10A and 10B is a schematic diagram of a plate formed by horizontal wells for underground coal gasification and / or carbon sequestration in accordance with an embodiment of the present technology.

[0016] Fig.11 is a schematic diagram of a subsurface carbonaceous formation including a process fluid injection point at a bottom of the carbonaceous formation according to an embodiment of the present technology.

[0017] Fig.12 is a schematic diagram of a subsurface carbonaceous formation including a process fluid injection point at a bottom of the carbonaceous formation according to an embodiment of the present technology.

[0018] Fig.13 is a schematic diagram of a subsurface carbonaceous formation including a low pressure zone and a process fluid injection point at the bottom of the carbonaceous formation according to an embodiment of the present technology.

[0019] Fig.14 is a schematic diagram of a subsurface carbonaceous formation at a vertical angle according to an embodiment of the present technology, which includes injecting a process fluid into a bottom of the carbonaceous formation.

[0020] Fig.15 is a schematic diagram of an underground carbonaceous formation according to an embodiment of the present technology, the underground carbonaceous formation including an underground coal gasification chamber, a process well, and induced fractures from the underground coal gasification chamber.

[0021] Fig.16 is a schematic diagram of a vertical pipeline extending through a subterranean carbonaceous formation in accordance with an embodiment of the present technology.

[0022] Fig.17 is a schematic diagram of a pipeline extending through a subterranean carbonaceous formation in accordance with an embodiment of the present technology.

[0023] Fig.18 is a matrix characterizing multiple categories of methods and systems for effectively sequestering process fluids in subterranean carbonaceous formations. DETAILED DESCRIPTION

[0024] As described above, underground coal gasification (UCG) is a process in which one or more oxidants are injected into a carbonaceous formation (e.g., a coal seam) to promote an in-situ gasification reaction. The gasification reaction produces a product gas, which can then be extracted and brought to the surface using one or more production wells extending from the carbonaceous formation to the surface. The product gas may contain hydrogen, carbon monoxide, methane, and / or carbon dioxide, and is sometimes referred to as "synthesis gas" or synthesis gas. The specific composition of the product gas can vary based on many factors, such as formation pressure, depth to the carbonaceous formation, oxidant balance, and gasification conditions.

[0025] Figure 1 A UCG system 5 is shown. Figure 1 As shown, the UCG system 5 includes an underground carbonaceous formation (UCF) 10 having a UCG reaction zone 70, an injection well 20 extending from the surface 50 to the UCG reaction zone 70, and a production well 45 extending from the UCG reaction zone 70 to the surface 50. As used herein, a UCF may include any underground formation containing elemental carbon as part of a solid or liquid material that is largely fixed and can form a matrix of a porous medium of the UCF or a material occupying porous spaces of the matrix. The UCF 10 and / or the UCG reaction zone 70 are located at a distance (e.g., 100 meters (m) to 1600 m) below the surface 50 and are the location where the in-situ gasification reaction occurs. The injection well 20 can be configured to receive an oxidant (e.g., oxygen, air, or a combination thereof) and deliver it to the UCG reaction zone 70, and the production well 45 can be configured to receive a product gas 55 (e.g., syngas) produced at the UCG reaction zone 70 and deliver the product gas 55 to the surface 50, where the product gas 55 can undergo further processing and can be used as desired, for example, to produce methanol or pure hydrogen. The product gas 55 can also be used to generate electricity, such as through a turbine. The end 25 of the injection well 20 can be located at the reaction zone 30 of the UCG reaction zone 70, and the end 40 of the production well 45 can be located at the production zone 32 of the UCG reaction zone 70. The distance between the end 25 of the injection well 20 and the end 40 of the production well 45 can be 15 to 300 m, and can vary according to the various characteristics of the particular UCG reaction zone 70.

[0026] The oxidant 15 may be supplied (e.g., pumped) from the surface 50 at a generally high pressure and / or ambient (or higher) temperature. In some embodiments, during the gasification reaction, the oxidant 15 may have a temperature of 700° C. to 1500° C., or any suitable value therebetween (e.g., 800° C., 900° C., 1000° C., 1200° C., 1400° C., etc.) at the UCG reaction zone 70. In some embodiments, water may also be supplied via the injection well, e.g., in combination with the oxidant 15, and may enable the gasification reaction to produce more product gas 55. In some embodiments, the UCF 10 includes sufficient water, e.g., because the UCF 10 is located below the groundwater table 35, and thus no additional water needs to be supplied via the injection well 20. In operation, the carbon of the UCF 10 is ignited and the gasification reaction is initiated, such that the injected oxidant 15 and / or water are able to promote the in-situ gasification reaction and produce product gas 55.

[0027] As previously described, product gas 55 may comprise a mixture of hydrogen, carbon monoxide, methane, and carbon dioxide. Product gas 55 is represented in simplified terms as hydrogen and carbon monoxide in reaction 1 below.

[0028] 3C(s) + H 2 O(g) + O 2 (g) → 3CO(g) + H 2 (g) (Reaction 1)

[0029] In practice, product gas 55 generated via the gasification reaction flows to production area 32 and then to surface 50 via production wells 45. The extracted product gas 55 may then be treated (e.g., purified) and / or further processed depending on the desired end use or commercial application.

[0030] During the UCG process, a variety of organic and inorganic condensable byproducts may be formed, which may serve as potential contaminants of groundwater in the surrounding UCF. Contaminants may include ammonia, phenol, inorganic contaminants, and / or hydrocarbons (e.g., C6 to C10 hydrocarbons), and may be trapped in the product gas 55. During the UCG process, the flow rate and pressure of the injected oxidant and the flow rate and pressure of the produced syngas are adjusted so that the operating pressure in the UCG reaction zone 70 is lower than the hydrostatic pressure in the surrounding formation of the UCF 10. In doing so, there is a fluid pressure gradient in the formation, which drives any formation fluid (including groundwater) into the UCG reaction zone 70 and prevents the gasification products from leaving and entering the formation. However, once the UCG reaction zone 70 becomes exhausted and the standard quality of syngas can no longer be consistently maintained, the injection and production process stops, the pressure gradient can no longer be controlled, and the contaminants may no longer be trapped in the product gas. At this point, the pressure in the UCG reaction zone 70 may equal or exceed the reservoir pressure, and as a result, any potential contaminants may escape into the formation. If, as is commonly practiced, the depleted plates are cooled by in situ natural phenomena, including dissipation of heat by thermal conductivity and cooling by natural inflow of groundwater, groundwater contamination of the underground environment may occur and may be very difficult and expensive to clean up.

[0031] II. Remediation of Depleted Underground Coal Gasification Pads and Associated Systems and Methods

[0032] Embodiments of the present technology are directed to solving the above problems by maintaining the pressure of the UCG reaction zone 70 below the hydrostatic pressure and / or cooling the UCG reaction zone 70 to the formation temperature to inhibit further chemical reactions from occurring in the UCG reaction zone 70. During and after the process of cooling the UCG reaction zone 70, contaminants within the UCG reaction zone 70 can be removed and transported to the surface for cleanup and disposal.

[0033] Figure 2 is a schematic cross-sectional isometric view of a system 200 for using underground carbonaceous formations and represents one embodiment for mitigating the above-mentioned problems regarding groundwater contamination. The system 200 includes Figure 1 , and further includes a re-regulation device or apparatus 220 ("device 220") fluidly connected to the production well 45 and the injection well 20, which is configured to receive a process fluid. The process fluid may include a carbonaceous fluid, a pure carbon dioxide fluid, a fluid with at least 90% carbon dioxide, flue gas, etc. Note that the system 200 may include additional pipes, valves, sensors, and / or controls (e.g., controllers) for regulating the flow of the process fluid through the system 200.

[0034] The apparatus 220 may include a filter (e.g., a membrane) configured to separate contaminants and organic compounds from the process fluid, and / or a compressor configured to increase the pressure of the input stream from the production well 45. In embodiments including a compressor, the apparatus 220 may include a separation unit between the production well 45 and the inlet of the compressor, which is configured to separate (e.g., separate) the syngas and process fluid traveling through the production well 45 from each other. The process fluid is pressurized, and / or may include various concentrations of carbon dioxide (e.g., at least 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 95%, or 99% carbon dioxide purity) and / or supercritical carbon dioxide. In such embodiments where the carbon dioxide is supercritical, the injected carbon dioxide may have (i) a temperature of 10°C-50°C, or not more than 50°C or 70°C, and / or (ii) a pressure of at least 6 megapascals (MPa), 7 MPa, 8 MPa, 9 MPa, 10 MPa, 12 MPa, 14 MPa, 16 MPa, 18 MPa, or 20 MPa.

[0035] In some embodiments, the end of the injection well 20 is located at the bottom or lowest height of the UCG reaction zone 70 (about Figure 2 In doing so, the buoyancy of the injected process fluid (e.g., carbon dioxide) enables the process fluid to rise through the UCG reaction zone 70. In addition, injecting the process fluid at the bottom of the UCG reaction zone 70 enables the process fluid to entrain liquids (e.g., water and / or condensed contaminants) and carry them to the surface 50.

[0036] In operation, after the UCG reaction zone 70 becomes depleted and / or syngas is no longer consistently produced, a process fluid is injected toward the UCF 10 via the injection well 20. When the process fluid contacts the depletion plate, the process fluid heats and expands, thereby saturating the available free volume of the carbonaceous formation of the depletion plate and penetrating the pore space, cleat fractures, surrounding rock, ash and / or slag. The process fluid dissolves organic compounds present within the depletion plate, and as the process fluid is heated by the surrounding high temperature carbonaceous material, it moves at a higher velocity through the depletion plate and the production well 45 to produce production fluid 230. As the production fluid 230 travels through the production well 45 and is received at the surface 50, it is cooled (e.g., without the use of water), and filtered and compressed via the device 220 to produce a clean injection process fluid 232 ("injection fluid 232"). The compression causes the partial pressure of the gaseous contaminants to increase, which enables them to condense and separate from the injection fluid 232 along with other liquids and solids (e.g., via gravity). The injection fluid 232 is re-injected into the plate via the injection well 20.

[0037] This process may be repeated until the plate is cooled to the natural formation temperature via the injection fluid 232, and the production fluid 230 has contaminants below an acceptable level. Thus, the end of the process may be determined by monitoring the temperature and / or contaminant levels of the production fluid 230. After the UCF 10 is cooled and the contaminant levels are determined to be below an acceptable level, the production well 45 may be shut in and injection of the injection fluid 232 may continue until the pressure in the UCF 10 reaches or approaches the lithostatic pressure as measured or estimated at the relevant depth (e.g., within 5%, 10%, or 20% of the lithostatic pressure). The lithostatic pressure may be at least 20 barg (barg), 30 barg, 50 barg, 100 barg, 150 barg, 200 barg, 250 barg, 300 barg, or 350 barg. Once the pressure in the UCF 10 reaches or approaches the lithostatic pressure, injection may be stopped and the injection well 20 may be "shut in." As the process fluid (e.g., carbon dioxide) from the UCF 10 diffuses into the surrounding area, the pressure in the plate will slowly decay to reach the hydrostatic and / or formation fluid pressure levels. In addition, as the injected fluid 232 is adsorbed into the surrounding area to cause swelling, a low permeability cocoon or zone is formed and the environment is further protected from any materials and / or contaminants that may remain in the UCG reaction zone 70. Advantageously, embodiments of the present technology enable (i) all or most contaminants to be removed from the UCF 10, and (ii) the UCF 10 to be cooled to ambient or near ambient temperature. In doing so, components of the process fluid are sequestered, as further described below, and further coal conversion reactions are inhibited. In addition, the potential for reignition, production of new organic compounds, and / or groundwater contamination is limited.

[0038] It is noteworthy that, as described herein, utilizing process fluid to cool the UCG reaction zone 70 has multiple advantages over utilizing other sources, such as water. For example, injecting water into the UCG reaction zone 70 will produce steam, which is not an effective solvent for most organic contaminants of the UCG process because they are not hydrophilic. In addition, because the temperature is not uniform throughout the UCG reaction zone 70, the injected water is converted to steam only in the hot portion of the UCG reaction zone 70, and therefore the cooler portions do not produce steam, and the contaminants there are not removed. As another example, once steam is formed, the steam will re-condense in the cooler portions of the plate and the production wells, resulting in ineffective removal of potential contaminants. As another example, separating soluble organic products from water in a purification device can be a complex and expensive process.

[0039] III. Sequestration of process fluids in subsurface carbonaceous formations and related systems and methods

[0040] Embodiments of the present technology enable process fluids as described herein to be enclosed in a UCF, which process fluids may include carbonaceous fluids, carbon dioxide-containing fluids, flue gases, etc. There are many types of carbonaceous gaseous fluids that are produced as a result of industrial processes and / or in the process of recovering and processing fossil fuels. The most common examples of such processes are flue gases produced by power generation equipment, coal-fired boilers, natural gas turbines, diesel turbines, reciprocating gas engines, cement plants, blast furnaces, refineries, and coking plants. Typical flue gases, such as from natural gas-fired power generation equipment, may contain (mol / mol%) 8%-10% carbon dioxide, 18%-20% water, 2%-3% oxygen, and 67%-72% nitrogen, and flue gases from coal-fired boilers may contain 12%-14% carbon dioxide, 8%-10% water, 3%-5% oxygen, and 72%-77% nitrogen. Other common examples of carbon dioxide-containing streams are the effluents of acid gas separation plants, which separate acid gases (e.g., hydrogen sulfide and carbon dioxide) from natural gas and other industrial and naturally occurring streams. In such streams, the share of carbon dioxide can reach 50%-85%.

[0041] In order to seal the process fluids and other greenhouse gases (GHGs) contained in common industrial effluents, one or more common gas fractionation processes are usually used to separate GHGs, which consume a lot of energy and water and have high capital and operating costs. Therefore, it is not economically practical to process these industrial effluents by adsorption separation. Other methods for isolating and sealing process fluids include injecting process fluid streams into carbonaceous formations to allow the carbon of the formation to directly contact and adsorb carbon dioxide from the process fluid, while being less prone to adsorbing other components of flue gas, such as nitrogen, which has a smaller affinity for carbon. More specifically, such methods require injecting process fluids into carbonaceous formations containing methane so that methane is desorbed from carbon and recovered via production wells, so that the economic value of the recovered methane can offset the cost of establishing and operating a flue gas injection system. However, these methods have multiple defects. For example, the volume and surface area of ​​the carbonaceous formation that can be entered via injection wells and production wells are limited by the diameter of the well and the distance at which the production well can be hydraulically connected to the injection well. As another example, restricted access to the formation, in turn, limits the penetration levels through the formation that the injected flue gas can reach, and therefore limits the amount of carbon dioxide that can be stored. As another example, the injectability and diffusion of flue gas within UCFs is severely limited by the significant reduction in formation permeability, which is caused by the expansion of the formation material due to carbon dioxide adsorption. Therefore, injecting flue gas into the formation can be very short-lived and generally ineffective. Further, the process is energy negative and requires large external energy sources, such as for compressing and injecting the flue gas. As described herein, embodiments of the present technology can address these deficiencies.

[0042] Figure 3 3 is a schematic block diagram of a system 300 for UCG and carbon sequestration according to an embodiment of the present technology. The system 300 includes a processing facility located above a surface 50 and a carbonaceous formation below the surface 50. The processing facility includes an oxidant compressor 305, a power generation facility 310, and a device configured to compress a process fluid 314 (e.g., reference Figure 2 The UCF may include an active plate 325, a depletion plate 330 spaced apart from the active plate 325, and an adjacent (or intermediate) formation 10a / b / c (collectively referred to as "adjacent formation 10"). Gasification reactions generally do not occur at the adjacent formation 10, which has a higher hydraulic resistance than the active plate 325 and the depletion plate 330. In some embodiments, the depletion plate 330 has a higher hydraulic resistance than the active plate 325. The adjacent formations may correspond to UCFs and may include a first adjacent formation 10a on a first side of the active plate 325, a second adjacent formation 10b on a second opposite side of the active plate 325 and a first side of the depletion plate 330, and a third adjacent formation 10c on a second opposite side of the depletion plate 330. The UCFs may include coal, tar sands, peat, carbonaceous shale, oil shale, and / or depleted oil / gas fields.

[0043] The oxidant compressor 305 is configured to receive the oxidant 304 (e.g., Figure 1 The oxidant compressor 305 is a compressor that compresses and pressurizes the oxidant 15 and is fluidly coupled to the active plate 325 via the injection conduit 306. In some embodiments, the oxidant compressor 305 may be part of an air separation unit or other equipment / facility. The active plate 325 may generate a product gas stream (e.g., Figure 1 The product gas stream may be directed to (i) a desired end use, e.g., for further processing to produce hydrogen, methanol, or other chemicals / products, and (ii) to power generation equipment 310 via active plate production conduit 326. In some embodiments, active plate 325 corresponds to Figure 1 UCG system5.

[0044] The power plant 310 is configured to generate an electrical output from a product gas stream received via an active plate production pipeline 326. The power plant 310 may include a gas turbine, a steam turbine, a boiler, a gas engine, and / or other equipment configured to generate a power output from a product gas stream received from the active plate 325. In some embodiments, the electrical output from the power plant 310 may offset the power consumption of the entire system 300, and in such embodiments, enable the system 300 to perform energy neutral or energy positive operation. For example, the electrical output from the power plant 310 may offset the power requirements of the oxidant compressor 305, the process fluid compressor 315, etc. The power plant 310 may generate a process fluid 311 (e.g., a carbonaceous fluid, a pure carbon dioxide fluid, a fluid comprising at least 90% carbon dioxide, a flue gas, etc.), which may be sequestered within the UCF and / or used to quench or clean an area of ​​the UCF as described herein.

[0045] The process fluid compressor 315 is configured to receive the process fluid 314 and produce a pressurized process fluid. The pressurized process fluid may include various concentrations of carbon dioxide (e.g., at least 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 95%, or 99% carbon dioxide purity) and / or supercritical carbon dioxide. The process fluid compressor 315 may be fluidly coupled to the depletion plate 330 via the depletion plate injection well 316 and fluidly coupled to the active plate 325 via the active plate injection conduit 306. In some embodiments, the depletion plate 330 is a previous "active plate" that includes a UCF where some or all of the volatile materials have been removed and / or the production of standard quality syngas can no longer be consistently sustained. In such embodiments, the depletion plate injection well 316 may correspond to an injection conduit previously drilled for the active plate. In operation, the pressurized process fluid provided to the depletion plate 330 may cool and remove (e.g., displace) contaminants from the carbonaceous formation of the depletion plate 330, as described with reference to Figure 2 The exhaust plate production fluid may include carbon dioxide and contaminants (e.g., ammonia, hydrocarbons, and other organic compounds) from the exhaust plate 330 and may be recycled to the process fluid compressor 315 via the exhaust plate production well 331. In some embodiments, the system 300 may also include a vacuum pump operably coupled to the exhaust plate production well 331, for example, so that the pressure of the exhaust plate 330 may be negative (e.g., -0.99 barg).

[0046] The system 300 may also include a contaminant separator 320 that is fluidly coupled to the depletion plate production well 331 and the process fluid compressor 315 and is configured to separate contaminants from the carbon dioxide and produce a separator outlet fluid that is directed to the process fluid compressor 315. The depletion plate 330 may have a cross-sectional dimension (e.g., diameter) of at least 0.5 m, 1 m, 5 m, 10 m, 50 m, 100 m, 200 m, or in the range of 0.5-200 m. In some embodiments, the cross-sectional dimension of the depletion plate injection well 316 is the same as or has a similar cross-sectional dimension to the cross-sectional dimension of the injection pipeline 306 and / or the production pipeline 326.

[0047] In operation, the depletion plate injection fluid is directed to the depletion plate 330 and then compressed via the process fluid compressor 315 for temporary recirculation back to the depletion plate 330, as shown in FIG. Figure 2 As described. For example, when a depletion plate injection fluid (e.g., carbon dioxide of the depletion plate injection fluid) contacts the depletion plate 330 and the surrounding UCF, the depletion plate injection fluid heats and expands, thereby saturating the available free volume of the UCF of the depletion plate 330 and penetrating its pore spaces, cleat fractures, surrounding rocks, ash and / or slag. The carbon dioxide dissolves organic compounds present within the depletion plate 330, and as the carbon dioxide is heated by the surrounding high temperature carbonaceous material, it moves through the depletion plate 330 at a higher speed to produce a depletion plate production fluid. As the depletion plate production fluid travels through the depletion plate production well 331 and is received at the surface 50, contaminants are separated via the contaminant separator 320, and the remaining fluid is compressed via the process fluid compressor 315 to produce a depletion plate injection fluid, which is directed back to the depletion plate 330 via the depletion plate injection well 316.

[0048] The process fluid 314 directed through the depletion plate injection well 316 can have a pressure at or near the static pressure of the lithostatic pressure at the depletion plate 330 (e.g., can be injected or compressed to a certain pressure). For example, the pressure of the process fluid 314 injected into the depletion plate injection well 316 can be at least 10 barg, 20 barg, 30 barg, 40 barg, 50 barg, 100 barg, 150 barg, 200 barg, 250 barg, 300 barg, or 350 barg. In operation, when fluid is injected via the depletion plate injection well 316 and / or withdrawn via the depletion plate production well 331, the depletion plate 330 can have an operating pressure of -0.99 barg, up to 99% of the pressure of the process fluid 314 traveling through the depletion plate injection well 316.

[0049] As reference Figure 2As described, the process can be repeated until the depletion plate 330 is fully quenched or cooled to the natural formation temperature via the depletion plate injection fluid, and the depletion plate production fluid has contaminants below an acceptable level. Therefore, the end of the process can be determined by monitoring the temperature and / or contaminant level of the depletion plate production fluid. After the depletion plate 330 is cooled and the contaminant level is determined to be below an acceptable level, the production well 45 can be closed and the injection fluid 232 can continue to be injected until the pressure in the depletion plate 330 reaches or approaches the static rock pressure. At this point, the injection of the depletion plate injection fluid can be stopped. As the carbon dioxide from the depletion plate 330 diffuses into the surrounding area, the pressure in the depletion plate 330 will slowly decay to reach the hydrostatic pressure level. In addition, as the depletion plate injection fluid is adsorbed in the surrounding area, a low permeability cocoon or area is formed, and the environment is further protected from any materials and / or contaminants that may remain. As described herein, in some embodiments, the depletion plate can be further used as a "low pressure zone" for controlling the migration of carbonaceous fluids and UCF. In operation, adsorption of the pressurized process fluid in the UCF may cause desorption of methane, which may be directed toward the active plates 325 where it may be used as a gasification agent.

[0050] During the above operation, the active plate 325 is generally maintained at a pressure lower than the formation pressure of the adjacent formation 10 and / or UCF, and the depletion plate 330 is maintained at a pressure higher than the UCF pressure. Operating the system 300 in this manner forms a pressure gradient within the UCF, wherein the depletion plate operates at the highest relative pressure, the active plate operates at the lowest relative pressure, and the adjacent formation operates at a pressure between the pressures of the depletion plate and the active plate. In some embodiments, the operating pressure of the depletion plate and / or the injection pressure of the depletion plate injection fluid is maintained above the UCF pressure and below the static rock pressure within the UCF. The static rock pressure is based on the weight of the formation covering the reaction zone or UCF. Since the permeability through the UCF increases with the injection fluid pressure, it is preferred that the depletion plate pressure can be maintained less than but close to the static rock pressure (e.g., within 40%, 30%, 20%, 10% or 5% of the static rock pressure). In addition, although the adsorption of carbon dioxide increases with the injection pressure when the pressure is relatively low, the adsorption decreases with the pressure when the pressure is relatively high. Thus, maintaining the injection pressure close to the lithostatic pressure can (i) increase permeability and enable injected CO2 to contact further regions of the UCF away from the boundary of the depletion plate, and (ii) reduce adsorption of CO2 in the UCF region near the boundary of the depletion plate. In doing so, adsorption of the depletion plate injected fluid within the UCF around the depletion plate 330 is relatively low, and the depletion plate injected fluid can spread throughout the UCF and achieve deeper UCF penetration, rather than remaining near the boundary of the depletion plate 330.

[0051] The temperature of the depletion plate 330 relative to the adjacent formation 10 can advantageously promote the desired adsorption of the process fluid 314. Since the depletion plate 330 and its adjacent formation 10 have an elevated temperature relative to the temperature of the UCF further away from the depletion plate 330, and given that adsorption generally decreases as the temperature of the process fluid 314 increases, injecting the process fluid 314 through the depletion plate 330 can advantageously improve adsorption. That is, as the process fluid 314 penetrates deeper into the UCF, the temperature of the process fluid 314 decreases and approaches ambient temperature, which thereby increases its adsorption. Therefore, with respect to quenching, it is beneficial to (1) reduce contaminants within the plate or region to acceptable levels, (2) "shut in" the production wells, and (3) maintain injection of the process fluid at high pressure so that the process fluid is injected into the surrounding formation while the temperature of the depletion plate 330 is still higher than the temperature of the surrounding area of ​​the UCF. In some embodiments, the depletion plate injection fluid is injected into the depletion plate 330 via the depletion plate injection well 316 at a maximum flow rate (e.g., at least 5 tons per hour (tph), 10 tph, 50 tph, or 100 tph) until the injection pressure reaches the static pressure of the UCF. Doing so can help maintain the depletion plate injection fluid at the maximum possible pressure throughout its injection period and can maximize its permeability through the UCF. As the depletion plate injection fluid diffuses from the depletion plate 330 to the surrounding UCF, the pressure in the depletion plate gradually decreases. The pressure is supplemented by additional injection fluid from the process fluid compressor 315 and the depletion plate injection well 316 so that the pressure in the depletion plate remains close to the static pressure for the duration of the injection process until injection into the depletion plate 330 becomes ineffective. In some embodiments, the injection pressure is increased relatively slowly (e.g., over a period of time greater than 60 minutes) to inhibit the rupture of the UCF and enable the process fluid to expand fractures in the general area of ​​the depletion plate 330 and / or the UCF. This type of injection can be referred to as "matrix injection." Additionally or alternatively, the injection pressure is rapidly increased to inject the process fluid at maximum pressure and flow rate for a period of time until a sufficient amount of the process fluid component (e.g., carbon dioxide) is injected. In such an embodiment, the carbon dioxide is concentrated within the general area of ​​the depletion plate 330 and then dissipated to the surrounding area over time.

[0052] In addition to or in lieu of injecting the depletion plate injection fluid at the maximum possible flow rate, the flow rate and pressure of the injection gas can be varied. Since carbon dioxide adsorption within the UCF surrounding the depletion plate 330 may cause its carbonaceous materials to expand, the permeability of the UCF surrounding the depletion plate 330 may decrease over time. Intermittently adjusting (e.g., dramatically increasing) the flow rate and pressure of the depletion plate injection fluid can counteract this undesirable effect by enabling the injected fluid to break through the "expanding" area of ​​the UCF and allowing the depletion plate injection fluid to reach and contact the surrounding area. As an example, dramatically increasing the flow rate and / or pressure of the injection gas in a pulsed manner can help promote migration and deep penetration of the injected gas. For example, the injection flow can be increased from formation fluid pressure to static rock pressure in no more than 10 minutes, 20 minutes, 30 minutes, or 60 minutes.

[0053] The system 300 may also include a controller or control system 333 ("controller 333") and one or more sensors 332 (e.g., temperature sensors, pressure sensors, and / or contaminant sensors) in communication with the controller 333. The controller 333 is used to control and communicate with different elements of the system 300. For example, the controller 333 may control the injection pressure of the active plate injection fluid and the depletion plate injection fluid. The controller 333 allows an operator to control various aspects of the system 300 from a remote location. Many embodiments of the controller 333 and / or the techniques described below may take the form of computer-executable instructions, including routines executed by a programmable computer. The controller 333 may also include, for example, a combination of a supervisory control and data acquisition (SCADA) system, a distributed control system (DCSs) programmable logic controller (PLCs), a control device, and a processor configured to process computer-executable instructions. Those skilled in the relevant art will appreciate that the technology may be practiced on computer systems other than the computer systems described herein. The technology may be embodied in a special-purpose computer or data processor that is specifically programmed, configured, or constructed to execute one or more of the computer-executable instructions described below. Thus, the terms "controller" and "computer" are generally used herein to refer to any data processor.

[0054] The technology can also be practiced in a distributed environment, where tasks or modules are performed by remote processing devices linked through a communication network. In a distributed computing environment, program modules or subroutines can be located in local and remote memory storage devices. Various aspects of the technology described below can be stored or distributed on computer-readable media, including magnetic or optically readable or removable computer disks, as well as distributed electronically over a network. Data structures and transmission of data specific to aspects of the technology are also included within the scope of specific embodiments of the disclosed technology.

[0055] One or more sensors may be fluidly coupled to the depletion plate production well 331 and positioned to detect parameters of the depletion plate production fluid. In some embodiments, the sensor 332 is used to determine whether the depletion plate production fluid is below an acceptable contaminant level and / or below a predetermined temperature. In doing so, the sensor 332 may determine whether the depletion plate production fluid needs to be recirculated or may be shut down. For example, after the depletion plate 330 is cooled and the contaminants within the depletion plate production fluid are determined to be below an acceptable level, the depletion plate 330 may be shut down and the depletion plate 330 may continue to be injected until the pressure in the depletion plate 330 reaches or approaches the static rock pressure (e.g., within 5%, 10%, or 20% of the static rock pressure). At this point, the injection may be stopped. The system 300 may also include a pressure sensor 317, which is fluidly coupled to the depletion plate injection well 316 and is configured to monitor the pressure of the depletion plate injection fluid. The pressure sensor 317 may determine whether the pressure in the depletion plate 330 reaches or approaches the static rock pressure. Additionally, as process fluid 314 dissipates into the surrounding UCF and the pressure in depletion plate 330 decreases, more process fluid 314 may be injected into depletion plate 330 using pressure sensor 317, for example, to maintain process fluid flow into the UCF.

[0056] The adjacent formation 10 located on opposite sides of the active plate 325 and the depletion plate 330 can be used to create a pressure profile within the UCF to drive the depletion plate injection fluid to migrate through the UCF in a controlled manner. For example, the adjacent formation 10 can be used to drive the injection fluid away from the depletion plate 330, which has a pressure higher than the formation pressure of the UCF, and / or toward the active plate 325, which has a pressure lower than the formation pressure of the UCF.

[0057] Figure 4 is a schematic block diagram of another system 400 for UCG and carbon sequestration according to an embodiment of the present technology. System 400 includes many of the same (or substantially similar) features and components of system 300, including oxidant compressor 305, power generation equipment 310, process fluid compressor 315, active plate 325, depletion plate 330, and adjacent formation 10. In some embodiments, depletion plate 330 of system 400 has been cleaned and / or cooled, as described with reference to systems 300 and Figure 3 as described, and is therefore ready to receive carbon dioxide to be stored.

[0058] like Figure 4As shown, system 400 omits the depletion plate production well 331 of system 300 (e.g., because the depletion plate 330 has been "cleaned"), and the depletion plate injection well 316 of system 400 includes a first branch directed to the depletion plate 330 and a second branch directed to the adjacent formation 10c. The injection fluid provided from the process fluid compressor 315 can be directed to one or both of the depletion plate 330 and the adjacent formation 10c to form a desired pressure profile within the region of the UCF. For example, as previously described, in some embodiments, the depletion plate may have previously been an active plate, which now includes a UCF, where volatile materials have been removed and / or the production of standard quality syngas can no longer be consistently sustained. When the depletion plate is now an active plate producing syngas, it operates at a pressure below the formation pressure of the surrounding UCF. In such an embodiment, an injection fluid including carbon dioxide (e.g., supercritical carbon dioxide) can be advantageously injected into the adjacent formation 10c at a pressure higher than that of the then active plate, thereby forming a desired pressure profile to drive the injection fluid to migrate from the adjacent formation 10c and through the surrounding UCF toward the then active plate. In doing so, the CO2 injected into the fluid can be adsorbed by the surrounding UCF. Once the active panels are no longer producing syngas and have experienced the reference Figure 3 The process described above (where the depletion plate 330 is free of potential contaminants (ie, "clean") and is at formation temperature (ie, "cool")), the depletion plate 330 may then be removed for reference Figure 3 and system 300 for the reasons described herein.

[0059] An example is provided herein for demonstrating whether a UCG can be effective and efficient in building and operating a system 400 to determine: whether the system 400 can sustain the operation, how much energy is required, and whether building and operating the system 400 is feasible. In this example, the UCF includes a 10 m thick sub-bituminous coal seam at a depth of 1.5 km, and the carbon dioxide must be sequestered at a rate of 1,000,000 tons per year (tpa). For this example, it is assumed that (i) the process fluid 314 is pure carbon dioxide at an ambient temperature of 15°C and atmospheric pressure at the UCG site, and (ii) the carbon dioxide is injected at a constant flow rate and a pressure of 150 barg under steady-state conditions. An intercooling compressor with a fin fan cooler compressing 1,000,000 tpa of carbon dioxide is modeled using the Thermoflex software package, determining a total power requirement of 12.4 megawatts (MW). It is assumed that this power is generated by an integrated gasification combined cycle (IGCC) power plant fired with UCG syngas. If the system operates with air injection, it must produce syngas at an energy rate of approximately 90 gigajoules / hour. Thermoflex modeling of the intercooled air compressor gives an air injection power requirement of approximately 1.5 MW, resulting in a total plant power consumption of 13.9 MW. Detailed modeling of the UCG-IGCC process shows that the UCG panels required to provide energy for the process can be 1,500 m long and only 2 m wide. Assuming the IGCC plant operates without carbon dioxide capture, the total carbon dioxide emissions of the carbon dioxide sequestration plant are equal to approximately 73,000 tpa, meaning that the plant maintains a net carbon dioxide sequestration of 927,000 tpa. That is, the process has a negative carbon balance of -92.7%. According to an embodiment of the present technology, these 1,000,000 tpa of carbon dioxide must be injected through a nearby, same-sized, exhausted UCG plate, and the resulting balance of carbon dioxide storage is as follows: 3.5% of the carbon dioxide is stored in the exhausted plate, while 96.5% of the carbon dioxide saturates the adjacent formations on either side of the surrounding plate. In this case, the sufficient width of each adjacent formation is 150m.

[0060] UCG using air injection is a mature process and the construction and operation of a 1.5 km long plate is a technically feasible task. The scale of CO2 sequestration can be easily scaled by building and operating multiple plates. For example, a typical 350MW coal-fired power plant emits about 3,000,000 tpa of CO2. Sequestering this much CO2 would require operating a 3 plate UCG-IGCC unit, similar to that described above.

[0061] Figure 5is a schematic isometric view of a system 500 for sequestering a process fluid as described herein, according to an embodiment of the present technology. For example, the term "process fluid" may correspond to any fluid having a carbon dioxide content of at least 5%, including any flue gas from an industrial facility (e.g., a natural gas power plant, a coal-fired boiler, etc.) and / or any effluent containing carbon dioxide (e.g., from an acid gas separation plant).

[0062] like Figure 5 As shown, system 500 includes (i) depletion plate injection conduits 511a / b (collectively referred to as "depletion plate injection conduits 511") configured to direct process fluid 311 to the carbonaceous formation of depletion plate 330, as previously described with reference to Figure 3 As described herein, and (ii) a depletion plate production conduit 531 configured to direct a depletion plate production fluid containing nitrogen away from the depletion plate 330. The depletion plate 330, or UCFs in general, has a higher adsorption affinity for carbon dioxide than for nitrogen, and therefore adsorbs more carbon dioxide than nitrogen from the process fluid 311. As described herein, the depletion plate production fluid can be recycled through the depletion plate 330, for example, to (i) adsorb carbon dioxide from the process fluid 311, (ii) depolymerize carbon dioxide and nitrogen from the process fluid 311, and / or (iii) produce purified nitrogen. This ability to treat the process fluid 311 is at least partially due to (i) the relatively large cross-sectional size of the depletion plate 330, (ii) the relatively large surface contact area of ​​the injected process fluid 311 with the UCF, and / or (iii) the devolatilization nature of the depletion plate 330, which has a higher adsorption capacity relative to the active plate or undepleted UCF area. Figure 5 The depletion plate 330 shown in FIG. 3 may have a length of at least 100 m, 300 m, 500 m, 1000 m, or 1500 m and a width less than the length and no greater than 50 m, 100 m, 150 m, 200 m, 250 m, or 300 m.

[0063] Figure 6 is a schematic block diagram of another system 600 for UCG and carbon sequestration according to an embodiment of the present technology. System 600 includes many of the features previously described, including oxidant compressor 305, power generation equipment 310, process fluid compressor 315, active plate 325, depletion plate 330, and adjacent formation 10. Figure 6As shown, process fluid 314 and / or process fluid 311 from power generation equipment 310 is received by process fluid compressor 315 and directed to depletion plate 330 via depletion plate injection well 316. Process fluid 311 / 314 may also be directed to active plate 325 and adjacent formation 10c. In doing so, any carbon and / or oxygen in process fluid 311 / 314 may be utilized within active plate 325, and the composition of process fluid 311 may be improved and / or unified. Process fluid 311 / 314 directed to depletion plate 330 passes through carbonaceous formations that have a higher adsorption affinity for carbon dioxide than for nitrogen, and thus adsorbs more carbon dioxide from process fluid 311 / 314 than for nitrogen. Therefore, depletion plate 330 production fluids leaving depletion plate 330 have a higher nitrogen concentration than process fluid 311 / 314 provided to depletion plate 330. The depletion plate production fluid may be recycled and recompressed via the process fluid compressor 315 until a sufficient amount of carbon dioxide is removed from the process fluid 311 / 314 and / or the depletion plate 330 becomes saturated.

[0064] The system 600 may also include an extraction system 632 (e.g., a nitrogen separation system) that is fluidly coupled to the depletion plate production well 331. The extraction system 632 is configured to extract or remove carbon dioxide from the depletion plate production fluids that exit the depletion plate, while not removing nitrogen, to produce a nitrogen-rich fluid that exits the extraction system 632 and advances toward the surface 50. The extraction system 632 may include an activated carbon filter 633 and / or a membrane 634 that is more permeable to nitrogen than to carbon dioxide. The system 600 may also include one or more sensors 640 (e.g., a nitrogen sensor) that are fluidly coupled to the extraction system 632 and determine whether the nitrogen purity of the depletion plate production fluids is above an acceptable level. If the nitrogen concentration in the production fluid is above an acceptable level, it may be directed to a nitrogen drain or used as a product for sale or distribution. If the production fluid is below an acceptable level, it may be recycled back to the depletion plate 330 for further processing.

[0065] Figure 7 is a schematic plan view of a UCF 700 according to an embodiment of the present technology, the UCF 700 including one or more depletion plates 710a / b (collectively referred to as "depletion plates 710") and an active plate 705. The UCF 700 may correspond to the reference Figure 4 The system 400 and / or operations described herein, and the active board 705 may correspond to Figure 4 The active plate 325. Figure 7As shown, active plate 705 is located between first depletion plate 710a and second depletion plate 710b. Active plate 705 includes (i) active plate injection conduit 306 extending to underground gob 726 and configured to direct oxidant to UCG reaction zone 70, and (ii) production conduit 326 configured to direct product gas from UCG reaction zone 70 to the surface. First depletion plate 710a includes first depletion plate injection conduits 715c / d, and second depletion plate 710b includes second depletion plate injection conduits 715a / b, each of first depletion plate injection conduits 715c / d being configured to direct process fluid (e.g., process fluid 311 or 314) to a region of UCF 700. As previously described, depletion plates 710a and 710b may have a larger diameter or cross-sectional size to provide less resistance relative to conventional wellbores.

[0066] In operation, the relative arrangement of the active plates 705 and the depletion plates 710 creates a pressure profile that causes the process fluid (e.g., injected carbon dioxide) to migrate from the depletion plates 710 toward the active plates 705. The active plates 705 operate at a pressure less than the hydrostatic pressure or formation fluid pressure (e.g., 0.5 barg to 100 barg, depending on depth and formation pressure), which is less than the formation pressure of the UCF 700 (e.g., 20 barg to 280 barg). The operating pressure of the active plates 705 is controlled in part by the injection pressure and the flow rates of the oxidant and product gases. The depletion plates 710 receive the injected carbon dioxide-containing fluid at a pressure above the formation pressure. For example, as described herein, the injection pressure of the depletion plates 710 can be close to the lithostatic pressure (e.g., within 5%, 10%, or 20% of the lithostatic pressure). Depending on the depth, the lithostatic pressure can be 25-300 barg. For example, the lithostatic pressure may be 25-30 barg at a depth of 100 m and 400 barg at a depth of 1500 m. Thus, the process fluid injected into the depletion plate 710 travels from the depletion plate 710 through the UCF 700 toward and / or to the active plate 705. By positioning the depletion plate 710 near the active plate 705 and creating this pressure profile, the injected process fluid permeates through a larger area of ​​the UCF, and thus enables, for example, carbon dioxide of the process fluid to be injected at the depletion plate 710. This helps to increase or maximize the amount of the UCF 700 that is in contact with and / or saturated with the injected process fluid. If the depletion plate 710 is not positioned near the active plate 705, there will be less driving force between the depletion plate 710 and the active plate 705, and thus less penetration of the process fluid through the UCF. As another benefit, the pressure profile formed via the relative arrangement of the active plate 705 and the depletion plate 710 enables the operator to control the direction of migration of the injected carbon dioxide-containing fluid. For example, Figure 7As shown, the injected process fluid migrates only or primarily in a direction from the depletion plate 710 toward the active plate 705 , and does not migrate from the depletion plate 710 away from the active plate 705 .

[0067] Figure 8 is a schematic plan view of a UCF 800 according to an embodiment of the present technology, the UCF 800 including one or more depletion plates 810a / b (collectively referred to as "depletion plates 810") and an active plate 705. The UCF 800 may correspond to reference Figure 6 The system 600 and / or operation described herein, and the active board 705 may correspond to Figure 6 The active plate 325. Figure 8 As shown, the first depletion plate 810a is located between the active plate 705 and the second depletion plate 810b. The active plate 705 includes the previously described active plate injection conduit 306 and production conduit 326, and the second depletion plate 810b includes depletion plate injection conduits 816a / b (collectively referred to as "depletion plate injection conduits 816"), which are configured to inject process fluid (e.g., process fluid 311 or 314) into the area of ​​the UCF 800. The first depletion plate 810a includes depletion plate production conduits 831a / b (collectively referred to as "depletion plate production conduits 831"), which are configured to extract the provided nitrogen from the flue gas of the second depletion plate 810b. As previously described with reference to Figure 6 As described above, the nitrogen-containing gas extracted from the depletion plate production conduit 831 may be recycled and injected into the UCF 800, for example, via the depletion plate injection conduit 816 of the second depletion plate 810b.

[0068] In operation, the relative arrangement of the active plate 705 and the depletion plate 810 creates a pressure profile that causes the injected carbon dioxide-containing fluid to migrate from the second depletion plate 810b toward the first depletion plate 810a. As described elsewhere herein, the active plate 705 operates at a pressure less than the hydrostatic pressure or formation fluid pressure, which is less than the formation pressure of the UCF 800, and the second depletion plate 810b operates at a pressure greater than the formation pressure. Due to the extraction of the depletion plate production tubing 831 and the nitrogen-containing gas therein, the first depletion plate 810a operates at a pressure less than the formation pressure. In this way, the first depletion plate 810a acts as a "low pressure zone" to help control the migration of injected process fluids within the region 820 of the UCF 800. In this way, the UCF 800 has a pressure distribution that drives the injected process fluid of the second depletion plate 810b toward the first depletion plate 810a, and enables the region 820 of the UCF between the second depletion plate 810b and the first depletion plate 810a to contact and / or be saturated with, for example, carbon dioxide of the injected process fluid.

[0069] Additional depletion plates may be formed to saturate additional regions of UCF 800 with carbon dioxide and / or to control the migration of injected gas in a desired direction. For example, once the volatiles of active plate 705 have been removed and / or the production of standard quality syngas produced therefrom is no longer sustainable, active plate 705 may become the new depletion plate, which may be "quenched", as described in reference to Figure 3 As described, to clean and cool it, and can be maintained at a pressure below the formation fluid pressure. At this point, a new active plate can be created adjacent to the new depletion plate, and the new active plate can be operated to generate syngas via the UCG process described herein. In doing so, the first depletion plate 810a can receive flue gas for sequestration, as previously described for the second depletion plate 810b; the new depletion plate (i.e., the previous active plate 705) can withdraw nitrogen-containing gas, as previously described for the first depletion plate 810a; and the new active plate (not shown) can receive oxidant and produce product gas, as previously described for active plate 705. In doing so, region 825 of the UCF contacts and / or becomes saturated with carbon dioxide from the carbon dioxide-containing fluid. The process can be repeated as needed to sequester additional carbon dioxide.

[0070] Fig. 9 is a schematic plan view of injection wells 918 extending (e.g., laterally and / or horizontally) through multiple zones 910a / b / c (collectively, “zones 910”) of a UCF 900 in accordance with an embodiment of the present technology. The system can inject process fluids (e.g., process fluids 311 / 314) directly into the UCF (e.g., without passing through a depletion plate). Fig. 9As shown, injection well 918 is drilled from right to left into zone 1 of UCF 900. Initially, a process fluid is injected into zone 910a, which is isolated on the left side by the bottom (or end) of injection well 918 and on the right side by packer 916, through which a carbon dioxide injection pipe 920 passes. Injection is performed at a pressure close to the static pressure of the rock until the expansion caused by carbon dioxide adsorption within zone 910a reduces the permeability and injectivity of carbon dioxide of the process fluid. The injection pressure can be increased sharply (i.e., as previously described, the formation permeability can be stimulated thereby), for example, from the formation fluid pressure to the static pressure within a predetermined time period (e.g., no more than 30 minutes) to break through the expansion zone into the fresh UCF material. This cycle of injection and stimulation can be repeated until the stimulation becomes ineffective in increasing the carbon dioxide injectivity. At this point, a plug 912 can be set to block zone 910a. Thereafter, the packer 916 is pulled toward the heel of the injection well 918 and placed in a position to isolate the region 910b between the plug 912 and the packer 916. Injection into the region 910b is performed in the same manner as described for the region 910a. After the injection into the region 910b is completed, the plug 914 is set to block the region 910b. Then, by setting the packer 916 in the Fig. 9 At the position shown, the process fluid injection is transferred to area 910c. Fig. 9 As shown, the process fluid begins to dissipate into region 910c. This process can continue to additional regions until the packer 916 reaches the heel of the injection well 918. Sequential injection of process fluid into successive isolated sections of region 910 can be accomplished, for example, using different drilling and completion techniques and equipment. Such techniques and equipment may not include setting plugs and packers, but rather use other means for injecting into isolated regions.

[0071] IV. Horizontal Wells for Subsurface Carboniferous Formations and Related Systems and Methods

[0072] As described herein, for example, reference Figure 5 , pipelines typically extend vertically from the surface to access the UCF below. However, in some embodiments, UCFs may not be accessible via vertical wells or pipelines, and can only be accessed via horizontal wells. This is the case, for example, for UCFs located offshore or beneath protected areas (e.g., national parks), where drilling from above the UCF is not possible. Given such a UCF, Fig. 10A and 10B is a schematic diagram of a UCG plate or plates 1005, 1010 formed by drilling horizontal wells according to an embodiment of the present technology, which can be used for UCG, carbon sequestration or other purposes.

[0073] It is generally preferred to maximize the surface area of ​​the UCG plate in contact with the surrounding UCF, because the utility of the plate as a conduit for injection of process fluids or CO2-containing fluids is determined in part by its cross-section, which should ensure low hydraulic resistance and surface area in contact with the UCF. Accordingly, embodiments of the present technology include plates that are relatively long along a length dimension (A) and relatively narrow along a width dimension (b), such as Fig. 10A As shown, since the surface area in contact with the UCF is (a / b) 1 / 2 Proportional. Fig. 10B As shown, the plate 1010 can include a curved surface and / or a sinusoidal shape to further increase the surface area of ​​the plate in contact with the surrounding UCF. Without being bound by theory, the curved surface of the plate 1010 can increase the contact with the surrounding UCF by at least 20%, 30%, 40%, or 50% relative to the plate 1005 without a curved surface. In doing so, embodiments of the present technology have more contact with the carbonaceous formation, which enables more carbon to be sequestered, among other benefits.

[0074] V. Injection of Fluids Containing Carbon Dioxide into Subsurface Carboniferous Formations and Related Systems and Methods

[0075] Fig.11 is a schematic diagram of a UCF 1100 according to an embodiment of the present technology, which includes a process fluid (e.g., process fluid 311 or 314) injection site 1105 at a bottom portion of the UCF. As described herein, injection in the UCF preferably increases (e.g., maximizes) (i) contact between the process fluid and the UCF and (ii) saturation of the UCF with the process fluid. The UCF is typically saturated with formation fluids, which include groundwater, hydrocarbons, and hydrogen sulfide. The formation fluids typically occupy the formation matrix pore space and are adsorbed to the matrix material of the UCF. In order for the process fluid to displace the formation fluid, injection should typically occur at the bottom of the UCF but above the UCF floor, which includes rock that is typically less permeable than the UCF. For example, injection can occur in the bottom 0.5 m of the formation thickness, such as Fig.11 In doing so, the buoyancy of the process fluid, which has a density less than that of the formation fluid, can promote greater saturation within the UCF by rising through the UCF and displacing formation fluid from the pore space.

[0076] The same principle can be applied to the lateral distance of the UCF, such as Fig.12 As shown, Fig.12 1 is a schematic diagram of a UCF 1200 including process fluid injection sites 1105a / 1105B / 1105C (collectively referred to as “injection sites 1105”) at a bottom portion of the UCF 1200. Fig.12As shown, the UCF 1200 has undulations that result in multiple low elevation points across the lateral distance of the UCF 1200. Having the injection site 1105 at the lowest elevation of the UCF 1200 and above the floor of the UCF 1200 promotes greater saturation of the UCF 1200 with process fluid.

[0077] As described elsewhere herein, the location of injection can create a pressure profile that drives migration of fluid injected into the UCF. Fig.13 An example of this is shown, and is a schematic diagram of a UCF 1300 that includes low pressure regions 1310a / b / c (collectively, "low pressure regions 1310") between process fluid injection sites 1105a / b / c / d / e / f (collectively, "injection sites 1105") at a bottom portion of the UCF 1300. The injection sites 1105 may each receive a process fluid injected at a pressure greater than the surrounding formation pressure of the UCF. The low pressure region 1310 may be formed at an area adjacent to the injection sites 1105, for example, between adjacent injection sites 1105a / b, 1105c / d, 1105e / f, as shown. Fig.13 1305. The low pressure zones may include one or more conduits, such as depletion plate production conduits described herein, that extract nitrogen or other fluids from the zones. As a result of the extraction of nitrogen or other fluids, the pressure in these zones is lower than the formation pressure, which is lower than the pressure at the injection location 1105. A "cone of depression" is formed at the low pressure zones 1310b of the UCF 1300, and in operation, the pressure profile of the UCF 1300 causes the injected process fluid to migrate primarily from the injection site 1105 to the corresponding low pressure zones 1310. Over time, the injected process fluid first fills the lower pressure zones (i.e., lower elevation zones) of the UCF 1300, and then fills the higher pressure zones (i.e., higher elevation zones) of the UCF 1300, such that the entire UCF 1300 is eventually saturated with process fluid.

[0078] In some embodiments, the formation will have a steep dip, for example, with an angle (β) exceeding 30°. Fig.14 is a schematic diagram of a UCF 1400 including a vertical angle of a process fluid injection site 1105. For such embodiments, positioning the injection site 1105 within the depressed cone is difficult, and therefore the injection site 1105 is located at the lowest accessible elevation of the formation floor.

[0079] VI. Interconnected Rock Formations of Subsurface Carbon-Bearing Formations and Related Systems and Methods

[0080] Most UCFs exist as a series of carbonaceous rock layers intercalated by inert rock. Unless the UCFs are shallow enough for open pit mining, any voids or undersaturated zones can only be created by mining, drilling, or UCG. It is rare for more than one carbonaceous rock layer within the series to be thick enough to be mined or targeted by UCG, so these thin UCFs are not usually used. Fig.15 A UCF 1500 is shown including a UCG cavity 1505, a process well 1510, and an induced fracture 1515 from the UCG cavity 1505. Fig.15 An example of this is shown. Fig.15 As shown, the thickest rock layer 1506 of the UCF 1500 is the rock layer with the lowest height in the series. The bottom thick rock layer 1506 should be mined or gasified so that the upper carbonaceous rock layer is destroyed and the deformation fractures generated above it are hydraulically interconnected with the carbonaceous rock layers of the UCF 1500 above the bottom thick rock layer 1506. After the mining operation or UCG process is completed, injecting the process fluid into the depleted pit or UCG plate of the UCF 1500 can sequester the process fluid in all carbonaceous rock layers of the UCF 1500. Therefore, more carbonaceous material becomes available for sequestration than is suitable for mining or UCG process.

[0081] like Fig.16 and Fig.17 As shown, in some embodiments, a mineable or suitable rock formation for UCG is located in the middle of the UCF. Fig.16 As shown, the rock formations of the UCF 1600 can be interconnected by vertically drilling wells 1610a / b from the ground 50 through each rock formation 1606 of the UCF 1600. The wells 1610a / b can be drilled after the mining or UCG process is completed. Since the wells can provide access from the ground 50 to a series of rock formations, the wells 1610a / b can be used to inject process fluids or as production conduits to create low pressure areas, as described elsewhere herein.

[0082] Interconnection of the UCF 1600 can also be achieved by drilling wells with both horizontal and vertical components. Fig.17 An example of this is shown in FIG. 1700 , which includes wells 1710 extending horizontally and vertically through each of the rock formations of UCF 1700. Wells 1710 may remain open throughout UCF 1700 and may be used to inject process fluids or used as production conduits to create low pressure zones, as described elsewhere herein. Fig.16 Compared to the multiple vertical wells shown in , directional horizontal wells may be a more cost-effective alternative for interconnecting series UCFs over a large lateral extent.

[0083] VII. Matrices for Sequestering Fluids Containing Carbon Dioxide in UCFs

[0084] Fig.18 A matrix characterizing multiple categories of methods and systems for efficient and scalable storage of process fluids in UCFs is illustrated. Each category includes multiple options for implementing the storage process, which can be arranged to build variations of the storage methods and systems that are optimal for a particular set of conditions. These categories include the type of process fluids and their phases, the type of carbonaceous formations and their structures and depths, the locations of injection targets and injection points within the UCF, the types of injection pipelines that can be constructed within the UCF and the methods used to construct these pipelines, the types of low-pressure zones and adsorption and filtration media within the UCF, methods for upgrading production fluids to enhance carbon sequestration, options for the construction and operation of process fluid storage systems offshore and inaccessible areas, fluid injection schemes and systems for implementing them, and parameters of UCG systems applicable to various storage conditions.

[0085] VIII. Conclusion

[0086] It is obvious to those skilled in the art that the details of the above-described embodiments may be changed without departing from the basic principles of the present disclosure. In some cases, well-known structures and functions are not shown or described in detail to avoid unnecessarily obscuring the description of the embodiments of the present technology. For example, valves, pipelines, controllers and other features have been omitted from some of the descriptions of the present technology. Although the steps of the method may be presented in a particular order herein, other embodiments may perform the steps in a different order. Similarly, certain aspects of the present technology disclosed in the context of a particular embodiment may be combined or eliminated in other embodiments. In addition, although the advantages associated with certain embodiments of the present technology may have been disclosed in the context of those embodiments, other embodiments may also exhibit such advantages, and not all embodiments must exhibit such advantages or other advantages disclosed herein to fall within the scope of the present technology. Therefore, the present invention and associated technologies may encompass other embodiments that are not explicitly shown or described herein, and the present invention is not limited except by the appended claims.

[0087] Throughout this disclosure, the singular terms "a," "an," and "the" include plural referents unless the context clearly dictates otherwise. When used in reference to a list of two or more items, the term "and / or" should be interpreted to include (a) any single item in the list, (b) all items in the list, and (c) any combination of items in the list. Additionally, the terms "including," "comprising," and "having" should be interpreted to mean including at least the recited features, such that any greater number of the same features and / or additional types of other features are not excluded.

[0088] References herein to "one embodiment," "an embodiment," "some embodiments," or similar expressions mean that a particular feature, structure, operation, or characteristic described in conjunction with the embodiment may be included in at least one embodiment of the present technology. Therefore, the appearances of such phrases or expressions herein do not necessarily all refer to the same embodiment. Furthermore, various particular features, structures, operations, or characteristics may be combined in any suitable manner in one or more embodiments.

[0089] Unless otherwise indicated, all numbers used in the specification and claims to represent numerical values ​​(e.g., pressure, temperature, etc.) should be understood to be modified by the term "about" or "approximately" in all cases. When used with respect to a value, the terms "about" and "approximately" should be interpreted as indicating within 10% of the value. Therefore, unless otherwise indicated, the numerical parameters set forth in the following specification and the appended claims are approximate values, which may vary according to the desired properties sought to be obtained by the present technology. At least, and without attempting to limit the application of the doctrine of equivalents to the scope of the claims, each numerical parameter should at least be interpreted according to the numerical value of the reported significant figures and by applying ordinary rounding techniques. In addition, all ranges disclosed herein should be understood to cover any and all sub-ranges contained therein. For example, the range of "1 to 10" includes any and all sub-ranges between (and including) a minimum value of 1 and a maximum value of 10, i.e., any and all sub-ranges having a minimum value equal to or greater than 1 and a maximum value equal to or less than 10, such as 5.5 to 10.

[0090] The disclosure set forth above should not be interpreted as reflecting an intention that any claim requires more features than those expressly recited in the claim. Rather, as reflected in the following claims, inventive aspects lie in a combination of less than all of the features of any single preceding disclosed embodiment. Therefore, the claims following this detailed description are hereby expressly incorporated into this detailed description, with each claim independently serving as a separate embodiment. This disclosure includes all permutations of independent claims and their dependent claims.

[0091] For example, the present technology is illustrated according to the various aspects described below. For convenience, various examples of various aspects of the present technology are described as numbered examples (1, 2, 3, etc.). These are provided as examples and do not limit the present technology. Note that any dependent examples can be combined in any combination and placed into corresponding independent examples. Other examples can be presented in a similar manner.

[0092] 1. A system for using a subterranean carbonaceous formation, the system comprising:

[0093] a process fluid source comprising at least one of (i) at least 90% carbon dioxide, (ii) nitrogen, or (iii) steam;

[0094] an injection well fluidly connected to the process fluid source and extending from the surface to a subterranean zone including contaminants, wherein volatile materials have been at least partially removed from the subterranean zone; and

[0095] a production well extending from the underground zone to the surface;

[0096] Wherein, in operation, the process fluid cools the subterranean zone.

[0097] 2. A system as described in any of the clauses herein, wherein the process fluid comprises pure carbon dioxide.

[0098] 3. The system of clause 2, wherein, in operation, after cooling the subterranean region, the process fluid displaces at least some contaminants from the subterranean region.

[0099] 4. The system of any of the clauses herein, further comprising a compressor above the surface, wherein an inlet fluid of the compressor is connected to the production well and an outlet fluid of the compressor is connected to the injection well.

[0100] 5. The system of clause 4, further comprising a separator unit between the production well and the inlet of the compressor, wherein the separator unit is configured to separate the syngas from a process fluid traveling through the production well.

[0101] 6. A system as described in any of the clauses herein, wherein, in operation, the process fluid is directed from the underground region to the surface via the production well, and wherein at least a portion of the process fluid directed toward the surface via the production well is recirculated to the underground region via the injection well.

[0102] 7. A system for sequestering carbon in a subterranean carbonaceous formation and / or quenching a subterranean carbonaceous formation with carbon, the system comprising:

[0103] an injection conduit extending into a first subterranean zone of a carbonaceous formation, wherein the injection conduit is configured to be fluidly connected to a source of an oxidant, and wherein the first subterranean zone has a first hydraulic resistance;

[0104] a production conduit spaced apart from the injection conduit and extending from the first subterranean zone toward the surface; and

[0105] an injection well fluidly connected to a source of a process fluid and extending toward a second subterranean zone of the carbonaceous formation, wherein the process fluid comprises carbon dioxide, and wherein:

[0106] the second underground region having a second hydraulic resistance,

[0107] the second subterranean region is laterally spaced from the first subterranean region by an adjacent formation having a third hydraulic resistance greater than the first hydraulic resistance and the second hydraulic resistance, and

[0108] The second subsurface zone includes contaminants.

[0109] 8. A system as claimed in any one of the clauses herein, wherein, in operation:

[0110] The adjacent strata have fluid pressure,

[0111] The first subsurface zone has a first pressure that is lower than a fluid pressure in an adjacent formation, and

[0112] The second subterranean zone has a second pressure that is higher than the fluid pressure of the adjacent formation.

[0113] 9. The system of clause 8, wherein the first pressure is (i) lower than the second pressure, (ii) lower than the injection pressure of the injection pipeline, and (iii) is at least 20 barg.

[0114] 10. A system according to claim 8, wherein the first underground region includes an active plate and the second underground region includes a depletion plate, and wherein the first pressure in the first underground region is less than the second pressure in the second underground region, so that in operation, at least a portion of the process fluid injected through the injection well migrates from the second underground region toward the first underground region through adjacent formations of the carbonaceous formation.

[0115] 11. A system as described in any of the clauses herein, wherein the carbonaceous formation is under a static rock pressure of at least 15 barg, and wherein the injection well is configured to deliver the process fluid to the second underground zone at an injection pressure within 30% of the static rock pressure.

[0116] 12. The system of clause 11, wherein the injection pressure is higher than the fluid pressure of the adjacent formation.

[0117] 13. The system of any of the clauses herein, further comprising a power generation facility fluidly coupled to the first subterranean zone via the production well, such that the power generation facility is configured to receive the product gas.

[0118] 14. The system of any of the clauses herein, wherein the second subsurface zone comprises a depletion plate having a cross-sectional dimension of at least 0.5 meters.

[0119] 15. The system of any of the clauses herein, wherein the process fluid comprises at least one of a flue gas or a gas stream, the flue gas or gas stream comprising less than 30% carbon dioxide.

[0120] 16. The system as described in clause 15 further includes a production well extending from the second underground area toward the surface, wherein the injection well is configured to receive a gas flow including a first amount of carbon dioxide, and the production well is configured to receive at least a portion of a gas flow including a second amount of carbon dioxide, the second amount of carbon dioxide being less than the first amount of carbon dioxide.

[0121] 17. A system as described in any of the clauses herein, further comprising a production well extending from the second underground region toward the ground, wherein the production well is configured to receive a gas flow including carbon dioxide from the second underground region, and wherein in operation, at least some of the carbon dioxide in the gas flow received by the production well is recycled to the injection well via the production well.

[0122] 18. A system as described in any of the clauses herein, wherein a portion of the injection well is fluidly connected to the injection pipeline so that in operation, the process fluid is provided to the first subterranean zone via the injection pipeline.

[0123] 19. The system of clause 18, further comprising a separation system comprising an activated carbon filter and / or a membrane, wherein the separation system is positioned to separate carbon dioxide and nitrogen.

[0124] 20. The system of any of the clauses herein, wherein the process fluid is at least one of pure carbon dioxide or a gas stream comprising at least 90% carbon dioxide.

[0125] 21. A system as described in any of the clauses herein, wherein the adjacent formation is a first adjacent formation on a first side of the second underground region, and the system further includes a second adjacent formation on a second side of the second underground region opposite to the first side, wherein the second adjacent formation fluid is connected to the injection pipe.

[0126] 22. A system as described in any of the clauses herein, wherein the process fluid is at least one of pure carbon dioxide or a gas stream containing at least 90% carbon dioxide, and wherein a portion of the fluid from the injection well is connected to the injection pipeline so that, in operation, the process fluid is provided to the first underground area via the injection pipeline.

[0127] 23. A system as described in any of the clauses herein, wherein the process fluid is at least one of pure carbon dioxide or at least 90% carbon dioxide, the system further comprising a production well extending from the second underground region toward the ground and configured to receive a gas stream containing carbon dioxide from the second underground region, wherein, in operation, at least some of the carbon dioxide in the gas stream received by the production well is recycled to the injection well via the production well.

[0128] 24. The system of any of the clauses herein, wherein the first subterranean zone supports a reaction with the oxidant in which a product gas comprising hydrogen is produced.

[0129] 25. The system of any of the clauses herein, wherein, in operation, the process fluid injected via the injection well cools the second subterranean zone and displaces at least some contaminants from the second subterranean zone.

[0130] 26. A method for sequestering carbon in a subterranean carbonaceous formation and / or quenching a subterranean carbonaceous formation with carbon, the method comprising:

[0131] extracting a product gas from a first subterranean zone of the carbonaceous formation via a production conduit, wherein the first subterranean zone supports a reaction with an oxidant in which a product gas comprising hydrogen is produced; and

[0132] A process fluid containing carbon is injected through an injection well into a second subsurface zone of the carbonaceous formation, wherein volatile materials have been removed from the second subsurface zone, and wherein the second subsurface zone is laterally spaced from the first subsurface zone by an adjacent formation.

[0133] 27. The method of any one of the clauses herein, wherein injecting the process fluid comprises injecting the process fluid at a pressure of at least 10 barg and / or a flow rate of at least 5 tonnes / hour.

[0134] 28. The method of any one of the clauses herein, wherein injecting the process fluid comprises (i) injecting the process fluid at a first pressure of at least 20 barg, and (ii) injecting the process fluid at a second pressure of no more than 5 barg after injecting at the first pressure.

[0135] 29. The method of clause 28, further comprising, after injecting the process fluid at the second pressure, injecting the process fluid at a third pressure higher than the second pressure.

[0136] 30. A method as described in any of the clauses herein, wherein the carbonaceous formation is at a static rock pressure of at least 15 barg, and wherein injecting the process fluid comprises injecting carbon dioxide into the second underground zone at an injection pressure less than 30% and within 30% of the static rock pressure.

[0137] 31. A method as described in any of the clauses herein, wherein injecting the process fluid comprises increasing the pressure of the process fluid from an initial pressure to at least 25 barg within a period of time not exceeding 60 minutes.

[0138] 32. A method as set forth in any of the clauses herein, wherein:

[0139] the adjacent formation is a first adjacent formation on a first side of the second subterranean region,

[0140] The carbonaceous formation further includes a second adjacent formation on a second side of the second subterranean region opposite the first side, and

[0141] The hydraulic resistance of the second adjacent formation is higher than the hydraulic resistance of the first subterranean region and the second subterranean region.

[0142] 33. The method of any of the clauses herein, wherein the first subterranean region has a first hydraulic resistance, the second subterranean region has a second hydraulic resistance, and the adjacent formation has a third hydraulic resistance greater than the first hydraulic resistance and the second hydraulic resistance.

[0143] 34. The method of any of the clauses herein, wherein the process fluid comprises flue gas or at least 90% carbon dioxide.

Claims

1. A system for using a subterranean carbonaceous formation, the system comprising: a process fluid source comprising at least one of (i) at least 90% carbon dioxide, (ii) flue gas, (iii) nitrogen, or (iv) steam; an injection well fluidly coupled to the process fluid source and extending from the surface to a subterranean zone including contaminants, wherein volatile materials have been at least partially removed from the subterranean zone; and a production well extending from the underground zone to the surface; Wherein, in operation, the process fluid cools the subterranean zone.

2. The system of claim 1, wherein the process fluid comprises pure carbon dioxide.

3. The system according to claim 2, wherein: In operation, after cooling the subterranean zone, the process fluid displaces at least some contaminants from the subterranean zone.

4. The system of claim 1 further comprising a compressor above the surface, wherein an inlet of the compressor is fluidly coupled to the production well and an outlet of the compressor is fluidly coupled to the injection well.

5. The system of claim 4, further comprising a separator unit between the production well and the inlet of the compressor, wherein the separator unit is configured to separate syngas from the process fluid traveling through the production well.

6. The system according to claim 1, wherein: In operation, the process fluid is directed from the subterranean region to the surface via the production well, and wherein at least a portion of the process fluid directed toward the surface via the production well is recirculated to the subterranean region via the injection well.

7. A system for sequestering carbon in a subterranean carbonaceous formation and / or quenching a subterranean carbonaceous formation with carbon, the system comprising: an injection conduit extending to a first subterranean zone of a carbonaceous formation, wherein the injection conduit is configured to be fluidly coupled to a source of an oxidant, and wherein the first subterranean zone has a first hydraulic resistance; a production conduit spaced apart from the injection conduit and extending from the first subterranean zone toward the surface; and an injection well fluidly coupled to a source of a process fluid and extending toward a second subterranean zone of the carbonaceous formation, wherein the process fluid comprises carbon dioxide, and wherein: the second underground region having a second hydraulic resistance, the second subterranean region is laterally spaced from the first subterranean region by an adjacent formation having a third hydraulic resistance greater than the first hydraulic resistance and the second hydraulic resistance, and The second subterranean zone includes contaminants.

8. The system according to claim 7, wherein: In operation: The adjacent strata have fluid pressure, The first subsurface zone has a first pressure that is lower than a fluid pressure in an adjacent formation, and The second subterranean zone has a second pressure that is higher than a fluid pressure in an adjacent formation.

9. The system of claim 8, wherein the first pressure is (i) lower than the second pressure, (ii) less than an injection pressure of the injection pipeline, and (iii) at least 20 barg.

10. The system of claim 8, wherein the first subterranean region comprises an active plate and the second subterranean region comprises a depletion plate, and wherein the first pressure in the first subterranean region is less than the second pressure in the second subterranean region, such that, in operation, at least a portion of the process fluid injected through the injection well migrates from the second subterranean region toward the first subterranean region through the adjacent formation of the carbonaceous formation.

11. The system of claim 7, wherein the carbonaceous formation is at a lithostatic pressure of at least 15 barg, and wherein the injection well is configured to deliver the carbon dioxide to the second subsurface zone at an injection pressure within 30% of the lithostatic pressure.

12. The system of claim 7, further comprising a power generation facility fluidly coupled to the first subterranean zone via the production well such that the power generation facility is configured to receive a product gas.

13. The system of claim 7, wherein the second subsurface region comprises a depletion plate having a cross-sectional dimension of at least 1.0 meter.

14. The system of claim 7, further comprising a production well extending from the second subterranean zone toward the surface, wherein: The injection well is configured to receive the process fluid comprising a first amount of carbon dioxide, and the production well is configured to receive at least a portion of the process fluid comprising a second amount of carbon dioxide, the second amount of carbon dioxide being less than the first amount of carbon dioxide.

15. The system of claim 7, further comprising a separation system comprising an activated carbon filter and / or a membrane, wherein the separation system is positioned to separate carbon dioxide and nitrogen.

16. The system of claim 7, wherein the process fluid comprises at least one of pure carbon dioxide or a gas stream comprising at least 90% carbon dioxide.

17. A system according to claim 7, wherein the adjacent formation is a first adjacent formation on a first side of the second underground area, and the system also includes a second adjacent formation on a second side of the second underground area opposite to the first side, wherein the second adjacent formation fluid is connected to the injection pipe.

18. The system according to claim 7, wherein: The process fluid includes at least one of pure carbon dioxide or at least 90% carbon dioxide, and the system also includes a production well, which extends from the second underground area toward the ground and is configured to receive a gas flow including carbon dioxide from the second underground area, wherein, in operation, at least some of the carbon dioxide in the gas flow received by the production well is recycled to the injection well via the production well.

19. The system of claim 7, wherein the first subterranean zone supports a reaction with the oxidant in which a product gas comprising hydrogen is produced.

20. The system of claim 7, wherein: In operation, the process fluid injected via the injection well cools the second subterranean zone and displaces at least some contaminants from the second subterranean zone.

21. A method for sequestering carbon in a subterranean carbonaceous formation and / or quenching a subterranean carbonaceous formation with carbon, the method comprising: extracting a product gas from a first subsurface zone of a carbonaceous formation via a production conduit, wherein the first subsurface zone supports a reaction with an oxidant in which a product gas comprising hydrogen is produced; and A process fluid comprising carbon is injected into a second subterranean zone of the carbonaceous formation via an injection well, wherein volatile materials have been removed from the second subterranean zone, and wherein the second subterranean zone is laterally spaced from the first subterranean zone by adjacent formations.

22. The method of claim 21, wherein injecting the process fluid comprises injecting the process fluid at a pressure of at least 10 barg and / or a flow rate of at least 5 tons / hour.

23. The method of claim 21, wherein injecting the process fluid comprises (i) injecting the process fluid at a first pressure of at least 20 barg, and (ii) injecting the process fluid at a second pressure of no more than 5 barg after injecting at the first pressure.

24. The method according to claim 23, further comprising: After injecting the process fluid at the second pressure, injecting the process fluid at a third pressure higher than the second pressure.

25. The method of claim 21, wherein the carbonaceous formation is at a geostatic pressure of at least 15 barg, and wherein injecting the process fluid comprises injecting carbon dioxide into the second subsurface zone at an injection pressure less than the geostatic pressure and within 30% of the geostatic pressure.

26. The method of claim 21, wherein injecting the process fluid comprises increasing the pressure of the process fluid from an initial pressure to at least 25 barg.

27. A method according to claim 26, wherein increasing the pressure of the process fluid to at least 25 barg occurs over a period of time not exceeding 60 minutes.

28. The method of claim 21, wherein: the adjacent formation is a first adjacent formation on a first side of the second subterranean region, The carbonaceous formation also includes a second adjacent formation on a second side of the second subterranean region opposite the first side, and The hydraulic resistance of the second adjacent formation is higher than the hydraulic resistance of the first subterranean region and the second subterranean region.

29. The method according to claim 21, wherein: The first subterranean region has a first hydraulic resistance, the second subterranean region has a second hydraulic resistance, and the adjacent formation has a third hydraulic resistance greater than the first hydraulic resistance and the second hydraulic resistance.

30. The method of claim 21, wherein the process fluid comprises flue gas or at least 90% carbon dioxide.

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