A system for hydrogen production by (subsurface) serpentinization and carbonization of mafic or ultramafic rocks in situ.

Abstract

To provide systems and methods for hydrogen recovery and carbon dioxide sequestration by in-situ engineering within mafic and / or ultramafic rock formations.SOLUTION: A method of producing hydrogen gas from a formation comprising pyrogamous, ultra-pyrogamous, or a combination thereof, the method comprising: providing a wellbore at least partially traversing the formation, the wellbore providing a pathway for injection of fluids into the formation and collection of fluids from the formation; injecting a water-based stimulant through the pathway provided by the wellbore to contact a reactive surface of the formation; and collecting a fluid composition comprising hydrogen gas from the formation via the pathway.SELECTED DRAWING: Figure 1A

Description

[Background technology]

[0001] The environmental burden of greenhouse gases, primarily carbon dioxide (CO2) and methane (CH4), has been the subject of much public discussion over the past few decades. More recently, voluntary private sector initiatives and government-mandated regulations have begun to be implemented to reduce greenhouse gas emissions into the environment. In addition to the capture and / or sequestration of carbon dioxide and other greenhouse gases to mitigate their release into the atmosphere, much research and development effort has focused on the use of alternatives to fossil fuel combustion for energy production to reduce the amount of carbon dioxide that is produced and / or that needs to be captured and sequestered.

[0002] Hydrogen (H) gas is a promising energy source (e.g., as hydrogen fuel or through the use of green ammonia) and a chemical feedstock (e.g., methanol, ammonia, hydrocarbon fuels) that produces little or no greenhouse gases upon combustion. Indeed, when hydrogen gas is combusted, only water is produced as a reaction product. However, hydrogen gas has traditionally been produced using fossil fuels (e.g., through natural gas / methane conversion in a steam reformer), which produces carbon dioxide, a greenhouse gas, as a reaction product. For example, in the aforementioned steam methane reforming reaction, methane reacts with steam (i.e., water) to produce hydrogen gas and carbon monoxide. In the subsequent water-gas shift reaction, carbon monoxide further reacts with steam to produce carbon dioxide and additional hydrogen gas. The hydrogen gas is then separated from the carbon dioxide by pressure swing adsorption, membrane separation, or other gas separation processes. Thus, for example, most hydrogen produced in smelter operations produces greenhouse gases that must be captured and sequestered to provide any meaningful benefit.

[0003] Alternatively, hydrogen gas can be produced by electrolysis of water into hydrogen gas and oxygen. The hydrogen gas is subsequently separated from the oxygen by pressure swing adsorption, membrane separation, or other gas separation processes. Producing hydrogen by electrolysis or partial pyrolysis requires significant amounts of electricity. While at least a portion of the electricity required for hydrogen production by electrolysis and / or partial pyrolysis can be obtained from renewable sources (e.g., wind, solar, hydroelectric), in practice, the majority of the electricity used for hydrolysis has traditionally and continues to be generated by the combustion of fossil fuels, which also produces greenhouse gases.

[0004] Abiotic production of hydrogen gas is known to occur within certain geological formations, such as the young oceanic crust near mid-ocean ridges, as shown in Figures 1A-1D. These natural reactions occur over a wide range of environmental conditions, including varying pH, oxygen fugacity, chemical composition, and pressure. While such reactions result in diverse and complex mineralogical compositions and chemistries, they do not predictably yield any particular combination of reaction products. Indeed, as generally illustrated in the cross-section photograph of Figure 2, rock deposits 200 capable of producing abiotic hydrogen often contain complex mixtures or layers of mineral phases that are difficult to extract, or will not produce the desired product if other competing reactions are favored based on in situ geochemical conditions (e.g., variable redox potential (Eh), pH, pore water composition, gas chemistry, and temperature). For example, the kinetics and magnitude of hydrogen production are inherently highly variable, and its occurrence is highly dependent on pH, Eh, and other aspects of fluid geochemistry within pore spaces and at mineral surfaces. Thus, the complex kinetics of the reaction phases and the occurrence of competing reactions under natural conditions (e.g., near-neutral pH, variable oxygen fugacity, and variable pore water chemistry) dictate the products produced by these naturally occurring reactions. Certain geological formations and / or their rocks are also known to contain minerals that, under certain conditions, favor reaction with carbon dioxide to form carbonate mineral phases, e.g., carbonates. Summary of the Invention [Problem to be solved by the invention]

[0005] Figure 3 provides a map highlighting example locations of selected suitable and / or robust mafic and ultramafic rock deposits around the world. Olivine- and pyroxene-bearing ores can be found in such mafic and / or ultramafic formations. As can be seen from Figure 3, mafic and ultramafic igneous rock sources can be found in many locations and are highly abundant, comprising at least 10% of the Earth's continental crust, demonstrating the global applicability of the solutions described herein. More recently, such mafic and ultramafic igneous rock sources have attracted interest due to their potential use for carbon dioxide sequestration (mineralization) in carbonate mineral phases. However, despite extensive prior research on carbon sequestration, considerable debate exists regarding the best mechanical responses and optimized rates for carbon mineralization. As a result, the economics of in situ processes have not been fully developed, nor have the hydrogen production and carbon sequestration potential of underground mafic and ultramafic rocks been realized. Additionally, porosity, permeability, and subsurface fracture formation must be optimized to provide sufficient surface area for the reaction to reach thermodynamic completion and / or economic viability.

[0006] Although such geological formations and / or ores therein have the theoretical potential to be utilized for geological hydrogen or other products, and potentially for carbon sequestration, the processes and kinetics of these reactions have not been rigorously evaluated or optimized for subsurface or sub-surface conditions. Furthermore, processes for producing hydrogen from these formations underground have not been developed. Accordingly, Applicant has recognized a need for systems and methods that utilize specific geological formations and / or ores therein in situ to liberate and / or produce hydrogen from formations containing olivine- and pyroxene-rich ores, and in addition, sequester carbon dioxide as carbonates. [Means for solving the problem]

[0007] The disclosure herein provides one or more embodiments of systems and methods for in-situ engineered hydrogen recovery and carbon dioxide sequestration within mafic and / or ultramafic rock formations.

[0008] For example, a method of producing hydrogen gas from a formation comprising mafic igneous rock, ultramafic igneous rock, or a combination thereof may include providing a wellbore at least partially across the formation, the wellbore providing a pathway for injection of fluids into and withdrawal of fluids from the formation; injecting an aqueous stimulated agent through the pathway provided by the wellbore and into contact with a reactive surface of the formation; and withdrawing a fluid composition comprising hydrogen gas from the wellbore via the pathway.

[0009] In some embodiments, the method may include hydraulically fracturing the formation by pumping an aqueous stimulation agent through a wellbore at high pressure into the formation. In some embodiments, the aqueous stimulation agent does not include carbon dioxide. In some embodiments, the aqueous stimulation agent includes dihydrogen sulfide. In some embodiments, the aqueous stimulation agent has an oxygen fugacity with a negative Eh value. In some embodiments, the aqueous stimulation agent includes sodium chloride at a salinity between about 0.1 parts per million and 4.5. And, in some embodiments, the aqueous stimulation agent injected into the pathway has a pH between about 8.3 and about 11.1.

[0010] In some embodiments, the pressure near the reactive surface of the formation is greater than about 1 atmosphere (about 1 bar) and less than the lithostatic pressure of the target formation. Further, in some embodiments, the reactive surface of the formation has a temperature between about 60°C and about 260°C. Alternatively, the reactive surface of the formation may have a temperature greater than about 260°C. In the latter case, the method may include minimizing interaction of carbon dioxide with the reactive surface of the formation during injection of the aqueous stimulation agent. In various embodiments, the reactive surface of the formation comprises one or more of fayalite, fayalite, or a combination thereof.

[0011] In some embodiments, the method includes draining fluid from the formation prior to injecting the aqueous stimulation agent into the formation through a pathway provided by the wellbore.

[0012] In some embodiments, the fluid composition recovered from the wellbore further comprises one or more redox-sensitive components from the rock formation. In some such embodiments, the method may further comprise separating the one or more redox-sensitive components from the fluid composition recovered from the wellbore.

[0013] In various embodiments, the method may include using the fluid composition recovered from the well as a fuel. Additionally or alternatively, recovering the fluid composition from the well via a pathway may include storing the fluid composition near the well and / or transporting the fluid composition via a pipeline.

[0014] In some embodiments, the method includes injecting carbon dioxide into the formation through a pathway provided by the well after the fluid composition has been recovered, wherein at least a portion of the carbon dioxide reacts with one or more mafic or ultramafic rocks in the formation to produce at least magnesium carbonate or calcium carbonate. In some such embodiments, the injected carbon dioxide includes a mixture of water and carbon dioxide. For example, the water and carbon dioxide mixture may have a pH between about 4.8 and about 6.5. Further, the water and carbon dioxide mixture may include sodium chloride at a salinity between 0.1 and 4.5. Further, the water and carbon dioxide mixture may include nitrogen, dihydrogen sulfide, methane, or other trace gases.

[0015] In various embodiments, the carbon dioxide injected into the formation may be injected at a pressure between 1 bar and the lithostatic pressure of the target formation. Additionally, the carbon dioxide injected into the formation may include supercritical carbon dioxide or a mixture of supercritical carbon dioxide and other fluids. In some embodiments, injecting carbon dioxide through a pathway provided by a well bore is performed as part of a well stimulation process.

[0016] Corresponding means for performing the various method steps are described below.

[0017] An exemplary system for in-situ engineered hydrogen recovery and / or carbon dioxide sequestration within a mafic and / or ultramafic rock formation may include a wellbore at least partially traversing the formation; a source of aqueous stimulated agent in fluid communication with the wellbore and configurable to allow the aqueous stimulated agent to pass to the formation through a path defined at least in part by the wellbore; a fluid containment device positioned near the top of the wellbore and having one or more outlets through which a fluid composition comprising hydrogen gas may be recovered from the wellbore; and a source of carbon dioxide in fluid communication with the wellbore and configurable to allow the carbon dioxide to pass to the formation through a path defined at least in part by the wellbore.

[0018] In some embodiments, the system includes a pipeline connected to one or more outlets of the fluid containment device and configured to discharge a fluid composition comprising hydrogen gas that has passed from the wellbore through the fluid containment device. The system may further include a fluid storage vessel connected to one or more outlets of the fluid containment device and configured to store the fluid composition comprising hydrogen gas that has passed from the wellbore through the fluid containment device. Additionally, the fluid containment device may be a wellhead.

[0019] In various embodiments, the carbon dioxide source can be configured to deliver carbon dioxide to the wellbore at a pressure between 1 atmosphere (approximately 1 bar) and the lithostatic pressure of the target formation. In some such embodiments, the delivered carbon dioxide can be supercritical carbon dioxide or a mixture of supercritical carbon dioxide and other fluids. In some such embodiments, the carbon dioxide can be a mixture of water and carbon dioxide, which in some such embodiments can have a pH between about 4.8 and about 6.5 and / or can contain sodium chloride at a salinity between 0.1 parts per million and 4.5 parts per million. Furthermore, in some embodiments, the carbon dioxide can be a mixture of water and carbon dioxide containing nitrogen, dihydrogen sulfide, methane, and / or other trace gases.

[0020] In various embodiments, the aqueous irritant may include hydrogen sulfide. The aqueous irritant may have an oxygen fugacity with a negative Eh value. Furthermore, the aqueous irritant may include sodium chloride at a salinity of between about 0.1 parts per million and 4.5 parts per million. Furthermore, the aqueous irritant may have a pH of between about 8.3 and about 11.1.

[0021] In some embodiments, the system may further include a fracturing device that may be configured to hydraulically fracture a region of the formation near the wellbore.

[0022] The foregoing Summary of the Invention has been provided solely for the purpose of summarizing some exemplary embodiments described herein. The above-described embodiments are merely examples, and therefore should not be construed as narrowing the scope of the present disclosure in any way. It will be understood that the scope of the present disclosure encompasses many potential embodiments in addition to those summarized above, some of which are described in further detail below. [Brief explanation of the drawings]

[0023] Having generally described certain exemplary embodiments above, reference is now made to the accompanying drawings, which are not necessarily drawn to scale. Some embodiments may include fewer or more components than shown in the figures.

[0024] [Figure 1A] FIG. 1A shows a series of cross sections of young oceanic crust and associated structures located near theoretical mid-ocean ridges that could result in and / or host abiotic hydrogen production. [Figure 1B] Figure 1B shows a series of cross sections of young oceanic crust and associated structures located near theoretical mid-ocean ridges that could result in and / or host abiotic hydrogen production. [Figure 1C] Figure 1C shows a series of cross sections of young oceanic crust and associated structures located near theoretical mid-ocean ridges that could result in and / or host abiotic hydrogen production. [Figure 1D] FIG. 1D shows a series of cross sections of young oceanic crust and associated structures located near theoretical mid-ocean ridges that could result in and / or host abiotic hydrogen production. [Figure 2] Figure 2 shows an exemplary cross section of serpentinized ultramafic rock. [Figure 3] FIG. 3 shows a map depicting the location of suitable olivine and pyroxene-bearing sources around the world. [Figure 4] FIG. 4 illustrates an exemplary well site proximate a geological source of mafic or ultramafic igneous rock, according to some exemplary embodiments described herein. [Figure 5] FIG. 5 illustrates an exemplary flow chart for facilitating in-situ generation of hydrogen gas from mafic or ultramafic igneous rocks, according to some exemplary embodiments described herein. DETAILED DESCRIPTION OF THE INVENTION

[0025] Certain illustrative embodiments will now be described in more detail hereinafter with reference to the accompanying drawings, in which some, but not necessarily all, embodiments are shown. Because the invention described herein may be embodied in many different forms, the invention should not be limited to only the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements.

[0026] [overview] Hydrogen production and carbon dioxide sequestration are significant hurdles that must be cleared for society to transition to a future economy less dependent on carbon-rich fossil fuels. As previously mentioned, the exemplary embodiments described herein provide systems and methods for performing both serpentinization reactions, which produce hydrogen, and carbonation reactions, which mineralize carbon, in the same operation by applying specific stimuli in situ to mafic and / or ultramafic igneous rocks to promote both reactions. Implementation of the various embodiments contemplated herein requires a wellbore that at least partially traverses a mafic or ultramafic igneous rock formation. The wellbore provides a pathway for the injection of fluids into and the recovery of fluids from the mafic or ultramafic portions of the formation. As described in more detail below, exemplary embodiments utilize a two-stage reaction to first produce hydrogen by injecting an aqueous stimulant (the unique properties of which are described below) into the well, and then sequester carbon dioxide within the rock formation by injecting carbon dioxide into the well for permanent storage within the rock formation. By identifying rock formations with suitable properties, subsurface depths that optimize favorable chemical reactions of the fluid with the rock, the sequence and nature of the injection and recovery of the fluid, and the unique properties of the fluid injected into the rock formation, exemplary embodiments can achieve both meaningful hydrogen recovery and carbon sequestration.

[0027] In contrast to strategies for ex-situ hydrogen production and carbon dioxide sequestration, optimizing the economics of hydrogen production and corresponding subsurface carbon dioxide sequestration requires unique mechanistic processes. In an ex-situ environment, sufficiently complete hydraulic stimulation and / or rock fracturing may occur to maximize the effectiveness of both the hydrogen production and carbon dioxide sequestration reactions. However, while the degree of hydraulic stimulation and rock fracturing that may be possible ex-situ cannot be achieved subsurface, and therefore full thermodynamic completion of either the carbonation or serpentinization reactions cannot be achieved, additional considerations are required to operate in-situ in a manner that further favorably enhances porosity, permeability, and subsurface fracture formation to ensure that injection of fluids (i.e., water, carbon dioxide, and carbon dioxide-rich brines) promotes both hydrogen production and carbon sequestration at a meaningful scale and in a controllable manner.

[0028] Other underground carbon sequestration strategies can inject gas-phase carbon dioxide into isolated geological formations and into saline aquifers, but each of these strategies has significant challenges. With regard to storing fluid carbon dioxide, all such strategies create environmental risks and future carbon management challenges, as any stored gas may migrate at some point in the future. Therefore, carbon mineralization is the preferred mechanism for carbon sequestration (as evidenced by the fact that the United States offers significantly higher tax credits for permanent carbon sequestration in carbonate minerals than for other forms of storage).

[0029] However, existing carbon mineralization strategies also face significant challenges inherently associated with the carbon mineralization process. The process of carbon mineralization causes volumetric expansion of rocks, which manifests itself in situ as a decrease in porosity, a decrease in permeability in most cases, and changes in the fracture characteristics (openness, diameter, pore throat size, connectivity) of fluid flow paths within the rock, or, in the worst case, the complete closure of these flow paths. Injecting carbon dioxide to induce carbon mineralization reduces the hydraulic conductivity of the rock into which the carbon dioxide is injected, thereby reducing both the potential for hydrogen production and the remaining overall ability to use existing underground well infrastructure for ongoing carbon sequestration. Because mafic and ultramafic rocks have very low porosity and permeability to begin with, and carbon mineralization in such formations further reduces porosity and permeability, strategies focused solely on carbon mineralization can sequester relatively small amounts of carbon. This makes the economics of such strategies particularly challenging. A technique that partially ameliorates this problem is the use of supercritical carbon dioxide, which allows it to penetrate all available flow paths to a greater extent than would be possible using any other form of carbon dioxide, and Applicant uses this aspect in some embodiments.

[0030] As a result, the economics of in situ processes have not been fully developed, nor have the hydrogen production and carbon sequestration capabilities of subsurface mafic and ultramafic rocks been realized. To Applicant's knowledge, there have been no prior attempts to use optimized chemical processes for hydrogen production followed by carbon mineralization to improve the kinetics and total volume of in situ hydrogen production, reservoir fluid flow characteristics, or carbon sequestration.

[0031] While a high level description of the steps of the exemplary embodiments is provided above, specific details regarding the construction of such exemplary embodiments are provided below.

[0032] [Serpentinization and carbonation reactions] The disclosure herein provides one or more embodiments of systems and methods for promoting the production of hydrogen and / or other desired minerals through serpentinization reactions involving olivine- and pyroxene-rich ores found in mafic and / or ultramafic igneous rocks. Olivine is a major component of both mafic and ultramafic rocks and is a solid solution series of magnesium silicate (forsterite) and iron silicate (ferro-olivine). In olivine-rich deposits, fayalite is typically a minor component, with concentrations ranging from 5% to 20% of olivine, with lower concentrations being more common. As a result, the thermochemical activity of fayalite in such deposits is relatively low compared to that of forsterite. Nevertheless, the reaction, when completed, produces magnetite, silica, and hydrogen (from the reaction of fayalite with water). Pyroxene is also a common component of both mafic and ultramafic rocks, often consisting of a solid solution of ferro-sapphire and enstatite. As with fayalite, the reaction of ferro-sapphire (5%-20% of pyroxene) with water produces magnetite, silica, and hydrogen.

[0033] Table 1, provided below, shows a representative serpentinization reaction involving fayalite (Fe2SiO4), fayalite (Fe2SiO6), and forsterite (Mg2SiO4). Fayalite and forsterite are mineral phases associated with olivine-rich ores, while fayalite is a mineral phase associated with pyroxene-rich ores. Under certain conditions (i.e., pH greater than 8, low oxygen fugacity (having a negative Eh value or negative potential)), water reacts with fayalite and fayalite to produce magnetite (Fe3O4), silica (SiO2), and hydrogen gas (H2) in the preferred stoichiometric ratio. In each case, two moles of hydrogen gas are produced from three moles of fayalite or fayalite minerals. Under other conditions (acidic or near-neutral pH, oxidizing conditions), water reacts with forsterite to produce antigorite (Mg3SiO5(OH)4), brucite (Mg(OH)2), and / or numerous other accessory mineral phases in favorable stoichiometric ratios. In such cases, two moles of forsterite mineral do not produce hydrogen gas, but these conditions promote the corresponding mineralization of carbon dioxide, which reduces porosity, permeability, and fluid flow potential.

[0034] [Table 1]

[0035] In one or more embodiments, the disclosed systems and methods may also facilitate the sequestration of gaseous carbon dioxide (e.g., as a carbonate mineral phase) through carbonation reactions involving olivine- and pyroxene-rich ores found in mafic and / or ultramafic rocks. Table 2, provided below, shows exemplary carbonation reactions involving forsterite (MgSiO), enstatite (MgSiO), anorthite (CaAlSiO), antigorite (MgSiO(OH)), and brucite (Mg(OH)). Forsterite is a mineral phase associated with olivine-rich ores, enstatite is a mineral phase associated with pyroxene-rich ores, anorthite is a mineral phase associated with plagioclase-rich ores, and antigorite and brucite are mineral phases associated with serpentine-rich ores.

[0036] Carbon dioxide reacts with forsterite, enstatite, anorthite, and / or antigorite to produce at least magnesium carbonate (or, in the case of anorthite, at least calcium carbonate) and silica (SiO2) (or, in the case of anorthite, kaolinite (Al2SiO5(OH)4)); these reactions are promoted under acidic conditions in the presence of water and CO2. The reaction of antigorite and brucite with carbon dioxide also produces stoichiometric amounts of water. In carbonation reactions involving forsterite and enstatite, two moles of carbon dioxide gas are converted to magnesium carbonate per mole of forsterite or enstatite mineral. In the carbonization of antigorite, three moles of carbon dioxide gas are converted to magnesium carbonate per mole of antigorite. In the case of anorthite, three moles of carbon dioxide gas are converted to calcium carbonate per mole of anorthite. Finally, the reaction of brucite with carbon dioxide produces one mole of magnesium carbonate per two moles of water, as shown in the stoichiometric ratios in Table 2.

[0037] [Table 2]

[0038] In nature, and as previously mentioned, the serpentinization and carbonization reactions described above occur, but only in a combination of reactions occurring simultaneously (or sequentially) in situ under a variety of environmental conditions that are difficult to predict and often chaotic, based on the properties of fluids with variable and sometimes changing properties (e.g., pH, oxygen fugacity, pore water chemistry (e.g., salinity), gas chemistry, and pressure found in nature). The numerous reactions occurring in nature result in diverse and complex mineralogical compositions and chemistries, but do not predictably result in any particular combination of usable reaction products.

[0039] Applicant recognizes that, as discussed above, despite the great theoretical potential of mafic and / or ultramafic igneous rocks (i.e., ores containing olivine and pyroxene with high iron content, for example), the processes and kinetics of serpentinization and carbonation reactions have not been rigorously evaluated or optimized for production purposes underground. Accordingly, such reactions have not historically been deployed to utilize geological resources for economic geological hydrogen and as a natural resource and catalyst for hydrogen production or carbon sequestration. Specifically, process steps to enhance underground carbon sequestration and production of hydrogen and / or other minerals from these rock types have not been developed. Furthermore, to Applicant's knowledge, there have been no prior attempts to use optimized chemical processes of hydrogen production or carbon mineralization to improve the kinetics and overall volume of hydrogen production, the fluid flow characteristics of the reservoir, or the capacity for additional underground carbon dioxide mineralization.

[0040] On-site hydrogen generation and carbon dioxide sequestration In various embodiments contemplated herein, carbon dioxide can be mineralized and hydrogen can be produced economically (and with an overall neutral to net-negative carbon footprint) by an engineered system that uses olivine- and pyroxene-rich ores accessed by underground drilling and hydraulic stimulation of mafic or ultramafic rocks to optimize serpentinization and carbonation reactions. To produce these results, applicants have developed an engineered process that stimulates sequential reactions that can be carried out by and / or within a well site system such as that shown in FIG. 4.

[0041] FIG. 4 illustrates an exemplary engineered system including a well site 400 proximate a mafic igneous or ultramafic igneous rock formation. As shown in FIG. 4, a system of components is disposed at the well site 400 to facilitate the injection and withdrawal of fluids into and from the formation. These components interact with the formation through a well bore 402 drilled into the formation to enable the injection and withdrawal of fluids. The well bore may be drilled in any suitable manner, such as using a drilling rig 404, as shown in FIG. 4. A fluid containment device, such as a wellhead (not shown in FIG. 4), may be disposed near the top of the well bore 402 (in lieu of the drilling rig 404) to provide a structural and pressure-containing interface for the injection and withdrawal of fluids from the well bore 402. The fluid containment device may have one or more outlets through which fluids are injected into or withdrawn from the well bore 402.

[0042] The depth of well 402 may be designed based on the unique characteristics of the formation into which well 402 is drilled, with the goal of drilling well 402 to a depth that allows fluids to interact with subsurface regions of the formation that have temperatures suitable for hydrogen production or carbon dioxide mineralization.

[0043] Injection of fluid into the formation hydraulically stimulates the rock, which may induce or widen fractures 406 within the rock formation near the wellbore. For example, injection of aqueous stimulation agents may promote serpentinization and other reactions within reactive mineral phases in the rock. As previously discussed, serpentinization reactions cause chemical reactions (i.e., changes in constituent minerals) that alter the crystalline structure of the rock formation to produce hydrogen and introduce additional pore space, permeability, and hydraulic connectivity to the formation near the wellbore 402. Without the increase in pore volume during the initial hydrogen production step, the occurrence of carbon dioxide mineralization processes (i.e., known to occur in natural systems) would reduce the porosity of the constituent mafic and ultramafic rocks. As another example, available techniques such as directional drilling and hydraulic fracturing may be used to induce fractures, thereby increasing (engineered secondary) porosity and permeability, and thus increasing the surface area available for reaction underground. In this regard, hydraulic stimulation (i.e., hydraulic fracturing) techniques may utilize fracturing equipment to hydraulically fracture the formation by pumping fluid, and possibly proppant, at high pressure through a wellbore 402 into the formation to induce new fractures 406 or enlarge and / or maintain existing fractures 406 in the rock formation.

[0044] 4 further illustrates that fluid may be provided for injection into the well 402 by a tanker truck carrying a fluid tank 408. The fluid tank 408 may be connected to an outlet of the fluid containment device via a hose 410 (which may facilitate transport of the fluid in the fluid tank 408 through the well 402 and into the target formation). While the fluid tank 408 is shown for ease of explanation, it will be understood that various illustrative embodiments may utilize a variety of different methods of delivering fluid to the fluid containment device for injection into the well 402. For example, while such fluid may be received by a truck as shown in FIG. 4, the fluid may be transmitted by a pipeline or containment pond connecting a source of the fluid to the fluid containment device. Similarly, it will be appreciated that various exemplary embodiments can be configured to inject any of a variety of different types of fluids (e.g., brine, CO2-enriched brine, H2S-enriched brine, CO2) into the wellbore 402 via the fluid containment device, and other fluids, such as aqueous stimulant and carbon dioxide, fracturing fluids, and / or proppants, as described herein, can also be injected into the rock formation via the wellbore 402.

[0045] Finally, the well site 400 may contain one or more fluid storage vessels 412A-412N that may be configured to connect (e.g., via a pipeline) to a fluid containment device via a pipeline and deliver fluid to the fluid containment device for injection into the well 402 or to receive recovered fluid from the well 402 via the fluid containment device. The fluid storage vessels 412A-412N may further connect to additional processing or purification components located at the well site 400, or may be connected or configurable to connect to a pipeline for transmitting the stored gas to a remote location away from the well site 400. In some embodiments, the fluid storage vessels 412A-412N may be further configurable to transmit the stored gas to a tanker for transport by truck, rail, or boat, or in some embodiments, may themselves be portable and transported in such manner. Additionally or alternatively, the recovered fluid may be transmitted directly to a remote location away from the well site 400 that is not at the well site 400. In some embodiments, fluids recovered from the well 402 may be utilized on-site as fuel to power processing or refining machinery, to generate heat to be added to fluids injected into the rock formation, or for other energy needs at the well site for any other suitable purpose.

[0046] 5, a flow chart including exemplary steps for on-site hydrogen production and carbon dioxide sequestration according to embodiments described herein is shown. The procedure shown in FIG. 5 may begin at step 502, where a new well is drilled to enable subsequent steps in the procedure, or at step 508, where an existing well may be repurposed for use in the exemplary methods described herein.

[0047] An exemplary method may begin in step 502 and include locating a geological formation containing mafic igneous rock or ultramafic igneous rock. As previously discussed, certain desirable reactions for producing hydrogen and sequestering carbon involve olivine- and pyroxene-rich ores found in mafic igneous rock and / or ultramafic igneous rock. Olivine is a solid solution of forsterite and fayalite. In olivine deposits of interest for hydrogen production, fayalite is typically a minor component ranging from 6% to 20%, typically present at the lower end of the concentration spectrum. Pyroxene is often organized in a solid solution series comprising fayalite and enstatite in proportions comparable to the iron-bearing fayalite. As a result, the potential thermochemical activity of both fayalite and fayalite as part of the solid solution series is relatively low compared to the potential thermochemical activity of pure fayalite and fayalite. The mineral mixture is a nearly "ideal" solution. In an ideal solution, thermochemical activity scales linearly with and is approximately equal to mole fraction. Therefore, catalyzing a multi-step reaction that initially targets one end of the olivine-pyroxene solid solution enhances the chemical reactivity of the remaining phase, further benefiting the increased activity resulting from incipient cracking and the corresponding increase in permeability.

[0048] In addition to the ideal rock formation characteristics for utilization in the engineered solutions contemplated herein, economic considerations also drive the identification of suitable formations. To this end, ideal locations for implementing exemplary embodiments have rock formations near potential users of the produced hydrogen gas, thereby enabling the supply of produced hydrogen to nearby end users without the additional costs or logistics associated with transporting the hydrogen gas from the well site to a buyer.

[0049] Furthermore, because the primary driver of the hydrogen production reaction is the presence of iron-rich mineral phases in the source rock, other rock formations besides mafic or ultramafic rocks may also be suitable for certain embodiments contemplated herein. For example, reduced iron minerals such as pyrite can effectively generate hydrogen when reacted with water and therefore may be suitable locations for the hydrogen-producing components of some embodiments contemplated herein (even though such locations may not be suitable for subsequent carbon sequestration).

[0050] As indicated by operation 504, an exemplary method may include drilling a well into the located formation. The well may be drilled to a depth having a temperature profile suitable for catalyzing and / or promoting the serpentinization reaction. For example, the serpentinization reaction described above is highly temperature-sensitive, with the reaction beginning to produce hydrogen above about 60°C and increasing in reaction rate as the temperature increases. However, higher temperatures are not necessarily preferred in all embodiments contemplated herein. Above about 260°C, hydrogen produced in situ from the reaction of water with the source rock may react with carbon dioxide to produce methane in a reaction known as the Sabatier reaction. Thus, in some embodiments, the well may be drilled to a depth where the formation has a temperature between about 60°C and about 260°C, particularly in the presence of CO2, which is common and often abundant underground. However, because methane itself is a useful product, in some embodiments where both hydrogen and methane may be recovered from the formation, wells extending into subsurface regions having temperatures greater than 260°C may be even more preferred. Furthermore, it is believed that higher temperatures may produce more hydrogen, although some of the produced hydrogen will react to produce methane because higher temperatures promote the serpentinization reaction. Finally, in some embodiments, methane production by the Sabatier process may be avoided by minimizing the interaction of carbon dioxide with hydrogen underground, for example, by minimizing or eliminating the presence of carbon dioxide in any fluids injected into the well during the initial serpentinization / hydration step; in this case, drilling wells to depths that provide higher temperatures may also be preferable. At these depths, pressures near the reactive surface of the formation would be about 50 bar or greater.

[0051] As illustrated by step 506, some exemplary methods may hydraulically fracture the formation to improve the formation's hydraulic connectivity and expose additional reactive surfaces. However, as previously discussed, the injection of aqueous stimulation agent into the rock formation itself may cause a sufficient increase in porosity, permeability, and hydraulic connectivity so that a precursor fracturing step is not necessary. Following step 504, or following optional step 506, the procedure may then proceed to step 510, described below. In embodiments where an existing well site is selected for use, the procedure may begin with step 508 rather than step 502.

[0052] In step 508, some example methods may begin by locating an existing well that provides access to a reactive surface of mafic or ultramafic rock. For example, a particular geothermal well may be drilled into a mafic or ultramafic formation and then be a suitable candidate for the example embodiments described herein. Furthermore, the same considerations related to locating rock formations suitable for drilling a well may be used to identify existing wells that can be repurposed for hydrogen production and / or carbon sequestration, as described herein.

[0053] Following drilling (and possibly hydraulic fracturing) of a well as described in steps 504 and 506, or after simply locating a suitable existing well as described in step 508, the procedure may then proceed to step 510 for the first of two artificially induced rock reaction stages. Optionally, before performing step 510, the well may be evaluated to remove any potential fluids (e.g., gas, water, brine, drilling fluid, etc.) present in the well.

[0054] As indicated by step 510, an exemplary method includes injecting an aqueous stimulated agent into a path provided by a wellbore so that the stimulated agent contacts reactive surfaces of the formation. According to the serpentinization reaction described above, reaction of at least a portion of the aqueous stimulated agent with one or more of the formation's reactive surfaces produces hydrogen. Following hydraulic stimulation, or when utilizing a natural fracture network, thermochemical activity, and therefore reaction rate, can be enhanced by first removing the fayalite by reacting it with water under favorable conditions of temperature (60°C-260°C), pressure (>1 atmosphere, but typically above 50 bar), gas chemistry, pore water chemistry (e.g., salinity), pH (>8.3, but typically above 9.5), and reducing conditions / low oxygen fugacity (i.e., negative Eh). As fayalite and fayalite are expelled from solid solution by reaction with water of optimized composition, the thermochemical activity of the remaining forsterite and enstatite, and of antigorite and / or brucite and / or other mineral phases produced by the carbonation reaction, increases with the newly exposed surface area. Thus, the reactivity of the remaining forsterite and enstatite minerals proceeds at an increased rate (found to be 4% to 19% faster in laboratory simulations) with the now higher mole fraction of this phase in solid solution.

[0055] In many embodiments, the aqueous stimulant may be intentionally free of carbon dioxide. By injecting the aqueous stimulant into the formation without the co-reaction of carbon mineralization common in nature, which is facilitated by the presence of carbon dioxide, step 510 increases the porosity and permeability in the rock formation itself, thereby allowing for greater infiltration of additional water for further hydrogen production, ultimately improving the likelihood of increased carbon dioxide mineralization within the newly formed pores (up to the theoretical limit of iron silicate phases, e.g., up to ∼20%). This improvement occurs because the reaction of water with fayalite and fayalite in mafic or ultramafic rocks produces rock structures with volumetrically smaller crystalline structures. For example, magnetite can be produced by injecting water into the formation with pre-reacted fayalite (4,390 kg / m 3 ) or iron pyroxene (3,880 kg / m 3) has a higher density (5,170 kg / m 3 ), which has a volumetrically small spinel crystal structure. Thus, the injection of aqueous stimulateant in step 510 promotes the reaction of the fayalite and fayalite with water, thereby reducing the reactive surface volume of the formation and increasing porosity and permeability, which in turn increases hydraulic connectivity in the subsurface region adjacent to the wellbore, thereby increasing the surface area available for subsequent reaction.

[0056] Furthermore, this water-rock reaction differs in several important ways from reactions that occur naturally underground. First, the aqueous irritant may contain properties not found in nature. For example, the aqueous irritant may not contain pure water but may also contain other components such as hydrogen sulfide (0% to 30% by volume in the gas phase) or salts (e.g., Na, Ca, Cl, Br). Furthermore, the aqueous irritant may have an oxygen fugacity with a negative Eh value (i.e., a negative potential) across a range of sodium chloride (NaCl) salinities (0.1 part per mille to 4.5 part per mille), a pH between about 8.3 and about 11.1. This combination of properties rarely occurs naturally in situ and is difficult to maintain through the evolution of various geological processes. To produce aqueous stimulated agents with low oxygen fugacity, water may be sourced from groundwater, municipal wastewater, mineral water, geothermal water, and / or other wastewater / process water streams that naturally have low oxygen fugacity, or may be pretreated to artificially induce low oxygen fugacity (e.g., by passing the aqueous stimulated agent through a bed of heated copper tailings or otherwise electrocatalyzing the removal of oxygen prior to injection into the well). Additionally, the pH balance of the aqueous stimulated agent may be adjusted by the addition of sodium bicarbonate or various hydroxides. Finally, the salinity of the aqueous stimulated agent may be adjusted by the addition of sodium chloride or other common salts (e.g., KCl).

[0057] Thereafter, in step 512, a fluid composition including hydrogen, a mixture of hydrogen and nitrogen, a mixture of hydrogen and methane, and / or a mixture of hydrogen and carbon dioxide gas may be recovered from the well. Importantly, the molecular and isotopic composition of the hydrogen formed by the in-situ reaction may be determined and used to quantify the contribution from in-situ hydrogen production based on measurements of in-situ temperature conditions and comparison with a standard geothermometer based on the known fractionation coefficient (α) between HO and H. The fluid may flow spontaneously under its own pressure or may be pumped from the well following step 512, after which it may be stored for later use, further processed and delivered from the well site, or even used as a fuel at the well site itself. While hydrogen production was previously described as being a product of interaction between the injected aqueous irritant and reactive surfaces of the mafic or ultramafic rock, other reactions may also occur. For example, depending on the fluid composition used during treatment, certain redox-sensitive components of the rock formation, such as lithium, nickel, molybdenum, cobalt, rare earth elements (e.g., lanthanum, cerium), and uranium, may be mobilized from the water injection described in step 510. The disclosed two-step fluid injection process involves a change in redox conditions (i.e., Eh, from oxidizing to reducing) and a change in pH conditions (from acidic to basic), so that various rare metals are solubilized and thus recoverable by the permeable fluid from the wellbore. The fluid composition recovered from the wellbore may also contain these mobilized components, which may then be further separated from the fluid composition after extraction from the wellbore. Separation may be performed using density separation, membranes, or gangue material collection.

[0058] Following step 512, the procedure may return to step 510 for another injection of aqueous stimulant, or the procedure may proceed to step 514, as described below.

[0059] After recovery of the fluid composition, step 514 indicates that the exemplary method may utilize subsequent injection of carbon dioxide into the formation and the pathway provided by the well. The carbon dioxide may be injected at pressures above atmospheric pressure, up to (but below) the lithostatic pressure expected for the potential pressure within the target rock formation (taking into account various safety factors). Reaction of at least a portion of the carbon dioxide with one or more of forsterite, enstatite, antigorite, or brucite in the formation permanently mineralizes the carbon from the injected carbon dioxide into a solid (mineralized) form of magnesium carbonate or other carbonate minerals. In various embodiments, the injected carbon dioxide may be supercritical carbon dioxide and / or a fluid mixture of carbon dioxide, water, and other elements. For example, the carbon dioxide mixture may also include various percentages of nitrogen (N, up to at least 50%) or various percentages of other gases (e.g., helium (He, up to at least 1%), argon (Ar, up to at least 1%), dihydrogen sulfide (HS, up to at least 10%). The carbon dioxide mixture may have a pH between about 4.8 and about 6.5 and may contain a salinity of sodium chloride (NaCl) (0.1 to 4.5 parts per million).

[0060] Injecting carbon dioxide promotes mineralization within the rock formation, thereby reducing the rock's porosity, permeability, and hydraulic connectivity. Thus, because carbon mineralization tends to "plug" the rock formation, in some embodiments, the step of injecting carbon dioxide through a pathway provided by the wellbore, operation 514, may be performed as part of the wellbore stimulation process.

[0061] As described above, the illustrative embodiments provide methods and systems for on-site hydrogen production and permanent (mineralization) sequestration of carbon dioxide.

[0062] FIG. 5 illustrates steps performed in various exemplary embodiments. It will be understood that each flowchart block and each combination of flowchart blocks can be implemented by various means. The flowchart blocks support combinations of means for performing a particular function and combinations of steps for performing a particular function. In some embodiments, some of the steps described above may be modified or further extended. Furthermore, in some embodiments, additional optional steps may be included. Modifications, extensions, or additions to the steps described above may be performed in any order and in any combination.

[0063] [Laboratory Experiment] In a simulated implementation of the system and method of the present disclosure, ultramafic ore was reacted with carbon dioxide to sequester the carbon dioxide as magnesium carbonate, and the ultramafic ore was reacted with water to produce hydrogen gas. This example was carried out in three stages: 1) rock preparation; 2) water preparation; and 3) the reaction process, each of which is described in more detail below. As part of the analysis of the overall system and method, the composition of the ore (i.e., forsterite, fayalite, and other minerals), the reaction conditions to which the ore was exposed, and the properties of the carbonation / serpentinization reaction products were evaluated. For example, with respect to the ore composition, the mass, mineralogical composition, and geochemical composition of the bulk rock were determined by powder X-ray diffraction (XRD) to assess the abundance of relevant components (e.g., fayalite, fayalite, FeO, MgO, CaO).

[0064] For the rock preparation phase, ultramafic aggregate material, primarily consisting of lightly crushed rock approximately 1.0 cm in size, was collected from four operating quarries (i.e., two quarries in Pennsylvania, one quarry in Virginia, and one quarry in Kentucky). The ultramafic aggregate material was first crushed (i.e., lightly crushed / ground) with a rock hammer and then with a Spex Ball mill. The powder material was then sieved using a mineral sieve designed to pass 150 micron particles and then 80 micron particles. This allowed for experiments with at least two different particle sizes. Another material, homogenized olivine mineral, was also purchased from a scientific supplier in California. This olivine material was homogenized in size and composition and had a uniform particle size of approximately 100 microns.

[0065] Two preparations were made during the water preparation stage. First, low-oxygen fugacity, high-pH water was obtained by adding sodium bicarbonate to tap water to adjust the water's pH to between about 8.5 and about 11.1. As will be understood by those skilled in the art, oxygen fugacity (fO2) is a measure of the amount of oxygen available to react with elements with multiple valence states, such as iron and carbon. High oxygen fugacity indicates a high chemical potential for oxygen in water. Reducing the oxygen fugacity of water can be achieved in a variety of ways (e.g., by using a low-oxygen fugacity feedwater such as municipal wastewater, groundwater, mine water, or other wastewater stream). One simple and reliable method for generating low-oxygen fugacity water utilizes a bed of copper filings heated to 125°C and passes the water through the bed. Another method, brine water, was obtained by adding salt (sodium chloride) to tap water to create a salt solution ranging from 0.09% to 1.5%. In preparation for the carbon mineralization experiments, the pH of the brine was adjusted to between about 4.8 and about 6 using dilute HCl in a mixture of distilled water and sodium acetate buffer.

[0066] Regarding the reaction process, a batch reactor was designed and constructed to perform the carbonation and serpentinization reactions in both batch and sequential configurations. All reactions were carried out as "batch" reactions (i.e., a closed system) within this sealed stainless steel reactor. For each experiment, a whole sample (approximately 250 grams) was selected and sliced ​​equally into two pieces, and approximately 125 grams of the raw material was placed in the airtight stainless steel reactor. To prepare the vessel for injection, high-pH (8.3-11.1 obtained using tap water and sodium bicarbonate) low-oxygen fugacity water and brine (obtained by adding NaCl to concentrations from 0.1 to 4.5 parts per million) were used. To reduce oxygen fugacity, the experimental setup utilized a bed of copper filings heated to 125°C. For a separate CO2 introduction step, tap water is lightly acidified using dilute HCl in a mixture of distilled water and sodium acetate buffer, mixed with NaCl at ambient oxygen fugacity from 0.1 to 4.5 parts per million, and sprayed onto powdered rock to provide a moist surface (known to improve CO2 reactivity) for the reaction.

[0067] The first reaction stage aimed to produce hydrogen. A mechanical roughing pump was used to remove ambient oxygen and evacuate the reactor before introducing water with low oxygen fugacity. Water was then introduced at room temperature and atmospheric pressure. The initial pressure was recorded. The temperature was increased to 60°C, 100°C, 150°C, 200°C, 250°C, 300°C, and 400°C, controlled by an external band heater and measured with an Omega K-wire thermocouple. At each step, the gas-phase pressure was measured at the sampling port by monitoring with a standard Omega 0-100 psi pressure gauge, and an aliquot of gas was measured using a Stanford Research Systems Residual Gas Analyzer ("quadrupole mass spectrometer") and an SRI gas chromatograph equipped with a thermocouple detector. The total hydrogen pressure was calculated by multiplying the hydrogen gas fraction measured using a residual gas analyzer and / or gas chromatograph by the pressure relative to atmospheric pressure, assuming PV = nRT. Preliminary results indicated that reducing the particle size from 150 microns to 80 microns improved the reaction rate of hydrogen at thermodynamic equilibrium (approximately 1.3 times) and the total volume of hydrogen (1.8 times more at a given temperature and composition).

[0068] The second series of experiments focused on carbon sequestration in pursuit of carbon-neutral to carbon-negative hydrogen. This setup initially focused on powdered rock, then the process was stepped up to utilize whole rock core plug samples. In both cases, the material was sprayed with water and placed in a stainless steel reactor vessel, and the reactions were carried out as "batch" reactions. Before the introduction of water, a mechanical roughing pump was used to remove ambient oxygen and evacuate the reactor; subsequent experiments demonstrated that the presence of oxygen was not critical to the reaction. Next, carbon dioxide (UHP CO2 and separately, CO2 mixed 4:1 with N2) was introduced at room temperature and at an initial pressure of 2 atm (above atmospheric pressure). The temperature (controlled by an external band heater and measured by a thermocouple) was then increased to 100°C, 150°C, 200°C, 250°C, 300°C, and 400°C. At each step, the gas-phase pressure was measured at the sampling port by monitoring with a standard Omega 0-100 psi pressure gauge, and an aliquot of gas was measured using a Stanford Research Systems residual gas analyzer ("quadrupole mass spectrometer") and an SRI gas chromatograph equipped with a thermocouple detector. The total hydrogen pressure was calculated by multiplying the hydrogen gas fraction measured using the residual gas analyzer and / or gas chromatograph by the pressure relative to atmospheric pressure, assuming PV = nRT. As a next step in this process, the CO2 pressure, measured using an on-tank CO2 pressure gauge, was increased to 5 bar, 10 bar, 25 bar, and 50 bar. While significantly higher pressures can be achieved underground, they were not feasible with the current experimental equipment; increasing the pressure would improve the reaction rate. At each step, the gas phase pressure was measured at a sampling port attached to the depressurizing expansion volume and monitored using a standard Omega 0-100 psi pressure gauge, and an aliquot of gas was measured using a Stanford Research Systems residual gas analyzer ("quadrupole mass spectrometer") and an SRI gas chromatograph equipped with a thermocouple detector. The total hydrogen pressure was calculated by multiplying the hydrogen gas fraction measured using the residual gas analyzer and / or gas chromatograph by the pressure relative to atmospheric pressure, assuming PV = nRT.CO2 sequestration kinetics also improved (approximately 1.8 times) with decreasing particle size. The same systematic experimental design utilized supercritical CO2. After the experiment, sections of each sample (from both the first and second runs) were compared under an optical microscope to identify mineralization and assess porosity.

[0069] After the hydrogen generation experiments, "pre-concentration" of Mg-rich Mg-silica phases in magnetite, brucite, and serpentine, as well as in the bulk rock, was confirmed. An optimized carbon sequestration experimental design was applied to the new material. With each temperature step, the pressure from the injected CO2 decreased more significantly, indicating a faster CO2 sequestration reaction rate (a 3.6-fold faster decrease was observed between 50°C and 400°C over 18 hours in the batch experiment). After the experiments, sections of each sample (from both the first and second runs) were compared under an optical microscope to identify mineralization and assess porosity. The reaction rate improved (approximately 1.4-fold) because hydrogen generation and CO2-induced comminution helped promote further decomposition of the rock.

[0070] After the sequential reactions, the mass, mineralogical composition, and geochemical composition of the bulk rock were determined by XRD to assess the abundance of relevant elements (e.g., fayalite, fayalite, FeO, MgO, and CaO). The abundance of magnesite and calcite was observed to be significantly higher (1.4 times) in the sequential reactions than in the reactions without first initiating hydrogen production. Prior to the start of the experiment, the first fragments were evaluated using an optical microscope to identify mineral distribution, cracks, and pore space, and compared with the processed samples. The first fragment of each sample was placed in the reaction chamber within an airtight stainless steel reaction vessel. The second fragment of each sample was used as a control for comparison.

[0071] [Green (carbon negative) hydrogen] As previously mentioned, carbon sequestration in carbon dioxide has been targeted through carbonation reactions. The formation of magnesite (magnesium carbonate) and calcite (calcium carbonate) through a "water-rock" serpentinization reaction using CO2 and water injected (in situ) into mafic or ultramafic rocks provides an economical, scalable, and permanent (i.e., mineralized) form of carbon sequestration. The carbon sequestration invention, coupled with in-situ engineered hydrogen production, is a two-step process involving: 1) first, the removal of Fe-rich Fe-silicate (or, in some cases, Fe-sulfide) phases through in-situ engineered hydrogen production using optimized serpentinization conditions, thereby enhancing the thermochemical driving force of the carbonation reaction; and 2) the chemical decomposition of the Mg-rich and Ca-rich silicate fraction of mafic and ultramafic rocks through the injection of a mixture of water and CO2 under optimized conditions (pH 4.4-6 under atmospheric (oxidizing) conditions) at temperatures between 100°C and 400°C and pressures exceeding approximately 50 bar, to produce magnesite (magnesium carbonate) and calcite (calcium carbonate). This process is carried out sequentially under optimized conditions that enable and promote the production of magnesite and calcite while minimizing the formation of secondary / competing phases, resulting in the formation of high porosity, permeability, and fracture strength achieved by the sequential reactions.

[0072] [Conclusion] Many modifications and other embodiments of the inventions described herein will come to mind to one skilled in the art to which these inventions pertain having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. It is, therefore, to be understood that the invention is not limited to the specific embodiments disclosed, and that modifications and other embodiments are intended to be included within the scope of the appended claims. Furthermore, while the foregoing description and the associated drawings describe exemplary embodiments with reference to certain illustrative combinations of elements and / or functions, it is to be understood that different combinations of elements and / or functions may be provided in alternative embodiments without departing from the scope of the appended claims. In this regard, other combinations of elements and / or functions than those expressly described above are also contemplated, for example, as set forth in some of the appended claims. Although specific terms are employed herein, they are used in a generic and descriptive sense only and not for purposes of limitation.

[0073] (Addendum) (Appendix 1) 1. A method for producing hydrogen gas from a geological formation comprising mafic igneous rock, ultramafic igneous rock, or a combination thereof, comprising: providing a wellbore at least partially across the formation, the wellbore providing a path for injection of fluid into the formation and withdrawal of fluid from the formation; injecting an aqueous stimulant through the pathway provided by the wellbore and into contact with a reactive surface of the formation; recovering a fluid composition comprising hydrogen gas from the well via the pathway; Including, method.

[0074] (Appendix 2) hydraulically fracturing the formation by pumping the aqueous stimulation agent at high pressure through the wellbore and into the formation; The method described in Appendix 1.

[0075] (Appendix 3) The aqueous stimulant does not contain carbon dioxide. 3. The method according to claim 1 or 2.

[0076] (Appendix 4) The aqueous irritant comprises dihydrogen sulfide. 4. The method of any one of claims 1 to 3.

[0077] (Appendix 5) The aqueous stimulant has an oxygen fugacity with a negative Eh value; 5. The method of any one of claims 1 to 4.

[0078] (Appendix 6) The aqueous irritant comprises sodium chloride at a salinity of about 0.1 parts per million to 4.5 parts per million. 6. The method of any one of appendices 1 to 5.

[0079] (Appendix 7) The aqueous irritant infused into the pathway has a pH between about 8.3 and about 11.1. 7. The method of any one of appendices 1 to 6.

[0080] (Appendix 8) the pressure near the reactive surface of the formation is greater than about 1 atmosphere and less than the lithostatic pressure of the formation; 8. The method of any one of appendices 1 to 7.

[0081] (Appendix 9) the reactive surface of the formation has a temperature between about 60°C and about 260°C; 9. The method of any one of appendices 1 to 8.

[0082] (Appendix 10) the reactive surface of the formation has a temperature greater than about 260°C; 9. The method of any one of appendices 1 to 8.

[0083] (Appendix 11) further comprising the step of minimizing carbon dioxide interaction with the reactive surfaces of the formation during injection of the aqueous stimulation agent. 11. The method described in Appendix 10.

[0084] (Appendix 12) the reactive surface of the formation comprises one or more of fayalite, fayalite, or a combination thereof; 12. The method of any one of claims 1 to 11.

[0085] (Appendix 13) further comprising draining fluid from the formation prior to injecting the aqueous stimulation agent into the formation through the pathway provided by the well; 13. The method of any one of appendices 1 to 12.

[0086] (Appendix 14) the fluid composition recovered from the well further comprises one or more redox-sensitive components from the formation. 14. The method of any one of appendices 1 to 13.

[0087] (Appendix 15) further comprising separating the one or more redox-sensitive components from the fluid composition recovered from the well. The method described in Appendix 14.

[0088] (Appendix 16) further comprising using the fluid composition recovered from the well as a fuel. 16. The method of any one of appendices 1 to 15.

[0089] (Appendix 17) Recovering the fluid composition from the well via the pathway comprises: storing the fluid composition in the vicinity of the well; or transporting said fluid composition through a pipeline; Including, 17. The method of any one of appendixes 1 to 16.

[0090] (Appendix 18) after the fluid composition is recovered, further comprising injecting carbon dioxide into the formation through the pathway provided by the well; reaction of at least a portion of the carbon dioxide with one or more mafic or ultramafic rocks in the formation to produce at least magnesium carbonate or calcium carbonate; 18. The method of any one of appendices 1 to 17.

[0091] (Appendix 19) injecting the carbon dioxide through the pathway provided by the well includes injecting a mixture of water and carbon dioxide into the formation through the pathway provided by the well; 18. The method described in Appendix 18.

[0092] (Appendix 20) the water and carbon dioxide mixture has a pH of between about 4.8 and about 6.5; 19. The method described in Appendix 19.

[0093] (Appendix 21) the mixture of water and carbon dioxide contains sodium chloride at a salinity of between 0.1 parts per million and 4.5 parts per million; 21. The method of claim 19 or 20.

[0094] (Appendix 22) The mixture of water and carbon dioxide contains nitrogen, dihydrogen sulfide, methane, or other trace gases; 22. The method of any one of appendices 19 to 21.

[0095] (Appendix 23) the carbon dioxide is injected into the formation at a pressure between 1 bar and the lithostatic pressure of the formation; 23. The method of any one of appendices 18 to 22.

[0096] (Appendix 24) The carbon dioxide injected into the formation comprises supercritical carbon dioxide or a mixture of supercritical carbon dioxide and another fluid. 18. The method described in Appendix 18.

[0097] (Appendix 25) injecting the carbon dioxide through the pathway provided by the well occurs as part of a well stimulation process; 25. The method of any one of claims 18 to 24.

[0098] (Appendix 26) 1. An apparatus for producing hydrogen gas from a geological formation comprising mafic igneous rock, ultramafic igneous rock, or a combination thereof, comprising: means for carrying out the method according to any one of claims 1 to 25; Device.

[0099] (Appendix 27) 1. A system for producing hydrogen gas from or sequestrating carbon dioxide in situ within a geological formation comprising mafic igneous rock, ultramafic igneous rock, or a combination thereof, comprising: a wellbore at least partially intersecting the formation; a source of aqueous stimulation agent in fluid communication with the wellbore and configurable to allow the aqueous stimulation agent to pass to the formation through a path defined at least in part by the wellbore; a fluid containment device positioned near an upper portion of the wellbore, the fluid containment device having one or more outlets through which a fluid composition comprising hydrogen gas may be withdrawn from the wellbore; a source of carbon dioxide configurable in fluid communication with the wellbore to allow the carbon dioxide to pass to the formation through the pathway defined at least in part by the wellbore; Equipped with system.

[0100] (Appendix 28) a pipeline connected to the one or more outlets of the fluid containment device for discharging the fluid composition comprising hydrogen gas that has passed through the fluid containment device from the well; 28. The system of claim 27.

[0101] (Appendix 29) further comprising a fluid storage vessel connected to the one or more outlets of the fluid containment device, the fluid storage vessel storing the fluid composition comprising hydrogen gas that has passed from the well through the fluid containment device; 29. The system of claim 27 or 28.

[0102] (Appendix 30) the fluid containment device is a wellhead; 30. The system of any one of appendixes 27 to 29.

[0103] (Appendix 31) the carbon dioxide source can be configured to deliver the carbon dioxide to the wellbore at a pressure between 1 atmosphere and the lithostatic pressure of the formation; 31. The system of any one of appendixes 27 to 30.

[0104] (Appendix 32) The aqueous stimulant does not contain carbon dioxide. 32. The system of any one of appendixes 27 to 31.

[0105] (Appendix 33) The aqueous irritant comprises hydrogen sulfide. 33. The system of any one of appendixes 27 to 32.

[0106] (Appendix 34) The aqueous stimulant has an oxygen fugacity with a negative Eh value; 34. The system of any one of appendixes 27 to 33.

[0107] (Appendix 35) The aqueous irritant comprises sodium chloride at a salinity of between about 0.1 parts per million and 4.5 parts per million. 35. The system of any one of appendices 27 to 34.

[0108] (Appendix 36) The aqueous stimulant has a pH of between about 8.3 and about 11.1. 36. The system of any one of appendixes 27 to 35.

[0109] (Appendix 37) and further comprising a fracturing device that can be configured to hydraulically fracture a region of the formation proximate the wellbore. 37. The system of any one of appendixes 27 to 36.

[0110] (Appendix 38) The carbon dioxide includes supercritical carbon dioxide. 38. The system of any one of appendices 27 to 37.

[0111] (Appendix 39) The carbon dioxide comprises a mixture of water and carbon dioxide. 39. The system of any one of appendices 27 to 38.

[0112] (Appendix 40) the water and carbon dioxide mixture has a pH of between about 4.8 and about 6.5; 39. The system of claim 39.

[0113] (Appendix 41) the mixture of water and carbon dioxide contains sodium chloride at a salinity of between 0.1 parts per million and 4.5 parts per million; 41. The system of claim 39 or 40.

[0114] (Appendix 42) The mixture of water and carbon dioxide contains nitrogen, dihydrogen sulfide, methane, or other trace gases; 42. The system of any one of appendices 39 to 41.

Claims

1. A system for generating hydrogen gas from strata containing mafic igneous rocks, ultramafic igneous rocks, or combinations thereof, or for situally sequestering carbon dioxide within said strata, A well that crosses the aforementioned geological formation at least partially, A water-containing aqueous stimulant source, configured to be in fluid communication with the well and to allow the aqueous stimulant to pass into the geological formation through a path defined at least partially by the well, A fluid containment device is positioned near the top of the well and has one or more outlets through which a fluid composition containing hydrogen gas can be recovered from the well. A carbon dioxide source configured to be in fluid communication with the well, allowing the carbon dioxide to pass into the geological formation through a path defined at least partially by the well, wherein at least a portion of the carbon dioxide reacts with one or more mafic or ultramafic rocks in the geological formation to produce at least magnesium carbonate or calcium carbonate, and at least the water reacts with one or more mafic or ultramafic rocks in the geological formation to produce at least hydrogen, Equipped with, system.

2. The pipeline further comprises being connected to one or more outlets of the fluid containment device and discharging the fluid composition containing hydrogen gas that has passed from the well through the fluid containment device. The system according to claim 1.

3. The fluid storage container is connected to one or more outlets of the fluid containment device and stores the fluid composition containing hydrogen gas that has passed from the well through the fluid containment device, The system according to claim 1 or 2.

4. The fluid containment device is a well head, The system according to claim 1 or 2.

5. The carbon dioxide source can be configured to supply the carbon dioxide to the well at a pressure between 1 atmosphere and the lithosophical pressure of the rock at the boundary between the rock formation and other rock formations below it. The system according to claim 1 or 2.

6. The aqueous stimulant is free of carbon dioxide. The system according to claim 1 or 2.

7. The aqueous irritant comprises hydrogen sulfide, The system according to claim 1 or 2.

8. The aqueous stimulant has an oxygen fugacity having a negative Eh value, The system according to claim 1 or 2.

9. The aqueous stimulant comprises sodium chloride at a salinity between about 0.1 per mille and 4.5 per mille. The system according to claim 1 or 2.

10. The aqueous irritant has a pH between about 8.3 and about 11.

1. The system according to claim 1 or 2.

11. Further comprising a crushing device configured to crush the region of the geological formation near the well by hydraulic pressure, The system according to claim 1 or 2.

12. The carbon dioxide includes supercritical carbon dioxide, The system according to claim 1 or 2.

13. The carbon dioxide includes a mixture of water and carbon dioxide. The system according to claim 1 or 2.

14. The mixture of water and carbon dioxide has a pH between about 4.8 and about 6.

5. The system according to claim 13.

15. The mixture of water and carbon dioxide contains sodium chloride at a salinity between 0.1 per mille and 4.5 per mille. The system according to claim 13.

16. The mixture of water and carbon dioxide contains nitrogen, dihydrogen sulfide, methane, or other trace gases. The system according to claim 13.

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