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WO2025185840A1 - Traitement de réservoirs de pétrole mis en production précédemment pour la production d'hydrogène - Google Patents

Traitement de réservoirs de pétrole mis en production précédemment pour la production d'hydrogène

Info

Publication number
WO2025185840A1
WO2025185840A1 PCT/EP2024/063849 EP2024063849W WO2025185840A1 WO 2025185840 A1 WO2025185840 A1 WO 2025185840A1 EP 2024063849 W EP2024063849 W EP 2024063849W WO 2025185840 A1 WO2025185840 A1 WO 2025185840A1
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WO
WIPO (PCT)
Prior art keywords
reservoir
well
hydrogen
oxidant
gas
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
PCT/EP2024/063849
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English (en)
Other versions
WO2025185840A8 (fr
Inventor
Ian Gates
Jingyi Wang
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Protonh2 Analytics Ltd
Original Assignee
Protonh2 Analytics Ltd
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Filing date
Publication date
Application filed by Protonh2 Analytics Ltd filed Critical Protonh2 Analytics Ltd
Publication of WO2025185840A1 publication Critical patent/WO2025185840A1/fr
Publication of WO2025185840A8 publication Critical patent/WO2025185840A8/fr
Pending legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/243—Combustion in situ
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/06—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of inorganic compounds containing electro-positively bound hydrogen, e.g. water, acids, bases, ammonia, with inorganic reducing agents
    • C01B3/12—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of inorganic compounds containing electro-positively bound hydrogen, e.g. water, acids, bases, ammonia, with inorganic reducing agents by reaction of water vapour with carbon monoxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/295—Gasification of minerals, e.g. for producing mixtures of combustible gases
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
    • C01B2203/0211—Processes for making hydrogen or synthesis gas containing a reforming step containing a non-catalytic reforming step
    • C01B2203/0216—Processes for making hydrogen or synthesis gas containing a reforming step containing a non-catalytic reforming step containing a non-catalytic steam reforming step

Definitions

  • 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.
  • heavy oil may be classified as having a density of which is between 920 and 1000 kg/m3
  • 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.
  • 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.
  • 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 include a water phase, which may refer to the interstitial water present in the porous reservoir rock.
  • 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.
  • 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.
  • 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.
  • the techniques described herein relate to a method, wherein the injecting the oxidant is restarted.
  • 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.
  • 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.
  • the techniques described herein relate to a method, further including installing the production well.
  • the techniques described herein relate to a method, further including injecting an enhancement into the depleted zone.
  • the techniques described herein relate to a method, wherein injecting the enhancement is done simultaneously with injecting the oxidant.
  • 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.
  • the techniques described herein relate to a method, wherein the enhancement includes methane.
  • the techniques described herein relate to a method, wherein the enhancement includes nitrous oxide.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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 a petroleum 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.
  • 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.
  • 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.
  • the techniques described herein relate to a system, further including a pressure sensor configured to measure a oxidant partial pressure.
  • the techniques described herein relate to a system, further including a temperature sensor configured to measure a reactive zone temperature.
  • the techniques described herein relate to a system, wherein the production well includes a second existing well previously used for producing the petroleum fluid.
  • 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.
  • 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.
  • 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.
  • 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.
  • FIG. 1 illustrates a conventional method 100 for producing oil or gas from a reservoir.
  • FIG. 2 illustrates a method 200 for producing hydrogen from a previously-produced reservoir, according to one or more implementations herein.
  • FIGs. 3A-3E illustrate examples and phases of a well system 300, according to one or more implementations herein.
  • FIG. 1 illustrates a conventional method 100 for producing oil or gas from a reservoir.
  • a petroleum reservoir containing one or both of oil or natural gas may be provided.
  • 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.
  • 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).
  • a tertiary recovery process may be performed.
  • the reservoir stimulated, for example, by hydraulic fracturing in tight low permeability reservoirs or steam-injection in viscous oil reservoirs.
  • an economic limit of recovery of petroleum fluids may be reached, and the recovery process of petroleum fluids may be stopped.
  • 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.
  • the wellhead may be removed, and the well may be abandoned. The land may be returned to its state prior to the operation.
  • 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.
  • the reservoir fluids 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.
  • the cost of the EOR operation exceeds that of the oil revenues and at that point the recovery process is stopped.
  • the oil remaining in the reservoir is a large fraction of the original oil that was in the reservoir.
  • up to 65% of the original oil remains in the reservoir at the economic end of the operation.
  • over 50% of the original oil remains in the reservoir at the economic end of the EOR operation.
  • EGR enhanced gas recovery
  • 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.
  • 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.
  • the oil 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.
  • SAGD Steam-Assisted Gravity Drainage
  • THAI Toe-to-Heel Air Injection
  • 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.
  • 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 civilization 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.
  • Hydrogen is also needed as a feedstock material for chemicals.
  • hydrogen may contribute to changing the chemical industry and a more sustainable and environmentally friendly future.
  • Hydrogen when used in various chemical processes, may enable the production of a wide range of chemicals such as ammonia, methanol, and various petrochemicals.
  • Hydrogen may be found within all three phases of hydrocarbon-containing oil and gas systems (e.g., oil, gas, and water).
  • Oils e.g., heavy oils, extra heavy oils, bitumen, or other oils
  • Oils can be cold-produced under solution gas foamy oil flow in systems having a viscosity lower 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.
  • SMR steam methane reforming
  • 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.
  • 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.
  • 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.
  • depleted zones depleted with respect to oil
  • 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.
  • the depleted zones can take the form of wormholes as well as oil depleted zones within the reservoir.
  • depleted zones e.g., depleted with respect to oil
  • 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.
  • saturated steam e.g., liquid and vapour phase water
  • 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.
  • 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.
  • 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.
  • the high temperatures e.g., greater than 350°C
  • the high temperatures 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.
  • 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.
  • 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.
  • 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 other products.
  • the heat may also generate additional steam from the formation water that was contained in the reservoir.
  • the heat and carbon monoxide may enable a water-gas shift reaction, which may generate hydrogen within the reservoir.
  • Aquathermolysis hydrous pyrolysis
  • gasification gasification
  • steam reforming reactions may also generate additional hydrogen.
  • 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.
  • 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.
  • Reactions that consume hydrogen may also occur in the reservoir including hydrogen combustion with the injected oxygen and methanation reactions which may form methane.
  • 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.
  • FIG. 2 illustrates a method 200 for producing hydrogen from a previously-produced reservoir, according to one or more implementations herein.
  • 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.
  • a petroleum reservoir containing one or both of oil or natural gas may be provided.
  • 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.
  • Such recovery processes may include producing petroleum fluids by stimulation (e.g., water flood, gas flood, chemical flood, thermal stimulation, or hydraulic fracturing).
  • stimulation e.g., water flood, gas flood, chemical flood, thermal stimulation, or hydraulic fracturing.
  • 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.
  • 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.
  • 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.
  • new wells may be added to the reservoir.
  • 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.
  • existing wells may be used in the hydrogen generation and production steps.
  • 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 a temperature and/or pressure at a subterranean location (e.g., proximate or in the reactive/depleted zone)), installation of downhole safety valves, and the like.
  • liners e.g., metal liners
  • 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 a temperature and/or pressure at a subterranean location (e.g., proximate or in the reactive/depleted zone)
  • downhole gauges e.g., a temperature gauge and/or pressure gauge to measure a
  • 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).
  • fuel e.g., flammable fuel
  • methane injection e.g., methane injection
  • nitrous oxide injection e.g., nitrous oxide injection
  • well treatments e.g., acid stimulation
  • hydraulic stimulation e.g., hydraulic fracturing
  • reservoir treatments e.g., wettability changes, water shutoff, and coked zones
  • 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 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.
  • 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.
  • 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.
  • new wells e.g., infill wells
  • new 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.
  • steam may be injected into the reservoir before or after or during oxidant injection.
  • fuel 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.
  • 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.
  • 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.
  • hydrogen-bearing gas may be produced from the reservoir, for example, to the surface with stimulation of the reservoir.
  • 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.
  • the stimulation wells and production wells may be operated so that the hydrogenbearing gas is motivated towards the production wells.
  • the same physical well can be used for stimulation and production.
  • 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.
  • 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.
  • hydrogen production from the system may start. This process can be done in both cyclic 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).
  • the injection wells can remain as injection wells and different wells are the production wells.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the aggregate volume of the petroleum fluids 308 within the petroleum reservoir may decrease.
  • the system 300 may be configured such that petroleum reservoir stimulation may begin.
  • the well(s) 310 may be used to stimulate the petroleum 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.
  • 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.
  • 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.
  • 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.
  • an oxidization agent 332 e.g., an oxidant, oxygen-bearing gas, oxygen, etc.
  • the well(s) 310 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • Clause 9 The method of any of clauses 1-8, further comprising installing the production well.
  • 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.
  • Clause 11 The method of any of clauses 1-10, further comprising injecting an enhancement into the depleted zone.
  • Clause 13 The method of any of clauses 11-12, wherein the enhancement comprises steam.
  • Clause 14 The method of any of clauses 11-13, wherein the enhancement comprises pre-heated water.
  • Clause 15 The method of any of clauses 11-14, wherein the enhancement comprises methane.
  • Clause 16 The method of any of clauses 11-15, wherein the enhancement comprises fuel.
  • Clause 17 The method of any of clauses 11-16, wherein the enhancement comprises nitrous oxide.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • Clause 28 The system of any of clauses 25-27, further comprising a pressure sensor configured to measure a oxidant partial pressure.
  • Clause 29 the system of any of clauses 25-28, further comprising a temperature sensor configured to measure a reactive zone temperature.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • a list described as comprising A, B, and C defines a list that includes A, includes B, and includes C.
  • use of “or” to join elements in a list forms a group of at least one element of the list.
  • a list described as comprising A, B, or C 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.
  • 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.

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Abstract

Certains modes de réalisation comprennent le traitement de réservoirs de pétrole mis en production précédemment pour générer et produire de l'hydrogène par la création de réacteurs in situ dans lesquels la combustion, la gazéification, le reformage à la vapeur, le déplacement de gaz à l'eau et les réactions d'aqua-thermolyse ont lieu. L'opération de production d'hydrogène peut faire intervenir une stimulation des zones appauvries du réservoir qui résultent de l'exploitation antérieure de pétrole et de gaz naturel. Le gaz contenant de l'hydrogène peut ensuite être acheminé vers la surface.
PCT/EP2024/063849 2024-03-06 2024-05-20 Traitement de réservoirs de pétrole mis en production précédemment pour la production d'hydrogène Pending WO2025185840A1 (fr)

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US20210047905A1 (en) 2018-03-06 2021-02-18 Proton Technologies Canada Inc. In-situ process to produce synthesis gas from underground hydrocarbon reservoirs
US20210189856A1 (en) * 2016-02-08 2021-06-24 Proton Technologies Inc. In-situ process to produce hydrogen from underground hydrocarbon reservoirs
WO2022126257A1 (fr) * 2020-12-18 2022-06-23 Proton Technologies Inc. Procédés de réorientation d'opérations de récupération thermique d'hydrocarbures pour la production de gaz de synthèse
WO2023044149A1 (fr) * 2021-09-20 2023-03-23 Texas Tech University System Génération et production d'hydrogène in situ à partir de réservoirs de pétrole
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WO2022126257A1 (fr) * 2020-12-18 2022-06-23 Proton Technologies Inc. Procédés de réorientation d'opérations de récupération thermique d'hydrocarbures pour la production de gaz de synthèse
WO2023044149A1 (fr) * 2021-09-20 2023-03-23 Texas Tech University System Génération et production d'hydrogène in situ à partir de réservoirs de pétrole
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