Treatment of previously-produced petroleum reservoirs for production of hydrogen

Abstract

Implementations include treating previously-produced petroleum reservoirs to generate and produce hydrogen through the creation of in-situ reactors wherein combustion, gasification, steam-reforming, water-gas shift, and aquathermolysis reactions occur. The hydrogen production operation may involve stimulating the depleted zones of the reservoir that result from the prior oil and natural gas operation. The hydrogen-containing gas may then be produced to the surface.

Description

TREATMENT OF PREVIOUSLY-PRODUCED PETROLEUM RESERVOIRS FOR PRODUCTION OF HYDROGENCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U.S. Provisional Application No. 63 / 562,043, filed on 6 March 2024, the entire disclosure of which is hereby incorporated by reference.BACKGROUND

[0002] Oil is a naturally-occurring, unrefined fluidic petroleum product comprising hydrocarbon components. Oil may be described as heavy oil, extra heavy oil, or bitumen, which can be distinguished from each other based on densities and viscosities. For example, heavy oil may be classified as having a density of which is between 920 and 1000 kg / m3, and extra heavy oil or bitumen may be classified as having a density greater than 1000 kg / m3. Oil may additionally include nonhydrocarbon elements entrained in the oil through, for example, suspension, sorption, emulsion, molecular bonding, or other means, which can be co-produced or mobilized by or with the oil. The energy contained in oil and natural gas is chemical energy that is generated when they are combusted.

[0003] Conventional oil is refined and treated to create fuels and chemical feedstocks for the petrochemical industry. Following the extraction of heavy oil and bitumen, an upgrading process typically transforms them into synthetic crude oil. This synthetic crude oil undergoes refining processes, ultimately producing transportation fuels and feedstocks vital for the petrochemical industry. Combusting these fuels, whether from conventional oil or heavy oil or extra heavy oil, generates carbon dioxide emissions, contributing to greenhouse gas emissions.

[0004] Natural gas contains methane and when produced from gas reservoirs, it is typically combusted as fuel or used as a chemical feedstock. When combusted, carbon dioxide emissions are generated contributing to greenhouse gas emissions.

[0005] A petroleum reservoir may include subsurface formations comprising porous matrices, which may comprise petroleum fluids including oil and gas. Examples of petroleum reservoirs include heavy oil reservoirs and oil sands reservoirs. A heavy oil reservoir may be a petroleum reservoir comprising porous rock that includes heavy oil. An oil sands reservoir may be a petroleum reservoir comprising porous rock that includes extra heavy oil or bitumen. Petroleum reservoirs may also includea water phase, which may refer to the interstitial water present in the porous reservoir rock.

[0006] Numerous oil and gas reservoirs are widely distributed across the globe, and many technologies are employed for the extraction of oil or gas from these reservoirs. These technologies encompass primary extraction methods, as well as enhanced oil recovery processes, including but not limited to water flooding, steam flooding, chemical flooding, and hydraulically stimulated recovery processes such as hydraulic fracturing of low-permeability oil and gas reservoirs, all aimed at augmenting the production of additional hydrocarbons from conventional oil and gas reservoirs.SUMMARY

[0007] This Summary is intended to introduce, in an abbreviated form, various topics to be elaborated upon below in the Detailed Description. This Summary is not intended to identify key or essential aspects of the claimed invention. This Summary is similarly not intended for use as an aid in determining the scope of the claims.

[0008] In some aspects, the techniques described herein relate to a method for recovering a hydrogen-bearing gas from a reservoir, including: determining a location of a depleted zone within the reservoir, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid, is subterranean to a surface of the earth, and includes an existing well previously used for producing the petroleum fluid; retrofitting the existing well located in the depleted zones with thermal completions to convert the existing well to an injection well; injecting an oxidant via the injection well into the depleted zone; allowing one or more of a gasification reaction, a steam-reforming reaction, a water-gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogenbearing gas; and producing the hydrogen-bearing gas to the surface through a production well.

[0009] In some aspects, the techniques described herein relate to a method wherein the oxidant includes an oxygen-containing gas including one or more of air, or oxygen- enriched air, or pure oxygen.

[0010] In some aspects, the techniques described herein relate to a method, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

[0011] In some aspects, the techniques described herein relate to a method, wherein after the injecting the oxidant and before the allowing the one or more of gasification, steam-reforming, water-gas shift, or aquathermolysis reactions to occur in the depleted zone, the injecting the oxidant is stopped.

[0012] In some aspects, the techniques described herein relate to a method, wherein the injecting the oxidant is stopped when a measured oxidant partial pressure reaches a target oxidant partial pressure and a measured reactive zone temperature reaches a target reactive zone temperature.

[0013] In some aspects, the techniques described herein relate to a method, wherein the injecting the oxidant is restarted.

[0014] In some aspects, the techniques described herein relate to a method, wherein the injecting the oxidant is restarted when the measured oxidant partial pressure falls below the target oxidant partial pressure or the measured reactive zone temperature falls below the target reactive zone temperature.

[0015] In some aspects, the techniques described herein relate to a method, further including, when a measured reactive zone partial pressure falls below a target reactive zone partial pressure: stopping the producing the hydrogen-bearing gas; waiting for the one or more of the gasification reaction, the steam-reforming reaction, the water-gas shift, or the aquathermolysis reaction to yield sufficient hydrogen-bearing gas to increase the measured oxidant partial pressure to the target oxidant partial pressure; and resuming the producing the hydrogen-bearing gas to the surface through the production well.

[0016] In some aspects, the techniques described herein relate to a method, further including installing the production well.

[0017] In some aspects, the techniques described herein relate to a method, wherein the production well includes a second existing well previously used for producing the petroleum fluid.

[0018] In some aspects, the techniques described herein relate to a method, further including injecting an enhancement into the depleted zone.

[0019] In some aspects, the techniques described herein relate to a method, wherein injecting the enhancement is done simultaneously with injecting the oxidant.

[0020] In some aspects, the techniques described herein relate to a method, wherein the enhancement includes steam.

[0021] In some aspects, the techniques described herein relate to a method, wherein the enhancement includes pre-heated water.

[0022] In some aspects, the techniques described herein relate to a method, wherein the enhancement includes methane.

[0023] In some aspects, the techniques described herein relate to a method, wherein the enhancement includes fuel.

[0024] In some aspects, the techniques described herein relate to a method, wherein the enhancement includes nitrous oxide.

[0025] In some aspects, the techniques described herein relate to a method, wherein a new injection well is installed in a non-depleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

[0026] In some aspects, the techniques described herein relate to a method, wherein a new production well is installed in a non-depleted zone to enhance the producing the hydrogen-bearing gas to the surface.

[0027] In some aspects, the techniques described herein relate to a method, wherein an ignitor is disposed proximate the injection well or the production well and the method further includes, using the ignitor, igniting the oxidant and remaining petroleum fluids in the depleted zone.

[0028] In some aspects, the techniques described herein relate to a method, further including treating one or more of the injection well or the production well with acid to enhance a capability of fluid flow therethrough.

[0029] In some aspects, the techniques described herein relate to a method, further including stimulating the reservoir using one or more of hydraulic fracturing to enhance a permeability of the reservoir.

[0030] In some aspects, the techniques described herein relate to a method, wherein the hydraulic fracturing employs a proppant including a catalyst to enhance a hydrogengenerating reaction in the reservoir.

[0031] In some aspects, the techniques described herein relate to a method, wherein the catalyst includes one or more of pure iron, iron oxide, magnesium, chromium, copper, zinc, or aluminum.

[0032] In some aspects, the techniques described herein relate to a system for recovering a hydrogen-bearing gas from a reservoir, including: a reservoir, wherein: the reservoir is a previously-produced petroleum reservoir which previously produced apetroleum fluid and is subterranean to a surface of the earth, and the reservoir includes a depleted zone; an injection well, wherein the injection well was created by retrofitting an existing well of the reservoir previously used for producing the petroleum fluid with thertmal completions to convert the existing well to the injection well, and wherein the injection well is configured for the injection of an oxidant therethrough into the depleted zone to cause one or more of a gasification reaction, a steam-reforming reaction, a water-gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogen-bearing gas; and a production well configured for producing the hydrogen-bearing gas to the surface.

[0033] In some aspects, the techniques described herein relate to a system wherein the oxidant includes an oxygen-containing gas including one or more of air, or oxygen- enriched air, or pure oxygen.

[0034] In some aspects, the techniques described herein relate to a system, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

[0035] In some aspects, the techniques described herein relate to a system, further including a pressure sensor configured to measure a oxidant partial pressure.

[0036] In some aspects, the techniques described herein relate to a system, further including a temperature sensor configured to measure a reactive zone temperature.

[0037] In some aspects, the techniques described herein relate to a system, wherein the production well includes a second existing well previously used for producing the petroleum fluid.

[0038] In some aspects, the techniques described herein relate to a system, further including a new injection well installed in a non-depleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

[0039] In some aspects, the techniques described herein relate to a system, further including a new production well installed in a non-depleted zone to enhance the producing the hydrogen-bearing gas to the surface.

[0040] In some aspects, the techniques described herein relate to a system, further including an ignitor is disposed proximate the injection well or the production well and wherein the ignitor is configured to ignite the oxidant and remaining petroleum fluids in the depleted zone.

[0041] In some aspects, the techniques described herein relate to a system, wherein one or more of the injection well or the production well are treated with acid to enhance a capability of fluid flow therethrough.BRIEF DESCRIPTION OF THE FIGURES

[0042] For a fuller understanding of the nature and objects of the disclosure, reference should be made to the following detailed description taken in conjunction with the accompanying drawings, in which:

[0043] FIG. 1 illustrates a conventional method 100 for producing oil or gas from a reservoir.

[0044] FIG. 2 illustrates a method 200 for producing hydrogen from a previously-produced reservoir, according to one or more implementations herein.

[0045] FIGs. 3A-3E illustrate examples and phases of a well system 300, according to one or more implementations herein.DETAILED DESCRIPTION

[0046] It is to be understood that the invention is not limited in its application to the details of construction and the arrangements of components and / or method steps set forth in the following description or illustrated in the drawings, and phraseology and terminology used herein is for the purpose of description and should not be regarded as limiting. The invention is capable of other embodiments and of being practiced or being carried out in various ways. Accordingly, other aspects, advantages, and modifications will be apparent to those skilled in the art to which the invention pertains, and these aspects and modifications are within the scope of the invention, which is limited only by the appended claims.

[0047] Design elements of oil and natural gas recovery processes include well design, number of injection and production wells, arrangement of wells within the reservoir, and operating ( / .e., injection and production) strategy for the production of oil or natural gas or both from the reservoir, such as pressure and flow rate management, stimulation, and scheduling of well injection and production operations.

[0048] In conventional oil reservoirs, oil is produced from the reservoir under natural drive mechanisms such as oil expansion, solution-gas drive, formation recompaction, and water drive. Production is stopped when the pressure in the reservoir is insufficient to move the oil from the reservoir to the surface. When production is stopped, it is typical that more than 50% of the oil originally in the reservoir remained in thereservoir. Given the sunk costs of the well infrastructure, there is a need options for getting more energy, in the form of oil or natural gas or other chemical species, from the reservoir.

[0049] FIG. 1 illustrates a conventional method 100 for producing oil or gas from a reservoir. At 102, a petroleum reservoir containing one or both of oil or natural gas may be provided. At 104, a primary recovery process is performed. Production wells are placed within the reservoir and under natural drive mechanisms, oil or natural gas or both are produced to the surface. At 106, one or more follow-up secondary recovery processes are performed. Such secondary recovery processes may include producing petroleum fluids by stimulation (e.g., water flood, gas flood, chemical flood, thermal stimulation, or hydraulic fracturing). At 108, a tertiary recovery process may be performed. If stimulation is required from the start of the operation, then the reservoir stimulated, for example, by hydraulic fracturing in tight low permeability reservoirs or steam-injection in viscous oil reservoirs. At 110, an economic limit of recovery of petroleum fluids may be reached, and the recovery process of petroleum fluids may be stopped. After a period, the reservoir operation is not economic when the operations cost more than the revenue from the sales of oil or natural gas or both and the production operation is stopped. At 112, the wellhead may be removed, and the well may be abandoned. The land may be returned to its state prior to the operation.

[0050] Enhanced oil recovery (EOR) methods can be done where water or polymer or alkali or other chemical agents or gas, for example, carbon dioxide, is injected into the reservoir. The injection of fluids into the reservoir raises its pressure and displaces the reservoir fluids, including oil, natural gas, and formation water, within the reservoir. The injected gas can be as a bulk gas phase or a foam. Chemical agents have the benefit of aiding production of oil by altering the wettability of the reservoir rock or changing the relative flow of oil relative to that of water within the reservoir by altering the interfacial tension between the oil and water. When displaced to a production well, the reservoir fluids can be produced to the surface. EOR processes are used to enhance the production of oil beyond that achieved in primary production. At some point in the EOR operation, the cost of the EOR operation exceeds that of the oil revenues and at that point the recovery process is stopped. Typically, at the end of the EOR operation, the oil remaining in the reservoir is a large fraction of the original oil that was in the reservoir. For water floods, up to 65% of the original oil remains in the reservoir at the economic end ofthe operation. Typically, over 50% of the original oil remains in the reservoir at the economic end of the EOR operation.

[0051] Conventional natural gas reservoirs are produced by opening the reservoir and allowing it to produce the natural gas under its pressure within the reservoir. The recovery mechanisms are gas expansion, formation recompaction, and water-drive. After the pressure in the reservoir has been depleted to a point that the well operation is no longer economically viable, the well is shut in. Typically, up to 50 to 80% of the original natural gas in the reservoir is recovered by the end of the operation. This means that there is a large amount of natural gas that remains in the reservoir after operations have stopped.

[0052] To improve the recovery of gas from natural gas reservoirs, enhanced gas recovery (EGR) processes can be used where a gas, for example, carbon dioxide, is injected into the gas reservoir with the goal of displacing the gas to a production well. The injection of the gas into the reservoir raises the pressure in the reservoir enabling more production of natural gas from the reservoir.

[0053] Heavy oil is crude oil where the viscosity of the oil is greater than 100 cP and in some cases is greater than 1 ,000 cP. In heavy oil systems that have sufficiently high solution gas, the heavy oil can be produced as foamy oil to the surface under primary production. However, when the solution gas or pressure or both are depleted, production stops. In typical cold production heavy oil systems, between 5 and 15% of the heavy is recovered to the surface.

[0054] In extra heavy oil (bitumen) systems, the oil typically has viscosity greater than 10,000 cP and traditional extraction techniques become impractical due to the oil's inherent viscosity at original reservoir conditions. To recover these resources, first the viscosity of the oil must be reduced and this is most commonly done by using thermal recovery processes. A common method to heat the reservoir is by injecting high pressure and high temperature steam into the reservoir. For example, in Steam-Assisted Gravity Drainage (SAGD), steam is injected into the upper horizontal well and reservoir fluids, as well as steam condensate, is produced from the reservoir by using a parallel horizontal well a few meters below the injection well. At some point of time, the process becomes uneconomic because the amount of steam (process cost) is too large versus the amount of oil (process revenue) being produced. In Cyclic Steam Stimulation (CSS), a target volume of steam is injected into the reservoir through a well after which the well is shut in for a period of time after which reservoir fluids are produced from the reservoir. The steamheats the oil thereby lowering its viscosity enabling its production to the surface. For CSS, multiple injection-soak-production cycles are done until the thermal stimulation and drive pressure is insufficient to move oil to the surface after which the process is stopped. Even with thermal recovery processes, not all of the original oil in place within the reservoir is produced from the reservoir. One key feature of the steam-based recovery processes is that at the end of life, the pore space in the reservoir is at elevated temperature with large amounts of steam.

[0055] In other reservoirs, air is injected into the reservoir to generate gas or heat or both to enable oil recovery. The heat can mobilize the oil enabling its flow to a production well and the gas can displace oil to the production well. These processes, such as Toe-to-Heel Air Injection (THAI) have relatively low recovery factor with typically less than 15% recovery of the original oil in place to the surface.

[0056] In tight low-permeability oil or natural gas reservoirs, the oil or gas has low viscosity but the permeability of the reservoir is too low for economic production of oil or natural gas to the surface. In coal bed reservoirs containing natural gas, the permeability of the coal seams and surrounding formations are insufficient to produce economic amounts of natural gas. In these reservoirs, hydraulic fracturing is a method where high pressure fluids and solids are placed within the reservoir creating cracks within the reservoir that enhances its overall permeability. This improves the mobility of the oil or natural gas in the reservoir enabling its production to surface and the reservoir fluids are produced to the surface under fluid expansion and solution gas drive. The process is stopped after the reservoir pressure is not able to move the reservoirs fluids from the reservoir to the surface. In these recovery processes, typically between 5 and 20% of the oil in oil reservoirs and between 20 and 60% of the natural gas in natural gas reservoirs is produced to the surface before the process is rendered uneconomic.

[0057] In all of the recovery processes described in the preceding descriptions for oil and natural gas reservoirs, at the economic end of the recovery process where the process is stopped, there remains a large amount of oil or natural gas or both in the reservoir. In other words, there remains hydrocarbons within the reservoir at the end of the recovery process that are unused and have no opportunity for production to the surface given economic constraints. There is a need to make more use of the reservoir fluids for the production of energy.

[0058] There is a continuous need to produce fuels with relatively low carbon intensity from oil and natural gas reservoirs. Producing hydrogen from oil reservoirs instead of oilis a clean energy option, with the produced hydrogen also serving as feedstock for chemicals such as methanol and ammonia or for use in refining processes.

[0059] The amount of petroleum (oil or gas) produced from a reservoir as a percent of the original petroleum (oil or gas) is generally lower than 100% and, in many oil and gas production operations, it is less than 50% when the operation has reached its economic commercial threshold — at which point the operation is stopped. This means that there is a large fraction of the original petroleum that remains in the reservoir after the petroleum production operation is ended. Furthermore, given that the original petroleum remaining in the reservoir is no longer economic, there is no commercial value for the petroleum reservoir at the end of the operation.

[0060] To produce hydrogen from oil and natural gas reservoir after they have been produced is a clean option for energy production extending the useful life of the wells and infrastructure associated with the prior oil and natural gas production operation.

[0061] Globally, there is an ongoing need to produce energy and to store energy.Hydrogen (H2) is a versatile and clean energy carrier in the context of addressing climate issues. Hydrogen holds significant potential as a sustainable energy source due to its capacity to store and deliver energy efficiently, especially in applications such as transportation and industrial processes. It has the capacity to reduce greenhouse gas emissions when produced using low-carbon methods, such as electrolysis powered by renewable energy sources. By embracing hydrogen as an alternative to fossil fuels, the adverse impacts of climate change can be mitigated, moving humanity towards a more sustainable and environmentally responsible energy landscape. However, the production, transportation, and utilization of hydrogen should also align with stringent environmental standards to fully realize its potential to mitigate climate issues and foster a greener future.

[0062] In a state ready for end-use, hydrogen is a clean fuel — its end use yields no greenhouse gases as the only product is water. Hydrogen has high energy density and the ability to release that energy when needed making it a viable option for long-term energy storage. When consumed in fuel cells or hydrogen turbines, hydrogen can be converted back into electricity and heat with minimal environmental impact, offering a clean and efficient energy solution.

[0063] Hydrogen is also needed as a feedstock material for chemicals. In this application also, hydrogen may contribute to changing the chemical industry and a more sustainable and environmentally friendly future. Hydrogen, when used in variouschemical processes, may enable the production of a wide range of chemicals such as ammonia, methanol, and various petrochemicals.

[0064] Hydrogen may be found within all three phases of hydrocarbon-containing oil and gas systems (e.g., oil, gas, and water).

[0065] Oils (e.g., heavy oils, extra heavy oils, bitumen, or other oils) can be cold-produced under solution gas foamy oil flow in systems having a viscosity lower than about 50,000 cP. For systems with original oil viscosity greater than about 50,000 cP, the inherent viscosity of the oil at its natural reservoir conditions, for example, at a natural reservoir temperature ( / .e., an ambient temperature of a cold or unheated reservoir), renders extracting oil using traditional techniques impractical. Therefore, heavy oil and bitumen conventionally undergo thermal treatment to reduce their viscosity, facilitating enhanced reservoir mobility and enabling extraction to the surface. Furthermore, this thermal treatment promotes improved fluid (e.g., liquid or gas) flow within the reservoir.

[0066] Following the extraction of heavy oil and bitumen, these products are conventionally subjected to an upgrading process, whereby they are transformed into synthetic crude oil. Subsequently, the synthetic crude oil undergoes refining processes, ultimately yielding transportation fuels and feedstocks essential for the petrochemical industry. When the fuel is combusted for generation of heat or in combustion engines, it generates greenhouse gas emissions, namely carbon dioxide emissions, which are released to the atmosphere.

[0067] Given climate change and the need to reduce greenhouse gas emissions from human activities, there is a need to obtain and use fuels that do not emit greenhouse gases on combustion. Oil and natural gas systems, containing hydrocarbons and water, also contain hydrogen. Extracting hydrogen from these phases could yield a clean fuel with no greenhouse gas emissions on end use — only water.

[0068] One conventional method of producing hydrogen is steam methane reforming (SMR). SMR is an industrial process for producing hydrogen and is often employed in the production of hydrogen for various industrial applications. In this process, natural gas, primarily composed of methane (CH4), is combined with high- temperature steam in the presence of a catalyst to produce hydrogen gas (H2) and carbon dioxide (CO2). While SMR can be efficient and cost-effective, it has notable environmental shortcomings. One shortcoming of SMR is the release of carbon dioxide, a potent greenhouse gas, into the atmosphere as a by-product of thereaction. The environmental impact of SMR is exacerbated when the natural gas feedstock is derived from fossil fuel sources, which further contributes to carbon emissions and climate change. These emissions can be offset somewhat through the use of carbon capture and sequestration technologies, though such technologies require additional equipment and energy to operate.

[0069] Another conventional method of producing hydrogen is electrolysis. Electrolysis is a chemical process that involves the use of electrical energy to split water molecules into hydrogen and oxygen gases, which can then be harnessed as a clean fuel source. This method may reduce carbon emissions, since hydrogen, when used as an energy carrier, produces no greenhouse gases. However, electrolysis has several shortcomings that impact its viability. Electrolysis’s dependence on input electricity ties its environmental benefits to its source of electricity. If the ultimate source of the electricity used includes burning fossil fuels, the process may inadvertently contribute to emissions. Furthermore, the efficiency and cost of electrolysis technologies make it less economical compared to conventional fossil fuels.

[0070] Implementations include treating previously-produced petroleum reservoirs to generate and produce hydrogen through the creation of in-situ (e.g., the environment of a subsurface petroleum reservoir) reactors wherein combustion, gasification, steam-reforming, water-gas shift, and aquathermolysis reactions occur. The hydrogen production operation may involve stimulating the depletion zones (e.g., regions of the reservoir surrounding the well which have been depleted of petroleum fluids) of the reservoir that result from the prior oil and natural gas operation. The hydrogen-containing gas may then be produced to the surface.

[0071] There exist depleted zones (depleted with respect to oil) within previously-produced oil (conventional oil and heavy oil) reservoirs following an economic end of the recovery operation. These depleted zones can be filled with gas (e.g., from the solution gas that was originally in the reservoir or injected gas from the recovery process) or water (e.g., formation or injected water). The depleted zones may also be at a depleted pressure relative to the original virgin pressure of the reservoir. These depleted zones may provide for the creation and placement of in-situ reactors for in-situ generation of hydrogen. The depleted zones have low pressure and gas phase present, which enables injection of oxygen into the reservoir as well as gas phase reactions that enable the generation of hydrogen within the reservoir. For heavy oil systems produced under cold production, the depleted zones can take the form of wormholes as well as oil depleted zones within the reservoir.

[0072] In previously-produced extra heavy oil where thermal steam-based stimulation was done, at the economic end of the recovery process, there exist depleted zones (e.g., depleted with respect to oil) within the reservoir. The depleted zones are typically filled with saturated steam (e.g., liquid and vapour phase water) at elevated temperature equal to that of the corresponding saturated steam temperature. In steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) operations, the temperature of the depleted zones can be greater than 160°C and in some cases greater than 200°C. The elevated temperature depleted zones may provide for the creation and placement of in-situ reactors for in-situ generation of hydrogen. This is advantageous in post-SAGD and post-CSS operations since the temperature of the depleted zone is at elevated temperature which supports the reactions and the steam present in the depleted zones in the reservoir at the end of the oil production operation participates in the water-gas shift reaction to generate hydrogen. Furthermore, the steam-filled depleted zone in the post-SAGD and post- CSS are gas-filled zones which enable gas-phase reactions enabling the production of hydrogen. For air injection processes, similarly, there exists a depleted zone that may provide for the creation and placement of in-situ reactors for in-situ generation of hydrogen.

[0073] In previously-produced natural gas reservoirs, the gas reservoir may have depleted zones with lower pressure. As such, these depleted zones are ideal zones for creation and placement of in-situ reactors for the in-situ generation of hydrogen.

[0074] In previously-produced tight low permeability oil reservoirs that were hydraulically stimulated or fractured to enable production, at the economic end of the recovery process, there exists a depleted zone around the production well where the oil saturation is reduced, the pressure is reduced below that of the original reservoir pressure, and there is gas phase present in the depleted zone. These depleted zones may provide for the creation and placement of in-situ reactors for in-situ generation of hydrogen. This is because the depleted zones have low pressure and gas phase present that enables injection of oxygen into the reservoir as well as gas phase reactions that enable the generation of hydrogen within the reservoir. The high temperatures (e.g., greater than 350°C) that occurs within the in-situ reactor during oxygen injection also further stimulate the reservoir creating thermal-induced fracturing of the tight rock which aids in supplying more oil to the reactor enabling more reactions.

[0075] In previously-produced tight low permeability gas and gas-condensate reservoirs that were hydraulically stimulated or fractured to enable production, at the economic end of the recovery process, there exists a depleted zone around the production well where the pressure is reduced below that of the original reservoir pressure. Similar to hydraulically fractured oil reservoirs, these depleted zones may provide for the creation and placement of in-situ reactors for in-situ generation of hydrogen.

[0076] In oil reservoirs, the process of in situ combustion and in-situ gasification may facilitate the generation of a gas mixture, which includes hydrogen as one of its components. The gas mixture may also comprise other gases resulting from combustion reactions in the reservoir, such as carbon dioxide, carbon monoxide, water vapor, methane, hydrogen sulphide, and additional gases.

[0077] Various techniques for producing hydrogen and synthesis gas have been disclosed in patents, including U.S. Patent 11 ,530,603, incorporated herein by reference in its entirety, which outlines a method involving the injection of an oxidizing agent into a petroleum reservoir for heating and subsequent hydrogen generation. Another method, described in patent application U.S. Pub. 2021 / 0047905, incorporated herein by reference in its entirety, utilizes in-situ gasification to produce synthesis gas. However, these approaches lack specific guidance on an injection and production method that maximizes hydrogen generation. In a study by Kapadia et al. (2013) [Applied Energy 107:281-296, 2013, D0l:10.1016 / j.apenergy.2013.02.035], incorporated herein by reference in its entirety, steam and oxygen injection into an oil reservoir for in-situ gasification is discussed, demonstrating the feasibility of hydrogen production under steam- oxygen cycles and continuous injection. Nevertheless, the study does not provide an optimal strategy for injection and production.

[0078] Implementations of methods and systems described herein leverage previously- produced petroleum resources as sources of fuel that can be combusted in-situ for the generation of heat and carbon oxides which in turn enables the production of hydrogen within the reservoir.

[0079] Implementations may treat previously-produced oil reservoirs (conventional oil, heavy oil, extra heavy oil, oil sands, and carbonate oil reservoirs) or treat previously-produced natural gas reservoirs where oxygen or an oxygen-rich gas stream is injected into the reservoir causing in-situ combustion of the petroleum contained in the reservoir. The remaining petroleum within the reservoir may undergo reactions which generate heat, steam, and carbon oxides, among otherproducts. The heat may also generate additional steam from the formation water that was contained in the reservoir.

[0080] In the gas phase, the heat and carbon monoxide may enable a water-gas shift reaction, which may generate hydrogen within the reservoir. Aquathermolysis (hydrous pyrolysis), gasification, and steam reforming reactions may also generate additional hydrogen.

[0081] The heat generated by the combustion reactions may also enable thermal cracking (pyrolysis) that leads to the formation of carbon-rich residues such as coke within the formation. Steam reforming of coke can generate more hydrogen.

[0082] Methane present in the reservoir either in the gas phase or as solution gas that exsolves from the oil phase may undergo steam reforming reactions that produce carbon monoxide and hydrogen. The water-gas shift reaction may cause steam in the reservoir plus the carbon monoxide to generate more hydrogen.

[0083] Reactions that consume hydrogen may also occur in the reservoir including hydrogen combustion with the injected oxygen and methanation reactions which may form methane.

[0084] As such, implementations may enable creation of an in-situ reactor for the generation of hydrogen using multiple reaction families including combustion, gasification, reforming, aquathermolysis, pyrolysis, and water-gas shift for previously produced oil and natural gas reservoirs. The hydrogen after being produced to the surface when used as an energy source, for example, for power or heat generation, may generate no greenhouse gases. The hydrogen may also be used as a chemical feedstock for the production of chemicals, for example, ammonia or methanol.

[0085] FIG. 2 illustrates a method 200 for producing hydrogen from a previously-produced reservoir, according to one or more implementations herein. In the method 200, rather than stopping production and abandoning the well after economical recovery of petroleum fluids has reached a limit, the reservoir may be converted for production of hydrogen. The method 200 may provide a sequence of operations of an oil or natural gas reservoir where hydrogen is produced from the reservoir after its life as an oil or natural gas production operation.

[0086] At 202, a petroleum reservoir containing one or both of oil or natural gas may be provided.

[0087] At 204, a primary recovery process is performed. Production wells are placed within the reservoir and under natural drive mechanisms, oil or natural gas or both are produced to the surface.

[0088] At 206, one or more follow-up recovery processes are performed. Such recovery processes may include producing petroleum fluids by stimulation (e.g., water flood, gas flood, chemical flood, thermal stimulation, or hydraulic fracturing).

[0089] At 208, a tertiary recovery process may be performed. If stimulation is required from the start of the operation, then the reservoir stimulated, for example, by hydraulic fracturing in tight low permeability reservoirs or steam-injection in viscous oil reservoirs.

[0090] At 210, an economic limit of recovery of petroleum fluids may be reached, and the recovery process of petroleum fluids may be stopped. The economic limit of recovery of petroleum fluids may be determined in a variety of ways, including both using physical equipment limitations as well as financial constraints. In some implementations, an economic limit of recovery of petroleum fluids may be the limit at which it the cost for an operator to operate a recovery operation exceeds the value of petroleum fluids produced by that recovery operation. The detection of depleted zones within the reservoir after the economic end of the oil or natural gas recovery process can be obtained by standard methods such as seismic image interpretation, observation wells, or reservoir simulation models. The temperature of the near well region may be monitored by using thermocouples or other sensors placed in the wells.

[0091] At 220, in some implementations, new wells may be added to the reservoir. For example, new wells can be placed at the top of the formation to support gas production from the reservoir or additional injection wells can be placed in the reservoir. The added wells can be vertical or horizontal or deviated or multilateral. To lower costs, existing wells may be used in the hydrogen generation and production steps. In some implementations, the roles of production wells and injection wells in the oil or natural gas extraction process may be interchanged when used in the hydrogen generation and production process. Existing wells may be converted so that they can withstand high temperatures, that is, they may be converted to thermal completions. Such a conversion may include, for example, the installation of liners (e.g., metal liners), the application of cements (e.g., high- temperature cements), perforating a portion of the well, heat treating, installation of downhole gauges (e.g., a temperature gauge and / or pressure gauge to measure atemperature and / or pressure at a subterranean location (e.g., proximate or in the reactive / depleted zone)), installation of downhole safety valves, and the like.

[0092] At 222, the reservoir may be stimulated for hydrogen generation and production. Multiple stimulations may be done on multiple wells, including, for example, during hydrogen production. Stimulation can be done cyclically or continuously into depleted zones within the reservoir enabling creation of in-situ reactors. Stimulation includes oxidant injection, enhancements such as steam injection, hot water injection, fuel (e.g., flammable fuel) injection, methane injection, or nitrous oxide injection, well treatments (e.g., acid stimulation), hydraulic stimulation (e.g., hydraulic fracturing), or reservoir treatments (e.g., wettability changes, water shutoff, and coked zones).

[0093] In some implementations, in-situ hydrogen generation and subsequent extraction of a significant portion of the produced hydrogen to the surface in a depleted zone within the reservoir may be optimized by injecting an oxidant including oxygen (either in the form of air or enriched air) into the reservoir. This injection may initiate reactions that generate heat and carbon monoxide and carbon dioxide within the reservoir. The generated heat may result in steam (water vapor) production through the boiling of in-situ formation water. Steam can also be injected before or after or during oxidant injection. The heat, in turn, facilitates gasification, steam reforming, and aquathermolysis reactions. After the require volume of oxidant has been injected to achieve a target pressure or in-situ temperature or both. Both the heat, steam, and carbon monoxide enable the water-gas shift reaction generating hydrogen within the reservoir.

[0094] The heat and steam together may enable steam reforming of methane, either injected or originating from solution gas within the reservoir, which further generates hydrogen.

[0095] Adverse reactions also can occur in the reservoir that consume hydrogen, including the hydrogen combustion reaction (where hydrogen and oxygen react to produce water) and methanation reactions (involving the reaction of coke and heavy hydrocarbons to produce methane). Oxidant injection and gas production may be managed to minimize the impact of adverse hydrogen-consuming reactions.

[0096] In some implementations, new wells (e.g., infill wells) can be placed between the depleted zones to stimulate the reservoir between the depleted zones. Such new wells can provide for enhancements of one or both of the injection and production operations.

[0097] In some implementations, steam may be injected into the reservoir before or after or during oxidant injection.

[0098] In some implementations, prior to oxidant injection, fuel can be injected into the reservoir. This fuel can support the initiation of combustion in the reservoir when oxidant injection starts.

[0099] In some implementations, an ignitor may be placed within the injection or production wells to enable combustion within the reservoir. The ignitor may be one of a variety of ignitors known in the art, including, but not limited to an electrical- or chemical-based ignitor.

[0100] In some implementations, natural gas may be injected into the reservoir before or after oxidant and / or steam injection. The methane in the natural gas participates in steam-reforming reactions that generate hydrogen within the reservoir.

[0101] At 224, hydrogen-bearing gas may be produced from the reservoir, for example, to the surface with stimulation of the reservoir. In some implementations, the production of gas can be done over a specified period after which the well may be shut in to allow for pressure build up or an accumulation of gas around the production well, after which it may be again opened for production.

[0102] The stimulation wells and production wells may be operated so that the hydrogenbearing gas is motivated towards the production wells. In cyclic processes, the same physical well can be used for stimulation and production.

[0103] Stimulation of the reservoir may be imparted to depleted zones within the oil or natural gas reservoir where the pressure is reduced, and gas phase may be present. An oxidant or other stimulation additives such as fuel or methane may be injected into the reservoir to create a reactive zone in the depleted zone, which may generate heat, carbon monoxide, and carbon dioxide. The temperature of this zone may reach over 300°C and in some implementations above 400°C. Steam can be injected concurrently into the reservoir and may also be generated from the generated heat from water contained in the depleted zone in the reservoir. After the oxidant is injected into the reservoir and the pressure has reached a target value, for example, such that the oxidant partial pressure exceeds 500 kPa or in some implementations, 800 kPa, oxidant injection may be stopped. Fuel and / or methane and / or steam injection can continue after oxidant injection has stopped until the temperature of the system has peaked or has reached a plateau. Thereafter, hydrogen production from the system may start. This process can be done in bothcyclic manner (e.g., single wells used for both stimulation and production) or a non- cyclic manner (e.g., one or more injection wells and one or more production wells).

[0104] In a non-cyclic process, the injection wells can remain as injection wells and different wells are the production wells. For example, the injection wells can be operated with injection of oxidant for a period, then steam may be injected, then methane may be injected, or the well may be shut in, for periods of time to optimize (e.g., maximize) the generation of hydrogen. The production wells can be open for a period and shut in if needed.

[0105] In some implementations, the wells may be stimulated by using hydraulic squeeze or fracturing where proppant is placed within the reservoir. The proppant can permanently enhance the permeability of the reservoir. The proppant can also contain catalyst particles that enhance the production of hydrogen through the water-gas shift reaction. The catalyst can contain, for example, iron, magnesium, chromium, copper, zinc, and aluminum and combinations thereof or oxides of these metals and combinations thereof.

[0106] At 226, it may be determined whether an economic limit is reached. If the economic limit is not reached, the process may return to 222 and / or 224. If the economic limit is reached, the process may advance to 228.

[0107] At 228, the recovery process of hydrogen may be stopped.

[0108] Although FIG. 2 depicts an example method 200 and operations thereof, in some implementations, a method illustrated herein may include additional operations, fewer operations, differently arranged operations, or different operations than the operations depicted in FIG. 2. Moreover, or in the alternative, two or more of the operations depicted in FIG. 2 may be performed at least partially in parallel.

[0109] FIGs. 3A-3E illustrate a well system 300, according to one or more implementations herein. The well system 300 may include one or more wells operating together to perform a process, for example, similar to the method 200. Implementations such as system 300 may enable production of hydrogen-bearing gas from a petroleum reservoir that has been previously exploited to produce petroleum fluids.

[0110] The system 300 may operate within a formation in the earth, which may include a petroleum reservoir. The formation may include a surface 302 and an understrata 304. The petroleum reservoir need not occupy the extents of the formation such that it extends completely from the understrata 304 to the surface 302 but rather thepetroleum reservoir may occupy some region within the formation. The formation may comprise permeable or semi permeable rock 306. It will be understood that the formation may include other components, such as sand, dirt, water, etc. In a starting state, the petroleum reservoir may be described as having a fluid level of petroleum fluids 308 within the formation. It will be understood that liquid levels shown herein are for illustrative purposes only, showing the relative change in a volume of petroleum fluids 308 in a petroleum reservoir. The petroleum fluids 308 may be dispersed through the petroleum reservoir in different ways and thus the fluid level of the petroleum fluids 308 should be properly understood as a representation of a determined volume (e.g., measured, actual, or estimated) of the petroleum fluids 308 in aggregate in the petroleum reservoir.

[0111] One or more well(s) 310 for petroleum recovery may be located within the petroleum reservoir such that the well(s) 310 may be used to recover an economical portion of petroleum fluids 308. In this way, the well(s) 310 may be used similarly to a conventional petroleum fluids recovery well and may include one of various well styles known in the art, including, for example, a vertical well, a split well, a horizontal well, a multilateral well, a multitude of wells, and the like. The well(s) 310 may engage in a primary recovery process. That primary recovery process may be followed with a follow up recovery process and / or a tertiary recovery process. Such processes may continue until an economical limit of recovery of the petroleum fluids 308 is reached. While the well(s) 320 are depicted in FIG. 3A, in some implementations the well 320 is not present during the petroleum fluids recovery process and is rather added after the economic limits of that recovery process is reached. In some implementations, the well(s) 320 may be present during the petroleum fluids recovery process, and it may be utilized to assist in recovery of petroleum fluids.

[0112] With reference to FIG. 3B, recovery of the petroleum fluids may continue such that the level of the petroleum fluids 308 within the reservoir may decrease relative to the starting state level. In other words, during the petroleum fluids recovery process, the aggregate volume of the petroleum fluids 308 within the petroleum reservoir may decrease. Once an economical limit of petroleum fluid recovery is reached (e.g., the limit past which it is undesirable or economically inefficient to continue recovery of the petroleum fluids), the recovery of petroleum fluids may be stopped.

[0113] With reference to FIG. 3C, the system 300 may be configured such that petroleum reservoir stimulation may begin. The well(s) 310 may be used to stimulate thepetroleum reservoir. It will be understood that various means can be used to stimulate the petroleum reservoir, including by the delivery of heat through various means as described herein. To configure the system 300 for stimulation of the petroleum reservoir, additional wells such as the well(s) 320 may be placed within the petroleum reservoir. The well(s) 320 may include for example, a vertical well, a split well, a horizontal well, a multilateral well, a multitude of wells, and the like. In embodiments where the well(s) 320 is present within the petroleum reservoir during the primary recovery process, at this stage the well(s) 320 may be reconfigured for extraction of hydrogen-bearing gases produced in the petroleum reservoir following commencement of stimulation of the petroleum reservoir. Additional well(s) 310 may be added to the system 300 to assist with or provide for stimulation of the petroleum reservoir. The well(s) 310 may include or be retrofitted with thermal completions.

[0114] In an implementation, heat for stimulation of the petroleum reservoir may be produced within the petroleum reservoir itself, outside of the well(s) 310 and / or the well(s) 320 by causing the petroleum reservoir to operate as an in-situ reactor. It will be understood that in such an implementation, heat is generated among the rock 306 within a reactive zone 338 and not within the well(s) 310 or well(s) 320 themselves. Such operation may be provided for by, for example, injecting an oxidization agent 332 (e.g., an oxidant, oxygen-bearing gas, oxygen, etc.) into a well, such as, for example, well(s) well 310. The well(s) 310 (e.g., the existing well(s) 310 or new well(s) 310 added when reconfiguring the system 300 for stimulation of the petroleum reservoir) may include one or more perforations, which may permit the oxidizing agent 332 to pass out of the well(s) 310 and into a reactive zone 338 of the rock 306 of the formation proximate the well. The reactive zone 338 may be understood as the physical locations where hydrogen-generating reactions (e.g., one or more of gasification, steam-reforming, water-gas shift, or aquathermolysis reactions) may occur due to stimulation, and may be understood to be bounded by the resultant extents within which those hydrogen-generating reactions may occur as effected by system parameters such as, for example, injection rate, injection pressure, well pressure, well temperature, formation temperature, formation pressure, geological characteristics, blockages, and other characteristics of the system 300 and the injection parameters. The oxidizing agent 332 may react with remaining or residual petroleum fluids 308 within the reactive zone 338 to cause hydrogen generating reactions 334 to occur within the reactive zone 338.

[0115] In some other implementations, heat may be generated from the well(s) 310 or the well(s) 320 themselves to effect hydrogen generating reactions 334 within the reactive zone 338. In such implementations, the reactive zone 338 may be understood as the physical locations where petroleum fluids have been depleted (e.g., depleted zones) and hydrogen-generating reactions may occur due to stimulation, and may be understood to be bounded by the resultant extents within which those hydrogen-generating reactions may occur as effected by system parameters such as, for example, heating rate, well pressure, well temperature, formation temperature, formation pressure, geological characteristics, blockages, and other characteristics of the system 300 and the heating parameters.

[0116] In some implementations, with reference to FIG. 3D, the injection of the oxidizing agent 332 into the well(s) 310 may cease while reactions within the reactive zone 338 continue such that the hydrogen generating reactions 334 continue. Hydrogenbearing gas 336 produced by the hydrogen-generating reactions 334 may then rise to a location of the well(s) 320 and be produced to the surface 302. In such implementations, the system 300 may be operated cyclically, alternating between injection of oxidizing agent 332 and production of hydrogen-bearing gas 336. If an economic limit of recovery of the hydrogen-bearing gas is not reached, operations of stimulating the reservoir followed by production of hydrogen-bearing gas may be repeated in succession. Once an economic limit of recovery of the hydrogenbearing gas 336 is reached, recovery operations may be stopped.

[0117] In other implementations, with reference to FIG. 3E, the injection of the oxidizing agent 332 into the well(s) 310 may continue while reactions within the reactive zone 338 continue such stimulation continues while the hydrogen generating reactions 334 continue. Hydrogen-bearing gas 336 produced by the hydrogen-generating reactions 334 may then rise to a location of the well(s) 320 and be produced to the surface 302. In such implementations, the system 300 may be operated non- cyclically, continuously injecting the oxidizing agent 332 and producing the hydrogen-bearing gas 336. Once an economic limit of recovery of the hydrogenbearing gas 336 is reached, recovery operations may be stopped.

[0118] The following clauses may provide additional context for the present disclosure but should be taken in no way as limiting.

[0119] Clause 1. A method for recovering a hydrogen-bearing gas from a reservoir, comprising: determining a location of a depleted zone within the reservoir, wherein the reservoir is a previously-produced petroleum reservoir which previouslyproduced a petroleum fluid, is subterranean to a surface of the earth, and includes an existing well previously used for producing the petroleum fluid; retrofitting the existing well located in the depleted zones with thermal completions to convert the existing well to an injection well; injecting an oxidant via the injection well into the depleted zone; allowing one or more of a gasification reaction, a steam-reforming reaction, a water-gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogen-bearing gas; and producing the hydrogen-bearing gas to the surface through a production well.

[0120] Clause 2. The method of clause 1 wherein the oxidant comprises an oxygencontaining gas including one or more of air, or oxygen-enriched air, or pure oxygen.

[0121] Clause 3. The method of any of clauses 1-2, wherein the reservoir is a previously- produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

[0122] Clause 4. The method of any of clauses 1-4, wherein after the injecting the oxidant and before the allowing the one or more of gasification, steam-reforming, water-gas shift, or aquathermolysis reactions to occur in the depleted zone, the injecting the oxidant is stopped.

[0123] Clause 5. The method of clause 4, wherein the injecting the oxidant is stopped when a measured oxidant partial pressure reaches a target oxidant partial pressure and a measured reactive zone temperature reaches a target reactive zone temperature.

[0124] Clause 6. The method of clause 5, wherein the injecting the oxidant is restarted.

[0125] Clause 7. The method of clause 6, wherein the injecting the oxidant is restarted when the measured oxidant partial pressure falls below the target oxidant partial pressure or the measured reactive zone temperature falls below the target reactive zone temperature.

[0126] Clause 8. The method of any of clauses 1-7, further comprising, when a measured reactive zone partial pressure falls below a target reactive zone partial pressure: stopping the producing the hydrogen-bearing gas; waiting for the one or more of the gasification reaction, the steam-reforming reaction, the water-gas shift, or the aquathermolysis reaction to yield sufficient hydrogen-bearing gas to increase the measured oxidant partial pressure to the target oxidant partial pressure; and resuming the producing the hydrogen-bearing gas to the surface through the production well.

[0127] Clause 9. The method of any of clauses 1-8, further comprising installing the production well.

[0128] Clause 10. The method of any of clauses 1-9, wherein the production well comprises a second existing well previously used for producing the petroleum fluid.

[0129] Clause 11 . The method of any of clauses 1-10, further comprising injecting an enhancement into the depleted zone.

[0130] Clause 12. The method of clause 11 , wherein injecting the enhancement is done simultaneously with injecting the oxidant.

[0131] Clause 13. The method of any of clauses 11-12, wherein the enhancement comprises steam.

[0132] Clause 14. The method of any of clauses 11-13, wherein the enhancement comprises pre-heated water.

[0133] Clause 15. The method of any of clauses 11-14, wherein the enhancement comprises methane.

[0134] Clause 16. The method of any of clauses 11-15, wherein the enhancement comprises fuel.

[0135] Clause 17. The method of any of clauses 11-16, wherein the enhancement comprises nitrous oxide.

[0136] Clause 18. The method of any of clauses 1-17, wherein a new injection well is installed in a non-depleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

[0137] Clause 19. The method of any of clauses 1-18, wherein a new production well is installed in a non-depleted zone to enhance the producing the hydrogen-bearing gas to the surface.

[0138] Clause 20. The method of any of clauses 1-19, wherein an ignitor is disposed proximate the injection well or the production well and the method further comprises, using the ignitor, igniting the oxidant and remaining petroleum fluids in the depleted zone.

[0139] Clause 21 . The method of any of clauses 1-20, further comprising treating one or more of the injection well or the production well with acid to enhance a capability of fluid flow therethrough.

[0140] Clause 22. The method of any of clauses 1-21 , further comprising stimulating the reservoir using one or more of hydraulic fracturing to enhance a permeability of the reservoir.

[0141] Clause 23. The method of clause 22, wherein the hydraulic fracturing employs a proppant comprising a catalyst to enhance a hydrogen-generating reaction in the reservoir.

[0142] Clause 24. The method of clause 23, wherein the catalyst comprises one or more of pure iron, iron oxide, magnesium, chromium, copper, zinc, or aluminum.

[0143] Clause 25. A system for recovering a hydrogen-bearing gas from a reservoir, comprising: a reservoir, wherein: the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid and is subterranean to a surface of the earth, and the reservoir comprises a depleted zone; an injection well, wherein the injection well was created by retrofitting an existing well of the reservoir previously used for producing the petroleum fluid with thertmal completions to convert the existing well to the injection well, and wherein the injection well is configured for the injection of an oxidant therethrough into the depleted zone to cause one or more of a gasification reaction, a steam-reforming reaction, a water- gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogen-bearing gas; and a production well configured for producing the hydrogen-bearing gas to the surface.

[0144] Clause 26. The system of clause 25 wherein the oxidant comprises an oxygencontaining gas including one or more of air, or oxygen-enriched air, or pure oxygen.

[0145] Clause 27. The system of any of clauses 25-26, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

[0146] Clause 28. The system of any of clauses 25-27, further comprising a pressure sensor configured to measure a oxidant partial pressure.

[0147] Clause 29. the system of any of clauses 25-28, further comprising a temperature sensor configured to measure a reactive zone temperature.

[0148] Clause 30. The system of any of clauses 25-29, wherein the production well comprises a second existing well previously used for producing the petroleum fluid.

[0149] Clause 31 . The system of any of clauses 25-30, further comprising a new injection well installed in a non-depleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

[0150] Clause 32. The system of any of clauses 25-31 , further comprising a new production well installed in a non-depleted zone to enhance the producing the hydrogen-bearing gas to the surface.

[0151] Clause 33. The system of any of clauses 25-32, further comprising an ignitor is disposed proximate the injection well or the production well and wherein the ignitor is configured to ignite the oxidant and remaining petroleum fluids in the depleted zone.

[0152] Clause 34. The system of any of clauses 25-33, wherein one or more of the injection well or the production well are treated with acid to enhance a capability of fluid flow therethrough.Various characteristics, advantages, implementations, embodiments, and / or examples relating to the invention have been described in the foregoing description with reference to the accompanying drawings. However, the above description and drawings are illustrative only. The invention is not limited to the illustrated implementations, embodiments, and / or examples, and all implementations, embodiments, and / or examples of the invention need not necessarily achieve every advantage or purpose, or possess every characteristic, identified herein. Accordingly, various changes, modifications, or omissions may be effected by one skilled in the art without departing from the scope or spirit of the invention, which is limited only by the appended claims. Although example materials and dimensions have been provided, the invention is not limited to such materials or dimensions unless specifically required by the language of a claim. Elements and uses of the above-described implementations, embodiments, and / or examples can be rearranged and combined in manners other than specifically described above, with any and all permutations within the scope of the invention, as limited only by the appended claims.

[0153] In the claims, various portions are prefaced with letter or number references for convenience. However, use of such references does not imply a temporal or ordered relationship not otherwise required by the language of the claims. Unless the phrase ‘means for’ or ‘step for’ appears in a particular claim or claim limitation, such claim or claim limitation should not be interpreted to invoke 35 U.S.C. § 112(f).

[0154] As used in the specification and in the claims, use of “and” to join elements in a list forms a group of all elements of the list. For example, a list described as comprising A, B, and C defines a list that includes A, includes B, and includes C. As used in the specification and in the claims, use of “or” to join elements in a list forms a group of at least one element of the list. For example, a list described as comprising A, B, orC defines a list that may include A, may include B, may include C, may include any subset of A, B, and C, or may include A, B, and C. Unless otherwise stated, lists herein are inclusive, that is, lists are not limited to the stated elements and may be combined with other elements not specifically stated in a list. As used in the specification and in the claims, the singular form of 'a', 'an', and 'the' include plural referents (e.g., one or more of the referent) unless the context clearly dictates otherwise.

[0155] It is to be expressly understood that the drawings are for the purpose of illustration and description only and are not intended as a definition of the limits of the invention.

[0156] It is to be expressly understood that the drawings are for the purpose of illustration and description only and are not intended as a definition of the limits of the invention.

[0157] Unless otherwise stated, any range of values disclosed herein sets out a lower limit value and an upper limit value, and such ranges include all values and ranges between and including the limit values of the stated range, and all values and ranges substantially within the stated range as defined by the order of magnitude of the stated range.

[0158] The inventors hereby state their intent to rely on the Doctrine of Equivalents to determine and assess the reasonably fair scope of their invention as pertains to any apparatus not materially departing from but outside the literal scope of the invention as set out in the following claims.

Claims

CLAIMSWe claim:1 . A method for recovering a hydrogen-bearing gas from a reservoir, comprising: determining a location of a depleted zone within the reservoir, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid, is subterranean to a surface of the earth, and includes an existing well previously used for producing the petroleum fluid; retrofitting the existing well located in the depleted zones with thermal completions to convert the existing well to an injection well; injecting an oxidant via the injection well into the depleted zone; allowing one or more of a gasification reaction, a steam-reforming reaction, a water- gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogen-bearing gas; and producing the hydrogen-bearing gas to the surface through a production well.

2. The method of claim 1 wherein the oxidant comprises an oxygen-containing gas including one or more of air, or oxygen-enriched air, or pure oxygen.

3. The method of claim 1 , wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

4. The method of claim 1 , wherein after the injecting the oxidant and before the allowing the one or more of gasification, steam-reforming, water-gas shift, or aquathermolysis reactions to occur in the depleted zone, the injecting the oxidant is stopped.

5. The method of claim 4, wherein the injecting the oxidant is stopped when a measured oxidant partial pressure reaches a target oxidant partial pressure and a measured reactive zone temperature reaches a target reactive zone temperature.

6. The method of claim 5, wherein the injecting the oxidant is restarted.

7. The method of claim 6, wherein the injecting the oxidant is restarted when the measured oxidant partial pressure falls below the target oxidant partial pressure or the measured reactive zone temperature falls below the target reactive zone temperature.

8. The method of claim 1 , further comprising, when a measured oxidant partial pressure falls below a target reactive zone partial pressure: stopping the producing the hydrogen-bearing gas; waiting for the one or more of the gasification reaction, the steam-reforming reaction, the water-gas shift, or the aquathermolysis reaction to yield sufficient hydrogenbearing gas to increase the measured oxidant partial pressure to the target oxidant partial pressure; and resuming the producing the hydrogen-bearing gas to the surface through the production well.

9. The method of claim 1 , further comprising installing the production well.

10. The method of claim 1 , wherein the production well comprises a second existing well previously used for producing the petroleum fluid.

11. The method of claim 1 , further comprising injecting an enhancement into the depleted zone.

12. The method of claim 11 , wherein injecting the enhancement is done simultaneously with injecting the oxidant.

13. The method of claim 11 , wherein the enhancement comprises steam.

14. The method of claim 11 , wherein the enhancement comprises pre-heated water.

15. The method of claim 11 , wherein the enhancement comprises methane.

16. The method of claim 11 , wherein the enhancement comprises fuel.

17. The method of claim 11 , wherein the enhancement comprises nitrous oxide.

18. The method of claim 1 , wherein a new injection well is installed in a non-depleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

19. The method of claim 1 , wherein a new production well is installed in a non-depleted zone to enhance the producing the hydrogen-bearing gas to the surface.

20. The method of claim 1 , wherein an ignitor is disposed proximate the injection well or the production well and the method further comprises, using the ignitor, igniting the oxidant and remaining petroleum fluids in the depleted zone.

21. The method of claim 1 , further comprising treating one or more of the injection well or the production well with acid to enhance a capability of fluid flow therethrough.

22. The method of claim 1 , further comprising stimulating the reservoir using one or more of hydraulic fracturing to enhance a permeability of the reservoir.

23. The method of claim 22, wherein the hydraulic fracturing employs a proppant comprising a catalyst to enhance a hydrogen-generating reaction in the reservoir.

24. The method of claim 23, wherein the catalyst comprises one or more of pure iron, iron oxide, magnesium, chromium, copper, zinc, or aluminum.

25. A system for recovering a hydrogen-bearing gas from a reservoir, comprising: a reservoir, wherein: the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid and is subterranean to a surface of the earth, and the reservoir comprises a depleted zone; an injection well, wherein the injection well was created by retrofitting an existing well of the reservoir previously used for producing the petroleum fluid with thertmal completions to convert the existing well to the injection well, and wherein the injection well is configured for the injection of an oxidant therethrough into the depleted zone to cause one or more of a gasification reaction, a steam-reforming reaction, a water-gas shift, or an aquathermolysis reaction to occur in the depleted zone, yielding a hydrogen-bearing gas; and a production well configured for producing the hydrogen-bearing gas to the surface.

26. The system of claim 25 wherein the oxidant comprises an oxygen-containing gas including one or more of air, or oxygen-enriched air, or pure oxygen.

27. The system of claim 25, wherein the reservoir is a previously-produced petroleum reservoir which previously produced a petroleum fluid until an economic limit of production of the petroleum fluid was reached.

28. The system of claim 25, further comprising a pressure sensor configured to measure a oxidant partial pressure.

29. the system of claim 25, further comprising a temperature sensor configured to measure a reactive zone temperature.

30. The system of claim 25, wherein the production well comprises a second existing well previously used for producing the petroleum fluid.

31. The system of claim 25, further comprising a new injection well installed in a nondepleted zone to enhance the injecting the oxidant via the injection well into the depleted zone.

32. The system of claim 25, further comprising a new production well installed in a nondepleted zone to enhance the producing the hydrogen-bearing gas to the surface.

33. The system of claim 25, further comprising an ignitor is disposed proximate the injection well or the production well and wherein the ignitor is configured to ignite the oxidant and remaining petroleum fluids in the depleted zone.

34. The system of claim 25, wherein one or more of the injection well or the production well are treated with acid to enhance a capability of fluid flow therethrough.

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