Storage capacity of natural hydrogen storage layer or integration of suitable subsurface storage layer with other hydrogen sources and sinks

Abstract

Embodiments are directed to storing, providing, and using hydrogen, helium, or carbon dioxide in a natural hydrogen storage layer or a depleted natural hydrogen storage layer. The hydrogen storage layer can be connected to a hydrogen production system, and hydrogen from the hydrogen production system can be injected into the hydrogen storage layer. The injected hydrogen can be extracted as needed for energy production, for chemical synthesis, or as a feedstock.

Description

Technical Field

[0001] (Cross - Reference to Related Applications) This application claims priority to U.S. Provisional Patent Application No. 63 / 349,892, filed on June 7, 2022, the disclosure of which is hereby incorporated by reference in its entirety.

[0002] Embodiments of the present disclosure generally relate to the fields of geology or geophysics. Some embodiments disclose methods for subsurface exploration of natural resources including hydrogen and carbon dioxide. More specifically, the present disclosure relates to methods for storing, transporting, monitoring, and recovering hydrogen, helium, and carbon dioxide subsurface.

Background Art

[0003] The purpose of this section is to introduce various aspects of the technical field that may be associated with the embodiments described in the present disclosure. Therefore, the foregoing considerations within this section provide a framework for better understanding the present disclosure and should not be considered an admission of prior art.

Summary of the Invention

Means for Solving the Problems

[0004] Embodiments are directed to methods for establishing the ability of a reservoir to hold large amounts of hydrogen (H2), helium (He), or carbon dioxide (CO2) subsurface and recover it at an economic and efficient rate. This subsurface storage capacity connects a demand reservoir for hydrogen, helium, or carbon dioxide to a sink by means of pipelines, wellheads, compressors, or other transport means that can be easily delivered from the reservoir. In other embodiments, the subsurface storage facility integrates a surface facility (e.g., an electrolyzer, a methanator, a pyrolysis furnace, a blast furnace) that produces hydrogen, helium, or carbon dioxide, a surface facility that isolates, or a surface facility that purifies (e.g., a pressure swing absorption unit, a selective permeable membrane, cryogenic separation, a hydrogen fuel cell) with its reservoir.

[0005] In one embodiment, a method of providing gas is disclosed. The method includes connecting a hydrogen storage layer to a gas production system. The method includes injecting gas from the gas production system into the hydrogen storage layer. The method includes extracting the injected gas from the hydrogen storage layer. Extracting the injected gas may occur after the hydrogen storage layer has depleted natural hydrogen. Extracting the injected gas may occur in parallel with the depletion of natural hydrogen from the hydrogen storage layer.

[0006] In one embodiment, a method of providing hydrogen is disclosed. The method includes connecting a hydrogen storage layer to a hydrogen production system. The method includes injecting hydrogen from the hydrogen production system into the hydrogen storage layer. The method may further include extracting the injected hydrogen as needed for energy production, chemical synthesis, or other means of utilization.

[0007] In one embodiment, a system for providing stored gas is disclosed. The system includes a natural hydrogen storage layer. The system includes a gas production system. The system includes one or more conduits connecting the natural hydrogen storage layer to the gas production system. The gas may include hydrogen, and the gas production system may include a hydrogen production system.

[0008] In one embodiment, a hydrogen storage layer is disclosed. The hydrogen storage layer includes a porous or permeable subsurface rock and an injection well configured to supply hydrogen gas to the subsurface rock. The hydrogen gas may be stored at a pressure above hydrostatic pressure. The hydrogen storage layer may further include carbon dioxide or helium within the porous subsurface rock. The carbon dioxide or helium may be in a supercritical state.

[0009] In one embodiment, a method for storing carbon dioxide is disclosed. The method includes connecting a carbon dioxide source to a natural hydrogen storage layer, where the carbon dioxide source is configured to produce or capture carbon dioxide. The method includes injecting the captured carbon dioxide into the natural hydrogen storage layer. The method can further include mineralizing the captured carbon dioxide. The carbon dioxide source may include a reformer such as at least one of a steam methane reformer or an autothermal reformer.

[0010] In one embodiment, a carbon dioxide storage layer is disclosed. The carbon dioxide storage layer may include a porous or permeable subsurface rock and an injection well configured to inject carbon dioxide gas or supercritical carbon dioxide into the subsurface rock. The carbon dioxide may be stored as supercritical carbon dioxide. The carbon dioxide storage layer may include hydrogen or helium within the porous subsurface rock. The hydrogen or helium can be in a supercritical state.

[0011] In one embodiment, a method for providing helium is disclosed. The method includes connecting a natural gas (e.g., including hydrogen, helium, CO2, hydrogen sulfide (H2S), or hydrocarbon gas) well, a natural gas storage layer (e.g., including hydrogen, helium, CO2, H2S, or hydrocarbon gas), or various industrial sources of hydrogen, helium, CO2, H2S, or hydrocarbon gas (e.g., purification devices, pipelines, cryogenic purification, membrane purification, or others) to a subsurface hydrogen storage layer. The method includes injecting helium, or a mixture of helium and other gases, into the storage layer. The method may include extracting the injected helium for various means of utilization. Extracting the injected helium may occur after the helium storage layer has depleted helium from the storage layer. Extracting the injected helium may occur in parallel with the depletion of natural hydrogen, helium, natural gas, or CO2 from the storage layer.

[0012] In one embodiment, a helium storage layer is disclosed. The helium storage layer includes a porous or permeable subsurface rock and an injection well configured to supply helium to the subsurface rock. The helium may be stored at a pressure above the hydrostatic pressure. The helium storage layer may contain carbon dioxide, hydrogen, or natural gas within the porous subsurface rock. The helium can be in a supercritical state. Features from any of the disclosed embodiments may be used in combination with each other, but are not limited thereto. Additionally, other features and advantages of the present disclosure will become apparent to those skilled in the art by considering the following "Detailed Description of the Invention" and the accompanying drawings.

[0013] The drawings illustrate several embodiments of the present invention, and the same reference numerals refer to the same or similar elements or features within different figures or embodiments shown in the drawings.

Brief Description of the Drawings

[0014]

Figure 1

Figure 2

Detailed Description of the Invention

[0015] The embodiments disclosed herein establish the ability of a storage layer to hold large quantities of hydrogen (H2), helium (He), or carbon dioxide (CO2) below, at, or above hydrostatic pressure, recover it at an economical and efficient rate, connect its storage layer by pipeline or other means of transport to a hydrogen, helium, or carbon dioxide demand sink, and integrate the surface-based hydrogen, helium, or carbon dioxide production, sequestration, or purification system with its storage layer. In other embodiments, disclosed herein is a method of establishing the ability of a storage layer to hold large quantities of hydrogen, helium, or carbon dioxide below, at, or above hydrostatic pressure, recover it at an economical and efficient rate, and connect its storage layer by pipeline or other means of transport for storage to a hydrogen, helium, or carbon dioxide supply at the surface.

[0016] There are efforts to explore and develop new salt cavern capacity for underground hydrogen or helium storage. Salt, due to its closest-packed structure and low porosity, can hold almost all gases at high pressures with self-healing after deformation events. However, salt caverns are generally relatively small. For example, most salt caverns are sized to be able to store approximately 6,000 to 10,000 tons of hydrogen. If 80% of the gas in the cavern is depleted daily and used at peak storage capacity and refilled, a 6,000-ton cavern can support only approximately 1.75 million tons of intermittent production per year. Above-ground storage or liquefaction and storage of hydrogen is very costly, making these strategies infeasible for most commercial applications.

[0017] Underground hydrogen storage is thought to be important for creating redundancy in the developing hydrogen economy, but also serves to compensate for potential irregularities in hydrogen production by renewable energy-driven electrolysis when the hydrogen production profile may follow, to achieve the lowest cost of production, even the wind power profile, the solar power profile, or the hydroelectric power profile. Electrolytic hydrogen production facilities generally face the following issues: building near the lowest-cost renewable energy production sites (e.g., the desert locations in the southwestern United States for solar power, windy locations such as the Great Plains or western Texas for wind power, or the northwestern United States for hydroelectric power) that are not proximal to the demand sink, producing hydrogen intermittently, or locating the electrolyzers near the demand sink (off-taker) or "on the other side of the fence" and paying significant grid usage fees, wire usage, and renewable energy certificates (RECs) to achieve a more flat production profile closer to the user. The production facilities can also be built in on-site buffer storage, but this is widely regarded as prohibitively costly. "Green" hydrogen production facilities are caught between Option 1 (low cost, intermittent, and far from demand, unconnected to demand) and Option 2 (high cost, grid-connected with synthetic-based load, and exorbitant).

[0018] Another form of clean hydrogen is natural gas-derived hydrogen from steam methane reforming or autothermal reforming with carbon capture and backend sequestration. This also poses geographical and supply chain challenges for manufacturing companies, where locating a "blue" hydrogen production facility near the demand sink may create transportation challenges for CO2 if the hydrogen production facility is located far from a geological CO2 sink, while locations near CO2 storage formations may be far from the demand sink / offtake for hydrogen. Specifically, desirable locations for greenfield blue hydrogen facilities would be either above a CO2 sequestration resource with hydrogen production connected to the demand sink via a pipeline or on the other side of a fence from a pipeline connected to a hydrogen demand sink and a CO2 fractionation resource. There are not many options that meet both of these criteria.

[0019] Natural hydrogen reservoirs (or other suitable subsurface reservoirs), if initially developed because large amounts of naturally captured hydrogen have been discovered, can include pressure resistance and sealing capabilities proven by geological evidence over hundreds of thousands and millions of years. The natural hydrogen present in the storage can be delivered to downstream customers or connected to a pipeline system that can enable storage from an upper manufacturing facility. Generally, the storage capacity within a natural hydrogen reservoir (or other suitable subsurface reservoir) can be on the order of 1 million tons or more. When discharged, it can enable intermittent production of over 1 billion tons per year. A natural hydrogen reservoir (or other suitable subsurface reservoir) linked to an electrolyzer or other hydrogen production means can supply hydrogen (H2) and operate continuously when connected to a demand sink due to its storage capacity.

[0020] In some embodiments, a system for storing hydrogen may be utilized to implement the methods disclosed herein. FIG. 1 is a block diagram of a system 100 for providing hydrogen gas, helium gas, carbon dioxide gas, or other forms of fluid according to one embodiment. System 100 includes a hydrogen storage layer 102, a production system 104 for gas or other forms of fluid, and one or more conduits 106 connecting the hydrogen storage layer 102 to the production system 104 for gas or other forms of fluid.

[0021] The hydrogen storage layer 102 may include a subsurface hydrogen storage layer such as a natural hydrogen storage layer (e.g., a subsurface reservoir containing natural hydrogen). In some embodiments, the hydrogen storage layer 102 may include a carbon dioxide or other subsurface gas reservoir that can hold hydrogen and other gases without leaking them. The hydrogen storage layer may be a subsurface gas reservoir that is at least partially depleted, such as a depleted natural hydrogen storage layer. The hydrogen storage layer may not be a salt cavern (e.g., an artificial or natural salt cavern). Compared to salt caverns, relatively larger-sized natural subsurface hydrogen storage layers provide a relatively larger storage capacity with proven hydrogen retention capabilities. As a result, the subsurface hydrogen storage layer may be sized to contain at least 15,000 tons of hydrogen (e.g., 179 million m 3 of hydrogen in gaseous form), such as 15,000 to 3,000,000 tons, 50,000 to 1,500,000 tons, 20,000 to 100,000 tons, less than 2,000,000 tons, or less than 200,000 tons of hydrogen.

[0022] The hydrogen storage layer 102 may contain more gas than hydrogen alone, such as carbon dioxide, helium, natural gas, oxygen, nitrogen, any other gas, or any combination of the foregoing.

[0023] The gas production system 104 may include one or more of a hydrogen production system, a carbon dioxide production or capture system, or a helium production or separation system. In an embodiment, the hydrogen production system may include one or more of a reformer system (e.g., SMR, ATR, or the like), an electrolysis system, a pyrolysis system, a plasma reformer, or any other suitable hydrogen production system. The gas production system 104 may include multiple hydrogen production systems or may include carbon dioxide addition for synthetic fuel production.

[0024] One or more conduits 106 may include one or more of a well, pipeline, pipe, or the like. One or more conduits 106 may include an injection well for injecting one or more gases (e.g., hydrogen, helium, carbon dioxide) into the hydrogen storage layer 102 and a production well for extracting one or more gases from the hydrogen storage layer 102. The system 100 may include one or more pumps for injecting hydrogen or any other gas into the hydrogen storage layer 102. One or more pumps may be connected to one or more conduits 106.

[0025] The system 100 may be connected to one or more hydrogen demand sinks. For example, the system 100 may be fluidly connected to a hydrogen combustion power plant, a hydrogen distribution hub (e.g., a hydrogen pump for vehicles), an ammonia plant, a synthetic fuel refinery, a cement plant, an ethanol refinery, a truck fueling station, a clean aviation fuel refinery, or a direct reduced iron production facility, a data center, or the like. The system 100 may be connected to the demand sink via one or more pipelines.

[0026] In some embodiments, the system 100 may not include the gas production system 104. In such examples, the system may include a natural hydrogen storage layer containing a gas that is not natural to the natural hydrogen storage layer, such as hydrogen, carbon dioxide, or helium obtained externally or produced, e.g., a gas that was not originally stored within the hydrogen storage layer.

[0027] In some embodiments, system 100 may not include an extraction well, a plurality of extraction wells, or an extraction system. For example, system 100 may include a natural hydrogen reservoir and an injection well. In such embodiments, system 100 may be used to permanently store or isolate one or more gases within the natural hydrogen reservoir. For example, the injection well may be utilized to inject carbon dioxide, hydrogen sulfide, or other fluids into the natural hydrogen reservoir for mineralization within the porous subsurface rock in the natural hydrogen reservoir. The injection well may be configured to supply one or more of hydrogen gas, helium, or carbon dioxide gas (or fluid) to the porous subsurface rock, and the hydrogen gas is stored at a pressure above the hydrostatic pressure. In some examples, a gas (e.g., carbon dioxide) may be injected and stored within the porous subsurface rock, and the gas (e.g., carbon dioxide) is a supercritical fluid. The porous subsurface rock of the hydrogen reservoir and the injection well may form the hydrogen reservoir. The natural hydrogen reservoir may store therein a "non-natural" gas such as hydrogen obtained from surface operations, production, collection, separation, or another method. The non-natural gas (e.g., hydrogen produced by electrolysis) can be distinguished from natural gas (e.g., natural hydrogen) by its isotope characteristics. Of course, the gas stored within the natural hydrogen reservoir, the gas stored and mineralized within the natural hydrogen reservoir, or the supercritical gas stored within the natural hydrogen reservoir may later be extracted through an extraction well or a production well fluidly connected thereto.

[0028] Any of the systems disclosed herein may be utilized to store and extract fluids from a subsurface hydrogen reservoir. For example, system 100 may be utilized to implement one or more portions of any of the methods disclosed herein.

[0029] Figure 2 is a flow diagram of a method 200 for storing and providing one or more gases from a subsurface hydrogen storage layer according to an embodiment. The method 200 includes an act 210 of connecting the hydrogen storage layer to a gas production system, an act 220 of injecting gas from the gas production system into the hydrogen storage layer, and an act 230 of extracting the injected gas from the hydrogen storage layer. In some embodiments, the method 200 may include more or fewer acts than acts 210 - 230. One or more of the acts 210 - 230 may be omitted, combined, or divided. For example, act 210 or 230 may be omitted in some embodiments. Additional acts may be performed as part of the method 200.

[0030] The act 210 of connecting the hydrogen storage layer to a gas production system may include connecting the hydrogen storage layer to a gas production system (such as connecting the hydrogen storage layer to a hydrogen production system, a carbon dioxide production system or capture system (e.g., reformer), a helium production system or capture system, or the like). For example, methods of providing hydrogen gas, helium, or carbon dioxide may include connecting a (natural) hydrogen or other gas storage layer to a hydrogen production system (e.g., electrolyzer), pipeline, or purification system (e.g., pressure swing absorption, selective permeable membrane, cryogenic separation system, or fuel cell).

[0031] Connecting a hydrogen storage layer to a gas (e.g., hydrogen) production system may include creating a fluid connection between the gas production system and the hydrogen storage layer using one or more of a well, pipeline, or pump. In some embodiments, the connection can include a pipeline system, injection well, or extraction well configured to adapt to hydrogen gas pressure and other related characteristics. The connection can include any suitable means of transporting hydrogen, helium, or carbon dioxide to bring hydrogen, helium, or carbon dioxide from a natural storage layer to the surface for various forms of utilization (e.g., ammonia production, hydrocarbon desulfurization, synthetic fuels, direct reduced iron steelmaking). In some embodiments, various forms of hydrogen, helium, or carbon dioxide production (e.g., electrolysis, reforming by wind power generation, solar power generation, hydropower generation, or others), isolation, or purification (e.g., pressure swing absorption, selective permeable membrane, cryogenic separation system, or fuel cell) systems can be connected to a natural storage layer for later utilization. For example, connecting a hydrogen storage layer to a gas production system may include connecting the hydrogen storage layer to the output of one or more of an electrolysis system, pyrolysis system, or reformer system configured to produce hydrogen. A conduit or pipeline coupled to the output of the gas production system can be connected to an injection well and / or production well at the hydrogen storage layer.

[0032] (Subsurface natural) hydrogen storage layer (102 in FIG. 1) can include porous subsurface rock. The porous hydrogen storage layer may have an injection well fluidly connected thereto to supply hydrogen (H2 gas) to the porous subsurface rock. The hydrogen storage layer can include a subsurface geological formation in which natural hydrogen gas is at least partially depleted. The hydrogen storage layer can contain at least 15,000 tons of hydrogen (e.g., 179 million m in gaseous form) 3It can be sized to hold large amounts of hydrogen gas, carbon dioxide, helium, or other gases, such as hydrogen (up to 15,000 tons to 3,000,000 tons, 50,000 tons to 1,500,000 tons, 20,000 tons to 100,000 tons, less than 2,000,000 tons, or less than 200,000 tons).

[0033] By connecting a renewable power electrolyzer (or other form of hydrogen production) to a large, geologically proven natural hydrogen storage formation (or other suitable subsurface storage formation), the electrolysis (or other form of hydrogen production) plant owner can overcome the major supply issue of intermittency and avoid paying high costs for grid-connected power that is located near the demand sink. Since the scale of electrolyzers is typically smaller compared to other production methods, it would usually be economically difficult to connect them to the demand sink via pipelines, but pairing them with large natural hydrogen storage formations (or other suitable subsurface storage formations) makes it much easier to economically justify the connectivity of the system.

[0034] The act 220 of injecting gas from a gas production system into a hydrogen storage formation may include one or more of injecting hydrogen from a hydrogen production system into the hydrogen storage formation, injecting helium from a helium production or separation system into the hydrogen storage formation, or injecting carbon dioxide from a carbon dioxide capture or production system into the hydrogen storage formation. Injecting gas from a gas production system into a hydrogen storage formation may include injecting gas into the hydrogen storage formation through an injection well.

[0035] For example, injecting gas from a gas production system into a hydrogen storage formation may include injecting hydrogen into the hydrogen storage formation from one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen.

[0036] Providing hydrogen can further include injecting hydrogen from a hydrogen production system into a hydrogen storage formation (e.g., a new or depleted natural hydrogen storage formation), and then extracting the injected hydrogen as needed for energy production. In some embodiments, the stability and redundancy of a new or depleted natural hydrogen storage formation (or other suitable subsurface storage formation) has been demonstrated as a resource capable of storing hydrogen, helium, or carbon dioxide at high pressure and can be used for other purposes as a storage resource for other means of intermittent hydrogen production, enabling a long-term topside hydrogen conversion infrastructure, such as an ammonia plant, a synthetic fuel plant, or the like, to be constructed with a predicted lifetime much longer than the hydrogen supply of the storage formation itself. In some embodiments, when the conversion infrastructure includes an electrolyzer, the oxygen from the electrolyzer can be used as a feedstock for an autothermal reformer or as an oxidant for any combustion-based process, such as power generation, a compressor, a pump, or other equipment. The heat from the electrolyzer can also be used to enhance steam production at a power plant or for steam production for downhole injection. A natural hydrogen storage formation (or other suitable subsurface storage formation) may be utilized as the center of a hydrogen ecosystem that enables a hydrogen hub, a synthetic fuel hub, and the complete use of all by-products from an electrolysis process or other hydrogen production processes.

[0037] The act 230 of extracting the injected gas from the hydrogen storage layer may include extracting one or more of hydrogen, carbon dioxide, or helium from the hydrogen storage layer. For example, extracting the injected gas from the hydrogen storage layer may include extracting the injected hydrogen for energy production, chemical synthesis, or the like. In some embodiments, extracting the injected gas may be performed after the natural species of gas (e.g., natural hydrogen, methane, helium, carbon dioxide) from the hydrogen storage layer has been depleted from the hydrogen storage layer. For example, extracting the injected hydrogen may occur after the hydrogen storage layer has been depleted of natural hydrogen. In some embodiments, extracting the injected gas may be performed in parallel with the depletion of the natural species of gas (e.g., natural hydrogen) from the hydrogen storage layer.

[0038] Method 200 may include supplying the extracted gas, such as hydrogen, helium, or carbon dioxide, to a user. For example, supplying the extracted hydrogen to a user may include supplying the extracted hydrogen through a pipeline to one or more of an energy production facility or a chemical production facility. The energy production facility may include one or more oxidation units configured to use hydrogen as a fuel. The chemical production facility may include one or more synthesis systems configured to use hydrogen, carbon dioxide, or the like as a feedstock for synthesizing one or more chemicals. For example, the chemical production facility may include a fuel production system configured to synthesize an alkane fuel using the extracted hydrogen.

[0039] Method 200 may include storing the injected gas within the hydrogen storage layer for a selected duration. In some embodiments, the hydrogen gas is stored at a pressure above the hydrostatic pressure. The duration may be several days, weeks, months, or years.

[0040] In some embodiments, the hydrogen storage layer can contain carbon dioxide (CO2) or helium within a porous subsurface rock. The helium or carbon dioxide can be made supercritical. Helium or carbon dioxide, or a mixture thereof, can be utilized to create a pressure that supports and reduces the viscosity of an oil reservoir using a technique known as enhanced oil recovery (or EOR). For promising hydrogen production facilities, carbon dioxide storage resources (whether they be brine aquifers, depleted oil or gas reservoirs, or EOR resources) are generally not connected to hydrogen demand sinks via a carbon dioxide pipeline. This is addressed by building sufficient upstream infrastructure that can convert hydrogen or carbon dioxide into more easily transportable liquid products such as ammonia or synthetic fuels above a carbon dioxide storage resource with a natural gas connection. In some embodiments, a large pipeline network carrying any of hydrogen, helium, or carbon dioxide may not be necessary. However, proven natural hydrogen storage layers (or other suitable subsurface storage layers) as described herein can address this issue.

[0041] The pores within a natural hydrogen storage formation (or other suitable subsurface storage formation) can be used to store carbon dioxide, such as from a “blue” hydrogen production facility constructed adjacent to or on top of the natural hydrogen storage formation (or other suitable subsurface storage formation). The carbon dioxide can be used to provide pressure support to increase the recovery of natural hydrogen within the storage formation, and the depleted storage formation can function as a storage resource for CO2. Since the natural hydrogen storage formation can include pipelines connected to demand sinks (e.g., injection and / or production wells), the issue of connecting the carbon dioxide storage resource to the hydrogen demand is solved. As hydrogen is removed from the natural hydrogen storage formation, the pores can be freed up to store the injected carbon dioxide. When the carbon dioxide is injected at the correct depth, it will be supercritical and will be significantly denser than any remaining hydrogen present above the dome or trap within the natural hydrogen storage formation. The open pore volume, the sealing and closure capabilities of a geologically proven natural hydrogen storage formation system (or other suitable subsurface storage formation system), and the use of carbon dioxide to provide pressure support to hydrogen provide a method of storing carbon dioxide that may be beneficial.

[0042] In some embodiments, storing carbon dioxide can include connecting a reformer to the natural hydrogen storage formation. The reformer can be configured to capture carbon dioxide. In some embodiments, the reformer can include at least one of a steam methane reformer, an autothermal reformer, or the like. The reformer can be connected to a downstream hydrogen demand via a pipeline shared with the natural hydrogen storage formation (or other suitable subsurface storage formation) and can also be configured to capture carbon dioxide from the process. Storing carbon dioxide can also include injecting the captured carbon dioxide into the natural hydrogen storage formation. In some embodiments, the carbon dioxide can be injected via an injection well, where the carbon dioxide can be stored within the empty pores within the natural hydrogen storage formation and provide pressure support for further hydrogen recovery.

[0043] In some embodiments, method 200 may not include extracting the injected gas from the hydrogen storage layer. For example, method 200 may include mineralizing CO2 or another chemical into the porous subsurface rock within the subsurface hydrogen storage layer. For example, the captured carbon dioxide can be injected into a natural hydrogen storage layer (and underlying source rock), where the carbon dioxide can be mineralized. Most natural hydrogen storage layers are above or near a source rock that can function as a carbon dioxide sink through the mineralization of carbon dioxide. Such mineralization further increases the carbon dioxide storage capacity within the natural hydrogen storage layer, which may be connected to a hydrogen demand sink via a pipeline. In some cases, it is possible to use a single injection wellbore to deliver carbon dioxide to depleted pores as well as to the source rock volume where carbon dioxide can be stored by both sequestration and mineralization.

[0044] In some embodiments, methane separated from the natural hydrogen gas within the natural hydrogen storage layer may be utilized as part or all of the feedstock for at least one of an SMR or an autothermal reformer (ATR) system. The oxygen and heat from an electrolyzer coupled within the same hydrogen storage layer (or other suitable subsurface storage layer) may be utilized to enhance the economics (e.g., efficiency) of the SMR or ATR system.

[0045] In some embodiments, method 200 may not include connecting a hydrogen storage layer to a gas production system. In such embodiments, the method may include only one or more of injecting, storing, or extracting gas within or from the hydrogen storage layer. For example, method 200 may include injecting gas from a gas production system into a hydrogen storage layer that includes a subsurface geological formation in which natural hydrogen is at least partially depleted, and later extracting the injected gas for later use. Later use may include energy production, chemical synthesis, or use as another feedstock. Certain embodiments may include injecting hydrogen from a hydrogen production system into a hydrogen storage layer that includes a subsurface geological formation in which natural hydrogen is depleted, and later extracting the injected hydrogen for energy production, for chemical synthesis, or as another feedstock.

[0046] In some embodiments, method 200 may be adapted to sequester carbon dioxide within a natural hydrogen storage layer. In such embodiments, the method may include connecting a carbon dioxide production or capture system, such as a reformer, to the natural hydrogen storage layer, where the reformer is configured to capture carbon dioxide, injecting the captured carbon dioxide into the natural hydrogen storage layer, and mineralizing the captured carbon dioxide within the natural hydrogen storage layer. The reformer may include a steam methane reformer or an autothermal reformer. Mineralizing the captured carbon dioxide may include performing one or more chemical reactions of the carbon dioxide and the rock matrix, such as one or more decarbonation reactions as described in Table 1 below.

Table 1

[0047] Suitable mineralization reactions are described in U.S. Patent Application No. 18 / 133,889, filed April 12, 2023, the disclosure of which is incorporated herein by reference in its entirety.

[0048] Although this specification focuses on hydrogen, helium, and carbon dioxide, the techniques disclosed herein are not so limited and can also be found in the identification, quantitative evaluation, or storage of other gases, minerals, gemstones, and other subsurface materials, as well as in the materials found in large structures such as foundations, dams, hydraulic facilities, nuclear facilities, etc., by way of several examples.

[0049] In the production of natural resources from subterranean formations, a well or borehole is drilled into the ground to a location where the natural resources are believed to be located. Similarly, in the sequestration of greenhouse gases in subterranean formations, a well or borehole is drilled into the ground to a location where the greenhouse gases are to be injected, positioned, or sequestered. These natural resources may be hydrogen, helium, carbon dioxide, methane, or other hydrocarbon gases, hydrogen sulfide, hydrogen storage formations, helium storage formations, carbon dioxide storage formations, hydrogen sulfide-enriched storage formations, hydrocarbon-enriched storage formations, may be fresh water, brackish water, salt water, may be a heat source for geothermal energy, or may be any other natural resources, ore deposits, minerals, metals, or gemstones located in the ground.

[0050] These resource-containing formations may be hundreds, thousands, or tens of thousands of feet below the surface of the earth, including beneath the bottom of a body of water, such as beneath the ocean floor, or beneath other natural resources, such as beneath an aquifer. In addition to being at various depths within the earth, these formations may cover areas of different sizes, shapes, and volumes.

[0051] Typically, and by way of a general example, in the drilling of a well, an initial borehole is made into the ground (e.g., the surface of the land or the ocean floor), and then subsequent smaller-diameter boreholes are drilled to extend the overall depth of the borehole. In this way, as the overall borehole gets deeper, its diameter gets smaller, resulting in what can be imagined as an assembled telescoping hole where the uppermost part of the borehole closest to the surface has the largest-diameter hole.

[0052] Therefore, as an example, the start of a subsea drilling process may generally be described as follows. When the drilling rig is positioned on the water surface above the area where drilling is to be performed, the first borehole is created by drilling a 36-inch hole into the ground to a depth of about 200 - 300 feet below the seabed. A 30-inch casing is inserted into this first borehole. This 30-inch casing may also be referred to as a conductor. The 30-inch conductor may or may not be cemented in place. During this drilling operation, risers are generally not used, and cuttings from the borehole, such as soil and other materials removed from the borehole by the drilling activity, are returned to the seabed. Next, a 26-inch diameter borehole is drilled within the 30-inch casing, extending the depth of the borehole to about 1,000 - 1,500 feet. This drilling operation may also be performed without using a riser. Then, a 20-inch casing is inserted into the 30-inch conductor and the 26-inch borehole. This 20-inch casing is cemented in place. The 20-inch casing has a wellhead secured to the casing. (In other operations, additional smaller diameter boreholes may be drilled, and smaller diameter casings are inserted into those additional smaller diameter boreholes that have a wellhead secured to that smaller diameter casing.) Next, a blowout preventer (BOP) is secured to the riser and lowered to the seabed by the riser, where the BOP is secured to the wellhead. From this point forward, all drilling activities within the borehole are performed through the riser and the BOP.

[0053] It should also be noted that riserless subsea drilling operations are also contemplated.

[0054] For land-based drilling processes, the procedures are similar, but typically, pipes with diameters larger than 20 inches to 30 inches are not used. Therefore, and generally, there is typically a surface casing with a diameter of approximately 13 3 / 8 inches. This may extend from the surface (e.g., wellhead and BOP) to depths of dozens of feet to hundreds of feet. One of the purposes of the surface casing is to address environmental concerns in groundwater protection and prevent surface casing emissions of greenhouse gases or flammable gases. The surface casing should have a diameter large enough to allow the drill string, manufacturing equipment such as an electric submersible pump (ESP), and circulating mud to pass through. Below the casing, one or more intermediate casings of different diameters may be used. (It is understood that sections of the borehole may not be cased, and this section is called an open hole.) These can have diameters in the range of approximately 9 inches to approximately 7 inches, although larger and smaller sizes may be used and can extend to depths of thousands to tens of thousands of feet. The section of the well located within the reservoir layer, e.g., the section of the formation containing natural resources, can be called the pay zone. The production pipe is inside the casing and extends from the production zone of the pay zone or borehole, through the surface wellhead, and to the wellhead. There may be a single production pipe or multiple production pipes within a single borehole, and each end of the production pipe is at a different depth.

[0055] Fluid communication between a formation and a well can be significantly enhanced by the use of hydraulic fracturing techniques. The first use of hydraulic fracturing dates back to the late 1940s to early 1950s. Generally, a hydraulic fracturing treatment involves forcing a fluid through a well and into a formation where the fluid enters and fractures (e.g., breaks apart or fractures) the formation. These fractures create channels or flow paths that can have sizes ranging from 2 - 3 micrometers to 2 - 3 millimeters and up to 4 - 5 millimeters, and potentially larger cross-sections. The fractures can also extend in all directions outward from the well by 2 - 3 feet, 4 - 5 feet, tens of feet, or more. The fractures may be kept open by using proppants (e.g., sand grains of various sizes) that are forced into the well along with the fracturing fluid in a single operation. It should be noted that the long-axis of the well within the reservoir may not be vertical, may be at an angle (tilted up or down), or may be horizontal.

[0056] As used herein, the terms "hydrogen exploration and production", "carbon dioxide exploration and production", "helium exploration and production", "hydrogen sulfide exploration and production", "exploration and production activities", "E&P", "E&P activities", and similar such terms shall, unless otherwise defined, be given their broadest possible meaning and shall include exploration, geological analysis, well planning, reservoir planning, reservoir management, well drilling, modification and completion activities, hydrogen production, helium production, or carbon dioxide production, the flow of hydrogen, helium, or carbon dioxide from a well, the collection of hydrogen, helium, or carbon dioxide, the secondary and tertiary recovery of various fluids from a well, the management of the flow of hydrogen, helium, or carbon dioxide from a well, and any other upstream activities.

[0057] As used herein, the term "soil" should, unless otherwise specified, be given its broadest possible meaning, including all natural materials such as the ground, rocks, and artificial materials such as concrete, whether these are found on the ground or may be found.

[0058] As used herein, the terms "offshore" and "offshore drilling activity" and similar such terms should, unless otherwise specified, be used in their broadest sense and include drilling activities in any body of water, whether fresh or salt water, artificial or natural, such as rivers, lakes, canals, inland seas, oceans, seas such as the North Sea, gulfs such as the Gulf of Mexico, and gulf coasts. As used herein, the term "offshore drilling rig" should, unless otherwise specified, be given its broadest possible meaning and include fixed towers, tenders, platforms, barges, jack-ups, floating platforms, drillships, dynamically positioned drillships, semi-submersible rigs, and dynamically positioned semi-submersible rigs. As used herein, the term "seabed" should, unless otherwise specified, be given its broadest possible meaning and include the surface of any ground beneath or at the bottom of any body of water, whether fresh or salt water, artificial or natural.

[0059] As used herein, the term "borehole" shall, unless otherwise defined, be given its broadest possible meaning and shall include any underground opening that is substantially longer than it is wide, such as a well, wellbore, wellhole, microhole, slimhole, etc., and other terms commonly used to define such narrow and elongated passages, or known in the art. Wells shall further include exploration wells, discovery wells, production wells, abandoned wells, re-drilled wells, workover wells, recycle wells, injection wells. They shall include both cased wells and uncased wells, as well as sections of those wells. An uncased well, or section of a well, is also referred to as an open hole, borehole, open borehole, open bore, open hole section. A borehole may further have segments or sections with different orientations, and may have straight sections and arcuate sections, as well as combinations thereof. Accordingly, as used herein, the "bottom", "bottom surface" of a borehole and similar terms shall, unless explicitly stated otherwise, refer to the end of the borehole, e.g., the opening of the borehole, the surface of the earth, or the portion of the borehole furthest along the path of the borehole from the start of the borehole. The terms "side" and "wall" of a borehole shall be given their broadest possible meaning and shall include the longitudinal surface of the borehole, whether or not there is a casing or liner present, and thus these terms shall include the sides of an open borehole, or the sides of a casing positioned within the borehole. A borehole may be made from a single passage, multiple passages, connected passages (e.g., a branched configuration, a fishbone configuration, a dual lateral configuration, a trilateral configuration, a quadrilateral configuration, a pitchfork configuration, a plume configuration, or a comb configuration), as well as combinations and variations thereof.

[0060] Boreholes are generally formed and advanced by using mechanical drilling equipment having a rotary cutting tool (e.g., a bit). For example, also generally, when creating a borehole in the ground, the cutting bit extends into the ground, enters the ground, and rotates to create a hole in the ground. To perform the drilling operation, the bit must be pressed against the material to be removed with sufficient force to exceed the shear strength, compressive strength, or a combination thereof of that material. The material cut from the ground is generally known as cuttings or drill cuttings (e.g., waste), which may be pieces of rock, dust, rock fibers, and other types of materials and structures that may be created by the interaction of the bit with the ground. These cuttings are typically removed from the borehole by the use of a fluid, which can be a liquid, foam or gas, or other materials known in the art.

[0061] As used herein, the term "drill pipe" should be given its broadest possible meaning unless otherwise defined, and includes all forms of pipe used in drilling activities, and refers to a single section or piece of pipe. As used herein, the terms "drill pipe stand", "drill pipe stand", "pipe stand", "stand" and similar types of terms should be given their broadest possible meaning and typically include two, three, or four sections of drill pipe connected (e.g., joined together) by threaded joints. As used herein, the terms "drill string", "string", "drill pipe string", "pipe string" and similar terms should be given their broadest definitions and will include stands (s) joined together for the purpose of use within a borehole. Therefore, a drill string can potentially include numerous stands and hundreds of sections of drill pipe.

[0062] As used herein, the terms "formation", "reservoir", "payzone", and like terms should, unless otherwise defined, be given their broadest possible meaning and shall include all subterranean locations, areas, and geological features that contain, may contain, or are thought to contain hydrogen, carbon dioxide, helium, or hydrogen sulfide.

[0063] As used herein, the terms "field", "oilfield", "gas field", and like terms should, unless otherwise defined, be given their broadest possible meaning and shall include any area of land, seabed, or water area that is broadly or directly associated with geological formations, and more specifically formations containing resources. Thus, a field may have one or more exploration and production wells associated therewith, a field may have one or more government agencies or private resource leases associated therewith, and one or more fields may be directly associated with a formation containing resources.

[0064] As used herein, the terms "conventional hydrogen", "conventional carbon dioxide", "conventional helium", "conventional hydrogen sulfide", "conventional natural gas", "conventional", "conventional production", and like terms shall, unless otherwise defined, be given their broadest possible meaning and shall include hydrogen, carbon dioxide, helium, or hydrogen sulfide trapped in subterranean structures or other capture mechanisms. Generally, in these conventional formations, hydrogen, carbon dioxide, helium, hydrogen sulfide, or natural gas migrates in permeable or semi-permeable formations to a trap or area where they accumulate. Typically, in conventional formations, non-porous and relatively impermeable layers are above or surround the area of accumulated hydrogen, carbon dioxide, helium, hydrogen sulfide, or natural gas and essentially trap the hydrogen, carbon dioxide, helium, hydrogen sulfide, or natural gas in a stored state. Conventional reservoirs have historically been the source of most of the observed natural gas, hydrogen, carbon dioxide, helium, hydrogen sulfide. As used herein, the terms "non-conventional hydrogen", "non-conventional carbon dioxide", "non-conventional helium", "non-conventional hydrogen sulfide", "non-conventional natural gas", "non-conventional", "non-conventional production", and like terms shall, unless otherwise defined, be given their broadest possible meaning and shall include hydrogen, carbon dioxide, helium, hydrogen sulfide, or natural gas held in impermeable rock and not migrated to a trap or area of accumulation.

[0065] The recitation of a range of values herein is merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein. Each separate value within the range is hereby incorporated into the specification as if it were individually recited herein, unless otherwise indicated herein.

[0066] Generally, as used herein, the term "about" shall, unless otherwise stated, mean a difference or range of ±10%, experimental error or instrumental error associated with obtaining the recited value, and preferably the greater of these.

[0067] Unless otherwise specified, the room temperature used in this specification is 25°C. Also, standard temperature and pressure are 25°C and 1 atmosphere.

[0068] The term "CO2e" is used to define other more potent greenhouse gases equivalent to carbon dioxide (e.g., methane) based on the 100-year global warming potential according to the IPCC AR5 methodology. The term "carbon intensity" is considered to mean the life cycle CO2e produced per unit mass of the product.

[0069] CO2 is widely recognized as a greenhouse gas (GHG), and the continuous accumulation of CO2 and other GHGs in the atmosphere is expected to cause problematic changes to the Earth's ecosystem and contribute to numerous other issues such as ocean acidification and sea-level rise. The two major causes of global carbon emissions are the use of fossil fuels for power generation and transportation.

[0070] Given the risk of CO2 emissions, significant efforts have been made to find alternatives to existing high-carbon energy sources or ways to decarbonize existing energy sources. However, many of these low-carbon alternatives have not been economic or fully feasible to replace current options.

[0071] In power generation, alternatives to reliable, low-cost but high-emitting sources (e.g., gas and coal) are either viable and expensive (e.g., nuclear, hydro, green hydrogen, or blue hydrogen) or inexpensive and intermittent (e.g., solar and wind, and in some cases green hydrogen). The only existing source that is lower cost and viable is geothermal. However, geothermal resources are limited, many of the economically productive geothermal resources have already been developed and are approaching the end of their life, and many geothermal resources are already in a state of decline. Thus, without significant technological advancements, the growth outlook for geothermal is limited.

[0072] Green hydrogen (hydrogen produced from water without using fossil fuels), which is generated by electrolysis powered by sunlight, wind, hydropower, or geothermal energy, can be a reliable low-carbon energy source when connected to a storage unit. However, high capital costs, intermittent production due to intermittent energy sources, high energy costs when grid-connected, and high costs and low availability of suitable hydrogen storage resources limit its applicability. In addition, electrolysis consumes significantly more energy to produce hydrogen than the energy stored in the hydrogen state, resulting in low round-trip efficiency in the system.

[0073] Blue hydrogen faces a similar set of problems as green hydrogen. Blue hydrogen requires a low-cost, high-emission fuel source such as coal or natural gas and adds an expensive and parasitic carbon capture facility to convert this low-cost, high-emission energy source into a high-cost, low-emission supply source. Therefore, despite the ability to form large amounts of hydrogen in a process that prevents subsequent greenhouse gas emissions from reaching the atmosphere, newly developed hydrogen resources are not cost-competitive compared to other forms of energy derived from fossil fuels. In addition, the challenges of finding carbon sequestration resources that can be used to permanently store the carbon captured from these processes ultimately provide only limited opportunities to deploy these technologies today.

[0074] Natural hydrogen (or gold hydrogen) produced from underground by drilling and manufacturing wells can provide a rich source of energy that is low in emissions, low in cost, and fully viable. Existing natural hydrogen reservoirs may constitute volumetric and reliable sources of surface hydrogen storage and easily viable hydrogen supply.

[0075] Each of these energy sources, and their respective advantages and limitations, are also relevant to transportation. When considering transportation fuels, the main fuel sources are undoubtedly diesel and gasoline, both of which are derived from crude oil production. In addition, although electric vehicles have been expanding their market share in recent years, the cost of electric vehicles is still higher than that of fossil fuel-powered vehicles, and there are limitations regarding cost, recharging time, and the main resources for batteries and energy storage. Considering the weight of the batteries, long-distance electric transport trucking is also difficult, and most long-distance transport truck manufacturers are looking for available low-carbon options such as hydrogen fuel trucking.

[0076] Natural hydrogen could potentially be the answer to the problems of low-carbon, low-cost, and reliable transportation for long-distance transport trucking and potentially other forms of transportation. Similar to other types of transportation, natural hydrogen as a compressed or liquefied product, or as a feedstock for synthetic fluid fuels ("efuel"), could be a reliable low-cost, low-carbon solution. In addition, natural hydrogen can be combined with nitrogen to produce carbon-free ammonia products, which are widely considered as potential alternatives to bunker fuels for ships.

[0077] Reduction of direct emissions: Since there is no direct CO2 emission from the combustion or typical use of hydrogen, the reduction of CO2 emissions is a function of what hydrogen replaces. In most cases, hydrogen is an alternative to natural gas, either in ammonia production, in refining, as a feedstock for other chemicals, or in power generation.

[0078] In the case of ammonia production and purification, natural gas is used to produce hydrogen via steam methane reforming, which is used as a feedstock for chemicals in both the purification process and the ammonia production process. Today, over 95% of hydrogen is produced using natural gas in steam methane reformers (SMRs). The carbon intensity of hydrogen production using SMRs without carbon capture is 10.4 tons of CO2 emitted per ton of hydrogen produced. Thus, direct substitution of natural hydrogen for hydrogen produced by the SMR process results in a CO2 reduction of 10.4 tons CO2 / ton H2.

[0079] In power generation using gas turbines, hydrogen needs to replace the energy (btu) equivalent to natural gas. The energy density of hydrogen is 290 btu / cf or 51,682 btu / lb. In comparison, the energy density of natural gas is 983 btu / cf or 20,267 btu / lb, while the carbon intensity of natural gas is 52.91 kg CO2 / mmbtu CH4, 54.87 kg CO2 / mcf CH4, or 3.5 kg CO2 / kg CH4.

[0080] Since hydrogen has an energy density 2.6 times higher per unit mass than natural gas, only 40% of the total tonnage of fuel is required to achieve the same energy output. Therefore, burning 1 ton of H2 for power generation reduces natural gas consumption by approximately 2.6 tons, and thus reduces CO2 emissions by 9.1 tons.

[0081] Comparing natural hydrogen to hydrogen produced by electrolysis, the carbon reduction is a function of the carbon intensity of the electricity used in the electrolysis process. However, while there may be significant indirect emissions associated with electrolysis, there are no direct emissions. Therefore, natural hydrogen does not result in a reduction in direct emissions compared to hydrogen produced by electrolysis.

[0082] Indirect Emission Reduction: Analysis of the life cycle carbon intensity of natural hydrogen using OPGEE indicates that the life cycle carbon intensity of natural hydrogen is in the range of 0.1 - 0.4 tons CO2 / ton H2. There is no similar available research on other methods of hydrogen production. However, assuming an average grid intensity of 0.5 tons CO2 / MWh and that electrolysis requires approximately 50 MWh / ton H2 of production, the indirect emissions associated with electrolysis are approximately 25 tons CO2 / ton H2 produced assuming grid power. Naturally, operators of electrolysis units can purchase renewable energy credits to artificially reduce the carbon footprint of their power use, but this may not be recognized as a sustainable way to reduce real-time carbon emissions in the market.

[0083] The realization of abundant natural hydrogen makes it possible to achieve a significant reduction in equivalent carbon emissions. Energy systems containing hydrogen can provide relatively low emissions and low costs linked to a reliable energy source. This advantage is included in both the power generation cost and the transportation cost. In some embodiments, the hydrogen can be from a natural source from either a geothermal reservoir or other natural or synthetic hydrogen source.

[0084] Note that there is no requirement to provide or address the theory underlying the novel and epoch-making manufacturing speed, performance, or other beneficial features and characteristics that are the subject of, or are associated with, embodiments of the present disclosure. Nevertheless, various theories are provided herein to further advance the art in this important area, specifically in the important areas of exploration, production, and downstream conversion or utilization of hydrogen, hydrogen sulfide, carbon dioxide, and helium. These theories in no way limit, restrict, or narrow the scope of protection afforded to the claimed invention, unless otherwise explicitly stated herein. These theories may not be required or practiced for the use of the present invention. It is further understood that the present invention may lead to new and previously unknown theories for explaining the conductivity, fracture, drainage, resource production, chemical, and functional characteristics of embodiments of the methods, articles, materials, devices, and systems of the present invention, and that such later-developed theories do not limit the scope of protection afforded to the present invention.

[0085] The present invention may be embodied in forms other than those specifically disclosed herein without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and non-limiting. The various aspects and embodiments disclosed herein are for illustrative purposes and are not intended to be limiting. The various embodiments of the apparatus, system, activity, method, operation described herein may be used with, by, or in various processes, industries, operations in addition to those of the embodiments in the figures, and may be used with, by, or in those processes, industries, operations, or may be disclosed herein. The various embodiments of the apparatus, system, method, activity, operation described herein may be used with other process industries and operations that may be developed in the future, existing process industries and operations that may be partially modified based on the teachings herein, and other types of gas recovery and price stabilization systems and methods. Further, the various embodiments of the apparatus, system, activity, method, operation described herein may be used with each other in different combinations and various combinations. Therefore, for example, the configurations provided in the various embodiments herein may be used with each other. For example, the components of an embodiment having A, A', and B, and the components of an embodiment having A'', C, and D may be used with each other in various combinations, such as A, C, D, and A, A'', C, and D, etc., in accordance with the teachings herein. Therefore, the scope of protection provided by the present invention should not be limited to a particular embodiment, example, or a particular embodiment, configuration, or arrangement described in a particular embodiment within a particular figure.

[0086] Terms of degree (e.g., "about", "substantially", "generally", etc.) indicate variations that are not structurally or functionally significant. In one embodiment, when a term of degree is included in a term indicating quantity, the term of degree is construed to mean ±10%, ±5%, or ±2% of the term indicating quantity. In one embodiment, when a term of degree is used to modify a shape, the term of degree indicates that the shape modified by the term of degree has the appearance of the disclosed shape. For example, the term of degree may be used to indicate that the shape may have rounded corners instead of sharp corners, may have curved edges instead of straight edges, may have one or more protrusions extending therefrom, is elliptical, is the same as the disclosed shape, etc.

[0087] (Appendix) (Appendix 1) A method for providing a gas, comprising: connecting a hydrogen storage layer to a gas production system; injecting gas from the gas production system into the hydrogen storage layer; extracting the injected gas from the hydrogen storage layer; and a method comprising the steps of:

[0088] (Appendix 2) The method according to Appendix 1, wherein connecting the hydrogen storage layer to the gas production system includes creating a fluid connection using one or more of a well, a pipeline, or a pump between the gas production system and the hydrogen storage layer.

[0089] (Appendix 3) The method according to Appendix 1, wherein connecting the hydrogen storage layer to the gas production system includes connecting the hydrogen storage layer to an output of one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen.

[0090] (Appendix 4) Injecting gas from the gas production system into the hydrogen storage layer includes injecting hydrogen from one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen, the method according to appendix 1.

[0091] (Appendix 5) Injecting gas from the gas production system into the hydrogen storage layer includes injecting the gas into the hydrogen storage layer through an injection well, the method according to appendix 1.

[0092] (Appendix 6) Extracting the injected gas occurs after the hydrogen storage layer has depleted natural hydrogen, the method according to appendix 1.

[0093] (Appendix 7) Extracting the injected gas occurs in parallel with the depletion of natural hydrogen from the hydrogen storage layer, the method according to appendix 1.

[0094] (Appendix 8) The hydrogen storage layer includes a subsurface geological formation with depleted natural hydrogen, the method according to appendix 1.

[0095] (Appendix 9) The gas includes one or more of hydrogen, carbon dioxide, or helium, the method according to appendix 1.

[0096] (Appendix 10) The method according to appendix 9 further includes supplying the extracted gas through a pipeline to one or more of an energy production facility or a chemical substance production facility.

[0097] (Appendix 11) A method of providing hydrogen, comprising: Connecting a hydrogen storage layer to a hydrogen production system; Injecting hydrogen from the hydrogen production system into the hydrogen storage layer; Extracting the injected hydrogen for energy production; A method comprising

[0098] (Appendix 12) Connecting a hydrogen storage layer to a hydrogen production system, the method according to Appendix 11, comprising connecting the hydrogen storage layer to one or more outputs of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen.

[0099] (Appendix 13) Injecting hydrogen from the hydrogen production system into the hydrogen storage layer, the method according to Appendix 11, comprising injecting hydrogen from one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen.

[0100] (Appendix 14) Extracting the injected hydrogen, the method according to Appendix 11, wherein the extraction occurs after the natural hydrogen in the hydrogen storage layer has been depleted from the hydrogen storage layer.

[0101] (Appendix 15) Extracting the injected hydrogen, the method according to Appendix 11, wherein the extraction occurs in parallel with the depletion of natural hydrogen from the hydrogen storage layer.

[0102] (Appendix 16) The method according to Appendix 11, wherein the hydrogen storage layer comprises a subsurface geological formation where natural hydrogen has been depleted.

[0103] (Appendix 17) The method according to Appendix 11, further comprising supplying the extracted hydrogen to one or more of an energy production facility or a chemical substance production facility.

[0104] (Appendix 18) A method for storing carbon dioxide, comprising Connecting a carbon dioxide source to a natural hydrogen storage layer, wherein the carbon dioxide source is configured to capture carbon dioxide, and Injecting the captured carbon dioxide into the natural hydrogen storage layer. Mineralizing the captured carbon dioxide in the natural hydrogen storage layer; A method comprising the above.

[0105] (Appendix 19) The method according to Appendix 18, wherein the carbon dioxide source includes at least one of a steam methane reformer or an autothermal reformer.

[0106] (Appendix 20) A method for providing hydrogen, comprising: Injecting hydrogen from a hydrogen production system into a hydrogen storage layer including a subsurface geological formation with depleted natural hydrogen; Extracting the injected hydrogen for energy production, chemical synthesis, or output to a feedstock; A method comprising the above.

[0107] (Appendix 21) A system for providing stored hydrogen, comprising: A natural hydrogen storage layer; A hydrogen production system; One or more conduits connecting the natural hydrogen storage layer to the hydrogen production system; A system comprising the above.

[0108] (Appendix 22) The system according to Appendix 21, wherein the natural hydrogen storage layer contains non-natural hydrogen therein.

[0109] (Appendix 23) The system according to Appendix 21, wherein the hydrogen production system includes one or more of a reformer system, an electrolysis system, a pyrolysis system, or a plasma reformer.

[0110] (Appendix 24) A hydrogen storage layer, comprising: A porous subsurface rock; An injection well configured to supply one or more of hydrogen gas, helium, or carbon dioxide gas to the porous subsurface rock, wherein one or more of the hydrogen gas, helium, or carbon dioxide gas are stored at a pressure equal to or greater than the hydrostatic pressure, and the injection well. A hydrogen storage layer comprising

[0111] (Appendix 25) The hydrogen storage layer according to Appendix 24, further comprising carbon dioxide in the porous subsurface rock, wherein the carbon dioxide is supercritical.

[0112] (Appendix 26) The hydrogen storage layer according to Appendix 24, further comprising a production well configured to remove one or more of the hydrogen gas, helium, or carbon dioxide gas from the porous subsurface rock.

Claims

Claim 1 A method for providing a gas, comprising: connecting a hydrogen storage layer to a gas production system; injecting a gas from the gas production system into the hydrogen storage layer; extracting the injected gas from the hydrogen storage layer. A method comprising the above steps. Claim 2 The method according to claim 1, wherein connecting the hydrogen storage layer to the gas production system includes creating a fluid connection using one or more of a well, a pipeline, or a pump between the gas production system and the hydrogen storage layer. Claim 3 The method according to claim 1, wherein connecting the hydrogen storage layer to the gas production system includes connecting the hydrogen storage layer to an output of one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen. Claim 4 The method according to claim 1, wherein injecting a gas from the gas production system into the hydrogen storage layer includes injecting hydrogen from one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen. Claim 5 The method according to claim 1, wherein injecting a gas from the gas production system into the hydrogen storage layer includes injecting the gas into the hydrogen storage layer through an injection well. Claim 6 The method according to claim 1, wherein extracting the injected gas occurs after the hydrogen storage layer has depleted its natural hydrogen. Claim 7 The method according to claim 1, wherein extracting the injected gas occurs in parallel with the depletion of natural hydrogen from the hydrogen storage layer. Claim 8 The method according to claim 1, wherein the hydrogen storage layer includes a subsurface geological formation with depleted natural hydrogen. Claim 9 The method according to claim 1, wherein the gas includes one or more of hydrogen, carbon dioxide, or helium. Claim 10 The method according to claim 9, further comprising supplying the extracted gas through a pipeline to one or more of an energy production facility or a chemical production facility. Claim 11 A method for providing hydrogen, comprising: connecting a hydrogen storage layer to a hydrogen production system; injecting hydrogen from the hydrogen production system into the hydrogen storage layer; extracting the injected hydrogen for energy production. A method comprising the above steps. Claim 12 Connecting the hydrogen storage layer to a hydrogen production system includes connecting the hydrogen storage layer to the output of one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen, the method according to claim 11.

13. Injecting hydrogen from the hydrogen production system into the hydrogen storage layer includes injecting hydrogen from one or more of an electrolysis system, a thermal decomposition system, or a reformer system configured to produce hydrogen, the method according to claim 11.

14. Extracting the injected hydrogen occurs after the hydrogen storage layer has depleted natural hydrogen from the hydrogen storage layer, the method according to claim 11.

15. Extracting the injected hydrogen occurs in parallel with the depletion of natural hydrogen from the hydrogen storage layer, the method according to claim 11.

16. The hydrogen storage layer includes a subsurface geological formation where natural hydrogen has been depleted, the method according to claim 11.

17. The method according to claim 11 further includes supplying the extracted hydrogen to one or more of an energy production facility or a chemical substance production facility.

18. A method for storing carbon dioxide, Connecting a carbon dioxide source to a natural hydrogen storage layer, wherein the carbon dioxide source is configured to capture carbon dioxide, the connecting, Injecting the captured carbon dioxide into the natural hydrogen storage layer, Mineralizing the captured carbon dioxide within the natural hydrogen storage layer, comprising the method.

19. The method according to claim 18, wherein the carbon dioxide source includes at least one of a steam methane reformer or an autothermal reformer.

20. A method for providing hydrogen, Injecting hydrogen from a hydrogen production system into a hydrogen storage layer including a subsurface geological formation where natural hydrogen has been depleted, Extracting the injected hydrogen for energy production, chemical synthesis, or output to a feedstock, comprising the method.

21. A system for providing stored hydrogen, A natural hydrogen storage layer, A hydrogen production system, One or more conduits connecting the natural hydrogen storage layer to the hydrogen production system, comprising the system.

22. The system according to claim 21, wherein the natural hydrogen storage layer contains non-natural hydrogen therein.

23. The system according to claim 21, wherein the hydrogen production system includes one or more of a reformer system, an electrolysis system, a thermal decomposition system, or a plasma reformer.

24. A hydrogen storage layer, comprising: a porous subsurface rock; and an injection well configured to supply one or more of hydrogen gas, helium, or carbon dioxide gas to the porous subsurface rock, wherein the one or more of hydrogen gas, helium, or carbon dioxide gas are stored at a pressure equal to or greater than the hydrostatic pressure. A hydrogen storage layer comprising the above.

25. The hydrogen storage layer according to claim 24, further comprising carbon dioxide in the porous subsurface rock, wherein the carbon dioxide is supercritical.

26. The hydrogen storage layer according to claim 24, further comprising a production well configured to remove one or more of the hydrogen gas, helium, or carbon dioxide gas from the porous subsurface rock.

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