Systems and methods for geologic hydrogen production

Abstract

NOT VISIBLE DUE TO STATUS OF PATENT

Description

[0001] SYSTEMS AND METHODS FOR GEOLOGIC HYDROGEN PRODUCTION

[0002] RELATED APPLICATIONS

[0003] This application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Patent Application No. 63 / 632,041, filed April 10, 2024, and entitled “Interfacial, Rheological and Chemo-Mechanical Multiscale Control for Giant Enhancement of Geologic Hydrogen Production,” which is incorporated herein by reference in its entirety for all purposes.

[0004] TECHNICAL FIELD

[0005] Geologic hydrogen production and related systems and methods are generally described.

[0006] BACKGROUND

[0007] Hydrogen is poised to play an important role in the transition away from fossil fuels and to clean energy sources. Currently available technologies for hydrogen production have serious drawbacks which are likely to hinder significant scaleup of hydrogen production in either a carbon-neutral or a cost-effective way, such as large associated carbon footprint, lack of scalability, and high costs. Accordingly, improved systems and methods for hydrogen production are needed.

[0008] SUMMARY

[0009] Geologic hydrogen production and related systems and methods are generally described. The subject matter of the present disclosure involves, in some cases, interrelated products, alternative solutions to a particular problem, and / or a plurality of different uses of one or more systems and / or articles.

[0010] In certain embodiments, a system comprises a source of a mineral comprising a material capable of reacting with water to produce hydrogen; a conduit fluidically connected to the source of a mineral comprising a material capable of reacting with water to produce hydrogen; and a mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5.

[0011] In some embodiments, a method comprises contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen such that at least a portion of the water reacts with the material to form hydrogen; and forming a mixture of water and hydrogen, wherein: the mixture is contained within a conduit fluidically connected to the source, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to IO'5

[0012] In certain embodiments, a system comprises a concentrator configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0013] In some embodiments, a method of recovering hydrogen from a multiphase gas-liquid mixture, comprises concentrating gas-containing bubbles from the multiphase gas-liquid mixture; and exposing the gas-containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0014] In certain embodiments, a system for producing hydrogen, comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; and an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen.

[0015] In some embodiments, a method of producing hydrogen, comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen.

[0016] In certain embodiments, a method of producing and processing hydrogen, comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; and forming a mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen, wherein: the mixture is contained within the injection conduit, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5. In some embodiments, a method of producing and processing hydrogen, comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; concentrating gas-containing bubbles from multiphase gas-liquid mixture comprising at least a portion of the aqueous fluid and the hydrogen; and exposing the gas-containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0017] In certain embodiments, a method of generating and processing a multiphase gas-liquid mixture, comprises contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen such that at least a portion of the water reacts with the material to form hydrogen; forming a multiphase gas-liquid mixture comprising water and hydrogen, wherein: the mixture is contained within a conduit fluidically connected to the mineral, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5; concentrating gas-containing bubbles from the multiphase gas-liquid mixture; and exposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas -containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0018] In some embodiments, a method of producing and processing hydrogen comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; forming a multiphase gas-liquid mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen, wherein the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5; concentrating gas-containing bubbles from the multiphase gas-liquid mixture; and exposing the gas-containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0019] In certain embodiments, a system for producing and processing hydrogen comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; and a mixture comprising liquid water and hydrogen disposed within the injection conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to IO’5.

[0020] In some embodiments, a system for producing and processing hydrogen, comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; a concentrator configured to concentrate gas -containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas comprising at least a portion of the hydrogen within the gas-containing bubbles and a liquid comprising at least a portion of the aqueous fluid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0021] In some embodiments, a system for producing and processing a multiphase gas-liquid mixture, comprises a source of a mineral comprising a material capable of reacting with water to produce hydrogen; a conduit fluidically connected to the source of the mineral; a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5; a concentrator fluidically connected to the conduit and configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0022] In some embodiments, a system for producing and processing hydrogen comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5; a concentrator fluidically connected to the conduit and configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0023] In certain embodiments, a method of producing geologic hydrogen comprises a. promoting chemical cracking of the source ultramafic rock from the serpentinization reaction; and b. enhancing transport of hydrogen in the fracture network via interfacial and rheological additives that foster bubble exsolution and coarsening.

[0024] One aspect of the disclosure herein is a method of producing geologic hydrogen comprising: a. promoting chemical cracking of the source ultramafic rock from the serpentinization reaction; b. enhancing transport of hydrogen in the fracture network via interfacial and rheological additives that foster bubble exsolution and coarsening; and c. designing Hs-philic membranes for fast and efficient downhole separation.

[0025] In one embodiment, promoting chemical cracking of the source ultramafic rock from the serpentinization reaction comprises use the ultrasound probes to send known pulses in regular intervals to sample the changes in travel time which will correspond to changes in elastic moduli, to obtain accurate reaction rates at a high temporal resolution. In one embodiment, the disclosed method further comprises using learning methods to distinguish between reactive cracking and bubble nucleation and burst.

[0026] In one embodiment, the method further comprises calibrating ultrasound measurements of reaction progress by scanning samples using pCT before and after deformation to quantify the volume of serpentinization and the resultant fracture patterns.

[0027] In one embodiment, the method further comprises performing electron microscopy to quantify the effects of serpentinization.

[0028] In one embodiment, enhancing transport of hydrogen comprises using interfacial modifiers with combinations of gasphilic nanoparticles and surfactants to stabilize the gas-liquid interface and make it unfavorable for bubbles to adhere to walls.

[0029] In one embodiment, phase-field methods are used to model bubble exsolution and evolution.

[0030] In one embodiment, hydrogen evolution is controlled by altering an applied current density. In one embodiment, the H -philic membranes comprise a cyclone separator equipped with a high permeability gasphilic membrane.

[0031] In one embodiment, the H2-philic membranes are configured so that rising bubbles at a central axis are concentrated and defoamed at the top by the gasphilic membrane where the gas is collected, while the liquid is pumped out to be reused.

[0032] Other advantages and novel features of the present disclosure will become apparent from the following detailed description of various non-limiting embodiments of the disclosure when considered in conjunction with the accompanying figures. In cases where the present specification and a document incorporated by reference include conflicting and / or inconsistent disclosure, the present specification shall control.

[0033] BRIEF DESCRIPTION OF THE DRAWINGS

[0034] Non-limiting embodiments of the present disclosure will be described by way of example with reference to the accompanying figures, which are schematic and are not intended to be drawn to scale unless otherwise indicated. In the figures, each identical or nearly identical component illustrated is typically represented by a single numeral. For purposes of clarity, not every component is labeled in every figure, nor is every component of each embodiment of the disclosure shown where illustration is not necessary to allow those of ordinary skill in the art to understand the disclosure.

[0035] FIGS. 1A-1C are, in accordance with certain embodiments, schematic diagrams of systems for producing hydrogen.

[0036] FIG. ID is, in accordance with certain embodiments, a schematic diagram of fractures in a solid domain.

[0037] FIG. IE is, in accordance with certain embodiments, a schematic diagram of a fracture network.

[0038] FIG. 2 is, in accordance with certain embodiments, a diagram of variations of compressive stress within a simulated subsurface.

[0039] FIG. 3 is, in accordance with certain embodiments, a series of schematics showing bubbles within a conduit.

[0040] FIGS. 4A-4B are, in accordance with certain embodiments, schematics of systems comprising a concentrator and a membrane-based separator.

[0041] FIGS. 5A-5C are, in accordance with certain embodiments, schematics of features on a surface. FIG. 6 is, in accordance with certain embodiments, a cross-sectional schematic diagram illustrating the interaction of bubbles with gas positioned between features on a surface.

[0042] FIG. 7A is, in accordance with some embodiments, a cross-sectional schematic diagram of a surface comprising pores.

[0043] FIG. 7B is, in accordance with certain embodiments, a top view schematic diagram of the surface shown in FIG. 7 A.

[0044] FIG. 8A is, in accordance with some embodiments, a cross-sectional schematic diagram illustrating the interaction of a liquid droplet with a surface that is non-wetting with respect to the liquid.

[0045] FIG. 8B is, in accordance with some embodiments, a cross-sectional schematic diagram illustrating the interaction of a liquid droplet with a surface that is wetting with respect to the liquid.

[0046] FIG. 8C is, in accordance with some embodiments, a cross-sectional schematic diagram illustrating the interaction of a gas-containing bubble with a surface that is gasphobic with respect to the gas.

[0047] FIG. 8D is, in accordance with some embodiments, a cross-sectional schematic diagram illustrating the interaction of a gas-containing bubble with a surface that is gasphilic with respect to the gas.

[0048] FIG. 9 is a cross-sectional schematic diagram of an electrochemical hydrogen looping apparatus.

[0049] FIGS. 10A-10F show an overall conceptual schematic of the proposed technology, according to some embodiments.

[0050] FIGS. 11A-11E show, according to some embodiments, a schematic of the apparatus, including: (A) a detailed schematic of the loading rams and pistons, with the position of the ultrasound sensor arrays indicated; (B) an exploded- view of sample assembly, with sensor locations indicated; (C) a detailed schematic of the sample assembly; (D) an example of active pulsing wavefield; and (E) an example of acoustic emission recorded in the rig.

[0051] FIG. 12 shows a sketch of fractured plagioclase grains between partially serpentinized olivine grains (stippled) with iron-oxides (black). The field of view is ~ 6 mm.

[0052] FIG. 13 shows, in accordance with certain embodiments, a cross-section of the variations in total compressive stress for an array of unit length square tensile dislocations with varying depths and orientations. The resulting stress depends on assumed elastic moduli and amount of opening. Equivalent results apply for ellipsoids with thickness << semi-major axes. Scalar compressive stress field for easy visualization is shown; the minimum compressive stress will be used to evaluate whether computed stresses are large enough to fracture the rock.

[0053] FIGS. 14A-14C show, according to some embodiments: (A) a schematic of a microfluidic Hele-Shaw flow cell filled with water and dissolved CO2 at high pressure; (B) a micrograph of the top surface (underside) which is transparent glass with microstructures; and (C) a sketch of exsolution configurations with and without surfactants.

[0054] FIGS. 15A-15E show, in accordance with some embodiments: (A) a schematic of a water-filled microfractures with hydrogen bubbles; (B) five possible scenarios of bubby flows in microchannels, with the inset showing that pinning defects can lead to undesirable capillary trappings clogging the system (left) and surfactants can assist in depinning the bubbles; (C) a sketch of a typical regime map of bubbly flows corresponding to the five proposed configurations (not to scale); (D) an experimental set-up to study the morphology of bubbly flows with the solid-outlined square showing region of interest; and (E) H2 evolution from a platinum electrode surface via water electrolysis.

[0055] FIGS. 16A-16D show, in accordance with certain embodiments: (A) a schematic of proposed gas separation device, comprising a cyclone mixer with an active gasphilic membrane for defoaming; (B) a micrograph of a high permeability gasphilic membrane and its AFM profile that shows nanoscale roughness; (C) a timelapse of a millimetric bubble evacuating through a gasphilic membrane in 6 ms; and (D) a demonstration of gasphilic membranes being used for active defoaming.

[0056] FIG. 17 shows a schematic of hydrogen separation via electrochemical oxidation and reduction, according to some embodiments.

[0057] DETAILED DESCRIPTION

[0058] Hydrogen is poised to play an increasing role in the future energy mix, given the pressing need to find sources of primary power that do not produce greenhouse gases as a byproduct. Currently available technologies for hydrogen production have serious drawbacks which are likely to hinder significant scaleup of hydrogen production in either a carbon-neutral or a cost- effective way. For example, the “gray” hydrogen generated by methane reforming has a large associated carbon footprint; the “green” hydrogen produced by water electrolysis powered by renewable energy and / or biomass would be very challenging to produce at scale; and the “blue” hydrogen generated via high-carbon emission methods with associated carbon capture and storage is very expensive to produce. Geologic hydrogen offers a pathway to the large-scale, efficient, low-cost, and low- emission production of hydrogen in the quantities that will be necessary for hydrogen to play a role in the ongoing energy transition. While natural deposits of geologic hydrogen exist, natural generation rates are generally low, resulting in small amounts of dispersed hydrogen which may be difficult to access. This disclosure describes systems and methods for the production of geologic hydrogen in situ by stimulating the production of hydrogen from geologic formations. The possibility of producing hydrogen generated in situ in the subsurface at large, sustainable rates using low-emissions technology may significantly alter the energy mix available from sustainable sources.

[0059] In some embodiments, a system for producing hydrogen is provided. Schematic representations of some possible configurations of such a system are shown in FIGS. 1A-1C. In some embodiments, the system I l la as shown in FIG. 1A comprises a solid domain 101. In some embodiments, the solid domain comprises one or more minerals comprising a material capable of reacting with water to produce hydrogen. In some embodiments, a mineral comprising a material capable of reacting with water to produce hydrogen may comprise a mineral containing ferrous iron. As used herein, the term “ferrous iron” refers to iron in the +2 oxidation state (e.g., Fe2+). In some instances, ferrous iron may also be referred to as iron(II). In some embodiments, a mineral comprising a material capable of reacting with water to produce hydrogen may comprise a mineral comprising magnesium (e.g., magnesium in the +2 oxidation state, or Mg2+).

[0060] The term “solid domain” is used herein to refer to a domain in which at least some solid material (e.g., rock) is present. Portions of the solid domain could also be occupied by fluid (e.g., liquid(s) and / or gas(es)), as might be the case when fractures are present. In some embodiments, at least 5 vol%, at least 10 vol%, at least 25 vol%, at least 40 vol%, at least 50 vol%, at least 75 vol%, at least 85 vol%, at least 90 vol%, or more (and / or less than or equal to 90 vol%, less than or equal to 80 vol%, less than or equal to 70 vol%, less than or equal to 60 vol%, less than or equal to 50 vol%, or less) of the solid domain is made up of solid material.

[0061] The solid domain may have any of a variety of suitable dimensions. For example, in some embodiments, the solid domain has a volume of greater than or equal to 1 m3, greater than or equal to 5 m3, greater than or equal to 10 m3, greater than or equal to 50 m3, greater than or equal to 100 m3, greater than or equal to 500 m3, greater than or equal to 1,000 m3, greater than or equal to 5,000 m3, greater than or equal to 10,000 m3, greater than or equal to 50,000 m3, greater than or equal to 100,000 m3, greater than or equal to 500,000 m3, greater than or equal to 1,000,000 m3, greater than or equal to 5,000,000 m3, greater than or equal to 10,000,000 m3, greater than or equal to 50,000,000 m3, greater than or equal to 100,000,000 m3, or greater than or equal to 500,000,000 m3. In some embodiments, the solid domain has a volume of less than or equal to 1,000,000,000 m3, less than or equal to 500,000,000 m3, less than or equal to 100,000,000 m3, less than or equal to 50,000,000 m3, less than or equal to 10,000,000 m3, less than or equal to 5,000,000 m3, less than or equal to 1,000,000 m3, less than or equal to 500,000 m3, less than or equal to 100,000 m3, less than or equal to 50,000 m3, less than or equal to 10,000 m3, less than or equal to 5,000 m3, less than or equal to 1,000 m3, less than or equal to 500 m3, less than or equal to 100 m3, less than or equal to 50 m3, less than or equal to 10 m3, or less than or equal to 5 m3. Combinations of these ranges are also possible (e.g., in some embodiments, the solid domain has a volume of greater than or equal to 1 m3and less than or equal to 1,000,000,000 m3, greater than or equal to 5 m3and less than or equal to 500,000,000 m3, or greater than or equal to 10 m3and less than or equal to 100,000,000 m3). Other ranges are also possible.

[0062] In some embodiments, the solid domain comprises rock (e.g., rock comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen). In some embodiments, the rock may comprise crystalline rock such as mafic rock (e.g., basalt) and / or ultramafic rock, granitic rock, metamorphic rock (e.g., gneiss, schist), and / or sedimentary rock. In some embodiments, the rock may comprise one or more minerals comprising ferrous iron, such as olivine, magnetite, pyroxene, chromite, or others (e.g., ferromagnesian minerals). In some embodiments, the solid domain may comprise an iron-rich clay, an iron-rich carbonate (e.g., ferroan calcite, ferroan dolomite, and / or ankerite), or other iron-rich sediments. In some embodiments, the rock may comprise one or more minerals comprising magnesium, such as olivine, magnetite, pyroxene, chromite, forsterite, enstatite, and others.

[0063] In some embodiments, the solid domain (e.g., the solid domain comprising rock) may comprise a geological formation. For example, in some embodiments, the solid domain may comprise a subsurface geological formation. A subsurface geological formation may comprise any of the rocks and / or rocks bearing any of the minerals as described above. In some embodiments, a subsurface geological formation may comprise rock of a variety of types, including some rocks which do not comprise one or more minerals comprising a material capable of reacting with water to produce hydrogen. In some embodiments, a subsurface geological formation may comprise veins and / or deposits of rocks comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, which may be dispersed in and / or surrounded by areas of rock(s) which do not comprise one or more minerals comprising a material capable of reacting with water to produce hydrogen. In some such embodiments, a portion of the solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen (e.g., a vein and / or deposit thereof) may be targeted for the production of hydrogen using the systems and methods described herein.

[0064] In some embodiments, the one or more minerals comprising a material capable of reacting with water to produce hydrogen in the solid domain (e.g., the subsurface rock formation) may be capable of reacting (e.g., via a chemical reaction) with an aqueous fluid (e.g., liquid water). In some embodiments, the one or more minerals comprising a material capable of reacting with water to produce hydrogen in the solid domain may react with water in the aqueous fluid such that the one or more minerals are hydrated. In some embodiments, ferrous iron contained in the one or more minerals may react with water in the aqueous fluid such that the ferrous iron is oxidized. In some embodiments, magnesium contained in the one or more minerals may react with water in the aqueous fluid such that the magnesium is oxidized. In some embodiments, the one or more minerals comprising a material capable of reacting with water to produce hydrogen in the solid domain may react with the aqueous fluid such that the one or more minerals are hydrated and a material (e.g., ferrous iron and / or magnesium) contained in the one or more minerals is oxidized. For example, in some embodiments, the one or more minerals comprising a material capable of reacting with water to produce hydrogen may be capable of reacting with the aqueous fluid in a serpentinization reaction.

[0065] In some embodiments, the chemical reaction may produce hydrogen. For example, in some embodiments, a serpentinization reaction may produce molecular hydrogen (e.g., Fh). In some embodiments, the hydrogen produced by the chemical reaction may be in the form of a gas. In some embodiments, the hydrogen produced by the chemical reaction may be dissolved within the aqueous fluid.

[0066] In some embodiments, the system 11 la as shown in FIG. 1A comprises a source of an aqueous fluid 102 (e.g., liquid water). For example, in some embodiments, the source of the aqueous fluid may comprise a tank, a reservoir, a pipeline, an aquifer, a lake, a river, a source of produced water (e.g., water that is a byproduct of another process and / or system, such as processes and / or systems for the extraction of oil and / or natural gas from a subsurface geological formation), and / or any other suitable source of an aqueous fluid.

[0067] In some embodiments, the aqueous fluid comprises one or more additives. For example, in some embodiments, the aqueous fluid comprises an interfacial modifier and / or a rheology modifier. The interfacial modifier and / or rheology modifier may comprise any of a variety of suitable compositions. For example, in some embodiments, the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant. Additives such as interfacial modifiers and / or rheology modifiers are discussed in detail elsewhere herein.

[0068] In some embodiments, the system I l la comprises a hydrogen storage location 104. In some embodiments, the hydrogen storage location comprises a location which is configured to contain hydrogen (e.g., without significant losses of hydrogen to the environment external to the hydrogen storage location). For example, in some embodiments in which the hydrogen storage location is configured to contain gaseous hydrogen, the hydrogen storage location may comprise vessel such as a tank (e.g., a pressurized tank), a canister, a pipeline, or any other suitable location. In some embodiments in which the hydrogen storage location is configured to contain hydrogen which is part of a mixture (e.g., a multiphase gas-liquid mixture) and / or hydrogen which is dissolved in a solution (e.g., hydrogen which is dissolved in an aqueous fluid), the hydrogen storage location may be configured to contain the mixture and / or solution. In some such embodiments, the hydrogen storage location may comprise a vessel (e.g., a tank), a pipeline, a reservoir, and / or any other suitable container and / or location.

[0069] In some embodiments, the hydrogen storage location may comprise a naturally occurring and / or artificially created subsurface structure such as a wellbore, a fracture network, an aquifer, a cavern, etc. In some embodiments, the hydrogen storage location may comprise a vessel (e.g., a tank) which is placed underground (e.g., built into the subsurface or placed in an excavated subsurface location).

[0070] In some embodiments, such as in system 111b as shown in FIG. IB, a system may comprise a volume (e.g., volume 122 of system 11 lb) which is both a source of aqueous fluid and a hydrogen storage location. In some such embodiments, the volume 122 may comprise an aqueous fluid (e.g., an aqueous fluid comprising one or more additives), as described above. In some embodiments, the volume 122 may comprise hydrogen (e.g., gaseous hydrogen and / or hydrogen which is part of a mixture). The volume 122 may have any of the properties and / or characteristics of a source of aqueous fluid and / or a hydrogen storage location, as described above.

[0071] In some embodiments, a system (e.g., system I l la as shown in FIG. 1A) for producing hydrogen as described herein comprises one or more conduits. In some embodiments, a conduit may be configured to transfer a material from one part of the system to another. For example, in some embodiments, a conduit may be configured to deliver a material (e.g., to deliver liquid water) to and / or remove a material (e.g., to remove hydrogen) from a part of the system (e.g., the solid domain). In some embodiments, a conduit that is configured to deliver a material to a part of the system may be referred to as an injection conduit, and a conduit that is configured to remove a material from a part of the system may be referred to as a removal conduit. In some embodiments, a conduit may be configured to both deliver a material and remove a material from a part of the system (e.g., a conduit may be both an injection conduit and a removal conduit).

[0072] In some embodiments, as shown in FIG. 1A, the system I l la comprises an injection conduit 103. In some embodiments, the injection conduit 103 is fluidically connected to a source of aqueous fluid 102 and the solid domain 101, as described above. In some embodiments, the injection conduit is configured to deliver aqueous fluid (e.g., from the source of the aqueous fluid) to the solid domain. In some embodiments, the aqueous fluid delivered to the solid domain by the injection conduit may react with one or more minerals comprising a material capable of reacting with water to produce hydrogen which are contained within the solid domain (e.g., via a chemical reaction such as a serpentinization reaction) to produce hydrogen, as described above.

[0073] In some embodiments, as shown in FIG. 1A, the system I l la comprises a removal conduit 106. In some embodiments, the removal conduit 106 is fluidically connected to the hydrogen storage location 104. In some embodiments, the removal conduit is configured to facilitate direction of at least a portion of the hydrogen (e.g., at least a portion of the hydrogen produced via a chemical reaction between an aqueous fluid and one or more minerals comprising a material capable of reacting with water to produce hydrogen which are contained within the solid domain, as described above) to the hydrogen storage location.

[0074] In some embodiments, as shown in FIGS. 1B-1C, the injection conduit and the removal conduit may be the same conduit (e.g., the system may comprise a conduit, the conduit being both an injection conduit and a removal conduit), such as conduit 123. In some such embodiments, the conduit may function as an injection conduit (e.g., may be configured to deliver a material to one part of the system) during a first period of time, and may function as a removal conduit (e.g., may be configured to remove a material from a part of the system) during a second period of time.

[0075] In some embodiments in which a conduit may be both an injection conduit and a removal conduit, as shown in FIG. IB, the conduit may be fluidically connected to the solid domain and a volume 122, which may be both a source of aqueous fluid and a hydrogen storage location. In some such embodiments, the conduit 123 may be configured to be placed in fluidic communication with the volume 122 in a modifiable and / or switchable manner. For example, the conduit may be configured such that, during a first period of time, the conduit is placed in fluidic communication with the volume 122 such that an aqueous fluid is flowed out of the volume 122 and into the conduit 123, and, during a second period of time, hydrogen (e.g., gaseous hydrogen and / or a mixture comprising hydrogen) is flowed out of the conduit 123 and into the volume 122. In some embodiments, the conduit may be fluidically connected to the volume in a manner that is modifiable and / or switchable (e.g., via a pressure swing) via the action of one or more pumps and / or valves which are configured to alter the direction of fluid flow to and / or from the volume to and / or from the conduit.

[0076] In some embodiments, one or more valves and / or pumps may be configured to increase the pressure exerted on an aqueous fluid within the volume 122 and / or from the volume 122, thereby flowing aqueous fluid from the volume and to the conduit 123 during a first period of time. In some embodiments, one or more pumps and / or valves may be configured to reduce the pressure exerted on a fluid (e.g., a fluid comprising hydrogen) within the conduit (e.g., gaseous hydrogen, dissolved hydrogen, and / or a multiphase gas-liquid mixture comprising gaseous hydrogen), thereby flowing the fluid from the conduit and to the volume during a second period of time. In some embodiments in which the solid domain in which the conduit is placed is a subsurface geological formation (e.g., comprising rock), the pressure exerted on a fluid (e.g., an aqueous fluid, a fluid comprising hydrogen) at the end of the conduit (e.g., the portion of the conduit at the greatest depth within the geological formation) may be greater than or equal to the minimum compressive stress in the subsurface geological formation during the first period of time. In some embodiments, the pressure exerted on a fluid at the end of the conduit may be less than the minimum compressive stress in the subsurface geological formation during the second period of time.

[0077] In some embodiments in which a conduit may be both an injection conduit and a removal conduit, as shown in FIG. 1C, the conduit may be fluidically connected to the solid domain and both a source of aqueous fluid 102 and a hydrogen storage location 104. In some such embodiments, the conduit may be configured to be placed in fluidic communication with the source of aqueous fluid and the hydrogen storage location in a modifiable and / or switchable manner. For example, the conduit may be configured such that, during a first period of time, the conduit is placed in fluidic communication with the source of aqueous fluid and, during a second period of time, the conduit is placed in fluidic communication with the hydrogen storage location. In some embodiments, the conduit may be placed in fluidic communication with the source of aqueous fluid and / or the hydrogen storage location in a manner that is modifiable and / or switchable via the action of a one or more pumps and / or valves (e.g., via a pressure swing) which are configured to alter the direction of fluid flow form the source of the aqueous fluid to the conduit and / or alter the direction of fluid flow from the conduit to the hydrogen storage location.

[0078] In some embodiments, one or more valves and / or pumps may be configured to increase the pressure exerted on an aqueous fluid within the source of aqueous fluid 103, thereby flowing aqueous fluid from the source of aqueous fluid and to the conduit 123 during a first period of time. In some embodiments, one or more pumps and / or valves may be configured to reduce the pressure exerted on a fluid (e.g., a fluid comprising hydrogen) within the conduit (e.g., gaseous hydrogen, dissolved hydrogen, and / or a multiphase gas-liquid mixture comprising gaseous hydrogen), thereby flowing the fluid from the conduit and to the hydrogen storage location during a second period of time. In some embodiments, the one or more pumps and / or valves may be configured such that the conduit is in fluidic communication with the source of aqueous fluid during a first period of time and / or placed in fluidic communication with the hydrogen storage location during a second period of time. In some embodiments in which the solid domain in which the conduit is placed is a subsurface geological formation (e.g., comprising rock), the pressure exerted on a fluid (e.g., an aqueous fluid, a fluid comprising hydrogen) at the end of the conduit (e.g., the portion of the conduit at the greatest depth within the geological formation) may be greater than or equal to the minimum compressive stress in the subsurface geological formation during the first period of time. In some embodiments, the pressure exerted on a fluid at the end of the conduit may be less than the minimum compressive stress in the subsurface geological formation during the second period of time.

[0079] In some embodiments, the injection conduit and / or removal conduit (and / or a conduit which is both an injection conduit and a removal conduit) may comprise a pipe (e.g., a drilling pipe). The pipe may be formed from of a variety of suitable materials. For example, in some embodiments, the pipe may be formed from concrete, steel, and / or any other material which has sufficient strength to withstand the highest pressures at which a fluid will be fluid through the conduit. In some embodiments, the injection conduit and / or removal conduit may comprise a borehole (e.g., a borehole which is drilled into the solid domain). In some such embodiments, the boundary of the injection conduit and / or removal conduit may comprise a wall, and the wall of the injection conduit and / or removal conduit (and / or wall of the borehole) may be defined by the solid domain. In some such embodiments, the wall of the injection conduit and / or removal conduit comprises substantially the same material as the solid domain (e.g., rock).

[0080] In some such embodiments, a conduit (e.g., an injection conduit and / or removal conduit) may comprise multiple materials. For example, in some embodiments, a conduit may comprise a pipe (e.g., a pipe formed from steel) in one portion and may comprise a borehole in another portion.

[0081] A system as described herein may comprise one or more other conduits in addition to the injection conduit and / or removal conduit. For example, in some embodiments, the system may comprise one or more injection conduits fluidically connected to a source of aqueous fluid. In some embodiments, one or more of the injection conduits are fluidically connected to the same source of aqueous fluid. In some embodiments, the one or more injection conduits are fluidically connected to different sources of aqueous fluid (e.g., in some embodiments, the system may comprise more than one source of aqueous fluid, each of which may be fluidically connected to one or more injection conduits, such as the injection conduit as described above).

[0082] In some embodiments, the system may comprise one or more removal conduits, each of which may be fluidically connected to a hydrogen storage location. In some embodiments, one or more of the removal conduits are fluidically connected to the same hydrogen storage location. In some embodiments, one or more of the removal conduits are fluidically connected to different hydrogen storage locations (e.g., in some embodiments, the system may comprise more than one hydrogen storage location, each of which may be fluidically connected to one or more removal conduits, such as the removal conduit as described above).

[0083] In some embodiments, the system may comprise one or more conduits which are both injection conduits and removal conduits, as described above. In some embodiments, one or more of the conduits may be fluidically connected to the same source of aqueous fluid and / or the same hydrogen storage location as another conduit in the system. For example, in some embodiments, the system may comprise a conduit which is both an injection conduit and a removal conduit which is fluidically connected to the same source of aqueous fluid as a different injection conduit (e.g., an injection conduit which is only an injection conduit, an injection conduit which is also a removal conduit). In some embodiments, the system may comprise a conduit which is both an injection conduit and a removal conduit which is fluidically connected to the same hydrogen storage location as a different removal conduit (e.g., a removal conduit which is only a removal conduit, a removal conduit which is also an injection conduit). In some embodiments, one or more of the conduits may be fluidically connected to a different source of aqueous fluid and / or a different hydrogen storage location as a different injection conduit and / or different removal conduit. In some embodiments, one or more of the conduits may be fluidically connected to the same source of aqueous fluid as a different injection conduit in the system and a different hydrogen storage location than a different removal conduit in the system. In some embodiments, one or more of the conduits may be fluidically connected to a different source of aqueous fluid than a different injection conduit in the system and the same hydrogen storage location as a different removal conduit in the system.

[0084] In some embodiments, as shown in FIGS. 1A-1C, a solid domain 101 as described herein (e.g., a geological formation) may comprise one or more fractures 107. In some embodiments, a fracture may function as a conduit (e.g., provide a flow path) for a fluid (e.g., the fracture may contain a fluid) within the solid domain (e.g., a fluid such as an aqueous fluid may flow through a fracture within the solid domain). In some embodiments, the injection conduit and / or removal conduit may be fluidically connected to one or more fractures in the solid domain (e.g., in some embodiments, the injection conduit and / or removal conduit may comprise one or more fractures in the solid domain). In some embodiments, the fractures may comprise naturally occurring fractures and / or induced fractures. As used herein, a “naturally occurring fracture” in the solid domain comprises a fracture which is formed as the result of natural processes (e.g., thermal stresses). As used herein, an “induced fracture” in the solid domain comprises a fracture which is formed as a result of some action taken upon the solid domain (e.g., via the stimulation of a chemical reaction).

[0085] In some embodiments, a fracture in the solid domain (e.g., fracture 107 as shown in FIG. 1A) may have any of a variety of scales. As used herein, the scale of a fracture refers to the approximate length (e.g., length scale) of the fracture. The scale of a fracture may be generally expressed as the closest power of 10 to the fracture’s length. For example, a fracture with an approximate length of greater than or equal to 0.5 meter and less than 5 meters may be said to have a scale of around 1 meter, a fracture with an approximate length of greater than or equal to 5 meters and less than 50 meters may be said to have a cale of 10 meters, etc. For example, at some embodiments as shown in FIG. ID, a solid domain 101 may comprise fracture may comprise a meter-scale fracture 117a. In some embodiments, a larger-scale fracture (such as the meter-scale fracture 117a) may branch into smaller-scale fractures (e.g., an edge of the meterscale fracture 117a may may comprise smaller-scale fractures). For example, in some embodiments, the meter-scale fracture 117a may branch into, for example, millimeter-scale fractures such as 117b and 117c. In some embodiments, a fracture of any scale may intersect with another facture of a similar scale (e.g., as millimeter-scale fracture 117b intersects with millimeter- scale fracture 117c at intersection point 118). In some embodiments, fractures of any scale may further branch into smaller-scale fractures. For example, as shown in FIG. ID, the millimeter- scale fracture 117c may further branch into nanoscale fracture 117d. In some embodiments, a fracture of any scale may be capable of containing and / or transporting a fluid (e.g., liquid water and / or gaseous hydrogen). In some embodiments, one or more fractures in the solid domain may form a fracture network. For example, in some embodiments, one or more fractures may intersect, branch off of one another, and / or join with each other, thereby forming a networked structure of fractures. For example, FIG. IE shows a schematic of fracture network 127 comprising fractures 107 a-g within solid domain 101. In some such embodiments, a fracture network comprises fractures (e.g., fractures 107 a-g) which intersect with one another such that the interior of the fractures are joined such as to form a continuous internal space defined by the walls of all of the fractures in the fracture network.

[0086] In some embodiments as shown in FIGS. 1A-1C, the solid domain 101 may comprise one or more fractures 107, as described above (e.g., one or more fractures that are fluidically connected to the injection conduit 103 and / or removal conduit 106, as shown in FIG. 1A, or one or more fractures that are fluidically connected to conduit 123, as shown in FIGS. IB and 1C). As described above, in some embodiments, the solid domain comprises fractures which are induced fractures. In some such embodiments, it may be advantageous to arrange the injection conduit and / or removal conduit in such a manner as to induce fracturing of the solid domain (e.g., to generate induced fractures). For example, in some embodiments, an injection conduit may be positioned and / or configured such that, when aqueous fluid is delivered to the solid domain via the injection conduit, a chemical reaction occurs between the water in the aqueous fluid and one or more minerals comprising ferrous iron (or another material capable of reacting with water to produce hydrogen) contained within the solid domain. In some embodiments, the chemical reaction may induce a volume change in the solid domain (e.g., a local volume change in the solid domain). In some embodiments, the injection conduit and / or removal conduit may be positioned and / or configured to control fracture development in the solid domain via control of a volume change of the solid domain caused by the chemical reaction. For example, in some embodiments, the injection conduit and / or the removal conduit are positioned and / or configured to induce fracturing of the solid domain via hydraulic fracturing (e.g., chemical hydraulic fracturing). Volume changes of the solid domain caused by chemical reactions of water with one or more components (e.g., minerals comprising ferrous iron) contained within the solid domain and hydraulic fracturing are described in greater detail elsewhere herein.

[0087] In some embodiments in which the system comprises several conduits (e.g., more than one injection conduit and / or more than one removal conduit), each of these conduits may be positioned and / or configured as described above (e.g., to induce fracturing of the solid domain). In some embodiments, as described in greater detail elsewhere herein, one or more of the conduits may be positioned and / or configured relative to each other such that fracture development may be controlled via the co-development of fractures induced by volume changes in the solid domain caused by a chemical reaction (e.g., by a chemical reaction between water and one or more minerals comprising a material capable of reacting with water to produce hydrogen within the solid domain, as described above) induced by the placement and / or configuration of each conduit. In some embodiments, the development of induced fractures due to the placement and / or configuration of each conduit may produce a fracture network, as described elsewhere herein.

[0088] In some embodiments, a system as described herein may comprise a sensor 108 (e.g., one or more sensors). In some embodiments, the sensor may be configured to measure any of a variety of properties of the system. For example, in some embodiments, the sensor may be configured to measure a pressure of a fluid within the system, a temperature of one or more components and / or at one or more locations within the system, deformation of one or more components and / or at one or more locations within the system (e.g., deformation at one or more locations within the solid domain), and / or a chemical composition of one or more components and / or at one or more locations within the system (e.g., the composition of a fluid, such as the aqueous fluid). For example, in some embodiments, the system may comprise a fluid pressure sensor, a temperature sensor, a rock deformation sensor, and / or a chemical composition sensor.

[0089] In some embodiments, the system comprises a fluid pressure sensor. In some embodiments, the fluid pressure sensor may comprise a piezoelectric sensor, strain gauge sensor, piezoresistive sensor, fiber optic sensor, capacitive sensor, microelectromechanical (MEMS) sensor, and / or mechanical sensor. In some embodiments, the fluid pressure sensor may be used to monitor when a fluid pressure within the system is outside of a desired range. In some embodiments, the fluid pressure sensor may be used to monitor the pressure in one or more conduits in the system (e.g., an injection conduit, a removal conduit, and / or a conduit which is both an injection conduit and a removal conduit). In some embodiments, the pressure in a conduit may be monitored to facilitate control of fluid flow within the conduit. For example, in some embodiments, the direction of fluid flow within a conduit may be at least in part determined by the pressure. As described above, in some embodiments in which the system comprises a solid domain which is a subsurface geological formation (e.g., comprising rock) and a conduit is within the geological formation, fluid (e.g., an aqueous fluid and / or a fluid comprising hydrogen) may flow into the conduit when fluid pressure within the conduit is greater than or equal to the least compressive stress in the formation, and fluid may flow out of the conduit when fluid pressure within the conduit is less than the least compressive stress in the formation. As such, a fluid pressure sensor (e.g., along with a controller to which the fluid pressure measurement from the fluid pressure sensor is provided as an input) may be used to support and / or inform processes to control the direction of fluid flow within a conduit. In some embodiments, the fluid pressure sensor may indicate a change in the pressure of a fluid within a conduit. In some embodiments, depending on the indication of the fluid pressure sensor and the fluid pressure setpoint during operation of the system, the pressure exerted on the fluid (e.g., via a pump) may be increased (e.g., if the pressure is indicated to be below the setpoint) or decreased (e.g., if the pressure is indicated to be above the setpoint). One or more other properties of a component in the system may also be altered in response to an indication of a fluid pressure, such as the temperature and / or flow rate of the fluid into and / or out of a conduit. For example, in some embodiments, if the pressure is indicated to be below the setpoint, the flow rate of a fluid into the conduit may be increased. In some embodiments, if the pressure is indicated to be above the setpoint, the flow rate of a fluid out of the conduit may be decreased.

[0090] In some embodiments, the system comprises a temperature sensor. In some embodiments, the temperature sensor may comprise a thermocouple, a resistance temperature detector, a microelectromechanical (MEMS) sensor, an infrared sensor, and / or a distributed acoustic sensor employing fiber optic cables. In some embodiments, the temperature sensor may be configured to measure the temperature of fluid in a conduit (e.g., an injection conduit, a removal conduit, and / or a conduit which is both an injection conduit and a removal conduit). In some embodiments, the temperature sensor may be configured to measure the temperature of the of the solid domain. For example, in some embodiments in which the solid domain is a subsurface geological formation comprising rock, the temperature sensor may be configured to measure the temperature of the rock. In some embodiments, the temperature sensor (e.g., along with a controller to which the temperature measurement from the temperature sensor is provided as an input) may be used to support and / or inform processes to control other aspects of the system. For example, in some embodiments, the temperature sensor may be used to monitor the down-hole fluid temperature within a conduit and / or the temperature of the solid domain (e.g., rock). In some such embodiments, when the sensor indicates that the fluid temperature and / or temperature of the solid domain has fallen below and / or above a desired temperature (e.g., outside of a desired temperature window), the fluid temperature can be increased and / or decreased in order to speed up and / or slow down a chemical reaction occurring within the solid domain (e.g., between an aqueous fluid supplied by the conduit and rock, such as rock comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, within the solid domain). In some such embodiments, when the temperature sensor indicates that the fluid temperature and / or temperature of the solid domain has fallen below and / or above a desired temperature (e.g. outside of a desired temperature window), the fluid temperature can be increased and / or decreased in order to induce fracturing of the solid domain (e.g., to induce fracturing of the rock), thereby providing access of the fluid to more surface area within the solid domain. One or more other properties of a component in the system may also be altered in response to an indication of a temperature within the system, such as the pressure and / or flow rate of the fluid into and / or out of a conduit. For example, in some embodiments, if the fluid temperature and / or temperature within the solid domain is indicated to be above the desired temperature, the flow rate of a fluid into the conduit (e.g., fluid having a lower temperature) may be increased. In some embodiments, if the fluid temperature and / or temperature within the solid domain is indicated to be below the desired temperature, the flow rate of a fluid into the conduit (e.g., a fluid having a higher temperature) may be adjusted (e.g., increased or decreased).

[0091] In some embodiments, the system comprises a rock deformation sensor. In some embodiments, the rock deformation sensor comprises a seismometer, a geophone, a borehole strain gauge, a tiltmeter, a surface deformation sensor, a repeat leveling sensor, a time-dependent gravity sensor, a time-dependent gravity gradiometer sensor, and / or a distributed acoustic sensor employing fiber optic cables. In some embodiments, the rock deformation sensor may be configured to measure the deformation of a rock formation within the system (e.g., the solid domain comprising a rock formation such as a subsurface geological formation). In some embodiments, the rock deformation sensor may be configured to determine the locations and / or magnitudes of seismic events (e.g., seismic events resulting from one or more chemical reactions taking place within the system, such as chemical reactions between water from an aqueous fluid and one or more minerals comprising a material capable of reacting with water to produce hydrogen within the solid domain). In some embodiments, the rock deformation sensor may be configured to measure the deformation of the rock formation within the system by determining the locations and magnitudes of events resulting from one or more chemical reactions within the system that are sufficiently slow that they do not cause seismic radiation. In some embodiments, the rock deformation sensor may be configured to measure the deformation of a rock formation outside the system (e.g., a rock formation adjacent the system) by determining the locations and magnitudes of events (e.g., seismic events) within the system. In some embodiments, the rock deformation sensor may be configured to measure the deformation of the rock formation within the system in communication with fluids by determining the deformation of a borehole. In some embodiments, the rock deformation sensor may be configured to measure the deformation of a rock formation outside the system (e.g., proximate the system) by determining the deformation of a borehole. In some embodiments, the rock deformation sensor may be configured to measure the deformation of the rock formation within and / or outside the system (e.g., proximate the system) by determining the tilting of the rock formation. In some embodiments, the rock deformation sensor may be configured to measure the deformation of the rock formation within and / or outside the system by determining the vertical displacement of the surface of the earth. In some embodiments, the rock deformation sensor may be configured to measure the deformation of a rock formation within and / or outside the system by determining the horizontal displacement of the surface of the earth. In some embodiments, the rock deformation sensor may be configured to measure the deformation of the rock formation within and / or outside the system by determining a combination of the vertical and horizontal displacements of the surface of the earth. In some embodiments, the rock deformation sensor may be configured to measure the deformation and / or change in mass of the rock formation within and / or outside the system by determining changes in gravitational acceleration (e.g., the rock deformation sensor may be a time-dependent gravity sensor). In some embodiments, the rock deformation sensor may be configured to measure the deformation and / or change in mass of the rock formation within and / or outside the system by determining changes in the spatial gradient of the gravitational acceleration (e.g., the rock deformation sensor may be a time-dependent gravity gradiometer sensor). In some embodiments, the rock deformation sensor may be configured to measure the change in seismic wavespeeds of the rock formation within and / or outside the system by determining changes in travel times of seismic waves passing through the region. In some embodiments, the rock deformation sensor may indicate a deformation of rock (e.g., rock which is part of the solid domain) at a particular location within the system. In some embodiments, depending on the location and / or magnitude of the deformation indicated by the rock deformation sensor, one or more parameters of the system may be changed. For example, in some embodiments, the pressure exerted on the fluid (e.g., via a pump) in a conduit within the system, pressure on a fluid in the conduit, the temperature of a fluid in a conduit, and / or the flow rate of a fluid into and / or out of the conduit may be altered. In some embodiments in which the system comprises multiple conduits within the solid domain, the temperature of a fluid in a conduit, and / or the flow rate of a fluid into and / or out of one or more of the conduits (e.g., each of the conduits) may be altered. In some embodiments, pressure of the fluid in a conduit, the temperature of a fluid in a conduit, and / or the flow rate of a fluid into and / or out of a conduit may be altered in response to the indication of a rock deformation sensor in order to induce further deformation of the rock in the same location and / or in a different location within the system. For example, in some embodiments, in response to an indication of rock deformation in one location in the system, the flow rate of a fluid into a conduit in a different location in the system may be increased (e.g., to promote rock deformation in the different location in the system). In some embodiments, in response to an indication of rock deformation at a location in the system, the flow rate of a fluid out of a conduit in that location may be decreased (e.g., to discourage further rock formation at that location in the system). Other system parameters, like fluid temperature and pressure, may be adjusted to promote and / or discourage further deformation of the rock at one or more locations in the system.

[0092] In some embodiments, the rock deformation sensor may be used to monitor the location, progression, and / or speed of a chemical reaction (e.g., a chemical reaction between water in an aqueous fluid and one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above). In some embodiments (e.g., along with a controller which takes, as an input, an output signal from the rock deformation sensor), the information from the rock deformation sensor may be used to determine whether or not to increase and / or decrease the rate of delivery, temperature, and / or pressure of an aqueous fluid (e.g., via a conduit) to a portion of the solid domain (e.g., the rock formation). In some embodiments, (e.g., along with a controller which takes, as an input, an output signal from the rock deformation sensor), the information from the rock deformation sensor may be used to determine whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain. In some embodiments, the rock deformation sensor may be used to monitor the location and amount of fracturing of the rock formation within the system to determine whether or not to increase and / or decrease the rate of delivery, temperature, and / or pressure of an aqueous fluid (e.g., via a conduit) to a portion of the solid domain (e.g., the rock formation). In some embodiments, the rock deformation sensor may be used to monitor the location and amount of fracturing of the rock formation within the system to determine whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain. In some embodiments, the rock deformation sensor may be used to monitor the location and amount of fracturing of a rock formation outside the system in order to determine whether or not to increase and / or decrease the rate of delivery, temperature, and / or pressure of an aqueous fluid (e.g., via a conduit) to a portion of the solid domain (e.g., the rock formation). In some embodiments, the rock deformation sensor may be used to monitor the location and amount of fracturing of the rock formation outside the system to determine whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain. In some embodiments, the rock deformation sensor may be used to determine whether the deformation changes are occurring as predicted by a model (e. g., as in FIG. 2), or whether a correction to the model is needed (e. g., modifying one or more assumptions of the model, such as the geometry or magnitude of the volume changes assumed in the model).

[0093] In some embodiments, the system comprises a chemical composition sensor. In some embodiments, the chemical composition sensor comprises a mass spectrometry-based sensor, electrochemical sensor, optical sensor (e.g., a UV-Vis sensor, an IR sensor), a Raman spectroscopy sensor, a Fourier-transform infrared (FTIR) spectroscopy sensor, a chromatography sensor, an ion-selective electrode, and / or an X-ray-based sensor. In some embodiments, a chemical composition sensor may be configured to perform a microstructural analysis (e.g., on a portion and / or sample of the solid domain, e.g., rock from the solid domain). In some embodiments, a chemical composition sensor may be configured to measure the total chemical composition of at least a portion of the solid domain (e.g., a sample of the solid domain).

[0094] In some embodiments, a chemical composition sensor may indicate a change in the chemical composition of one or more components of the system (e.g., within the aqueous fluid and / or within the solid domain) at one or more locations within the system (e.g., in the conduit, at the base of the conduit, at an inlet to the conduit, etc.). In some embodiments, depending on the indication of the chemical composition sensor, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of delivery of a fluid (e.g., an aqueous fluid) to a portion of the solid domain (e.g., via a conduit). In some embodiments, depending on the indication of the chemical composition sensor, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain.

[0095] A system as described herein may comprise a variety of sensors configured to measure other properties and / or components of interest within the system. For example, in some embodiments, the system may comprise a sensor configured to measure gas generation within the solid domain, a volume change of the solid domain, and / or a local elastic modulus of the solid domain. In some embodiments, the volume change of the solid domain may be determined by matching the deformation measured by a rock deformation sensor to the deformation calculated from a continuum mechanics model. For example, when a spherical region of a solid domain comprising a rock formation expands, the rock surrounding the expanded region is everywhere pushed outward (e.g., away from the expanding region) in a deterministic way. When a tabular- shaped region of a rock formation expands, the rock surrounding the expanded region is pushed outward (e.g., away from the long face of the tabularshaped region), while the regions near the tips of the tabular- shaped region are stretched and expand, as shown in FIG.2. Multiple expanding regions may cause more complicated deformation regions to develop, but their deformation patterns may still be found deterministically, as shown in FIG. 2. The rock deformation observed at multiple locations can be used in a standard geophysical inverse problem to estimate the shapes and volume changes of reacting regions. In some embodiments, one or more properties of the system may be altered based on the volume change of the solid domain measured at one or more locations within the system. In some embodiments, depending on the measurement of the volume change, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of deliver of a fluid (e.g., an aqueous fluid) to a portion of the solid domain (e.g., via a conduit). In some embodiments, depending on the measurement of the volume change, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain.

[0096] In some embodiments, the local elastic modulus of the solid domain may be determined by matching the arrival times measured at seismic sensors to arrival times calculated from a model of elastic modulus (e.g., using well-known techniques such as those used in seismology). In some embodiments, the local elastic modulus of the solid domain may be determined by matching the waveforms observed by seismic sensors to wave forms calculated using a wave propagation model that includes the effects of varying elastic modulus (e. g., “receiver function studies”). In some embodiments, the local elastic modulus of the solid domain may be determined by an inverse approach using the arrival times measured at seismic sensors as input data for the inversion. In some instances, such an approach may be referred to as “seismic tomography,” “back projection tomography,” and / or “seismic noise tomography.” In some embodiments, the change in the local elastic modulus of the solid domain over a period of time may be determined by use the ultrasound probes to send known pulses in regular intervals and sampling the changes in travel time, which correspond to changes in elastic moduli. In some embodiments, the changes in the elastic moduli over the period of time may correlate to reaction rates of chemical reactions occurring within the solid domain (e.g., between water and a mineral comprising a material capable of reacting with water to form hydrogen) at a high temporal resolution. In some embodiments, one or more properties of the system may be altered based on the elastic modulus of the rock formation measured at one or more locations within the system. In some embodiments, depending on the measurement of the elastic modulus, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of deliver of a fluid (e.g., an aqueous fluid) to a portion of the solid domain (e.g., via a conduit). In some embodiments, depending on the measurement of the elastic modulus, it may be determined whether or not to increase and / or decrease the temperature, pressure, and / or rate of removal of a fluid (e.g., a fluid comprising an aqueous fluid and hydrogen) from a conduit from a portion of the solid domain.

[0097] In some embodiments, a method of producing hydrogen is provided. In some embodiments, the method of producing hydrogen may comprise producing geologic hydrogen (e.g., from a geological formation). In some embodiments, a method of producing hydrogen as described herein comprises flowing an aqueous fluid from a source, through an injection conduit, and to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen.

[0098] In some embodiments, flowing the aqueous fluid from the source to the solid domain may comprise flowing the aqueous fluid from a source of aqueous fluid as described above (e.g., a tank). In some embodiments, flowing the aqueous fluid may comprise pressure-driven flowing (e.g., via pumping) of the aqueous fluid (e.g., high-pressure injection of the aqueous fluid). In some embodiments, flowing the aqueous fluid from the source to the solid domain comprises flowing the aqueous fluid through an injection conduit, which may have any of the properties and / or characteristics of an injection conduit as described above (e.g., the injection conduit may be fluidically connected to one or more fractures in the solid domain, etc.).

[0099] The solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen may have any of the properties and / or characteristics of a solid domain as described above. For example, in some embodiments, the solid domain comprises ultramafic rock, mafic rock, and / or sedimentary rock comprising a material capable of reacting with water to produce hydrogen (e.g., a mineral containing ferrous iron). As described above, the solid domain may comprise one or more fractures (e.g., induced fractures and / or naturally occurring fractures).

[0100] Prior to the flowing of the aqueous fluid from the source to the solid domain, the solid domain may have any of a variety of suitable volumes. For example, in some embodiments, prior to the flowing of the aqueous fluid, the solid domain has a volume of greater than or equal to 1 m3, greater than or equal to 5 m3, greater than or equal to 10 m3, greater than or equal to 50 m3, greater than or equal to 100 m3, greater than or equal to 500 m3, greater than or equal to 1,000 m3, greater than or equal to 5,000 m3, greater than or equal to 10,000 m3, greater than or - 1 - equal to 50,000 m3, greater than or equal to 100,000 m3, greater than or equal to 500,000 m3, greater than or equal to 1,000,000 m3, greater than or equal to 5,000,000 m3, greater than or equal to 10,000,000 m3, greater than or equal to 50,000,000 m3, greater than or equal to 100,000,000 m3, or greater than or equal to 500,000,000 m3. In some embodiments, prior to the flowing of the aqueous fluid, the solid domain has a volume of less than or equal to 1,000,000,000 m3, less than or equal to 500,000,000 m3, less than or equal to 100,000,000 m3, less than or equal to 50,000,000 m3, less than or equal to 10,000,000 m3, less than or equal to 5,000,000 m3, less than or equal to 1,000,000 m3, less than or equal to 500,000 m3, less than or equal to 100,000 m3, less than or equal to 50,000 m3, less than or equal to 10,000 m3, less than or equal to 5,000 m3, less than or equal to 1,000 m3, less than or equal to 500 m3, less than or equal to 100 m3, less than or equal to 50 m3, less than or equal to 10 m3, or less than or equal to 5 m3. Combinations of these ranges are also possible (e.g., in some embodiments, prior to the flowing of the aqueous fluid, the solid domain has a volume of greater than or equal to 1 m3and less than or equal to 1,000,000,000 m3, greater than or equal to 5 m3and less than or equal to 500,000,000 m3, or greater than or equal to 10 m3and less than or equal to 100,000,000 m3). Other ranges are also possible.

[0101] In some embodiments, a method of producing hydrogen as described herein comprises flowing aqueous fluid to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen. The chemical reaction may comprise any of the chemical reactions between water from an aqueous fluid and the one or more minerals as described above. For example, in some embodiments, the one or more minerals comprising a material capable of reacting with water to produce hydrogen may react with the aqueous fluid such that the one or more minerals are hydrated and / or ferrous iron and / or magnesium contained in the one or more minerals is oxidized. In some embodiments, the chemical reaction comprises a serpentinization reaction, as described above.

[0102] In some embodiments, the aqueous fluid may be delivered to the solid domain via one or more conduits fluidically connected to the solid domain, as described above. Any of a variety of suitable amounts of the aqueous fluid may be delivered to the solid domain by each conduit. In some embodiments, the total amount of aqueous fluid delivered to the solid domain may be the sum of the amount of aqueous fluid delivered by each conduit. For example, in some embodiments, an aqueous fluid may be delivered to the solid domain in an amount of greater than or equal to 100 L, greater than or equal to 200 L, greater than or equal to 500 L, greater than or equal to 1,000 L, greater than or equal to 5,000 L, greater than or equal to 10,000 L, greater than or equal to 50,000 L, greater than or equal to 100,000 L, greater than or equal to 500,000 L, greater than or equal to 1,000,000 L, greater than or equal to 5,000,000 L, or greater than or equal to 10,000,000 L (e.g., via each conduit fluidically connected to the solid domain and / or by the sum of all conduits fluidically connected to the solid domain). In some embodiments, the aqueous fluid may be delivered to the solid domain in an amount of less than or equal to 50,000,000 L, less than or equal to 10,000,000 L, less than or equal to 5,000,000 L, less than or equal to 1,000,000 L, less than or equal to 500,000 L, less than or equal to 100,000 L, less than or equal to 50,000 L, less than or equal to 10,000 L, less than or equal to 5,000 L, less than or equal to 1,000 L, less than or equal to 500 L, or less than or equal to 200 L (e.g., via each conduit fluidically connected to the solid domain and / or by the sum of all conduits fluidically connected to the solid domain). Combinations of these ranges are also possible (e.g., in some embodiments, the aqueous fluid may be delivered to the solid domain in an amount of greater than or equal to 100 L and less than or equal to 50,000,000 L, greater than or equal to 200 L and less than or equal to 10,000,000 L, or greater than or equal to 500 L and less than or equal to 5,000,000 L). Other ranges are also possible.

[0103] The aqueous fluid may be delivered to the solid domain at any of a variety of suitable rates by each conduit, as described above. For example, in some embodiments, the aqueous fluid is delivered to the solid domain at a rate of greater than or equal to 0.01 L / s, greater than or equal to 0.05 L / s, greater than or equal to 0.1 L / s, greater than or equal to 0.5 L / s, greater than or equal to 1 L / s, greater than or equal to 5 L / s, greater than or equal to 10 L / s, greater than or equal to 50 L / s, greater than or equal to 100 L / s, greater than or equal to 500 L / s, greater than or equal to 1,000 L / s, greater than or equal to 5,000 L / s, or greater than or equal to 10,000 L / s by each conduit. In some embodiments, the aqueous fluid is delivered to the solid domain at a rate of less than or equal to 50,000 L / s, less than or equal to 10,000 L / s, less than or equal to 5,000 L / s, less than or equal to 1,000 L / s, less than or equal to 500 L / s, less than or equal to 100 L / s, less than or equal to 50 L / s, less than or equal to 10 L / s, less than or equal to 5 L / s, less than or equal to 1 L / s, less than or equal to 0.5 L / s, less than or equal to 0.1 L / s, or less than or equal to 0.05 L / s by each conduit. Combinations of these ranges are also possible (e.g., in some embodiments, the aqueous fluid is delivered to the solid domain at a rate of greater than or equal to 0.01 L / s and less than or equal to 50,000 L / s, greater than or equal to 0.05 L / s and less than or equal to 10,000 L / s, or greater than or equal to 0.1 L / s and less than or equal to 5,000 L / s by each conduit). Other ranges are also possible.

[0104] In some embodiments, the amount of hydrogen produced may be altered by varying the amount of the aqueous fluid which is delivered to the solid domain and / or the rate at which the aqueous fluid is delivered to the solid domain. For example, in some embodiments, delivering a larger volume of the aqueous fluid may result in the production of a larger amount of hydrogen. In some embodiments, delivering a smaller volume of the aqueous fluid may result in the production of a larger amount of hydrogen. In some embodiments, the amount of the aqueous fluid that is delivered to the solid domain and / or the rate at which the aqueous fluid is delivered to the solid domain may be modified to adjust the amount of and / or rate at which the hydrogen is produced.

[0105] In some embodiments, the aqueous fluid comprises one or more additives. For example, in some embodiments, the aqueous fluid comprises an interfacial modifier and / or a rheology modifier. The interfacial modifier and / or rheology modifier may comprise any of a variety of suitable compositions. For example, in some embodiments, the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant.

[0106] In some embodiments, an interfacial modifier and / or rheology modifier may comprise a surfactant. In some embodiments, the surfactant may comprise a surfactant which promotes the formation of stable bubbles (e.g., stable gas-containing bubbles) within an aqueous fluid. As used herein, the term “bubble” is given its ordinary meaning in the art, and refers to a gaseous phase surrounded by a liquid. According to certain embodiments, a bubble can have any suitable shape, such as spherical, deviational from spherical, or ellipsoidal.

[0107] In some embodiments, the interfacial modifier and / or rheology modifier comprises a surfactant that promotes the formation of stable bubbles with an aqueous fluid may comprise a nonionic surfactant and / or a nonionic surfactant blended with other polymers (e.g., polyacrylamide polymers). In some embodiments, the interfacial modifier and / or rheology modifier may comprise a polyethylene glycol (PEG)-based surfactant having any of a variety of suitable molecular weights, wherein the molecular weight of the PEG-based surfactant is indicated as PEG-X, where X is the molecular weight in g / mol. For example, in some embodiments, the interfacial modifier and / or rheology modifier comprises PEG-300, PEG-400, PEG-500, PEG-600, PEG- 1000, PEG-2000, PEG-4000, and / or a PEG-X blend. In some embodiments, a surfactant which promotes the formation of stable bubbles within an aqueous fluid may comprise a PEG-polymer blend such as a PEG-copolymer.

[0108] In some embodiments, the interfacial modifier and / or rheology modifier may comprise a cationic surfactant (e.g., a cationic surfactant which promotes the formation of stable bubbles). In some embodiments, the cationic surfactant comprises cetyltrimethylammonium bromide (CTAB). In some embodiments, the interfacial modifier and / or rheology modifier may comprise a fluorinated surfactant (e.g., a fluorinated surfactant which promotes the formation of stable bubbles). In some embodiments, the fluorinated surfactant comprises fluorinated ethylene propylene (FEP).

[0109] In some embodiments, the interfacial modifier and / or rheology modifier may comprise a surfactant which promotes the formation of a stable foam within an aqueous fluid. In some embodiments, a surfactant which promotes the formation of a stable foam within an aqueous fluid comprises a PEG-based polymer, modified polymer, and / or copolymer, as described above. In some embodiments, an interfacial modifier and / or rheology modifier comprises PEG-Stearate, PEG-oleate, PEG-myristate, PEG-dodecyl ether, PEG-4000, PEG-Siloxane, PEG-silicone, and / or PEG-polyacrylamide.

[0110] In some embodiments, the hydrogen produced via a chemical reaction (e.g., a chemical reaction between the water in an aqueous fluid and one or more minerals comprising a material capable of reacting with water to form hydrogen, as described above) and the aqueous fluid (e.g., an aqueous fluid comprising one or more additives, as described above) form a mixture. In some embodiments, it may be advantageous for the mixture to comprise hydrogen produced via a chemical reaction which is either dissolved in the aqueous fluid or in the form of gascontaining bubbles (e.g., gas -containing bubbles comprising hydrogen gas) within the aqueous fluid (e.g., to form a multiphase gas-liquid mixture comprising water and gaseous hydrogen, as described elsewhere herein).

[0111] In some embodiments, it may be advantageous for the mixture to comprise hydrogen that is dissolved within the aqueous fluid. For example, in some embodiments, it may be simpler to predict and / or model the flow of an aqueous fluid comprising dissolved hydrogen than to predict and / or model the flow of a multiphase gas-liquid mixture comprising the aqueous fluid and gaseous hydrogen. In some embodiments, the fluid handling costs (e.g., pumping costs) may be relatively lower for an aqueous fluid comprising dissolved hydrogen. However, in certain embodiments, mixtures comprising hydrogen dissolved in an aqueous fluid may be susceptible to the loss of hydrogen from the mixture via diffusion. For example, in some embodiments, the mixture of the aqueous fluid and hydrogen may be contained within one or more conduits, as described above. In some such embodiments, the conduit may be comprised of and / or within a solid domain (e.g., a subsurface geological formation) comprising rock and / or another material (e.g., a porous material) which is permeable to hydrogen. In such embodiments, the hydrogen may diffuse out of the mixture and into the material from which the conduit and / or solid domain is formed. In some embodiments in which the hydrogen is a desired end product which could be recovered from the mixture, this may be undesirable, as it is difficult to recover any hydrogen which has diffused into the solid domain. The diffusion of hydrogen (e.g., from the mixture) into the solid domain may be characterized by the hydrogen flux JH into the solid domain. For example, in some embodiments, there may be a critical flux, JHC, above which the hydrogen loss to the solid domain becomes unacceptable. In some instances, when the hydrogen flux into the solid domain is less than the critical hydrogen flux (i.e., JH < JHC), it may be advantageous for the hydrogen to be dissolved in the aqueous fluid, as described above. In some instances, when the hydrogen flux into the solid domain is greater than or equal to the critical hydrogen flux (i.e., JH > JHC), it may become advantageous for the hydrogen to be in the form of gas-containing bubbles comprising hydrogen gas within the mixture. The critical hydrogen flux can be a threshold hydrogen flux, in some embodiments. In some embodiments, the critical hydrogen flux is a threshold amount of tolerable hydrogen flux while allowing for the recovery of a desired amount of hydrogen.

[0112] In some embodiments, hydrogen being in the form of hydrogen gas contained within the gas-containing bubbles may advantageously prevent and / or reduce hydrogen diffusing through the solid domain (e.g., diffusing out through the walls of the conduit). In some embodiments, this may allow for a larger portion of the hydrogen generated via the chemical reaction (as described above) to be recovered and / or captured from the system.

[0113] In some embodiments, a method of producing hydrogen as described herein comprises measuring the flux of hydrogen out of a mixture as described above (e.g., a mixture comprising hydrogen and an aqueous fluid). In some embodiments, a modified Devanathan-Stachurski (DS) electrochemical permeation cell can be used. A DS electrochemical permeation cell comprises two compartments separated by a portion of the solid domain (e.g., a portion of the solid domain for which it is desired to measure the influx of hydrogen). The DS electrochemical permeation cell may comprise an entry cell (e.g., a portion of the conduit comprising a mixture) which is filled with the mixture (e.g., a mixture comprising the aqueous fluid and hydrogen), and hydrogen (e.g., hydrogen generated by a chemical reaction of water and one or more minerals comprising a material capable of reacting with water to form hydrogen, as described above). The hydrogen (e.g., hydrogen atoms) may diffuse through the solid domain and emerge at an opposite surface defined by an exit cell, which also contains the aqueous fluid and is maintained at an anodic potential to oxidize the permeated hydrogen. A thin catalytic layer, such as palladium, may be applied to the exit surface to facilitate hydrogen oxidation. The resulting anodic current is recorded using a potentiostat, and its time-dependent profile is analyzed to determine hydrogen flux and effective diffusivity through the solid domain. Altematively, a hydrogen looping approach can be employed to detect the flux of gaseous hydrogen into the solid domain. In a hydrogen looping approach, hydrogen is introduced on one side of the solid domain (e.g., at a portion of the conduit) at a known pressure, and the hydrogen gas measured at an opposite surface defined by an exit cell is monitored using a gas chromatograph or mass spectrometer. This approach may allow for measurement of steady- state hydrogen permeability in the gas phase and is particularly useful when electrochemical access is limited. In some embodiments, a modified DS electrochemical permeation cell and a hydrogen looping approach may be used together. In some embodiments, the use of these approaches together may allow for the comprehensive evaluation of hydrogen generation, transport, and retention in a solid domain (e.g., a subsurface geological formation).

[0114] In some embodiments, a method of producing hydrogen may comprise performing one or more of the techniques described above for measuring the flux of hydrogen into a solid domain (e.g., out of a mixture comprising an aqueous fluid and dissolved hydrogen) within a conduit and / or within the solid domain of a system as described herein. In some embodiments, a system as described herein may comprise an apparatus configured to perform one or more of the techniques described above for measuring the flux of hydrogen into a solid domain. In some embodiments, if it is indicated (e.g., via the performance of one or more of the techniques described above using an apparatus configured to perform the technique) that the flux of hydrogen into the solid domain (e.g., from a mixture comprising the aqueous fluid and dissolved hydrogen) equals or exceeds the critical hydrogen flux (e.g., JH > JHC), at which point it may be advantageous for the hydrogen to be in the form of gas-containing bubbles within the aqueous fluid (e.g., a multiphase gas-liquid mixture comprising the aqueous fluid and gas -containing bubbles comprising hydrogen), one or more properties of the mixture and / or the conduit containing the mixture may be altered to promote the formation of gas-containing bubbles comprising hydrogen within the mixture. For example, in some embodiments, if it is indicated that the flux of hydrogen into the solid domain equals or exceeds the critical hydrogen flux (e.g., JH > JHC), a pressure exerted on the mixture (e.g., via the pumping of the aqueous fluid into the conduit) may be reduced. In some embodiments, reducing the pressure exerted on the mixture may promote the generation of gas-containing bubbles within the mixture (e.g., via the exsolution of hydrogen to form hydrogen gas). In some embodiments, if it is indicated the flux of hydrogen into the solid domain is less than the critical hydrogen flux (JH < JHC), a pressure exerted on the mixture may be maintained and / or increased.

[0115] In some embodiments, the addition of the aqueous fluid to the solid domain, the chemical reaction between the water of the aqueous fluid and one or more minerals comprising a material capable of reacting with water to form hydrogen (e.g., one or more minerals comprising ferrous iron, as described above), and / or the associated production of hydrogen within the solid domain may cause a volume of the solid domain to change (e.g., increase) as a method described herein is performed. For example, in some embodiments, a volume of the solid domain changes by greater than or equal to 0.5%, greater than or equal to 1%, greater than or equal to 5%, greater than or equal to 10%, greater than or equal to 50%, or greater than or equal to 100% relative to the original volume. In some embodiments, a volume of the solid domain changes by less than or equal to 150%, less than or equal to 100%, less than or equal to 50%, less than or equal to 10%, less than or equal to 5%, or less than or equal to 1% relative to the original volume. Combinations of these ranges are also possible (e.g., a volume of the solid domain may change by greater than or equal to 0.5% and less than or equal to 150%, greater than or equal to 1% and less than or equal to 100%, or greater than or equal to 5% and less than or equal to 50%). Other ranges are also possible.

[0116] In some embodiments, the volume of the solid domain may change in a way that is localized (e.g., in some embodiments, the volume of a portion of the solid domain may change, while the volume of another portion of the solid domain may not change).

[0117] In some embodiments, a change in the volume of the solid domain may result in changes of the stress field within the solid domain. For example, in some embodiments, a local increase in volume in a portion of the solid domain may compress some of the areas of the solid domain surrounding the portion of the solid domain which has increased in volume, resulting in a local increase in compressive stress in such portions of the solid domain. In some embodiments, a local increase in volume of a portion of the solid domain may extend some of the areas of the solid domain surrounding the portion of the solid domain which has increased in volume, resulting in a local decrease in compressive stress in such portions of the solid domain and / or compress some of the areas of the solid domain surrounding the portion of the solid domain which has increased in volume, resulting in a local increase in compressive stress in such portions of the solid domain. For example, FIG. 2 shows a simulated subsurface comprising multiple tabular shaped reaction zones (signified by thick lines), wherein each tabular shaped reaction zone is associated with a local increase in volume. The areas with thin solid contours in FIG. 2 indicate areas of increased compressive stress (e.g., due to compression caused by the local increase in volume at and around the reaction zone). The areas with thin dashed contours in FIG. 2 indicate areas of decreased compressive stress. The solid line of medium thickness labeled “0” indicates contours of no change in compressive stress. For the same tabular reaction zone length and thickness, the pattern of changes in compressive stress depends on the depth of the reaction zone below the surface of the solid domain (e.g., in embodiments in which the solid domain is a subsurface geological formation comprising rock, the surface of the earth), the orientation of the reaction zone fracture (e.g., horizontal, vertical, or at some other angle to vertical), and the effects of nearby reaction zones. These effects are illustrated in FIG. 2. As discussed below, controlling the locations and orientations of reaction zones and the compressive stress variations that result allow control of further fracturing from fluid injection and / or chemical reactions.

[0118] In some embodiments, a method as described herein comprises inducing fracturing of the solid domain. For example, in some embodiments, the flowing of the aqueous fluid to the solid domain in a method as described herein induces fracturing of the solid domain. The inducing of fracturing of the solid domain may happen through a variety of mechanisms. In some embodiments as described above, the flowing of the aqueous fluid to the solid domain may result in a change in the volume of the solid domain (e.g., a localized change in the volume of the solid domain) and / or a change of the stress field within the solid domain (e.g., a localized change in the stress field within the solid domain), for example, due to the pressure of the fluid and / or pressure buildup that occurs from one or more chemical reactions. In some embodiments, high stresses in an area of the solid domain may result in fracturing of the solid domain (e.g., when the stress exceeds the strength of the solid domain). In some embodiments, fractures may form within the solid domain adjacent to other fractures (e.g., one or more fractures may join to form a larger fracture). In some embodiments, fracturing of the solid domain may comprise the lengthening and / or expansion of existing fractures (e.g., existing induced and / or naturally occurring fractures) within the solid domain.

[0119] In some embodiments, the fracturing of the solid domain produces fractures that are fluidically connected to an injection conduit and / or removal conduit within the solid domain. In some embodiments, the fracturing of the solid domain produces fractures which are not fluidically connected to an injection conduit and / or removal conduit within the solid domain. In some embodiments, a conduit as described herein may be placed within the solid domain at a location proximate to an existing fracture (e.g., an existing induced and / or naturally occurring fracture) in the solid domain. In some such embodiments, further fracturing the solid domain may produce fractures which are joined with and / or proximate to the existing fracture. In some embodiments, fracturing the solid domain may produce a fracture network, as described elsewhere herein.

[0120] In some embodiments, fracturing of the solid domain may be induced via hydraulic fracturing. For example, in some embodiments in which the solid domain comprises rock (e.g., a subsurface geological formation comprising rock), the solid domain may comprise naturally occurring boundaries between layers of rock therein. In some embodiments, hydraulic fracturing may comprise introducing a liquid (e.g., an aqueous fluid as described herein) to one or more boundaries between layers of rock, thereby forcing the rock layers apart (e.g., inducing fracturing of the rock contained within the solid domain). In some such embodiments, inducing the fracturing of the rock may produce fractures within the rock, which may function as a channel and / or flow path of additional liquid (e.g., additional aqueous fluid) into the fractures. The fractures which are formed (e.g., induced) by hydraulic fracturing may have any of the scales as described above (e.g., the fractures may be meter-scale fractures and / or millimeterscale fractures).

[0121] In some embodiments, the fracturing of the solid domain (e.g., the inducing of fracturing the solid domain by the flowing of the aqueous fluid) comprises controlling fracture development in the solid domain (e.g., by controlling a volume change of the solid domain caused by the chemical reaction). As can be seen in FIG. 2, the placement of the reacting regions and their associated volume changes and / or stress field changes (which, in some embodiments, may correspond to the placement and / or configuration of an injection conduit and / or removal conduit, as described above) may allow for the control of further fracture development. For example, in some embodiments, the placement of an injection conduit in one portion of the solid domain (e.g., a portion of the solid domain that is undergoing extension from the effects of volume changes in existing reacting zones within the solid domain) may allow for the delivery of an aqueous fluid to that portion of the solid domain. In some embodiments, delivery of the aqueous fluid to the solid domain via the injection conduit may induce fracturing of the solid domain. In some such embodiments, the injection conduit may be fluidically connected to and / or comprise a fracture.

[0122] In some embodiments, controlling a volume change of the solid domain (e.g., controlling the changes in the stress field within the solid domain) may comprise joining one or more fractures which are not connected. For example, as shown in FIG. 2, the stress fields surrounding two fractures may align such that regions of low stress form proximate each other. In some such embodiments, such interactions may result in the joining of the two fractures to form a fracture network. As also seen in FIG. 2, in some embodiments, controlling the volume changes of the solid domain (e.g., controlling the changes in the stress field of the solid domain) may allow for the joining of one or more fractures with the surface of the solid domain to form a fracture network. For example, in embodiments in which the solid domain comprises a geological formation, controlling the volume changes of the solid domain may allow for the joining of one or more fractures to the surface (e.g., the earth’s surface) to form a fracture network.

[0123] In some embodiments, as described above, a solid domain may comprise conduits (e.g., an injection conduit, a removal conduit) which are placed and / or configured to control fracture development in the solid domain via control of a volume change of the solid domain (e.g., volume changes caused by a chemical reaction between water in an aqueous fluid introduced to the solid domain via a conduit and one or more minerals comprising a material capable of reacting with water (e.g., reacting with water to produce hydrogen) within the solid domain, as described above). In some embodiments in which the solid domain comprises several conduits, a conduit may be placed relative to another conduit such that the conduits may cooperatively induce fracturing, as described above (e.g., by inducing the formation of a fracture network).

[0124] In some embodiments, it may be desirable and / or advantageous to control fracture development within the solid domain such that a fracture network is formed at a particular depth and / or proximate to a portion of the solid domain having a particular composition (e.g., proximate a portion of a solid domain comprising rock which contains a vein and / or deposit of rocks and / or minerals comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above). For example, in some embodiments, it may be advantageous to place and / or configure two or more conduits relative to each other such that a fracture network is formed which does not comprise fractures which reach the surface of the solid domain (e.g., in embodiments in which the solid domain is a geological formation comprising rock, such that the fracture network does not comprise fractures which reach the earth’s surface). In some embodiments, the development of such fracture networks which do not contain fractures reaching the surface of the solid domain may advantageously prevent hydrogen (e.g., gaseous hydrogen) escaping from the solid domain via a fracture reaching the surface, thereby becoming unable to be captured (e.g., directed to a hydrogen storage location). In some embodiments, it may be advantageous to place one or more conduits (e.g., two or more conduits arranged relative to each other) such that fracturing is induced proximate to a portion of the solid domain (e.g., a portion of a solid domain comprising rock) which has a particularly large amount of one or more minerals comprising a material capable of reacting with water to produce hydrogen (e.g., a vein and / or deposit of such rocks and / or minerals). In some such embodiments, this may be particularly advantageous, as a fluid (e.g., an aqueous fluid) may be able to flow through the induced fractures proximate the portion of the domain having a particularly large amount of one or more minerals comprising a material capable of reacting with water to produce hydrogen. In some such embodiments, water from the aqueous fluid may react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above. The induced fractures may advantageously increase the amount of one or more minerals comprising a material capable of reacting with water to produce hydrogen that is thus exposed to water (e.g., water from an aqueous fluid), which may increase the amount of hydrogen produced via the chemical reaction.

[0125] In some embodiments, a method as described herein may comprise directing at least a portion of the hydrogen (e.g., at least a portion of the hydrogen generated by the chemical reaction) to a hydrogen storage location. In some embodiments, the at least a portion of the hydrogen may be directed to the hydrogen storage location via a removal conduit. The removal conduit may have any of the properties and / or characteristics of a removal conduit as described above (e.g., the removal conduit may comprise a borehole, etc.). In some embodiments, the hydrogen storage location may have any of the properties and / or characteristics of a hydrogen storage location as described above (e.g., the hydrogen storage location may comprise a tank and / or a pipeline). In some embodiments, the hydrogen which is directed to the hydrogen storage location may comprise gaseous hydrogen (e.g., gaseous hydrogen which is part of a multiphase gas-liquid mixture as described elsewhere herein) and / or hydrogen which is dissolved in a liquid (e.g., in an aqueous fluid).

[0126] In some embodiments, a system comprising a multiphase gas-liquid mixture is disclosed. In some embodiments, the system comprises a source of a mineral comprising a material capable of reacting with water to produce hydrogen. For example, in some embodiments, the source of a mineral comprising a material capable of reacting with water to produce hydrogen comprises ultramafic rock, mafic rock, and / or sedimentary rock. The source of a mineral comprising a material capable of reacting with water to produce hydrogen may comprise one or more minerals contained within a solid domain (e.g., rock), such as any of the solid domains (e.g., types of rock) described above.

[0127] In some embodiments, the system comprises a conduit fluidically connected to the source of the mineral comprising a material capable of reacting with water to produce hydrogen (e.g., ferrous iron). The conduit may have any of the properties and / or characteristics of a conduit (e.g., an injection conduit and / or a removal conduit) as described above. For example, in some embodiments, the conduit may comprise a pipe and / or a borehole. The conduit may be fluidically connected to a source of aqueous fluid and / or a hydrogen storage location. The source of aqueous fluid may have any of the properties and / or characteristics of a source of aqueous fluid as described above (e.g., may comprise a tank and / or a pipeline). The hydrogen storage location may have any of the properties and / or characteristics of a hydrogen storage location as described above (e.g., may comprise a tank and / or a pipeline).

[0128] In some embodiments, the conduit may be part of a system as described above (e.g., a system as described above may comprise the conduit). For example, the conduit may be an injection conduit, a removal conduit, and / or a conduit that is both an injection conduit and a removal conduit of any system described above. In certain embodiments, the conduit is a removal conduit of a system as described above. In some embodiments, the source of a mineral comprising a material capable of reacting with water to produce hydrogen (e.g., the source to which the conduit is fluidically connected) is the solid domain, a portion of the solid domain, and / or contained within the solid domain of any system as described above (e.g., a solid domain comprising one or more minerals containing a material capable of reacting with water to form hydrogen, such as the solid domain of any system described above). As such, the conduit fluidically connected to the source of the mineral comprising a material capable of reacting with water to produce hydrogen may part of another system as described elsewhere herein (e.g., any system comprising a conduit).

[0129] A system as described herein may comprise a mixture comprising liquid water and hydrogen disposed within a conduit (e.g., the conduit fluidically connected to a source of a mineral comprising a material capable of reacting with water to produce hydrogen as described above). In some embodiments, the hydrogen may comprise molecular hydrogen (i.e., H2).

[0130] In some embodiments, the mixture comprising liquid water and hydrogen disposed within the conduit may comprise liquid water which is part of an aqueous fluid (e.g., from a source of aqueous fluid) in any system comprising an aqueous fluid described above. In some embodiments, the mixture may comprise hydrogen that is produced via a chemical reaction between water (e.g., water in an aqueous fluid) and a mineral comprising a material capable of reacting with water to form hydrogen. As noted above, some embodiments, the source of the mineral comprising a material capable of reacting with water to produce hydrogen is the solid domain, a portion of the solid domain, and / or contained within the solid domain of any system as described above (e.g., a solid domain comprising one or more minerals containing a material capable of reacting with water to form hydrogen, such as the solid domain of any system described above). As such, the mixture may part of another system as described elsewhere herein. For example, any conduit in a system as described herein may be a conduit comprising such a mixture.

[0131] The mixture may comprise hydrogen in any of a variety of suitable amounts. For example, in some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5, greater than or equal to 5xl0'5, greater than or equal to 10'4, greater than or equal to 5xl0'4, greater than or equal to 10'3, greater than or equal to 5xl0'3, greater than or equal to 10'2, or greater than or equal to 5xl0'2. In some embodiments, the mixture comprises hydrogen in a mole fraction of less than or equal to 10’1, less than or equal to 5xl0'2, less than or equal to 10'2, less than or equal to 5xl0'3, less than or equal to 10'3, less than or equal to 5xl0'4, less than or equal to 10'4, or less than or equal to 5xlO'5Combinations of these ranges are also possible (e.g., in some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5and less than or equal to 10’1, greater than or equal to 5xl0'5and less than or equal to 5xl0'2, or greater than or equal to 10'4and less than or equal to 10'2). Other ranges are also possible.

[0132] In some embodiments, the mixture may comprise hydrogen in one or more phases. For example, in some embodiments, the hydrogen may be dissolved in the liquid water. In some embodiments, the mixture may comprise liquid water and hydrogen at high pressures. In some embodiments, the solubility of hydrogen in the liquid water may be approximated using Henry’s Law: where CHis the concentration of the dissolved hydrogen (mol / L), P is the partial pressure of the hydrogen gas (atm), and kHis Henry’s constant for hydrogen in water (approximately 7.8 x 10'4mol / L / atm). In some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high pressures that the solubility of the hydrogen in the liquid water is significantly higher than the solubility of hydrogen in liquid water at ambient conditions (e.g., a pressure of 1 atm and 25 °C). For example, in some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high pressures that the solubility of the hydrogen in the liquid water is higher than the solubility of hydrogen in liquid water at ambient conditions by greater than a factor of 1.5, greater than a factor of 2, greater than a factor of 5, greater than a factor of 10, greater than a factor of 50, greater than a factor of 100, greater than a factor of 500, greater than a factor of 1,000, greater than a factor of 1,500, greater than a factor of 2,000, greater than a factor of 2,500, greater than a factor of 3,000, or greater than a factor of 3,500. In some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high pressures that the solubility of the hydrogen in the liquid water is higher than the solubility of hydrogen in liquid water at ambient conditions by less than a factor of 4,000, less than a factor of 3,500, less than a factor of 3,000, less than a factor of 2,500, less than a factor of 2000, less than a factor of 1,500, less than a factor of 1,000, less than a factor of 500, less than a factor of 100, less than a factor of 50, less than a factor of 10, less than a factor of 5, or less than a factor of 2. Combinations of these ranges are also possible (e.g., in some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high pressures that the solubility of the hydrogen in the liquid water is higher than the solubility of hydrogen in liquid water at ambient conditions by greater than a factor of 1.5 and less than a factor of 4,000, etc.). For example, in some embodiments in which the liquid water is at a temperature of approximately 150 °C and a pressure of approximately 500 bar, the solubility of the hydrogen in the liquid water (0.47517 mol / kg) may be higher than the solubility of hydrogen in liquid water at ambient conditions (0.00075 mol / kg) by a factor of approximately 633.

[0133] In some embodiments, the mixture comprises hydrogen which is gaseous hydrogen. For example, in some embodiments, the mixture comprises a multiphase gas-liquid mixture comprising liquid water and gaseous hydrogen. In some such embodiments, the gaseous hydrogen may make up any suitable amount of the mixture. In some embodiments, the gaseous hydrogen makes up greater than or equal to 5 vol%, greater than or equal to 7.5 vol%, greater than or equal to 10 vol%, greater than or equal to 25 vol%, greater than or equal to 50 vol%, greater than or equal to 75 vol%, greater than or equal to 90 vol%, or greater than or equal to 95 vol% of the mixture. In some embodiments, the gaseous hydrogen makes up less than or equal to 99 vol%, less than or equal to 95 vol%, less than or equal to 90 vol%, less than or equal to 75 vol%, less than or equal to 50 vol%, less than or equal to 25 vol%, less than or equal to 10 vol%, or less than or equal to 7.5 vol% of the mixture. Combinations of these ranges are also possible (e.g., the gaseous hydrogen may make up greater than or equal to 5 vol% and less than or equal to 99 vol%, greater than or equal to 10 vol% and less than or equal to 95 vol%, or greater than or equal to 25 vol% and less than or equal to 90 vol% of the mixture). Other ranges are also possible. In some embodiments, the mixture comprises greater than or equal to 50 vol% of a gas (e.g., gaseous hydrogen) and is in the form of a foam. In some embodiments, the mixture comprising liquid water and gaseous hydrogen (e.g., the multiphase gas-liquid mixture comprising liquid water and gaseous hydrogen) comprises a foam. The term “foam,” as used herein, is given its ordinary meaning in the art, and refers to an accumulation of a plurality of pockets of entrapped gas, wherein the entrapped gas makes up a large portion of the volume of the foam.

[0134] In some embodiments, the mixture may comprise dissolved hydrogen and / or gaseous hydrogen at different points in time and / or under different conditions. For example, in some embodiments, the conduit fluidically connected to a source of a mineral comprising a material capable of reacting with water to produce hydrogen may comprise a conduit within a solid domain (e.g., rock), such as a subsurface geologic formation. In some such embodiments, at least a portion of the conduit may contain a mixture (e.g., a mixture comprising liquid water and hydrogen) at a relatively high temperature and / or pressure. For example, in some embodiments in which the conduit is in a geologic formation (e.g., rock), at least a portion of the conduit may extend from the surface (e.g., may be at atmospheric pressure and / or ambient temperatures) to depths as great as several kilometers below the surface of the earth. For example, in some embodiments, at least a portion of the conduit may extend from the surface to a depth of greater than or equal to 1 m, greater than or equal to 5 m, greater than or equal to 10 m, greater than or equal to 50 m, greater than or equal to 50 m, greater than or equal to 1,000 m, or greater than or equal to 5,000 m. In some embodiments, at least a portion of the conduit may extend from the surface to a depth of less than or equal to 10,000 m, less than or equal to 5,000 m, less than or equal to 1,000 m, less than or equal to 500 m, less than or equal to 100 m, less than or equal to 50 m, less than or equal to 10 m, or less than or equal to 5 m. Combinations of these ranges are also possible (e.g., in some embodiments, at least a portion of the conduit may extend from the surface to a depth of greater than or equal to 1 m and less than or equal to 10,000 m, greater than or equal to 5 m and less than or equal to 5,000 m, or greater than or equal to 5 m and less than or equal to 1,000 m). Other ranges are also possible.

[0135] The conduit and / or the mixture within the conduit may be subjected to a high temperature (e.g., at a large depth). For example, in some embodiments, a conduit and / or a mixture within the conduit may be at a temperature of greater than or equal to 25 °C, greater than or equal to 50 °C, greater than or equal to 100 °C, greater than or equal to 150 °C, greater than or equal to 200 °C, greater than or equal to 250 °C, greater than or equal to 300 °C, greater than or equal to 350 °C, greater than or equal to 400 °C, greater than or equal to 450 °C, greater than or equal to 500 °C, greater than or equal to 550 °C, greater than or equal to 600 °C, or greater than or equal to 650 °C. In some embodiments, a conduit and / or a mixture within the conduit may be at a temperature of less than or equal to 700 °C, less than or equal to 650 °C, less than or equal to 600 °C, less than or equal to 550 °C, less than or equal to 500 °C, less than or equal to 450 °C, less than or equal to 400 °C, less than or equal to 350 °C, less than or equal to 300 °C, less than or equal to 250 °C, less than or equal to 200 °C, less than or equal to 150 °C, less than or equal to 100 °C, or less than or equal to 50 °C. Combinations of these ranges are also possible (e.g., a conduit and / or a mixture within the conduit may be at a temperature of greater than or equal to 25 °C and less than or equal to 700 °C, greater than or equal to 50 °C and less than or equal to 650 °C, or greater than or equal to 100 °C and less than or equal to 600 °C). Other ranges are also possible. In some embodiments, the conduit and / or the mixture within the conduit may be subjected to a high pressure (e.g., when at a large depth). For example, in some embodiments, a conduit and / or a mixture within the conduit (e.g., at any of the temperatures listed above) may be subjected to a pressure (e.g., a gauge pressure) of greater than or equal to 0.1 MPa, greater than or equal to 0.25 MPa, greater than or equal to 0.5 MPa, greater than or equal to 0.75 MPa, greater than or equal to 1 MPa, greater than or equal to 2.5 MPa, greater than or equal to 5 MPa, greater than or equal to 7.5 MPa, greater than or equal to 10 MPa, greater than or equal to 25 MPa greater than or equal to 50 MPa, greater than or equal to 75 MPa, greater than or equal to 100 MPa, or greater than or equal to 250 MPa. In some embodiments, a conduit and / or a mixture within the conduit (e.g., at any of the temperatures listed above) may be subjected to a pressure (e.g., a gauge pressure) of less than or equal to 500 MPa, less than or equal to 250 MPa, less than or equal to 100 MPa, less than or equal to 75 MPa, less than or equal to 50 MPa, less than or equal to 25 MPa, less than or equal to 10 MPa, less than or equal to 7.5 MPa, less than or equal to 5 MPa, less than or equal to 2.5 MPa, less than or equal to 1 MPa, less than or equal to 0.5 MPa, or less than or equal to 0.25 MPa. Combinations of these ranges are also possible (e.g., a conduit and / or a mixture within the conduit (e.g., at any of the temperatures listed above) may be subjected to a pressure of greater than or equal to 0.1 MPa and less than or equal to 500 MPa, greater than or equal to 0.25 MPa and less than or equal to 250 MPa, or greater than or equal to 0.5 MPa and less than or equal to 100 MPa). Other ranges are also possible.

[0136] In some such embodiments, the mixture may comprise liquid water and dissolved hydrogen at large depths and / or when subjected to high pressures (e.g., by being subjected to subsurface pressures and / or being subjected to high pressures via a pump). In some embodiments, the mixture may comprise liquid water and gaseous hydrogen at shallower depths and / or when subjected to pressures which are close to atmospheric pressure. In some embodiments, the mixture may flow through the conduit (e.g., from a large depth to a shallower depth). In such embodiments, the mixture may change from a mixture of liquid water and primarily dissolved hydrogen to a mixture of liquid water and primarily gaseous hydrogen as the mixture is subjected to progressively less pressure as it flows toward the surface and / or when the mixture is subjected to less pressure due to the removal of pumping pressure.

[0137] In some embodiments, the mixture may comprise an additive (e.g., an interfacial modifier and / or rheology modifier). The interfacial modifier and / or rheology modifier may comprise any of the interfacial modifiers and / or rheology modifiers described above (e.g., nanoparticles, viscosifiers, polymer additives, and / or surfactants of any of the types described above). In some embodiments, the interfacial modifier and / or rheology modifier is configured to facilitate the formation of gas -containing bubbles and / or enhance the stability of gas -containing bubbles comprising hydrogen gas in the mixture. For example, in some embodiments, the interfacial modifier and / or rheology modifier may facilitate the formation and / or enhance the stability of gas-containing bubbles comprising hydrogen gas by reducing the surface tension of the liquid water in the mixture. In some embodiments, the interfacial modifier and / or rheology modifier is configured to prevent coalescence (e.g., prevent Ostwald ripening) of gas-containing bubbles comprising hydrogen gas. The formation of gas-containing bubbles and / or the stabilization of gas-containing bubbles may be advantageous in certain systems. For example, as described in greater detail above, the formation of gas-containing bubbles and / or the stabilization of gas-containing bubbles may be advantageous in systems in which a mixture comprising a material (e.g., hydrogen) which it is desirable to capture may diffuse out of a mixture (e.g., through the walls of a solid domain) before it can be captured. In such embodiments, the formation of gas-containing bubbles and / or stabilization of gas-containing bubbles within the system comprising the material (e.g., hydrogen) may be advantageous in preventing the diffusion of the material out of the mixture. Other possible advantages of the formation and / or stabilization of gas-containing bubbles in a mixture are described elsewhere herein.

[0138] As described above, a multiphase gas-liquid mixture generally includes a liquid (e.g., liquid water) and gas-containing bubbles contained within the liquid. The gas -containing bubbles may have any variety of morphologies. For example, as shown in FIG. 3, a conduit 301 may comprise a multiphase-gas liquid mixture comprising a liquid 302 and gas -containing bubbles. In some embodiments, the gas -containing bubbles may be in the form of pinned gascontaining bubbles 311. In some embodiments, the gas-containing bubbles may be in the form of gas-containing slugs 312. In some embodiments, the gas containing-bubble may be a single gas-containing bubble having an annular formation 313. In some embodiments, the gascontaining bubbles may have a wide range of relatively large cross-sectional dimensions, such as the churned gas bubbles 314. In some embodiments, the gas -containing bubbles may have a relatively small cross-sectional dimension, such as gas -containing bubbles 315. Other gascontaining bubble morphologies are also possible.

[0139] In some embodiments, the formation of gas-containing bubbles having a relatively small cross-sectional dimension (e.g., gas-containing bubbles 315) may be advantageous when compared to other possible configurations of gas (e.g., gaseous hydrogen) within the liquid water. For example, the formation of bubbles (e.g., bubbles having a relatively small cross- sectional dimension) may be advantageous compared to the development of slugs of gas (e.g., slugs 312) within the mixture, the development of an annular region of gas flow (e.g., annular formation 313) surrounded by a flow of liquid water (e.g., liquid water 302), and / or the development of a churned flow of gas-containing bubbles having a wide range of relatively large cross-sectional dimensions (e.g., churned gas bubbles 314) within the liquid water.

[0140] In some embodiments, the formation of bubbles may be particularly advantageous in that it can aid in the prevention of large pockets of gas becoming pinned to a solid surface (e.g., within a conduit), such as the pinned gas-containing bubbles 311 as shown in FIG. 3. A gas pocket may become pinned to a solid surface when the gas pocket adheres to the surface such that a three-phase contact line is formed between the gas pocket, solid surface, and a surrounding liquid (e.g., liquid water). In some embodiments (e.g., when the liquid is oversaturated with the gas), the pinned gas pockets may adhere strongly to the solid surface and become difficult to dislodge. The risk of pinned gas pocket development may be especially high in conduits and / or fractures as described herein. For example, a fracture within a solid domain (e.g., a subsurface fracture in a geologic formation) may have a rough surface and / or follow a tortuous path, which may make the fracture particularly susceptible to the development of pinned gas pockets. In some embodiments, in addition to aiding in the formation and / or stabilization of gascontaining bubbles, one or more additives (e.g., surfactants) may advantageously prevent adhesion of the bubbles to a solid surface (e.g., preventing the development of pinned bubbles, like the pinned pockets of gas described above). For example, in some embodiments, the addition of one or more additives, as described elsewhere herein, may result in the gas within gas-containing bubbles having a spreading coefficient on the surface of the solid domain which is negative (e.g., Sgs^ < 0), where the spreading coefficient is defined as: where asiis the solid-liquid interfacial energy, asgis the solid-gas interfacial energy, and o^is the gas-liquid interfacial energy. The interfacial energies depend on the composition and / or morphology of the liquid, gas, and solid phases. For example, in some embodiments in which the solid domain comprises rock (e.g., in embodiments in which the solid domain is a subsurface geological formation), the surface of the solid domain may have a roughness, which may affect the surface energy of the solid domain and thereby the solid-gas and / or solid-liquid interfacial energy.

[0141] In some embodiments, the spreading coefficient of the gas on the surface of the solid domain being negative may indicate that the gas is unlikely to accumulate at the surface of the solid (e.g., reducing the risk of pinned gas pockets developing). In such embodiments, the mixture is easily flowable through the conduit, for example without the formation of disadvantageous morphologies of the gas-containing bubbles (e.g., pinned gas pockets, annular formations, etc.).

[0142] In some embodiments, it may be advantageous for a portion the gas -containing bubbles in the mixture to have a negative spreading coefficient. For example, in some embodiments, a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the bubbles may have a negative spreading coefficient. In some embodiments, all of the gas -containing bubbles in the mixture have a negative spreading coefficient. In some embodiments, the gas -containing bubbles have the negative spreading coefficients described herein (to any of the extents described herein) during the entirety of their existence within the solid domain. In some embodiments, the gas -containing bubbles have the negative spreading coefficients described herein (to any of the extents described herein) during the entirety of their existence within the removal conduit. In some embodiments, the gascontaining bubbles have the negative spreading coefficients described herein (to any of the extents described herein) during the entirety of their existence within the solid domain and the removal conduit.

[0143] In some embodiments, it may be advantageous for a large portion of the total bubble volume in the mixture to be made up of bubbles having a negative spreading coefficient. The “total bubble volume” as used herein refers to the total additive volume of all of the bubbles of the mixture. For example, in some embodiments, it may be advantageous for a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the total bubble volume in the mixture to be made up of bubbles having a negative spreading coefficient. In some embodiments, the entire total bubble volume of the mixture is made up of bubbles having a negative spreading coefficient.

[0144] An interfacial modifier and / or rheology modifier within the mixture may modify one or more properties of one or more components of the mixture in one or more advantageous ways. For example, in some embodiments, the interfacial modifier and / or rheology modifier (e.g., surfactant) as described above may promote the formation of gas-containing bubbles (e.g., stable gas-containing bubbles having advantageous morphologies) within the mixture, as described above. In some embodiments, the interfacial modifier and / or rheology modifier may promote wetting of the liquid of the mixture (e.g., liquid water comprising dissolved hydrogen and the interfacial modifier and / or rheology modifier) to a solid surface. In some embodiments in which the mixture is a multiphase gas-liquid mixture (e.g., when the mixture comprises liquid water and gas -containing bubbles), the interfacial modifier and / or rheology modifier may promote wetting of the liquid phase of the multiphase gas-liquid mixture to one or more surfaces. Wetting of a liquid to solid surfaces is described in detail below. In some embodiments, the interfacial modifier and / or rheology modifier may discourage the adherence of a gas to one or more surface s (e.g., the gas -containing bubbles). In some embodiments, the interfacial modifier and / or rheology modifier within the mixture may result in a solid surface in contact with the mixture becoming gasphobic. Gasphobic surfaces are described in detail below. For example, in some embodiments, the interfacial modifier and / or rheology modifier within the mixture may encourage wetting of the liquid of the mixture (e.g., a liquid mixture and / or the liquid phase of the multi-phase gas-liquid mixture) to a solid surface and / or discourage the adherence of a gas (e.g., gas-containing bubbles) to the solid surface. In some embodiments, the solid surface may be a surface of a solid domain and / or a conduit as described above. As such, the solid surface may comprise any of the materials described which may make up some or all of a solid domain and / or conduit (e.g., rock, concrete, steel, etc.). In some embodiments, the surface may be a textured surface. In some embodiments, a textured surface may have some surface roughness.

[0145] In some embodiments, it may be advantageous for the gas-containing bubbles in the mixture to have relatively small maximum cross-sectional dimensions. In some embodiments, the gas -containing bubbles may have relatively small maximum cross-sectional dimensions relative to the minimum internal cross-sectional dimensions of the conduit at the location of the bubble. For example, in some embodiments, a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the bubbles may have a maximum cross-sectional dimension that is greater than or equal to 0.01 times, greater than or equal to 0.05 times, greater than or equal to 0.1 times, greater than or equal to 0.2 times, greater than or equal to 0.3 times, greater than or equal to 0.4 times, greater than or equal to 0.5 times, or greater than or equal to 0.6 times the minimum internal cross-sectional dimension of the conduit at the location of the bubble. In some embodiments, a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the bubbles may have a maximum cross-sectional dimension that is less than or equal to 0.9 times, less than or equal to 0.8 times, less than or equal to 0.7 times, less than or equal to 0.6 times, less than or equal to 0.5 times, less than or equal to 0.4 times, less than or equal to 0.3 times, less than or equal to 0.2 times, less than or equal to 0.1 times, or less than or equal to 0.05 times the minimum internal cross-sectional dimension of the conduit. To illustrate, if a conduit has a minimum internal cross-sectional dimension of 4 centimeters at the location of the bubble, and a bubble at that location within the conduit has a maximum cross-sectional dimension of 2 centimeters, then the bubble would be said to have a maximum cross-sectional dimension that is 0.5 times the minimum internal cross-sectional dimension of the conduit at the location of the bubble.

[0146] In some embodiments, it may be advantageous for a portion of the total bubble volume in the mixture to be made up of bubbles having relatively small maximum cross-sectional dimensions (e.g., relative to the minimum internal cross-sectional dimensions of the conduit at the location of the bubble at the location of the bubble). For example, in some embodiments, it may be advantageous for a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the total bubble volume to be made up of bubbles having a cross sectional dimension that is greater than or equal to 0.01 times, greater than or equal to 0.05 times, greater than or equal to 0.1 times, greater than or equal to 0.2 times, greater than or equal to 0.3 times, greater than or equal to 0.4 times, greater than or equal to 0.5 times, or greater than or equal to 0.6 times the minimum internal cross-sectional dimension of the conduit. In some embodiments, a majority (e.g., at least 50%, at least 60%, at least 70%, at least 80%, at least 90%, at least 95%, at least 99%, or more) of the total bubble volume is made up of bubbles having a cross sectional dimension that is less than or equal to 0.7 times, less than or equal to 0.6 times, less than or equal to 0.5 times, less than or equal to 0.4 times, less than or equal to 0.3 times, less than or equal to 0.2 times, less than or equal to 0.1 times, or less than or equal to 0.05 times the minimum internal cross-sectional dimension of the conduit at the location of the bubble.

[0147] In some embodiments, a method for generating a mixture (e.g., a mixture of hydrogen and liquid water) is provided.

[0148] In some embodiments, the method comprises contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen. The source of the mineral comprising a material capable of reacting with water to produce hydrogen (e.g., ferrous iron) may be any of the sources described above. For example, in some embodiments, the source may comprise ultramafic rock, mafic rock, and / or sedimentary rock comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen. In some embodiments, the contacting is done such that at least a portion of the water reacts with the material (e.g., ferrous iron) to form hydrogen, for example via a chemical reaction. The chemical reaction may be any chemical reaction between the material (e.g., ferrous iron) and water as described above (e.g., a serpentinization reaction).

[0149] In some embodiments, the water may comprise an additive (e.g., an interfacial modifier and / or rheology modifier), such that the method comprises contacting the water and an interfacial modifier and / or rheology modifier with the source of material (e.g., ferrous iron). The interfacial modifier and / or rheology modifier may comprise any of the interfacial modifiers and / or rheology modifiers described above (e.g., nanoparticles, viscosifiers, polymer additives, and / or surfactants of any of the types described above).

[0150] In some embodiments, the interfacial modifier and / or rheology modifier is configured to facilitate the formation of bubbles comprising hydrogen gas and / or prevent coalescence of bubbles comprising hydrogen gas, as described above.

[0151] In some embodiments, a method as disclosed herein comprises forming hydrogen. In some embodiments, the hydrogen is formed via a chemical reaction (e.g., via any suitable chemical reaction with a source of a mineral comprising a material capable of reacting with water to produce hydrogen as described above). For example, in some embodiments, the hydrogen is generated by a serpentinization reaction of the water with the source of ferrous iron (e.g., in embodiments in which the source of ferrous iron comprises olivine and / or one or more other minerals capable of undergoing a serpentinization reaction).

[0152] The mixture may comprise hydrogen in any of a variety of suitable amounts. For example, in some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5, greater than or equal to 5xl0'5, greater than or equal to 10'4, greater than or equal to 5xl0'4, greater than or equal to 10'3, greater than or equal to 5xl0'3, greater than or equal to 10'2, or greater than or equal to 5xl0'2. In some embodiments, the mixture comprises hydrogen in a mole fraction of less than or equal to 10’1, less than or equal to 5xl0'2, less than or equal to 10'2, less than or equal to 5xl0'3, less than or equal to 10'3, less than or equal to 5xl0'4, less than or equal to 10'4, or less than or equal to 5xlO'5Combinations of these ranges are also possible (e.g., in some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5and less than or equal to 10’1, greater than or equal to 5xl0'5and less than or equal to 5xl0'2, or greater than or equal to 10'4and less than or equal to 10'2). Other ranges are also possible.

[0153] In some embodiments, the mixture may comprise hydrogen in one or more phases. For example, in some embodiments, the hydrogen may be dissolved in the liquid water. For example, in some embodiments, method may be performed at relatively high pressures, such that the mixture may comprise liquid water and hydrogen at high pressures. For example, in some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high pressures that the solubility of the hydrogen in the liquid water is significantly higher than the solubility of hydrogen in liquid water at ambient conditions (e.g., atmospheric pressure). For example, in some embodiments, the mixture may comprise liquid water and hydrogen at sufficiently high temperatures that the solubility of hydrogen in the liquid water is higher than the solubility of hydrogen in liquid water at ambient conditions by a factor of greater than or equal to 1.5 and less than or equal to a factor of 4,000, as described above.

[0154] In some embodiments, the mixture comprises hydrogen which is gaseous hydrogen. For example, in some embodiments, the mixture comprises a multiphase gas-liquid mixture comprising liquid water and gaseous hydrogen. In some such embodiments, the gaseous hydrogen may make up any suitable amount of the mixture. In some embodiments, the gaseous hydrogen makes up greater than or equal to 5 vol%, greater than or equal to 7.5 vol%, greater than or equal to 10 vol%, greater than or equal to 25 vol%, greater than or equal to 50 vol%, greater than or equal to 75 vol%, greater than or equal to 90 vol%, or greater than or equal to 95 vol% of the mixture. In some embodiments, the gaseous hydrogen makes up less than or equal to 99 vol%, less than or equal to 95 vol%, less than or equal to 90 vol%, less than or equal to 75 vol%, less than or equal to 50 vol%, less than or equal to 25 vol%, less than or equal to 10 vol%, or less than or equal to 7.5 vol% of the mixture. Combinations of these ranges are also possible (e.g., the gaseous hydrogen may make up greater than or equal to 5 vol% and less than or equal to 99 vol%, greater than or equal to 10 vol% and less than or equal to 95 vol%, or greater than or equal to 25 vol% and less than or equal to 90 vol% of the mixture). Other ranges are also possible. In some embodiments, the mixture comprises greater than or equal to 50 vol% of a gas (e.g., gaseous hydrogen) and is in the form of a foam.

[0155] In some embodiments, a system for recovering a gas from a mixture is described. In some embodiments, a system as described herein may be configured to, for example, remove a gas from gas-containing bubbles within a multiphase gas-liquid mixture. In some embodiments, such a system may be configured to remove hydrogen gas from gas -containing bubbles in a multiphase gas-liquid mixture comprising gaseous hydrogen and liquid water. Such a multiphase gas-liquid mixture is described in detail elsewhere herein (e.g., a multiphase gasliquid mixtures comprising liquid water and gas-containing bubbles comprising hydrogen gas). In some embodiments, the multiphase gas-liquid mixture may comprise a multiphase mixture generated according to a method of generating a multiphase gas-liquid mixture as described elsewhere herein.

[0156] In some embodiments, the system comprises a concentrator. In some embodiments, the concentrator is configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture comprising gas within the gas -containing bubbles and a liquid. For example, in some embodiments, if a multiphase gas-liquid mixture comprises gas -containing bubbles which are relatively evenly dispersed through the mixture, the concentrator may be configured to stratify the mixture such that the majority of the gas -containing bubbles are concentrated in one part of the mixture.

[0157] In some embodiments, the concentrator may be part of a system comprising the concentrator and one or more components of another system as described elsewhere herein. For example, a conduit of a system described above (e.g., any system described above that comprises a conduit containing a mixture of liquid water and hydrogen) may be fluidically connected to the concentrator (e.g., as an input to the concentrator). In some embodiments, a removal conduit and / or a conduit that is both an injection conduit and a removal conduit of any system described elsewhere herein comprising such a conduit is fluidically connected to the concentrator (e.g., as an input to the concentrator). In some embodiments, concentrator may be configured to concentrate gas -containing bubbles from a multiphase gas-liquid mixture contained and / or generated within a system described elsewhere herein. For example, in some embodiments, the multiphase gas-liquid mixture may comprise liquid water from an aqueous fluid (e.g., the aqueous fluid of any system as described elsewhere herein). In some embodiments, the multiphase gas-liquid mixture may comprise hydrogen which is generated by a chemical reaction between a mineral comprising a material capable of reacting with water to form hydrogen and liquid water (e.g., from an aqueous fluid) within a system comprising such a mineral (e.g., a system comprising a solid domain comprising such a mineral), as described elsewhere herein.

[0158] A concentrator as described herein may comprise any of a variety of suitable concentrators. Generally, the concentrator will receive a multi-phase mixture comprises a gas (e.g., in the form of gas bubbles) and liquid and produce a liquid rich region and a gas rich region. In some embodiments, the concentrator comprises a cyclonic concentrator (e.g., a gas cyclone), such as the gas cyclone 401 shown in FIGS. 4A and 4B. In some embodiments, the cyclonic concentrator may comprise a container (e.g., a cylindrical and / or conical container). In some embodiments, the cyclonic concentrator may be configured to generate a high-speed rotational flow within the container such that a density stratification is established. For example, in some embodiments, the cyclonic concentrator may be configured to stratify a multiphase gasliquid mixture comprising gas -containing bubbles such that the bubbles are concentrated near the center of the cyclonic separator (e.g., toward the center of a rotational flow established within the cyclonic separator) to form a concentrated bubble stream. In some such embodiments, the concentrated bubble stream may be subjected to further processing (e.g., to remove the gas from within the gas-containing bubbles of the concentrated bubble stream). In some embodiments, a separator (e.g., a cyclonic separator 401 as shown in FIGS. 4A and 4B) may comprise an inlet 411. In some embodiments, the inlet 411 may be configured to receive an input 412. In some embodiments, the input 412 may comprise a multiphase gasliquid mixture comprising liquid 431 and gas-containing bubbles 432. In some embodiments, the cyclonic separator 401 may be configured to concentrate the gas-containing bubbles 432 and produce an output 414 which primarily contains the liquid 431. In some embodiments, the output 414 is removed from the cyclonic separator via an outlet 413. In some embodiments, the multiphase gas-liquid mixture and / or the liquid are flowed through the cyclonic gas separator by a pump 421 that is fluidically connected to the outlet 413.

[0159] In some embodiments, a system as described herein comprises a surface fluidically connected to the concentrator (e.g., the cyclonic concentrator). In some embodiments, as described above, the surface may be fluidically connected to a concentrator that is part of a system comprising the concentrator, the surface fluidically connected to the concentrator, and another system described elsewhere herein (e.g., a system in which a conduit containing a mixture of liquid water and hydrogen, as described elsewhere herein, is fluidically connected to the concentrator). In some embodiments, the surface may be fluidically connected to the concentrator via a conduit. In some embodiments, the surface may make up one or more components (e.g., walls) of the concentrator, or be otherwise disposed within and / or adjacent the concentrator. For example, as shown in FIG. 4A, a surface 504 may be disposed within the concentrator (e.g., such that the at least a portion of the surface 504 may be exposed to the multiphase gas-liquid mixture within the concentrator). In some embodiments, as shown in FIG. 4B, a surface 704 may make up at least a portion of a wall of the concentrator.

[0160] In some embodiments, as shown in the schematics of FIGS. 4A-4B, the surface may comprise a planar surface. However, the surface could have any of a variety of suitable configurations. For example, in some embodiments, the surface may comprise a curved surface. In some embodiments, the surface may be part of a filtration unit which is fluidically connected to the concentrator (e.g., the surface may be a spiral-wound surface in a spiral filtration unit). Other configurations of the surface are also possible.

[0161] In some embodiments, as described below, the surface (e.g., a surface 504 as in FIG. 4A or a surface 704 as in FIG. 4B) comprises a plurality of microscale and / or nanoscale features. In some such embodiments, the plurality of microscale and / or nanoscale features may be configured in a variety of advantageous ways. For example, in some embodiments, the plurality of microscale and / or nanoscale features may be configured to allow for the selective removal of a gas from a multiphase gas-liquid mixture by, for example, allowing for the selective removal of the gas from within gas-containing bubbles of the multiphase gas-liquid mixture relative to the liquid.

[0162] In some embodiments, surfaces having certain properties with respect to the gas phase and / or liquid phase of a multiphase gas-liquid mixture (e.g., properties that allow for the selective removal of gas from the multiphase gas-liquid mixture) may be advantageously included in the system. According to certain embodiments, surfaces having certain properties with respect to the gas phase of a multiphase gas-liquid mixture may be used. For example, in some embodiments, the surface may be a gasphilic surface. As used herein, a “gasphilic surface” is a surface that has a strong affinity for a gas (e.g., hydrogen). In some embodiments, a gasphilic surface may increase the gas-liquid interfacial area of a gas -containing bubble in a multiphase gas-liquid mixture (e.g., when the gas-containing bubble is in contact with the gasphilic surface). In some embodiments, a gasphilic surface may be configured to such that a gas bubble in contact with the gasphilic surface has a low (e.g., less than 90 °) gas contact angle with the surface. Additional details about the properties of gasphilic surfaces are included below.

[0163] According to certain embodiments, surfaces having certain wetting properties with respect to the liquid phase of a multiphase gas-liquid mixture can be used to transport gas out of gas-containing bubbles within the multiphase gas-liquid mixture and redirect the gas in order to reduce and / or eliminate the volume of bubbles present within the multiphase gas-liquid mixture and / or at the interface of a liquid and another fluid (e.g., gas and / or liquid). In some embodiments, the surface is not wetted by the liquid phase of the multiphase gas-liquid mixture. The surface can, in certain embodiments, interact with the gas within the gas -containing bubbles of the multiphase gas-liquid mixture such that the gas within the gas -containing bubbles is transported out of the bubbles and along and / or through the surface to a gaseous environment separate from the multiphase gas-liquid mixture. In some embodiments, the gas within the gascontaining bubbles is transported out of the bubbles and along and / or through the surface to a gaseous environment separate from the multiphase gas-liquid mixture in a manner such that bubbles do not accumulate to form a large degree of (or any) foam. In certain cases, the surface can interact with gas -containing bubbles of an already-formed foam to separate the gas from the foam and transport the gas to a gaseous environment separate from the multiphase gas-liquid mixture, thereby reducing the volume of foam that is present. In some embodiments, a surface having such wetting properties with respect to the liquid phase of the multiphase gas-liquid mixture may be a gasphilic surface. In one set of embodiments, the surface includes a gaseous fluidic pathway via which the gas from within the gas-containing bubbles is removed from the gas-containing bubbles and transported out of the multiphase gas-liquid mixture (e.g., the foam). The gaseous fluidic pathway may be provided, according to certain embodiments, by arranging features (e.g., milliscale, microscale, and / or nanoscale features) on the surface such that gas is retained between the feature (e.g., when the features comprise protrusions, as described below) and / or within the features (e.g., when the features comprise pores, as described below) when the surface is exposed to a multiphase gas-liquid mixture (e.g., a foam) comprising gas -containing bubbles. The gas retained between and / or within the features can form at least a portion of a gaseous fluidic pathway that connects portions of the surface which are exposed to the multiphase gasliquid mixture to a gaseous environment outside the multiphase gas liquid mixture (e.g., the foam). In some such embodiments, when gas -containing bubbles within the multiphase gasliquid mixture are exposed to the surface, the gas-containing bubbles interact with the gas between and / or within the features of the surface such that the gas within the gas -containing bubbles is removed from the gas -containing bubbles and incorporated into the gaseous fluidic pathway on the surface. In some such cases, the gas is transported along the surface, out of the gas-containing bubbles (e.g., gas -containing bubbles within the multiphase gas-liquid mixture), and into a gaseous environment outside the gas-containing bubbles without forming a new bubble (e.g., at the interface of a multiphase gas-liquid mixture and the gaseous environment outside of the multiphase gas-liquid mixture and / or anywhere else along the pathway out of the mixture). In some embodiments in which the gas -containing bubbles comprise hydrogen gas, the gaseous environment outside the gas-containing bubbles may be a hydrogen storage location, as described above.

[0164] In some embodiments, the bubbles adhere to the surface. In some such embodiments, features of the surface (e.g., nanoscale, microscale, and / or milliscale features) break the gasliquid interface of the bubbles. This can result in the exposure of the gas within the bubble to gas that is associated with the surface (e.g., in a plastron layer or trapped within pores of the surface). In some such embodiments, the gas within the bubble merges with the gas associated with the surface such that the gas within the bubble is separated from the liquid of the gas-liquid mixture, which can result in the formation of a gas stream.

[0165] According to certain embodiments, when the surface is exposed to the multiphase gasliquid mixture, the surface can be used to direct the gas from within the gas-containing bubbles from the bulk of the multiphase gas-liquid mixture to the gaseous environment outside of the multiphase gas-liquid mixture. In some embodiments, the surface is exposed to the multiphase gas-liquid mixture in a configuration such that a continuous gaseous pathway is established from the surface to the gaseous environment outside the multiphase gas-liquid mixture. This can be achieved, for example, by exposing the surface to the mixture such that gas between and / or within features (e.g., milliscale, microscale, and / or nanoscale features) of the surface forms a gaseous fluidic pathway from a portion of the surface which is exposed to the multiphase gasliquid mixture to a portion of the surface which is not exposed to the multiphase gas-liquid mixture.

[0166] For example, as shown in FIG. 4A, surface 504 is exposed to multiphase gas-liquid mixture 451 such that gas 512 is trapped between features 513. Gas 512 trapped between features 513 can establish a continuous gaseous pathway from the at least a portion of surface 504 to gaseous environment 591. The continuous gaseous pathway established by features 513 can be seen more clearly, for example, by referring to FIGS. 5A-5C. FIG. 5A is a cross- sectional schematic diagram of a surface portion comprising features 513, which can be used, according to certain embodiments, to remove a gas from a multiphase gas-liquid mixture. FIG. 5B is a perspective view schematic diagram of the surface portion shown in FIG. 5A, and FIG. 5C is a top view schematic diagram of the surface portion shown in FIGS. 5A-5B. The surface portions shown in FIGS. 5A-5C can, according to certain embodiments, be parts of the surfaces illustrated in FIGS. 4A. As shown in FIG 5B-5C, continuous gaseous fluidic pathway 522 is established between features 513. Continuous gaseous fluidic pathway 522 can be arranged, according to certain embodiments, such that one end of the pathway is exposed to multiphase gas-liquid mixture 451 and another end of the pathway is contained within gaseous environment 591.

[0167] As noted above, in some embodiments, the surface that is used to remove gas from gascontaining bubbles within a multiphase gas-liquid mixture (e.g., a foam) comprises a plurality of features. The features can include, according to certain embodiments, milliscale features, microscale features, and / or nanoscale features. In some embodiments, the features comprise protrusions. According to certain embodiments, the features may comprise ridges, pores, spikes and / or posts. Examples of suitable features that can be used to remove gas from gas -containing bubbles within a multiphase gas-liquid mixture (e.g., to reduce and / or prevent foam formation) are shown in FIG 5A-5C. In certain embodiments, the features may be dispersed on the surface in a random (e.g., fractal) or patterned manner.

[0168] According to certain embodiments, a portion of the surface which is exposed to the multiphase gas-liquid mixture may comprise features which thus are exposed to the multiphase gas-liquid mixture. For example, as shown in FIG. 4A, the surface 504 is exposed to multiphase gas-liquid mixture 451, and the surface comprises features 513 which are exposed to the multiphase gas-liquid mixture 451.

[0169] As noted above, according to certain embodiments, the gas positioned between and / or within the features defines a gaseous fluidic pathway from within the multiphase gas-liquid mixture to a gaseous environment outside the multiphase gas-liquid mixture. For example, in some cases, gas positioned between and / or within the features prior to the exposing of the surface to the multiphase gas-liquid mixture remains trapped between and / or within the features after the exposing. This can result in the formation of a continuous gaseous fluidic pathway from a portion of the surface that is exposed to the multiphase gas liquid mixture to a portion of the surface that is not exposed to the multiphase gas-liquid mixture. The trapped gas positioned between and / or within the features that forms a continuous gaseous fluidic pathway between and / or within the features adjacent to the surface is also referred to herein as a “plastron layer.”

[0170] In some embodiments, one or more features of the surface (e.g., the gasphilic surface, as described above) may break a liquid / gas interface of a gas-containing bubble once the gascontaining bubble has attached to the surface (e.g., to the feature). For example, referring to FIG. 4B, surface 704 a breaks liquid / gas interface of the bubble 514 as the bubble 514 becomes attached to surface 704 due to the milliscale, microscale, and / or nanoscale features of surface 704, according to some embodiments. Without wishing to be bound by any particular theory, it is believed that the liquid / gas interface of the gas-containing bubbles may be breached due to the non- wetting nature of surface 704 with respect to the liquid in which the gas-containing bubbles are contained (e.g., the liquid of a multiphase gas-liquid mixture).

[0171] According to certain embodiments, once the liquid / gas interface of the bubble is broken, the gas from within the gas -containing bubbles merges with the gas positioned adjacent the surface (e.g., between and / or within the features of the surface).

[0172] In some embodiments, gas positioned between and / or within the features of the surface can interact with the gas within the gas -containing bubbles of the multiphase gas-liquid mixture after the gas -containing bubbles have been transported proximate the exposed surface. For example, in the system as shown in FIG. 4A, gas from within the gas-containing bubbles 432 may completely merge with gas 512 between the features 513, such that there is no longer a bubble that is distinguishable from the other pockets of gas 512 trapped between features 513. In the system as shown in FIG. 4B, gas within bubble 514 attached to surface 704 of may merge with gas positioned within pores of the surface 704.

[0173] According to certain embodiments, gas from within the gas -containing bubbles (e.g., the gas-containing bubbles of the multiphase gas-liquid mixture) is transported along the surface, such as surface 504 as shown in FIG. 4A or surface 704 as shown in FIG. 4B, (e.g., via the gaseous fluidic pathway defined between and / or within features of the surface) until the gas from within the gas -containing bubbles enters a gaseous environment separate from the multiphase gas-liquid mixture.

[0174] Gas can also be removed from the multiphase gas-liquid mixture using a porous membrane. For example, in some embodiments, the bubbles adhere to a surface of the porous membrane. Adherence to the porous membrane can be enhanced, for example, by introducing nanoscale, microscale, and / or milliscale features onto surfaces of the porous membrane, which can cause bubbles to adhere to the membrane surface. In some such embodiments, features on the surface of the porous membrane break the gas-liquid interface of the bubbles. According to certain embodiments, once the liquid / gas interface of the bubble is broken, the gas from within the bubbles merges with the gas positioned within the pores and / or within a plastron layer associated with the surface of the porous membrane. For example, in some embodiments, the gas from within the gas -containing bubbles merges with gas positioned between the features of the surface. In some such embodiments, the gas from within the bubbles merges with a plastron layer associated with the surface. This can result in the separation of the gas from the bubbles from the liquid of the gas-liquid mixture, which can result in the formation of a gas stream. For example, referring to FIG. 4B, gas within bubbles 432 can be transported proximate to surface 704. In some such embodiments, bubbles 432 can stick to surface 704 and subsequently be ruptured. Subsequently, gas from within bubbles 432 can be transported through the pores of surface 704 and eventually merge with gas stream 591.

[0175] In some embodiments, the gas from within the bubbles is further transported through the surface (e.g., through a pore of the surface) until the gas from within the bubbles enters a gaseous environment separate from the multiphase gas-liquid mixture. For example, in FIG. 4B, gas from bubbles 432 can be transported through surface 704 via pores and be merged into gas stream 591. In some embodiments, the transport of the gas to the environment separate from the multiphase gas-liquid mixture occurs because the movement of the gas previously contained within the gas-containing bubble is no longer restricted by the wall of the bubble once the wall has been ruptured.

[0176] According to certain embodiments, the gas from within the bubbles merges with gas positioned adjacent the surface. For example, in some embodiments, the gas from within bubbles merges with gas positioned between the features that define the surface. In some such embodiments, the gas from within the bubbles merges with a plastron layer associated with the surface. In some embodiments, the gas from within the bubbles merges with the gas positioned between the features such that the gas from within the bubbles becomes part of the gaseous fluidic pathway (i.e., plastron layer).

[0177] In some embodiments, merging of a gas -containing bubble with the gaseous fluidic pathway can result in removal of the gas -containing bubble from the multiphase gas-liquid mixture.

[0178] According to certain embodiments, gas from within bubbles (e.g., gas-containing bubbles within a multiphase gas-liquid mixture) is transported along the surface (e.g., via the gaseous fluidic pathway defined between and / or within features) until the gas from within the gascontaining bubbles enters a gaseous environment separate from the liquid. For example, as noted above, when a gas-containing bubble impacts the plastron layer adjacent the surface, the gas-containing bubble can rupture and release the gas it contains to the plastron layer. In some embodiments, after the gas has been released to the plastron layer, the gas travels along the gaseous fluidic pathway until it is released to the environment outside the multiphase gas-liquid mixture. In some embodiments, the transport of the gas to the surrounding environment occurs because the movement of the gas previously contained within the gas-containing bubble is no longer restricted by the wall of the bubble once the wall has been ruptured.

[0179] According to certain embodiments, upon use of the systems and / or methods described herein for transporting gas out of gas-containing bubbles, the volume of the gas in the multiphase gas-liquid mixture (e.g., the foam) is reduced and / or the formation of a foam is prevented. According to certain embodiments, gas from within multiple bubbles is transported along the plastron layer such that accumulation of the bubbles into a foam layer is reduced or prevented. According to certain embodiments, if bubbles from the multiphase gas-liquid mixture are caught by the surface, then a foam layer in the multiphase gas-liquid mixture can be reduced and / or prevented. According to certain embodiments, as the gas from within multiple gas-containing bubbles (e.g., submerged bubbles) continuously travels along the gaseous fluidic pathway to the gaseous environment outside of the multiphase gas-liquid mixture, bubbles at the interface (e.g., layer bubbles) and / or a layer of bubbles (e.g., foam) will be reduced and / or prevented.

[0180] Certain embodiments relate to systems and methods for transporting gas out of gascontaining bubbles and reducing the volume of a foam that has already been formed. The systems and methods for reducing the volume of a foam can be performed in addition to or in place of methods for transporting gas out of bubbles.

[0181] In certain embodiments, gas-containing bubbles are transported from a source of the gascontaining bubbles (e.g., a chemical reaction and / or exsolution of the gas-containing bubbles), through the multiphase gas-liquid mixture, and to an interface of the multiphase gas-liquid mixture and a gaseous environment outside the liquid while the surface is not exposed to the multiphase gas-liquid mixture. This can generate, according to some embodiments, a layer of foam at the interface of the multiphase gas-liquid mixture and the gaseous environment outside of the liquid. In certain embodiments, the surface is exposed to this foam. The gas-containing bubble walls can, according to certain embodiments, contain a liquid, and the surface can be non-wetting with respect to the liquid, as described above.

[0182] According to certain embodiments, gas from within the bubbles is transported out of the gas-containing bubbles (e.g., along the surface and / or through the pores) and the volume of the foam is reduced. In some such embodiments, the gas -containing bubbles of the foam interact with the surface (e.g., the features of the surface) such that the walls of the gas -containing bubbles are breached (e.g., in a manner similar to that described above). In some embodiments, after the walls of the gas-containing bubble are breached, gas from within the gas -containing bubbles merges with the gas positioned between the features of the surface. In certain embodiments, the gas from within the gas-containing bubbles of the multiphase gas-liquid mixture is transported along (e.g., via a continuous gaseous pathway formed by the gas trapped between the features, such as the plastron layer) and / or through (e.g., through the milliscale, microscale, and / or nanoscale pores) the surface until the gas from within the gas-containing bubbles of the multiphase gas-liquid mixture enters a gaseous environment separate from the foam.

[0183] In some embodiments, certain of the surfaces described herein can be designed to have certain wetting properties that can be useful in reducing and / or eliminating an amount of gas within a multiphase gas-liquid mixture and / or a foam (foam that has already formed and / or foam that has not yet formed). According to some embodiments, the surface is non- wetting with respect to the liquid of the multiphase gas-liquid mixture. For example, in FIG. 5A, surface 504 is non- wetting with respect to liquid 431 of multiphase gas-liquid mixture 451, according to certain embodiments. In some embodiments, the surface is non- wetting with respect to the liquid that defines the wall of a foam.

[0184] As used herein, a surface is considered to be non- wetting with respect to a liquid when, if a droplet of the liquid is positioned on the surface in a gaseous environment at the temperature and pressure at which the liquid and surface are being used, the droplet forms a contact angle, as measured through the bulk of the droplet, of greater than 90°. FIG. 8A shows an exemplary cross-sectional schematic diagram illustrating the interaction of liquid droplet 804 with surface 812 of substrate 802 when the surface is non-wetting with respect to the liquid. As shown in FIG. 8A, contact angle 806 is measured between (1) line 810 drawn tangent to the exterior surface of droplet 804 at point of contact 808 with substrate surface 812 and (2) substrate surface 812. Contact angle 806 is measured through the bulk of droplet 804. In FIG. 8A, contact angle 806 is greater than 90° (e.g., about 120°). This indicates that substrate surface 812 is nonwetting with respect to droplet 804 of the liquid. Conversely, FIG. 8B shows an exemplary cross-sectional schematic diagram illustrating the interaction of a liquid droplet with a surface when the surface is wetting with respect to the liquid. Contact angle 806 between droplet 804 of the liquid on substrate surface 812 is less than 90° (e.g., about 50° in FIG. 8B), indicating that substrate surface 812 is non- wetting with respect to droplet 804 of the liquid.

[0185] As described above, the surface may be a gasphilic surface (e.g., a surface that may increase the gas-liquid interfacial area of a gas-containing bubble in a multiphase gas-liquid mixture when the gas-containing bubble is in contact with the gasphilic surface). As used herein, a surface is considered to be gasphilic when a gas-containing bubble is positioned on the surface in a liquid environment at the temperature and pressure at which the liquid and surface are being used, and the gas-containing bubble forms a gas contact angle, as measured through the bulk of the gas -containing bubble, of less than 90°. For example, FIG. 8C shows an exemplary cross-sectional schematic diagram illustrating the interaction of gas -containing bubble 854 with surface 862 of substrate 852 when the surface is not gasphilic (i.e., when the surface is gasphobic). As shown in FIG. 8C, contact angle 856 is measured between (1) line 860 drawn tangent to the exterior surface of gas-containing bubble 854 at point of contact 858 with substrate surface 862 and (2) substrate surface 862. Gas contact angle 856 is measured through the bulk of gas-containing bubble 854. In FIG. 8C, gas contact angle 856 is greater than 90° (e.g., about 120°). This indicates that substrate surface 862 is not gasphilic (i.e., is gasphobic) with respect to gas-containing bubble 854. Conversely, FIG. 8D shows an exemplary cross- sectional schematic diagram illustrating the interaction of a gas-containing bubble with a surface when the surface is gasphilic. Gas contact angle 856 between gas-containing bubble 854 on surface 862 is less than 90° (e.g., about 50° in FIG. 8D), indicating that surface 852 is gasphilic with respect to gas-containing bubble 854 of the gas.

[0186] In some embodiments, a gasphilic surface may be configured to promote contact line pinning of a gas-containing bubble in contact with the surface. In some embodiments, contact line pinning of the bubble to the surface may allow for the evacuation of gas from the gascontaining bubble to result in a decreased radius of curvature of the bubble, which in some embodiments may promote a higher Laplace pressure of the bubble, leading to faster evacuation of gas from the gas -containing bubble. In some embodiments, the evacuation time T of gas from a gas-containing bubble in contact with a gasphilic surface is determined by a balance between capillary and inertial forces. The balance of capillary and inertial forces can be written as T ~ ( R3 / y)1 / / 2, where R is the radius of the bubble, p is the density of water and y is the surface tension. For gas-containing bubbles having approximately millimeter-scale cross- sectional dimensions, this yields an evacuation time of the order 1 ms. In some embodiments, the decreased radius of curvature promoted by contact line pinning may promote a decrease in the evacuation time.

[0187] According to certain embodiments, the surface is non- wetting with respect to a liquid and / or gasphilic with respect to a gas at a temperature of 25 °C and at a pressure of 1 atmosphere.

[0188] Non-limiting examples of non-wetting surfaces include surfaces with properties understood by those skilled in the art. According to certain embodiments, for example, surfaces that are superhydrophobic, superoleophobic, supermetallophobic, superomniphobic, hydrophobic, oleophobic, metallophobic, and / or omniphobic can be used.

[0189] According to certain embodiments, the contact angle between the surface and the liquid may be relatively large when the surface is non- wetting with respect to the liquid. For example, according to certain embodiments, the contact angle between the surface and the liquid, when the surface is non-wetting with respect to the liquid, is greater than 100°, greater than 105 °, greater than 110°, greater than 120°, greater than 130°, greater than 140°, greater than 150°, greater than 160°, or greater than 170°. In some embodiments, the contact angle between the liquid and the surface, when the surface is non-wetting with respect to the liquid, is less than 179°, less than 170°, less than 160°, less than 150°, less than 140°, less than 130°, less than 120°, less than 110°, or less than 100°. Combinations of these values are also possible (e.g., greater than 100° and less than 130°, or greater than 150° and less than 179°). The contact angle between the surface and the liquid can fall within any of these ranges, for example, when the droplet of the liquid and the surface are present at conditions at which the method is performed (e.g., during use). In some embodiments, the surface is configured such that a droplet of the liquid of the multiphase gas-liquid mixture forms a contact angle of greater than 100° when the droplet of the liquid of the multiphase gas-liquid mixture is present on the surface, or when the droplet of the liquid and the surface are present at conditions at which the method is performed. According to certain embodiments, the surface is configured such that a droplet of the liquid of the multiphase gas-liquid mixture forms a contact angle of greater than 120° when the droplet of the liquid of the multiphase gas-liquid mixture is present on the surface, or when the droplet of the liquid and the surface are present at conditions at which the method is performed. According to certain embodiments, the gas contact angle between the surface and the gas-containing bubble may be relatively small when the surface is gasphilic with respect to the gas. For example, according to certain embodiments, the gas contact angle between the surface and the gas-containing bubble, when the surface is gasphilic with respect to the gas, is greater than 0°, greater than 5°, greater than 10°, greater than 20°, greater than 30°, greater than 40°, greater than 50°, greater than 60°, greater than 70 °, greater than 80°, or greater than 85°. In some embodiments, the gas contact angle between the gas -containing bubble and the surface, when the surface is gasphilic with respect to the gas, is less than 89°, less than 80°, less than 70°, less than 60°, less than 50°, less than 40°, less than 30°, less than 20°, less than 10°, or less than 5°. Combinations of these values are also possible (e.g., the gas contact angle between the surface and the gas-containing bubble may be greater than 0° and less than 89°, or greater than 5° and less than 85°). The gas contact angle between the surface and the gas -containing bubble can fall within any of these ranges, for example, when the gas-containing bubble and the surface are present at conditions at which the method is performed (e.g., during use). In some embodiments, the surface is configured such that gas-containing bubble within a multiphase gasliquid mixture forms a gas contact angle of less than 89° when the gas-containing bubble of the multiphase gas-liquid mixture is present on the surface, or when the gas-containing bubble and the surface are present at conditions at which the method is performed. According to certain embodiments, the surface is configured such that a gas-containing bubble of the multiphase gasliquid mixture forms a gas contact angle of less than 60° when the gas-containing bubble of the multiphase gas-liquid mixture is present on the surface, or when the gas-containing bubble and the surface are present at conditions at which the method is performed.

[0190] As noted above, in some embodiments, the surface comprises a plurality of features (e.g., milliscale features, microscale features, and / or nanoscale features, such as protrusions). The features, in accordance with certain embodiments, may be introduced to the surface using a variety of suitable methods, including mechanical and / or chemical methods. For example, in some embodiments, the features can be introduced to the surface via lithography. In certain embodiments, the features can be introduced to the surface via self-assembly. In some embodiments, the features can be deposited onto a substrate. According to certain embodiments, the features can be etched into the substrate (e.g., using acid etching, base etching, and / or plasma etching). In certain embodiments, the features can be introduced to the surface via laser ablation. In some embodiments, the features can be sintered onto the substrate (e.g., via powder sintering). Certain embodiments comprise forming the features by inducing phase change and / or crystallization. For example, in some embodiments, features are formed when a material is melted and / or dissolved and when the material solidifies again (e.g., during cooling and / or precipitation, for example, after solvent has evaporated) it forms solid features (e.g., in the form of crystals). These solid features can serve as the features described elsewhere herein (e.g., milliscale, microscale, and / or nanoscale features).

[0191] As noted above, according to certain embodiments, gas is positioned between the features on the surface. According to certain embodiments, the features form a matrix of solid features spaced sufficiently close to stably contain gas therebetween or therewithin once the surface has been at least partially submerged into the bubble-containing liquid. For example, FIG. 6 shows a cross-sectional schematic diagram illustrating the interaction of bubbles with gas positioned between features on a surface, according to some embodiments. In FIG. 6, surface 504 comprises a plurality of features 513. According to certain embodiments, features 513 are posts. Features 513 form, in accordance with certain embodiments, a matrix of solid features on substrate 526 that are sufficiently close and stably contain gas 508 therebetween. According to some embodiments, as shown in FIG. 6 and as described herein, gas-containing bubbles 574 from a multiphase gas-liquid mixture may approach surface 504. Upon reaching surface 504, gas 570 from within bubble 574c merges with gas 570 positioned between microscale and / or nanoscale features 513, in accordance with certain embodiments. Gas 570 from within bubbles 574c can then be transferred to and along the plastron layer, in accordance with certain embodiments.

[0192] In some embodiments, the spacing between the features is selected such that the features are able to trap gas between the features when exposed to a multiphase gas-liquid mixture (e.g., a foam). For example, referring to FIG. 5A, in some embodiments, spacing 584 between features 513 can be selected such that gas is trapped between features 513 when surface 504 is exposed to a multiphase gas -liquid mixture.

[0193] According to certain embodiments, the surface can be at least partially made up of milliscale features. “Milliscale” is used herein in a manner consistent with its ordinary meaning in the art. Milliscale features are features having a maximum height of greater than 100 micrometers and up to 10 millimeters. Maximum height generally refers to the longest dimension from the substrate on which the feature is positioned to the end of the feature opposite the substrate. As one illustrative example, referring to FIG. 5 A, feature 513 has maximum height 502d. The maximum heights of milliscale features may be measured by electron microscopy techniques (e.g., scanning electron microscopy and / or transmission electron microscopy). The electron microscopy techniques can be supplemented by, for example, profilometry (e.g., optical or contact profilometers). According to some embodiments, the maximum height of the milliscale features is greater than 100 micrometers and up to 1 millimeter, greater than 100 micrometers and up to 200 micrometers, from 200 micrometers to 300 micrometers, from 300 micrometers to 500 micrometers, from 500 micrometers to 700 micrometers, from 700 micrometers to 1 millimeter, from 1 millimeter to 3 millimeters, from 3 millimeters to 5 millimeters, and / or from 5 millimeters to 10 millimeters. Combinations of the above cited ranges are also possible (e.g., from 300 micrometers to 700 micrometers, or from 200 micrometers to 1 millimeter).

[0194] In accordance with various embodiments, the surface can be at least partially made up of microscale features. “Microscale” is used herein in a manner consistent with its ordinary meaning in the art. Microscale features are features having a maximum height of from 1 micrometer to 100 micrometers. According to some embodiments, the maximum height of the microscale features is from 1 micrometer to 10 micrometers, 10 micrometers to 20 micrometers, 20 micrometers to 30 micrometers, 30 micrometers to 50 micrometers, 50 micrometers to 70 micrometers, or 70 micrometers to 100 micrometers. Combinations of the above cited ranges are also possible (e.g., 30 micrometers to 70 micrometers, or 20 micrometers to 100 micrometers). The maximum height of microscale features may be measured by electron microscopy techniques (e.g., scanning electron microscopy and / or transmission electron microscopy). The electron microscopy techniques can be supplemented by, for example, profilometry (e.g., optical or contact profilometers).

[0195] In certain embodiments, nanoscale features are used. “Nanoscale” is used herein in a manner consistent with its ordinary meaning in the art. Nanoscale features are features from 1 nm to 1 micrometer in maximum height. According to some embodiments, the maximum height of the nanoscale features is from 1 nm to 100 nm, 100 nm to 200 nm, 200 nm to 300 nm, 300 nm to 500 nm, 500 nm to 700 nm, or 700 nm to 1 micrometer. Combinations of the above cited ranges are also possible (e.g., 300 nm to 700 nm, or 200 nm to 1 micrometer).

[0196] According to certain embodiments, the features (e.g., the milliscale, microscale, and / or the nanoscale features) may have any of a variety of suitable characteristic spacings. As used herein, the characteristic spacing of a particular feature refers to the shortest distance between the external surface of the feature and the external surface of that feature’s nearest neighbor. For example, referring to FIG. 5 A, the characteristic spacing of feature 513is 584, the shortest distance between the external surface of feature 513 and the surface of feature 513. For a plurality of features, the average characteristic spacing refers to the number average of the characteristic spacings of the individual features. According to some embodiments, the average characteristic spacing between the milliscale features, when present, is at least 100 micrometers, at least 500 micrometers, at least 1 millimeter, at least 3 millimeters, at least 5 millimeters, or at least 9 millimeters. According to certain embodiments, the average characteristic spacing between the milliscale features, when present, is less than or equal to 10 millimeters, less than or equal to 5 millimeters, less than or equal to 3 millimeters, less than or equal to 1 millimeter, least than or equal to 500 micrometers, or less than or equal to 200 micrometers. Combinations of these ranges are also possible (e.g., from 200 micrometers to 3 millimeters, from 500 micrometers to 5 millimeters, from 1 millimeter to 10 millimeters).

[0197] According to some embodiments, the average characteristic spacing between the microscale features, when present, is at least 1 micrometer, at least 5 micrometers, at least 10 micrometers, at least 30 micrometers, at least 50 micrometers, or at least 90 micrometers. According to some embodiments, the average characteristic spacing between the microscale features is less than or equal to 500 micrometers, less than or equal to 200 micrometers, less than or equal to 100 micrometers, less than or equal to 90 micrometers, less than or equal to 70 micrometers, less than or equal to 50 micrometers, less than or equal to 30 micrometers, less than or equal to 10 micrometers, or less than or equal to 5 micrometers. Combinations of these ranges are also possible (e.g., from 1 micrometer to 5 micrometers, from 5 micrometers to 10 micrometers, from 10 micrometers to 30 micrometers, from 30 micrometers to 50 micrometers, from 50 micrometers to 70 micrometers, from 70 micrometers to 90 micrometers, or from 90 micrometers to 100 micrometers).

[0198] According to some embodiments, the average characteristic spacing between the nanoscale features, when present, is at least 1 nm, at least 10 nm, at least 50 nm, at least 100 nm, at least 200 nm, at least 300 nm, at least 500 nm, or at least 700 nm. According to some embodiments, the average characteristic spacing between the nanoscale features, when present, is less than or equal to 1 micrometer, less than or equal to 700 nm, less than or equal to 500 nm, less than or equal to 300 nm, less than or equal to 200 nm, less than or equal to 100 nm, less than or equal to 50 nm, or less than or equal to 10 nm. Combinations of these ranges are also possible (e.g., from 1 nm to 100 nm, from 100 nm to 200 nm, from 200 nm to 300 nm, from 300 nm to 500 nm, from 500 nm to 700 nm, or from 700 nm to 1 micrometer).

[0199] According to certain embodiments, the features may be relatively regularly spaced across the surface. This may be achieved, for example, by spacing the features in a pattern. In some embodiments, the standard deviation of the nearest neighbor distances of the features on the surface is less than 20% (or less than 10%, or less than 5%, or less than 2%, or less than 1%) of the number average of the nearest neighbor distances of the features on the surface. This standard deviation can be determined by determining, for each feature, the nearest neighbor distance and comparing the standard deviation of those nearest neighbor distances to the number average of those nearest neighbor distances.

[0200] According to some embodiments, the features on the surface can include a combination of features of different characteristic lengths. Without wishing to be bound by any particular theory, it is believed that the use of surfaces having such combinations of features can, according to certain embodiments, reduce the amount of time required to remove gas from within bubbles that impinge on the surface. According to certain embodiments, the surface comprises both milliscale features and microscale features. In some embodiments, the surface comprises both microscale features and nanoscale features. In certain embodiments, the surface comprises both milliscale features and nanoscale features. According to some embodiments, the surface comprises milliscale features, microscale features, and nanoscale features.

[0201] According to certain embodiments, the surface may comprise features which are pores. As noted above, in some embodiments, the surface comprises milliscale pores, microscale pores, and / or nanoscale pores. In certain embodiments, the pores may be dispersed on the surface a random (e.g., fractal) or patterned manner. In some embodiments, a surface may comprise both pores and other features (e.g., milliscale, microscale, and / or nanoscale features such as features comprising protrusions, as described above).

[0202] In some embodiments, the surface comprises pores such that, when the surface is exposed to a multiphase-gas liquid mixture, at least a portion of the pores may be exposed to the multiphase-gas liquid mixture. For example, as shown in FIG. 4B, at least a portion of the pores 742 of surface 704 are exposed to multiphase gas-liquid mixture 451 In some such embodiments, the at least a portion of the pores is configured to restrict the transport of a liquid (e.g., liquid 431) of the foam and / or the multiphase gas-liquid mixture through the surface (e.g., to gaseous environment 591). Those of ordinary skill in the art, given the disclosure provided herein, would be capable of configuring and / or selecting pores such that the transport of the liquid of the foam and / or the multiphase gas-liquid mixture through the surface is restricted. For example, the pores may have properties (e.g., size, shape, tortuosity, etc.) that result in transport of the liquid through the pore being energetically disfavored (while, at the same time, transport of gas through the pore is energetically favored). In addition, in some cases, the material from which the surface is made can be selected such that transport of the liquid through the pore is energetically disfavored (e.g., by using materials that are not wetting with respect to the liquid) while, at the same time, transport of gas through the pore is energetically favored. According to certain embodiments, little or no liquid is transported from the multiphase gas-liquid mixture (e.g., the foam), through the surface, and to a gaseous environment outside of the multiphase gas-liquid mixture. This can be achieved, for example, by selecting properties of the surface that reduce or eliminate the amount of liquid that is transported through the surface. At the same time, according to certain embodiments, the surface may be freely capable of having gas transported through its pores, for example, as described elsewhere herein. In some embodiments, during operation, the ratio of the volume of gas transported through the surface and to a gaseous environment outside of the multiphase gas-liquid mixture (from the multiphase gas-liquid mixture, such as a foam) to the volume of liquid transported through the surface and to the gaseous environment outside of the multiphase gas-liquid mixture (from the multiphase gas-liquid mixture) is at least 100:1; at least 1000:1; at least 10,000:1, at least 100,000:1, at least 1,000,000:1, or more.

[0203] As noted above, according to certain embodiments, the gas within the pores forms a gaseous pathway from within the multiphase gas-liquid mixture to a gaseous environment outside of the multiphase gas-liquid mixture. For example, in some cases, gas positioned within the pores prior to exposure of the surface (e.g., the pores within the surface) to the multiphase gas-liquid mixture remains trapped within the pores after submersion. This can result in the formation of a continuous gaseous pathway from the surface, through the pores, and to a gaseous environment outside of the multiphase gas-liquid mixture. In some cases, this results in the formation of a continuous gaseous pathway from the multiphase gas-liquid mixture, through the pores, and to a gaseous environment outside of the multiphase gas-liquid mixture.

[0204] In certain embodiments, the system comprises a source of gas within the gas -containing bubbles within and / or fluidically connected to the liquid of the multiphase gas-liquid mixture. The source of gas within the gas -containing bubbles within and / or fluidically connected to the liquid, in accordance with some embodiments, can be any of a variety of suitable sources of bubbles (e.g., a chemical reaction), as described in more detail elsewhere herein (e.g., a serpentinization reaction and / or other chemical reaction between water and a mineral comprising a material capable of reacting with water to form hydrogen). In some such embodiments, the gas from the source of gas may initially be dissolved in the liquid. In some embodiments, the gas from the source of gas may exsolve from the liquid (e.g., in an exsolution process), thereby forming gas -containing bubbles within the liquid to form a multi-phase gas-liquid mixture. According to certain embodiments, the gas -containing bubbles are transported through the multiphase gas-liquid mixture (e.g., from the source of gas and / or after exsolving from the liquid), to the surface when the surface is exposed to the multiphase gas-liquid mixture. The pores, in accordance with certain embodiments, may be introduced to the surface using a variety of suitable methods, including mechanical and / or chemical methods. For example, in some embodiments, the pores can be introduced to the surface via lithography. In certain embodiments, the pores can be introduced to the surface via self-assembly. According to certain embodiments, the pores can be etched into a substrate (e.g., using acid etching, base etching, and / or plasma etching). In some embodiments, the pores can be sintered onto a substrate (e.g., via powder sintering). In some embodiments, the pores can be part of a membrane that has been integrated into the conduit. In certain embodiments, the pores can be introduced to the surface via laser ablation.

[0205] In some embodiments, the size and / or shape of the pores is selected such that the pores are able to trap gas when exposed to a multiphase gas-liquid mixture (e.g., a foam) comprising gas-containing bubbles. The sizes and shapes of the pores are described in more detail herein.

[0206] According to certain embodiments, the surface may comprise milliscale pores. As noted above, “milliscale” is used herein in a manner consistent with its ordinary meaning in the art. Milliscale pores are pores having a minimum cross-section of greater than 100 micrometers and up to 10 millimeters. The minimum cross-section of a pore corresponds to the smallest cross- sectional dimension of the pore, as measured perpendicular to the length of the pore. FIG. 7A is a cross-sectional schematic diagram of a surface comprising pores, according to certain embodiments and FIG. 7B is a top view schematic diagram of a surface, as shown in FIG. 7A. Referring to FIG. 7A, surface 704 comprises pores 706 with minimum cross-section 742. It should be noted that, as used herein, the minimum cross-section of a pore through which gas is transported from gas-containing bubbles through the surface is different from the maximum height of a feature located on the surface. The minimum cross-section of a pore through which gas is transported from bubbles through the surface is measured laterally relative to the surface in which it is formed, as shown, for example, by minimum cross-section 742 in FIG. 7B. The minimum cross-section of pores may be measured by electron microscopy techniques (e.g., scanning electron microscopy and / or transmission electron microscopy). The electron microscopy techniques can be supplemented by, for example, profilometry (e.g., optical or contact profilometers).

[0207] According to some embodiments, the minimum cross section of the milliscale pores is greater than 100 micrometers and up to 1 millimeter, greater than 100 micrometers and up to 200 micrometers, from 200 micrometers to 300 micrometers, from 300 micrometers to 500 micrometers, from 500 micrometers to 700 micrometers, from 700 micrometers to 1 millimeter, from 1 millimeter to 3 millimeters, from 3 millimeters to 5 millimeters, and / or from 5 millimeters to 10 millimeters. Combinations of the above cited ranges are also possible (e.g., from 300 micrometers to 700 micrometers, or from 200 micrometers to 1 millimeter).

[0208] According to certain embodiments, the surface may comprise microscale pores. As noted above, “microscale” is used herein in a manner consistent with its ordinary meaning in the art. Microscale pores are pores having a minimum cross-section of from 1 micrometer to 100 micrometers. According to some embodiments, the minimum cross section of the microscale pores is from 1 micrometer to 10 micrometers, 10 micrometers to 20 micrometers, 20 micrometers to 30 micrometers, 30 micrometers to 50 micrometers, 50 micrometers to 70 micrometers, or 70 micrometers to 100 micrometers. Combinations of the above cited ranges are also possible (e.g., 30 micrometers to 70 micrometers, or 20 micrometers to 100 micrometers).

[0209] In certain embodiments, nanoscale pores are used. As noted above, “nanoscale” is used herein in a manner consistent with its ordinary meaning in the art. Nanoscale pores are pores from 1 nm to 1 micrometer in minimum cross-section. According to some embodiments, the minimum cross-section of the nanoscale pores is from 1 nm to 100 nm, 100 nm to 200 nm, 200 nm to 300 nm, 300 nm to 500 nm, 500 nm to 700 nm, or 700 nm to 1 micrometer. Combinations of the above cited ranges are also possible (e.g., 300 nm to 700 nm, or 200 nm to 1 micrometer).

[0210] According to certain embodiments, the pores may have any of a variety of suitable pore characteristic spacings. As used herein, the characteristic spacing of a particular pore refers to the shortest distance between the surface of the pore and the surface of that pore’s nearest neighbor. For example, referring to FIG. 7B, the pore characteristic spacing of pore 706d is 752, the shortest distance between the surface of pore 706d and the surface of pore 706c. For a plurality of pores, the pore average characteristic spacing refers to the number average of the pore characteristic spacings of the individual pores.

[0211] According to some embodiments, the average pore characteristic spacing between the milliscale pores, when present, is at least 100 micrometers, at least 500 micrometers, at least 1 millimeter, at least 3 millimeters, at least 5 millimeters, or at least 9 millimeters. According to some embodiments, the average pore characteristic spacing between the microscale pores, when present, is at least 1 micrometer, at least 5 micrometers, at least 10 micrometers, at least 30 micrometers, at least 50 micrometers, or at least 90 micrometers. According to some embodiments, the average pore characteristic spacing between the microscale pores is less than or equal to 500 micrometers, less than or equal to 200 micrometers, less than or equal to 100 micrometers, less than or equal to 90 micrometers, less than or equal to 70 micrometers, less than or equal to 50 micrometers, less than or equal to 30 micrometers, less than or equal to 10 micrometers, or less than or equal to 5 micrometers. Combinations of these ranges are also possible (e.g., from 1 micrometer to 5 micrometers, from 5 micrometers to 10 micrometers, from 10 micrometers to 30 micrometers, from 30 micrometers to 50 micrometers, from 50 micrometers to 70 micrometers, from 70 micrometers to 90 micrometers, or from 90 micrometers to 100 micrometers).

[0212] According to some embodiments, the average pore characteristic spacing between the nanoscale pores, when present, is at least 1 nm, at least 10 nm, at least 50 nm, at least 100 nm, at least 200 nm, at least 300 nm, at least 500 nm, or at least 700 nm. According to some embodiments, the average pore characteristic spacing between the nanoscale pores, when present, is less than or equal to 1 micrometer, less than or equal to 700 nm, less than or equal to 500 nm, less than or equal to 300 nm, less than or equal to 200 nm, less than or equal to 100 nm, less than or equal to 50 nm, or less than or equal to 10 nm. Combinations of these ranges are also possible (e.g., from 1 nm to 100 nm, from 100 nm to 200 nm, from 200 nm to 300 nm, from 300 nm to 500 nm, from 500 nm to 700 nm, or from 700 nm to 1 micrometer).

[0213] According to certain embodiments, the pores may be relatively regularly spaced across surface. This may be achieved, for example, by spacing the pores in a pattern. In some embodiments, the standard deviation of the nearest neighbor distances of the pores on the porous wall portion is less than 20% (or less than 10%, or less than 5%, or less than 2%, or less than 1%) of the number average of the nearest neighbor distances of the pores on the porous wall portion. This standard deviation can be determined by determining, for each pore, the nearest neighbor distance and comparing the standard deviation of those nearest neighbor distances to the number average of those nearest neighbor distances.

[0214] In some embodiments, the surface is exposed to the multiphase gas-liquid mixture at a particular tilt angle. The “tilt angle,” as used herein, refers to the angle between the exposed surface and the interface between the multiphase gas-liquid mixture and the environment outside the multiphase gas-liquid mixture. For example, referring to FIG. 4A, surface 504 is partially exposed to multiphase gas-liquid mixture 451 at tilt angle 561 (i.e., the angle that surface 504 makes with the interface between multiphase gas-liquid mixture 451 and gaseous environment 591). Adjusting the tilt angle of the exposed surface can, according to certain embodiments, control the rate at which bubbles from the multiphase gas-liquid mixture interact with the surface and / or control the flow rate at which gas is removed from the multiphase gas-liquid mixture. In certain embodiments, the surface is exposed to the multiphase gas-liquid mixture at a 10° to 15° tilt angle, a 15° to 20° tilt angle, a 20° to 30° tilt angle, a 30° to 40° tilt angle, a 40° to 50° tilt angle, a 50° to 60° tilt angle, a 60° to 70° tilt angle, a 80° to 90° tilt angle. Combinations of the above ranges are also possible (e.g., 20° to 50° tilt angle or 50° to 90° tilt angle).

[0215] The surface can be made of a variety of materials. According to certain embodiments, at least a portion of the surface (e.g., at least 10%, at least 25%, at least 50%, at least 75%, at least 90%, or at least 99% of the surface area of the surface) is made of metal(s), semiconductor(s), polymer(s) (e.g., organic polymer(s)), ceramic(s), and / or combinations thereof.

[0216] In certain embodiments, the substrate and the features (e.g., the milliscale, microscale, and / or nanoscale features) are made of the same material. For example, in some embodiments, the features can be formed by etching portions of the substrate to leave behind non-etched substrate portions that form the features.

[0217] In some embodiments, the surface comprises chemically modified features, a coated surface, or a surface with a bonded monolayer.

[0218] In some further embodiments, the surface features define at least one member selected from the group consisting of pores, cavities, wells, interconnected cores, and interconnected cavities.

[0219] The surface (e.g., comprising features) can have a variety of suitable geometric surface areas. The term “geometric surface area” refers to the area that would be measured macroscopically (for example, without counting contributions from pores, small-scale roughness, etc.) and can generally be understood as the total projected area. According to certain embodiments, the surface has a geometric surface area of at least 0.1 cm2, at least 1 cm2, at least 10 cm2, at least 100 cm2, at least 1000 cm2, at least 10,000 cm2, at least 100,000 cm2, or at least 1,000,000 cm2. According to certain embodiments, the surface has a geometric surface area of at least 1 mm2, at least 10 mm2, at least 100 mm2, at least 1,000 mm2, at least 10,000 mm2, at least 100,000 mm2, or at least 1,000,000 mm2. In certain embodiments, the surface has a geometric surface area of at least 1 mm2.

[0220] According to certain embodiments, the features (e.g., the milliscale, microscale, and / or nanoscale features) of the surface are distributed over a geometric surface area of at least 0.1 cm2, at least 1 cm2, at least 10 cm2, at least 100 cm2, at least 1000 cm2, or at least 10,000 cm2.

[0221] In accordance with some embodiments, at least 10%, at least 25%, at least 50%, at least

[0222] 75%, or at least 90% of the geometric surface area of the surface is exposed to the multiphase gas-liquid mixture. In some embodiments, at least 10%, at least 25%, at least 50%, at least 75%, or at least 90% of the geometric surface area of the surface is exposed to a foam. In accordance with some embodiments, at least 10%, at least 25%, at least 50%, at least 75%, or at least 90% of the geometric surface area over which the features (e.g., the milliscale, microscale, and / or nanoscale features) are distributed is exposed to the multiphase gas-liquid mixture. In accordance with some embodiments, at least 10%, at least 25%, at least 50%, at least 75%, or at least 90% of the geometric surface area over which the features (e.g., the milliscale, microscale, and / or nanoscale features) are distributed is exposed to a foam.

[0223] According to certain embodiments, the features (e.g., the milliscale, microscale, and / or nanoscale features, such as ridges, pores, spikes and / or posts) are distributed over the substrate such that the features occupy a particular solid fraction. The term “solid fraction” (also referred to as ( / > ), as used herein, refers to the area fraction of the substrate that would be in direct contact with the liquid when exposed to the liquid. The solid fraction can be calculated by dividing the areas of the tops of the features that would be in contact with the liquid by the geometric surface area over which those features are distributed. For example, referring to FIG. 5C, when surface 504 is exposed to the liquid of a multiphase gas liquid mixture (as shown, for example, by liquid 431 of multiphase gas-liquid mixture 451 in FIG. 4A), the tops of features 513 are in contact with the liquid, while the rest of the surface over which the features are distributed is not. In the set of embodiments illustrated by FIG. 5C, each of features 513 have identical side lengths a and identical nearest neighbor spacings b. Accordingly, the surface solid fraction ( <p) occupied by the features in FIG. 5C would be calculated as follows:

[0224] <p = a2I (a + )2

[0225] In some embodiments, the surface comprising the features (e.g., the milliscale, microscale, and / or nanoscale features) has a particular surface roughness. The surface roughness is defined as the total surface area of the sample (including features, holes, etc.) divided by the geometric surface area. Thus, for the case of regularly-distributed square posts (as shown in FIG. 5C) the roughness would be: r = 1 + 4ah / a + b)2where h is the height of the post. In some embodiments, the surface has a surface roughness of greater than 1.

[0226] According to certain embodiments, the surface is configured such that the surface and the liquid of the foam and / or multiphase gas-liquid mixture satisfy the following relationship: wherein <p is the solid fraction of the surface, r is the roughness of the surface, and 9 is the contact angle that would be made between a hypothetical surface without the milliscale, microscale, and / or nanoscale features and a droplet of the liquid of the foam and / or the multiphase gas-liquid mixture. According to certain embodiments, the above relationship is the condition for a hydrophobic surface to sustain a plastron layer when exposed to a liquid.

[0227] The liquid phase of the multiphase gas-liquid mixture can have a variety of suitable compositions. In certain embodiments, the multiphase gas-liquid mixture comprises water. In some embodiments, the multiphase gas-liquid mixture comprises an aqueous solution.

[0228] According to certain embodiments, the source of bubbles may be present in solution prior to exposing the surface to the multiphase gas-liquid mixture. For example, the surface can be placed in a region where a layer of bubbles has already agglomerated (e.g., to form foam). In certain other embodiments, the source of bubbles may be added to the solution after the surface is already present in the liquid (e.g., gas is produced via a chemical reaction between water in an aqueous fluid and a mineral comprising one or more materials capable of reacting with water to produce hydrogen).

[0229] According to certain embodiments, the surface can be used to eliminate bubbles (e.g., from a foam and / or a multiphase gas-liquid mixture) at a relatively high rate. For example, in some embodiments, bubbles are eliminated at a rate of at least 10 bubbles per hour, at least 100 bubbles per hour, at least 1000 bubbles per hour, at least 10,000 bubbles per hour, or at least 100,000 bubbles per hour.

[0230] In some embodiments, the multiphase gas-liquid mixture contains an additive. As used herein, “additive” is used to refer to anything in the multiphase gas-liquid mixture that is not the liquid, bubbles (or foam), or the surface being exposed to the multiphase gas-liquid mixture. In some embodiments, the additive comprises proteins, surfactants, and / or salts (e.g., alkali-metal salts). In certain embodiments, the multiphase gas-liquid mixture comprises an additive to prevent or reduce evaporation of the multiphase gas-liquid mixture. For example, in certain embodiments in which biochemical reactions are performed in the multiphase gas-liquid mixture, biological substances (e.g., proteins) can be used as an additive, which can stabilize the bubbles until a layer of foam is created. Other additives that can be used include, but are not limited to, sodium bicarbonate, sodium alkylbenzene sulfonate, sodium tripolyphosphate, tetrasodium pyrophosphate, and / or sodium carbonate. In some embodiments, the additive comprises a surfactant, such as a non-ionic surfactant. Non-limiting examples of water-soluble surfactants that may be present include those sold under the Tween® brand (also known as Polysorbate), such as Tween® 20, Tween® 40, Tween® 60, Tween® 80, Tween® 21, Tween® 61, Tween® 81, Tween® 65, and Tween® 85. Non-limiting examples of oil-soluble surfactants that may be present include those sold under the Span® brand, such as Span® 20, Span® 40, Span® 60, Span® 80, Span® 65, and Span® 85. It should be understood that the use of additives is optional, and in some embodiments, additives are not included in the multiphase gas-liquid mixture.

[0231] In some embodiments, a system as described herein comprises a source of gas (e.g., a source of the gas within gas-containing bubbles in a multiphase gas-liquid mixture, as described above). In some embodiments, the source of gas is water and a mineral capable of undergoing a chemical reaction (e.g., a serpentinization reaction) with the water. The mineral capable of undergoing a chemical reaction with the water may, in some embodiments, be a mineral comprising a material capable of reacting with water to produce hydrogen (e.g., a mineral containing ferrous iron as described above). In some embodiments, the mineral may be contained within a solid domain (e.g., a solid domain comprising rock, as described above). In some embodiments, the source of gas may comprise a system for generating hydrogen, as described above.

[0232] In some embodiments, the source of gas may be part of any other system as described elsewhere herein. For example, in some embodiments, the source of gas may comprise be water from an aqueous fluid (e.g., from a source of aqueous fluid) and a mineral capable of undergoing a chemical reaction with the water (e.g., a mineral comprising a material capable of reacting with water to produce hydrogen, for example via serpentinization reaction with water). In some embodiments, the mineral comprising a material capable of reacting with water to produce hydrogen may be the solid domain, a portion of a solid domain, and / or contained within the solid domain of any system described above comprising a solid domain (e.g., in some embodiments, a solid domain of any system described above may comprise the mineral capable of undergoing a chemical reaction with water of the source of gas). The source of gas may therefore be part of another system as described elsewhere herein (e.g., a solid domain comprising a mineral comprising a material capable of reacting with water to produce hydrogen and water, such as water from an aqueous fluid in any system described above may also be a source of gas within this system).

[0233] In some embodiments, a system as described herein may comprise an apparatus configured to remove one or more impurities from a gaseous product from a multiphase gasliquid mixture. For example, in some embodiments, a system as described herein comprises an electrochemical hydrogen looping apparatus 901 as shown in FIG. 9. In some embodiments, as shown in FIG. 9, the electrochemical hydrogen looping apparatus 901 comprises a cathode 911, an anode 912, and an electrolyte 914 (e.g., a solid electrolyte). In some embodiments, the electrochemical hydrogen looping apparatus is configured to separate hydrogen gas (e.g., the hydrogen gas in the multiphase mixture) from gaseous impurities. In some embodiments, the electrochemical hydrogen looping apparatus may be configured to receive a gaseous stream 902, which can comprise gaseous hydrogen and one or more impurities. In some embodiments, gaseous stream 902 is the gaseous stream that has been separated from a multiphase gas-liquid mixture comprising gas-containing bubbles containing hydrogen gas, for example using any of the systems and / or methods for removing a gas from gas-containing bubbles in a gas-liquid mixture as described above (e.g., from gaseous environment 591 in FIGS. 4A-4B). In some embodiments, the electrochemical hydrogen looping apparatus may be configured to produce an output comprising relatively pure hydrogen gas 903. In some embodiments, the gaseous impurities may be removed from the system, e.g., via conduit 922.

[0234] In some embodiments, the relatively pure hydrogen gas may comprise hydrogen gas having a relative purity by volume of greater than or equal to 5%, greater than or equal to 10%, greater than or equal to 15%, greater than or equal to 20 %, greater than or equal to 25%, greater than or equal to 30%, greater than or equal to 35%, greater than or equal to 40%, greater than or equal to 45%, greater than or equal to 50%, greater than or equal to 55%, greater than or equal to 60%, greater than or equal to 65%, greater than or equal to 70%, greater than or equal to 75%, greater than or equal to 80%, greater than or equal to 85%, greater than or equal to 90%, or greater than or equal to 95%. In some embodiments, the relatively pure hydrogen gas may comprise hydrogen gas having a relative purity by volume of less than or equal to 100%, less than or equal to 95%, less than or equal to 90%, less than or equal to 85%, less than or equal to 80%, less than or equal to 75%, less than or equal to 70%, less than or equal to 65%, less than or equal to 60%, less than or equal to 55%, less than or equal to 50%, less than or equal to 45%, less than or equal to 40%, less than or equal to 35%, less than or equal to 30%, less than or equal to 25%, less than or equal to 20%, less than or equal to 15%, or less than or equal to 10%. Combinations of these ranges are also possible (e.g., the relatively pure hydrogen gas may comprise hydrogen gas having a relative purity by volume of greater than or equal to 5% and less than or equal to 100%, greater than or equal to 10 % and less than or equal to 95%, or greater than or equal to 15% and less than or equal to 90%). Other ranges are also possible.

[0235] In some embodiments, the cathode and / or the anode of the electrochemical hydrogen looping apparatus may comprise a platinum-group metal (e.g., platinum, palladium, iridium, osmium, rhodium, and / or ruthenium). In some embodiments, the cathode and / or anode may comprise a carbon-based material (e.g., a carbon-based support material). For example, in some embodiments, the cathode and / or anode may comprise a platinum on carbon (e.g., Pt / C) electrode. The operation of the electrochemical hydrogen looping apparatus is described elsewhere herein.

[0236] In some embodiments, a method of recovering hydrogen from a multiphase gas-liquid mixture is described. In some embodiments, the multiphase gas-liquid mixture comprises gaseous hydrogen (e.g., gas-containing bubbles comprising hydrogen gas) and liquid water, as descried above.

[0237] The multiphase gas-liquid mixture may be a multiphase gas-liquid mixture as described above. For example, in some embodiments, at least a portion of the multiphase gas-liquid mixture may be contained within a conduit (e.g., an injection conduit and / or removal conduit) within any of the systems described above having such a conduit.

[0238] In some embodiments, the method comprises concentrating gas -containing bubbles from a multiphase gas-liquid mixture. In some embodiments, the concentrating the gas -containing bubbles may comprise performing cyclonic concentrating on the multiphase gas-liquid mixture. In some embodiments, cyclonic concentrating may be performed using a cyclonic concentrator, as described above.

[0239] In some embodiments, the method comprises exposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture. In some embodiments, the surface may have any of the properties and / or characteristics of the surface comprising a plurality of microscale and / or nanoscale features as described above.

[0240] In some embodiments, the method comprises generating the gas within the gascontaining bubbles. In some embodiments, the multiphase gas-liquid mixture may be generated according to the methods of generating a mixture comprising liquid water and hydrogen (e.g., a multiphase gas-liquid mixture comprising hydrogen) described above. For example, in some embodiments, generating the gas within the gas-containing bubbles comprises exposing water to a mineral such that a chemical reaction (e.g., a serpentinization reaction) occurs between the mineral and the water. In some embodiments, the mineral may contain ferrous iron (e.g., the mineral may be any of the minerals comprising a material capable of reacting with water to produce hydrogen as described above). In some embodiments, the mineral may be contained within a solid domain (e.g., a solid domain comprising rock, as described above).

[0241] In some embodiments, the multiphase gas-liquid mixture may comprise one or more gaseous impurities. In some such embodiments, a method of recovering hydrogen from a multiphase gas-liquid mixture as described herein comprises separating hydrogen gas from gaseous impurities (e.g., separating hydrogen gas from gaseous impurities in the multiphase gas- liquid mixture and / or in a gaseous mixture comprising hydrogen gas and one or more gaseous impurities).

[0242] In some embodiments, separating hydrogen gas from gaseous impurities comprises separating using an electrochemical hydrogen looping apparatus, as described above. The electrochemical hydrogen looping apparatus may have any of the properties and / or characteristics of an electrochemical hydrogen looping apparatus described above. For example, in some embodiments, separating hydrogen gas from gaseous impurities comprises oxidizing the hydrogen gas at the anode of the electrochemical hydrogen looping apparatus to form protons (e.g., H+), and subsequently reducing the protons to form hydrogen gas (e.g., H2). In some embodiments, the operation of the electrochemical hydrogen looping apparatus may comprise flowing of electrons through the system. For example, as shown in FIG. 9, the operation of the electrochemical hydrogen looping apparatus may comprise flowing electrons (as represented by the arrows 921) through the anode 912, the electrolyte 914, and the cathode 911. In some embodiments, the separating the hydrogen gas from gaseous impurities comprises using a solid electrolyte 914 as shown in FIG. 9. In some embodiments, the solid electrolyte comprises a proton- selective electrolyte (e.g., a proton-selective metal oxide at relatively high temperatures and / or pressures) in the electrochemical hydrogen looping apparatus, such that relatively pure hydrogen gas is formed, and gaseous impurities remain within the mixture.

[0243] In some embodiments, the method comprises compressing gas removed from the gas bubbles and / or gas produced by the electrochemical hydrogen looping apparatus. For example, in some embodiments, the method comprises compressing the gas via a compressor (e.g., a compressor as described above). In some embodiments, the gas may be compressed such that it can be stored (e.g., in a pressurized tank), for example for shipment (e.g., via truck and / or rail). In some embodiments, the gas may be compressed such that it can be transported to different location via a pipeline. In some embodiments, compressing the gas may comprise compressing the gas and reducing the temperature of the gas (e.g., to cryogenic temperatures), such that at least a portion of the gas is liquefied. For example, in some embodiments in which the gas comprises hydrogen gas, the compressing the hydrogen gas may comprise cryogenically compressing the gas to form liquid hydrogen.

[0244] In some embodiments, a system may comprise any combination of the various systems described herein. For example, in some embodiments, a system for producing and processing hydrogen is provided. Such a system may comprise a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above. In some embodiments, the system may comprise a source of aqueous fluid, as described above. In some embodiments, the system may comprise an injection conduit (e.g., an injection conduit as described above). In some embodiments, the injection conduit fluidically connected to the source of aqueous fluid and the solid domain. In some embodiments, as described above, the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen. In some embodiments, a mixture comprising liquid water and hydrogen (e.g., any mixture comprising liquid water and hydrogen described above) is disposed within the injection conduit. In some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5.

[0245] In some embodiments, a system for producing and processing hydrogen is provided. In some embodiments, the system comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above. In some embodiments, the system comprises a source of aqueous fluid. In some embodiments, the system comprises an injection conduit fluidically connected to the source of aqueous fluid and the solid domain. In some embodiments, the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen. In some embodiments, the system further comprises a concentrator configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture. In some embodiments, the multiphase gas-liquid mixture comprises gas comprising at least a portion of the hydrogen within the gas-containing bubbles and a liquid comprising at least a portion of the aqueous fluid. In some embodiments, the system comprises a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0246] In some embodiments, a system for producing and processing a multiphase gas-liquid mixture is provided. In some embodiments, the system comprises a source of a mineral comprising a material capable of reacting with water to produce hydrogen. In some embodiments, the system comprises a conduit (e.g., a conduit as described above) fluidically connected to the source of the mineral. In some embodiments, the system comprises a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit. In some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5. In some embodiments, the system comprises a concentrator fluidically connected to the conduit and configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas- containing bubbles and a liquid. In some embodiments, the system comprises a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0247] In some embodiments, a system for producing and processing a multiphase gas-liquid mixture is provided. In some embodiments, the system comprises a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen, as described above. In some embodiments, the system comprises a source of aqueous fluid. In some embodiments, the system comprises an injection conduit fluidically connected to the source of aqueous fluid and the solid domain. In some embodiments, the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen. In some embodiments, the system comprises a conduit (e.g., a conduit as described above) fluidically connected to the source of the mineral. In some embodiments, the system comprises a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit. In some embodiments, the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5. In some embodiments, the system comprises a concentrator fluidically connected to the conduit and configured to concentrate gascontaining bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas -containing bubbles and a liquid. In some embodiments, the system comprises a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

[0248] In some embodiments, a method may comprise any combination of the various methods described herein. For example, in some embodiments, a method of producing and processing hydrogen is provided.

[0249] In some embodiments, the method comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen, as described above. In some embodiments, the method comprises forming a mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen. In some embodiments, the mixture is contained within the injection conduit. In some embodiments, the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5.

[0250] In some embodiments, a method of producing and processing hydrogen is provided. In some embodiments, the method comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen, as described above. In some embodiments, the method comprises concentrating gas-containing bubbles from multiphase gas-liquid mixture comprising at least a portion of the aqueous fluid and the hydrogen. In some embodiments, the method comprises exposing the gas-containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0251] In some embodiments, a method of generating and processing a multiphase gas-liquid mixture is provided. In some embodiments, the method comprises contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen such that at least a portion of the water reacts with the material to form hydrogen, as described above. In some embodiments, the method comprises forming a multiphase gas-liquid mixture comprising water and hydrogen. In some embodiments, the mixture is contained within a conduit fluidically connected to the mineral. In some embodiments, the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5. In some embodiments, the method comprises concentrating gas-containing bubbles from the multiphase gas-liquid mixture. In some embodiments, the method comprises exposing the gas-containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0252] In some embodiments, a method of producing and processing hydrogen is provided. In some embodiments, the method comprises flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen. In some embodiments, the method comprises forming a multiphase gas-liquid mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen. In some embodiments, the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5. In some embodiments, the method comprises concentrating gas-containing bubbles from the multiphase gas-liquid mixture. In some embodiments, the method comprises exposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas -containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

[0253] The following examples are intended to illustrate certain embodiments of the present invention, but do not exemplify the full scope of the invention.

[0254] EXAMPLE

[0255] Hydrogen is poised to play an increasing role in the future energy mix, given the pressing need to find sources of primary power that do not produce greenhouse gases as a byproduct. Current technology of hydrogen production-either from methane reforming or electrolysis- appears inadequate to scale up in either a carbon-neutral or a cost-effective way.

[0256] The possibility of producing hydrogen generated in situ from iron-rich rocks in the subsurface (FIG. 10A) at large, sustainable rates, brings the prospect of radically changing the landscape for a carbon-constrained energy future. Here it is proposed to reach giant enhancement in the production of geologic hydrogen by promoting chemical cracking of the source ultramafic rock from the serpentinization reaction (FIGS. 10B-10C); enhancing transport of hydrogen in the fracture network via interfacial and rheological additives that foster bubble exsolution and coarsening (FIGS. 10D-10E); and designing gasphilic and, specifically, H2-philic membranes for fast and efficient downhole separation (FIG. 10F). The proposed project combines (1) laboratory experiments probing the chemo-hydro-mechanics of fracture creation and hydrogen evolution / transport, (2) mathematical and computational modeling of these processes at different scales, from the microscale to the reservoir scale, and (3) detailed technoeconomic analysis to ascertain whether the ambitious targets of production rates and costs can be achieved. These advances would lead to technologies that will contribute to making geologic hydrogen at scale a reality.

[0257] 1. INNOVATION AND IMPACT

[0258] 1.1 Problem Statement

[0259] Hydrogen (H2) is poised to pay a critical role in the energy transition, increasingly substituting fossil fuels to mitigate the impact of our energy systems on the Earth's climate. For example, according to the International Energy Agency, reaching net zero by 2050 would require increasing the current global hydrogen use of approximately 100 million tonnes (Mt) / year, to 500 Mt / year by 2050. While most scenarios agree on the growing role of hydrogen in the future energy mix, existing hydrogen production technologies are inadequate either because of its associated carbon footprint ("gray" hydrogen from methane reforming), scalability ("green" hydrogen from water electrolysis powered by biomass or other renewable energy sources), or cost ("blue" hydrogen, i.e., "gray" hydrogen with carbon capture and storage). The possibility of producing hydrogen generated in situ in the subsurface at large, sustainable rates, brings the prospect of radically changing the landscape for a carbon-constrained energy future.

[0260] The overall goal of the proposed project is to develop technologies that, if successful, will make production of geologic hydrogen at scale a reality. The emphasis is not on natural accumulations of hydrogen that would be considered "fossil" (i.e., accumulations that would not be replenished within the time scale of years / decades). Instead, the emphasis is on engineering the subsurface processes to radically improve the production of hydrogen. The proposed work recognizes the critically important process by which the hydrogen is generated in situ.

[0261] 1.2 State of the Art

[0262] At present, steam methane reforming (SMR) is used to produce "gray" hydrogen at low cost ($ 1.50 / kg) but generates - 10 kg CCh / kg H2. Low-carbon "blue" and "green" hydrogen are estimated to cost $2.00+ / kg and $3.00+ / kg, respectively, and they both suffer from specific challenges: "blue" hydrogen requires the storage of gigatonnes (Gt) of CO2 / year, and "green" hydrogen requires critical minerals and the wind / solar generation capacity to power it. Thus, it is essential to develop alternate routes to low-cost (<$l / kg H2) and low emissions (<0.45 kg CCLc / kg H2) hydrogen.

[0263] In response to this need, the past two years have seen a surging interest in geologic hydrogen as a low-carbon energy source, requiring its discovery, stimulation and production. The existence of hydrogen seeps and the geochemical pathways for the generation of hydrogen in the subsurface have been known, but the natural generation rates are generally low, and the resulting hydrogen disperse. To date, only one producing well exists globally, in Bourakebougou, Mali-a lOOm-deep water well that taps into a somewhat exceptional gas-cap accumulation of hydrogen. Therefore, the science and technology for accelerated, economical production of geologic hydrogen from potential accumulations does not yet exist.

[0264] It is encouraging, however, that observations of high-concentration free-gas hydrogen have been documented worldwide, associated with the serpentinization of iron-rich rocks in diverse settings like ophiolites, mid-continent ridges and Precambrian rock masses. Indeed, the USGS is currently conducting an assessment of the resource potential of geologic hydrogen in the US, and has already identified at least two major areas of the country that have favorable geology for the generation of significant volumes of hydrogen: (1) the Atlantic coastal plain that stretches along most of the East Coast and is associated with a band of iron-rich rock; and (2) parts of the Great Plains and the Upper Midwest, related to the Midcontinent Rift that brought vast quantities of iron- rich minerals. The fact that these subsurface settings are prevalent in the United States is of particular importance for this effort.

[0265] 1.3 Proposed Technology

[0266] Here it is proposed to reach giant enhancement in the production of geologic hydrogen by: promoting chemical cracking of the source ultramafic rock from the serpentinization reaction (FIG. 10B and FIG. IOC); enhancing transport of hydrogen in the fracture network via interfacial and rheological additives that foster bubble exsolution and coarsening (FIG. 10D and FIG. 10E); and designing gasphilic and, specifically, H2-philic membranes for fast and efficient downhole separation (FIG. 10F). The proposed project combines (1) laboratory experiments probing the chemo-hydro-mechanics of fracture creation and hydrogen evolution / transport, (2) mathematical and computational modeling of these processes at different scales, from the microscale to the reservoir scale, and (3) detailed technoeconomic analysis.

[0267] 1.4 Impact

[0268] The proposed project would contribute to developing the science and engineering of new technology for producing geologic hydrogen, and therefore support (1) reduce imports by minimizing the need for critical minerals for "green" hydrogen; (2) improve efficiency by utilizing hydrogen as a primary energy source for electricity; and (3) reduce emissions via the provision of ultra-low-GHG emission H2. Importantly, because of the high prospectivity of several geographic regions in the United States, the effort would contribute directly to increasing energy security in the United States. It would also open new opportunities in the domestic energy sector, where a shift from fossil fuels to carbon-neutral energy technologies is bound to take place during the next years and decades.

[0269] Table 1. Technical performance targets addressed by the proposed work

[0270] 2 Technical Concepts

[0271] 2.1 Approach

[0272] The emphasis of the proposed work is not on natural accumulations of hydrogen that would be considered "fossil" (i.e., accumulations that would not be replenished within the time scale of years / decades). Instead, the emphasis is on engineering the subsurface processes to dramatically enhance the production of hydrogen from ultramafic rocks where the hydrogen is sourced or from adjacent rock formations. This means that this effort is not blind to the way in which the hydrogen is formed in the subsurface, and therefore should consider aspects of the stimulation / reaction process of serpentinization. In particular, one cannot rely on producing the hydrogen from a gas cap, as it is traditionally done in hydrocarbon reservoirs. Instead, the hydrogen is generated in situ. It is anticipated that the H2 generated from the water-rock reaction, because of its low solubility in brine, readily exsolves in the form of small bubbles that nucleate at the rock surfaces, as brine flows through the pore space and oxidizes iron minerals. These bubbles then grow, detach, and new bubbles form.

[0273] A central consideration to establish the viability of the proposed approach is estimating the volume of source rock required for production of H2 via serpentinization at the required rate and for a total resource deposit (see Table 1), as well as the resulting change in volume of the source region. Consider as an example the production of H2 by serpentinization of iron-bearing olivine. The first stage is the hydration of olivine to form chrysotile and brucite:

[0274] 2(Mg,Fe)2SiO4 +3H2O -> (Mg,Fe)3Si2O5(OH)4 + (Mg,Fe)(OH)2, followed by the reaction of Fe-chrysotile and Mg-brucite to form Mg-chrysotile, magnetite, H2 and water:

[0275] Fe3Si2O5(OH)4+ 3Mg(OH)2-> Mg3Si2O5(OH)4 + Fe3O4+ H2+ 2H2O.

[0276] Under some conditions Fe-brucite can also be oxidized to produce additional H2, e. g., 3Fe(OH)2-> Fe3O4+ H2+ 2H2O.

[0277] For a typical Mg / Fe ratio of 9, 10-20 moles of olivine are required to produce each mole of H2. TO produce the target 30 kt / y H2, serpentinization of 6-12 106m3 / y of olivine would be required. To reach a total production of 10 Mt H2, a source region ~2-4 km3 of olivine would be required. The associated volume change for serpentinization is of order 40%, equivalent to adding a cube of dimension -200 m each year, or 1-2 km3total to the source region. This volume increase activates both positive and negative feedback processes; Precipitation and fracture closure could clog up the porosity, limiting fluid-rock interactions and serpentinization. Alternatively, reaction-induced cracking due the volume increase could increase the porosity and expose fresh fracture surfaces to reaction leading to an increased production. Detailed understanding of the conditions under which individual positive and negative feedbacks are favored is therefore needed.

[0278] Technical Risks and Mitigation. One of the major technical risks is the ability to engineer and drive the flow of hydrogen within the mafic or ultramafic source rocks. Serpentinization occurs naturally-producing H2as part of the reaction-and veins of serpentine are observed. This set of veins might potentially also provide connectivity to drive the hydrogen that is produced, or the hydrogen might migrate in a more diffuse fashion through grain boundaries in the mafic rock. As a mitigation strategy for this risk, subsurface engineering scenarios that rely on production of hydrogen from the overlying crystalline rock are also considered, which almost certainly will develop well-connected fracture networks as a result of the volume change associated with serpentinization of the source rocks.

[0279] 2.2 Organization of Concepts

[0280] This section of the disclosure is organized in a way that recognizes the different stages of sustainable hydrogen production in the subsurface, Task 1 focuses on the coupled chemomechanics of serpentinization to elucidate and enhance the creation of fractures. Task 2 focuses on the fundamental aspects of nucleation, growth, detachment, and coalescence of hydrogen bubbles at the scale of fracture roughness. Task 3 bridges the scale from the microscale to the fracture network scale and investigates flow of hydrogen from its (dispersed) source at rock surfaces to the production well.

[0281] Task 4 focuses on developing technologies for hydrogen separation downhole, at the reservoir- well interface. Section 4 provides a techno-economic assessment of the proposed technology, to analyze the technical limits of each of the elements of the proposed technology, and integrate them into an economic model of the entire system.

[0282] Task 1. Fracture Creation Within the Source Rock

[0283] Laboratory Experiments of Serpentinization and Reactive Cracking in Ultramafic Rocks. Industrial hydrogen production requires firm understanding of potential positive and negative feedback processes occurring during serpentinization and their influence on H2 production. Characterizing the development of the fracture network in the host rock is useful as the first step in the hydrogen extraction process. Fracture creation is coupled with the rate of reactions; if reaction occurs rapidly, stress builds quickly up and can lead to fracturing. If the reaction is slow, stress can be relaxed over extended time periods suppressing potentially the formation of fractures. One of the limitations in quantifying reaction rates and the resulting fracture patterns is that serpentinization reactions, while rapid over natural timescales, are still sluggish for practical laboratory timescales.

[0284] Experiments on fine powders at low pressures report reaction extents of <1 % in a few days up to - 25% over the duration of more than a year. Experiments on powders inhibit potential reactive cracking processes as no load bearing skeleton that could be cracked by volume expansion exists. To partly overcome these challenges, it is proposed to conduct laboratory experiments where cores of ultramafic rocks will be reacted with H2O over extended periods of time at high pressures and high temperatures (100 MPa - 2 GPa and 300 - 500°C) while monitoring the reaction progress, potential reactive cracking activity and hydrogen bubble nucleation in- situ using ultrasound probes. The serpentinization reaction progress is strongly dependent on water activity hence the reaction should be accelerated at higher pressures. However high pressures could also inhibit fracturing due to increased work that is needed to open up a fracture against the acting pressure.

[0285] In the laboratory, a unique solid medium deformation apparatus with ultrasound probes has been developed that allows the collection of such measurements (FIG. 11). The ultrasound probes will be used to send known pulses in regular intervals (scaled to the total duration of experiment from seconds to hours) to sample the changes in travel time which will correspond to changes in elastic moduli as olivine is serpentinized and hence can be used as a proxy for reaction progress, allowing us to get accurate reaction rates at a high temporal resolution. In between active pulsing, the ultrasound sensors will be listening to any naturally emitted acoustic emissions (AEs) which could be caused by reactive cracking or hydrogen bubble nucleation.

[0286] Unsupervised learning methods will be used, coupled with hierarchical clustering analysis to distinguish individual sources given that the mechanism of acoustic emission is likely very different between reactive cracking and bubble nucleation and burst. To characterize the fracture network and calibrate the ultrasound measurements of reaction progress, the samples will be scanned using pCT before and after deformation to quantify the volume of serpentinization and the resultant fracture patterns. Further microstructural studies using electron microscopy will be performed to thoroughly quantify the effects of serpentinization on the microscale and to quantify the developed fracture network. These measurements should further help constrain conditions which lead to reaction inhibition or acceleration and its effects on concomitant cracking and hydrogen bubble nucleation as the pressure, temperature, starting material and water content and composition can be varied.

[0287] Fracture network design via controlled "chemo-fracking". The increase in volume of the source region has important geomechanical implications on a wide range of scales, both within and around the region being produced. Understanding these may allow improved extraction via "chemo-fracks" that, like hydrofracks, increase the transmissivity from the source rocks to the wells. The downside is that uncontrolled fracturing and stress changes in the region surrounding the source could result in risks of leakage and triggered seismic events. On a microscopic scale, at a given time, serpentinization occurs along the surfaces of quasi-planar fractures (FIG. 10E). Assuming a single isolated plane and linear fracture mechanics, the time evolutions of the width and lengths of the serpentinized and open segments of a single fracture are functions of the fracture energy and far- field normal stresses. The distribution of interacting fractures is complex, and depends on the geometry, mechanical properties, and the tectonic stress. Fractures on the scale of partially serpentinized olivine grains (FIG. 12) are produced preferentially in the regions of maximum extension between expanding olivine grains, with fracture density lower elsewhere. Fractures associated with partially serpentinized bodies from thin section to outcrop scale show similar geometric patterns, suggesting that the fracturing is approximately scale-independent, as is common in brittle processes.

[0288] These observations suggest a hierarchical approach to modeling stress and strain. As a first approximation, (scale-dependent) producing regions are treated as inclusions, each with a prescribed internal strain change resulting from serpentinization of a fraction of that inclusion. Because deviatoric stresses tend to be relaxed by changes in mineralogy and by fracturing, it is assumed that the strain within the inclusions is isotropic. Approximating producing regions as ellipsoidal inclusions of varying volumes, semi-major axes, and orientations, allows for a very flexible yet powerful parameterization.

[0289] Under these assumptions, the stress changes for a number of interacting low-strength ellipsoids can be computed semi-analytically. Where the fracture limit from the combined stresses from inclusions and tectonic stress is exceeded, fracture networks form, with orientations and spatial scales determined by the spatial variations in stress. Because the amount of reaction that occurs is dependent on the local normal stress, the interaction among producing regions should be considered. It is proposed to estimate the stimulation geometry that would maximize fracture production and connectivity within the source region, as well as assess whether fractures could be engineered to facilitate the transport of H2 from the source region towards the surface. The goal is to generate fractures that transport H2 part way to the surface, where they could be intercepted by production wells, while preventing fractures from extending to the near-surface. To illustrate, FIG. 13 shows a cross section of the volumetric strain field associated with imposed volume increases on square tensile dislocations. For nearby sources, interaction becomes significant, suggesting that additional fracture opening might result. Shallowly dipping sources focus the near-surface extensional strain.

[0290] Task 2. Hydrogen Evolution and Transport at Microscale

[0291] Hydrogen released from serpentinization of rocks is expected to be in a dissolved state in the source rock at large depths. However, as hydrogen rises through the fracture network, the decreasing pressure and continual hydrogen generation would lead to hydrogen exsolution and subsequent bubble-laden two-phase flow through the channels. Understanding hydrogen bubble exsolution and the morphology of the bubbly flow within individual microscale fractures is crucial to develop effective means to transport hydrogen across scales-from microscale features to macro-scale well head. For this it is proposed to take experimental and computational approaches as described below.

[0292] Exsolution and Growth. To experimentally visualize the exsolution process, it is proposed to build a microfluidic cell with a Hele-Shaw configuration (mimicking planar fractures), as shown in FIGS. 14A and 14B. The cell would be equipped with an optical window for high-speed visualization of the bubble exsolution and growth. To keep the system simple, yet representative it is proposed to use CO2 as a proxy because its solubility is 200 times more than that of H2 in water at 25°C. Filling the cell with deionized water with dissolved CO2, pressure would be gradually released until the onset of exsolution of gas bubbles is observed. Bubbles are expected to nucleate on the walls heterogeneously; in order to tune the nucleation kinetics as well as pinning forces, transparent micro -textured nanorough surfaces would be used as the top and bottom surfaces of the cell, further mimicking the roughness of the fracture walls.

[0293] Bubbles adhering to walls, however, are highly undesirable for transport of hydrogen as contact line pinning forces can be very high. This is further aggravated if bubbles coalesce and become larger as this will lead to multiple contact lines, trapping the bubbles in microfractures clogging the channels. Mimicking the roughness of rock surfaces using microtextures (FIG. 10B) allows one to study how exsolution dynamics within rough microchannels leads to capillary trappings and establish a regime map for such processes. To promote bubble exsolution in the bulk, it is proposed using interfacial modifiers with combinations of gasphilic nanoparticles and surfactants to stabilize the gas-liquid interface and make it unfavorable for bubbles to adhere to walls. It is proposed to design these modifiers using stable surfactant molecules and functionalized nano and core- shell particles with grafted and molecularly engineered interfaces using approaches developed for covalently grafting surfaces, nanoemulsions. While the presence of nanoparticles and surfactants at the gas-liquid interface would help create a high-quality foam, it is also expected to impact the growth of bubbles not only by inhibiting coalescence, but also constraining diffusion across the nanoparticle-laden interface. This would be studied by decreasing the gas pressure in the chamber that would lead to further exsolution and growth of bubbles. These experimental results will thus enable us to determine the composition of interfacial modifiers that will lead to optimal bubble morphology, for efficient hydrogen transport through microchannels.

[0294] Phase-field modeling. The microfluidic experiments described above provide a unique opportunity to develop new computational models of coupled multiphase flow and aqueous- solid reaction. Phase-field methods, which describe the system as being out of thermodynamic equilibrium, have a long history in modeling multiphase flows, and have been extended to model multicomponent mixtures. In this work, this approach has been adopted for rigorous modeling of the effects of wettability in simple geometries like capillary tubes and Hele-Shaw cells, and 2D porous media. The ability to model phase change, including cavitation has recently been demonstrated, which-a process closely related to exsolution of dissolved gas from the liquid.

[0295] It is proposed to develop phase-field models that address the main challenges in microscale modeling of hydrogen generation and evolution from iron-rich rocks. Indeed, different computational approaches to microscale modeling of multiphase, multicomponent, reactive flow have recently emerged, but the emphasis to date has been on single-phase flow and mineral dissolution, whereas precipitation is a substantially more challenging problem - especially in the system of interest, where there is very significant volume change from the serpentinization reaction. The mathematical and computational models at the microscale will be immensely helpful in determining the key mechanisms responsible for bubble exsolution and evolution in confined environments and can help elucidate the impact of interfacial and rheological modifiers beyond the range probed experimentally.

[0296] Task 3. Hydrogen Flow from Microscale to Reservoir Scale

[0297] Morphology of the Bubbly Flows. The exsolution experiments being in quiescent liquid do not capture the flow properties of the bubble-laden flows. To closely mimic the dynamics of the bubbly flows through geologic micro fractures, it is proposed to develop an electrochemical analogue using water electrolysis where the gas flux can be precisely controlled. The coinventors are well-positioned for this intersectional task, having extensive experience electrochemistry as well as bubble dynamics and capture.

[0298] The experimental set-up would comprise a microfluidic Hele-Shaw flow cell through which water is flowed. Unlike the previous set-up this does not require high pressure for gas dissolution, as th bubbles are generated from a Platinum electrode adhering to the bottom surface near the edge, as shown in FIG. 15D (counter-electrode not shown). This will allow us to systematically control the degree of hydrogen evolution by altering the current density, while varying the flow rate of water by orders of magnitude. Downstream from the electrode, where the flow has fully developed, the flows will be optically visualized with microscope atop. The nature of the bubbly flows strongly depends on the gas flux, liquid flux, surface tension, viscosity and the bubble size distribution. The flow will be studied with and without interfacial modifiers, viscosifiers (like polymer additives), changing gas flux, liquid flux and finally the roughness of the surface.

[0299] These experimental results would help construct a phase diagram relating the injection fluid properties, interfacial and rheology modifier parameters with the resulting bubble morphology (FIG. 15C). As the hydrogen emanating from serpentinizing rocks exsolves, it is expected to see bubbly flows in microfractures. The phase map will help us to identify the regime in which freshly exsolved bubbly flows lie, and how can the appropriate control strategy for enhanced extraction of geologic hydrogen.

[0300] Hydrogen Transport at the Fracture-Network Scale. The microfluidic experiments in single channels described above set the stage for microfluidic experiments that allow to capture emergent behavior at the fracture-network scale that is believed to be prevalent as a result of the serpentinization reaction in both the iron-rich source rock and the adjacent crystalline-rock formations. UV modulation of the surface energy can be used to precisely control wettability and simultaneously studying the cooperative behavior that emerges from thousands or tens-of- thousands of pores.

[0301] In a first generation of experiments, the same system as described above for the generation of hydrogen bubbles and their modulation will be used, but moving up in scale to understand the role of fracture intersections on bubble morphology and the role of flow architecture in the overall rate of formation of hydrogen. This will inform the evolution of the macroscopic fraction of hydrogen to ensure that it arrives at the production well with a high gas saturation (> 20%). In a second generation of experiments, conditions will move even closer to the conditions of hydrogen formation in subsurface iron-rich rocks via surface functionalization with relevant minerals. This will allow us to investigate, with unprecedented spatial and temporal resolution, whether surface passivation occurs and plays a role in the production of hydrogen at the fracture-network scale.

[0302] Task 4. Extraction and Separation of Gases

[0303] Gasphilic Membranes. Here, it is proposed to develop a gas separation device comprising a cyclone separator equipped with a high permeability gasphilic membrane at the top. As shown in FIG. 16A, the cyclone mixer creates a density stratification in the radial direction due to centrifugal forces, leading to a separation of the bulk liquid (away from axis) and hydrogen bubbles (near the central axis). The rising bubbles concentrated at the central axis are defoamed at the top by the gasphilic membrane where the gas is collected, while the liquid is pumped out to be reused. A pump at the bottom transports the surfactant laden liquid away to be re -pumped into the well, thereby reinjecting the fluid stream for further extraction.

[0304] High permeability gasphilic membranes can be used , as shown in FIG. 16D. These membranes can be manufactured using different materials including silicon-based functionalized surfaces. These surfaces are shown to have a remarkably stable thin film of plastron over them. Millimetric bubbles can be evacuated in the order of milliseconds, as illustrated in FIG. 16C. For efficient gas capture and transport, three parameters will be modeled to enable effective design of the aerophilic surfaces: (1) bubble capture efficiency, (2) plastron maintenance, and (3) maximum gas flow rate through this plastron. In accordance with certain embodiments, the thermodynamic condition to be satisfied to ensure a stable plastron for a given surface is cos(0w) < — (1 — 0) / (r — 0), where 0Wrepresents the equilibrium contact angle of the liquid phase on a non-textured surface, <p is the solid fraction of the aerophilic surface and r is the roughness of the aerophilic surface.

[0305] In accordance with certain embodiments, these membranes can be not only gasphilic but also configured to promote contact line pinning - a useful criterion for fast evacuation on the scale of individual bubble. Pinning ensures that evacuation leads to a decrease in radius of curvature leading to higher Laplace pressure and accelerated evacuation. This can be seen in the timelapse in FIG. 16C that shows the three-stage process of capture: I) rupture of the water film between plastron outside the bubble and the gas inside, II) evacuation of gas with pinned contact line and III) depinning and evacuation of the rest. While stage I and III are quick, it is stage II that dictates the evacuation time. For the high permeability membranes this stage is inertially limited; the corresponding evacuation time comes from a balance between capillary and inertial forces that can be written as T ~ (p / ?3 / y)1 / 2, where R is the radius of the bubble, p is the density of water and y is the surface tension. For millimetric bubbles, this yields a time of the order 1 ms, as seen in FIG. 16C. It is proposed to further enhance a H -philic membrane for the specific purpose of efficient yet fast separation of gases from hydrogen foam or bubbly flow.

[0306] Electrochemical Hydrogen Looping (EHL). Owing to its extremely low solubility in water, the gaseous mixture in the foam is expected to be primarily hydrogen. Nevertheless, should the mixture contain undissolved gasses, electrochemical hydrogen looping can be used as a subsequent step to separate the gases, where hydrogen is first oxidized into an ionic form (H+) at the anode, which is subsequently reduced back into hydrogen gas at the cathode (H2) as shown in FIG. 17. If appropriate proton- selective electrolytes are used, the reduction process can selectively produce are pure hydrogen gas output. Solid proton-selective mixed oxides are promising candidates for the given temperatures (~ 400°C) and pressures (10 bar). The energetics of the system is dictated by concentration, kinetic, and mass transport overpotentials. By using Pt-group catalysts and thin electrolyte layers, kinetic and mass transport overpotentials are reduced. Concentration overpotentials will be tailored based on the purity and pressure of inlet and outlet streams. This provides an opportunity to compress the Hydrogen further electrochemically, a process which has significant efficiency benefits compared to more conventional compression trains. As discussed in Task 1, H2 is the major product of the process and therefore the gas separation approaches described above will meet the 20% purity by volume metric. Electrochemical hydrogen looping costs can be modeled using the overpotentials to estimate the operating electricity costs and using readily available cost estimates of similar solid oxide electrolyzers for capital expenses. Technoeconomic models which can identify under what conditional regimes (stream purity, temperature, pressure, flow rates, etc.) will be developed; such an electrochemical separation would be favorable, and accordingly fabricate prototype system for validation.

[0307] TECHNOLOGY TO MARKET

[0308] Techno-economic analysis

[0309] The techno-economic analysis of geologic hydrogen production is bound to include uncertainty, as the technology currently does not exist. It is reasonable to assume, however, that the main cost driver will be well (drilling, completion and fracture stimulation of the near- well region). This cost will dwarf all other costs and uncertainty related to pumping and pipeline transport of hydrogen. The key target metrics to support the ARPA-Emission, when the technology is deployed at scale, are < $1 / kg H2 at the well head,> 1 million m3 H2 / day (equivalent to 30 kt H / y) produced from the field, and 10 Mt H2 of total hydrogen in place.

[0310] The key considerations are as follows:

[0311] 1. Source rock volume required. As discussed in Section 2 of this proposal, to produce the target 30 kt / y H2, serpentinization of 6 - 12 106m3 / y of olivine would be required. To reach a total gas in place of 10 Mt H2, a source region - 2 - 4 km3of olivine would be required.

[0312] 2. Producing source area constraints. Assume that a total reservoir volume increase of 1 % would generate an acceptable number of fractures. Then 2% = 1 / 50 of the volume of the source rock could be consumed, 100 - 200 km3in total, or a typical source region of 10km X 10km X 1km.

[0313] 3. Well productivity constraints and number of wells needed. Using as analogue wells from shale gas fields, a reasonable production rate is - 1000 boe / well / d, or - 1.7 x 105 m3 / d (equivalent to 5 kt tb / y). In this scenario, 6 horizontal wells (of about 10km length) would be needed.

[0314] 4. Cost of hydrogen production wells. There is large uncertainty, since there is essentially zero field experience in drilling these wells. If enhanced geothermal systems (EGS) are used as an analogue for drilling into very hard, tough rock, a reasonable range is $SM to $20M per well, depending on depth and length. One would expect that these costs would decrease significantly as drilling technology progresses.

[0315] 5. Cost per kg of H2 produced. Assuming a lifespan per well of 10 years, the yearly cost of wells would be $12M / y for the target production rate of 30 kt of th / y, or $0.4 / kg H2. 6. This analysis suggests that the proposed technology could meet the ARPA-E targets and would be significantly lower than current estimates for blue and green hydrogen ($2.00+ / kg and $3.00+ / kg, respectively).

[0316] 7. CO2e / kg of H2 produced. As described earlier in Section 2 .2-Task 1, the process results in H2 being the major product. Hence, the major sources of GHG emissions for the process would arise from the drilling and injection process. It is found that drilling CO2e to be negligible when compared to pumping: using CO2 footprint for shale-gas wells, conservative estimates for a 10km well amortized over 10 years - 50t CO2e / y (much smaller than 5kt H2 / y above). Assuming a 70% pump efficiency, pressure drop 30 MPa and flow rate of 500m3 / day (typical process) or 60MPa and 4000m3 / day (aggressive process), pumping power - 2000- 35000 MWh / y is obtained. Using the CO2 emission factors for electricity generation of2.26 Ib / kWh (coal), 0.97 Ib / kWh (gas), 0.11 Ib / kWh (solar), and 5 kt H2 / y production rate, it is estimated - 0.45 (coal), 0.2 (gas), 0.02 (solar) kg CO2e / kg of H2 produced. Similarly, for aggressive process - 7.1 (coal), 3.0 (gas), 0.35 (solar) kg CO2e / kg of H2 produced. Hence, there is enough P A-E target of < 1kg CO2e / kg of H2 produced by engineering the injection process and choosing the electricity source.

[0317] While several embodiments of the present invention have been described and illustrated herein, those of ordinary skill in the art will readily envision a variety of other means and / or structures for performing the functions and / or obtaining the results and / or one or more of the advantages described herein, and each of such variations and / or modifications is deemed to be within the scope of the present invention. More generally, those skilled in the art will readily appreciate that all parameters, dimensions, materials, and configurations described herein are meant to be exemplary and that the actual parameters, dimensions, materials, and / or configurations will depend upon the specific application or applications for which the teachings of the present invention is / are used. Those skilled in the art will recognize, or be able to ascertain using no more than routine experimentation, many equivalents to the specific embodiments of the invention described herein. It is, therefore, to be understood that the foregoing embodiments are presented by way of example only and that, within the scope of the appended claims and equivalents thereto, the invention may be practiced otherwise than as specifically described and claimed. The present invention is directed to each individual feature, system, article, material, and / or method described herein. In addition, any combination of two or more such features, systems, articles, materials, and / or methods, if such features, systems, articles, materials, and / or methods are not mutually inconsistent, is included within the scope of the present invention.

[0318] The indefinite articles “a” and “an,” as used herein in the specification and in the claims, unless clearly indicated to the contrary, should be understood to mean “at least one.”

[0319] The phrase “and / or,” as used herein in the specification and in the claims, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Other elements may optionally be present other than the elements specifically identified by the “and / or” clause, whether related or unrelated to those elements specifically identified unless clearly indicated to the contrary. Thus, as a non-limiting example, a reference to “A and / or B,” when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A without B (optionally including elements other than B); in another embodiment, to B without A (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.

[0320] As used herein in the specification and in the claims, “or” should be understood to have the same meaning as “and / or” as defined above. For example, when separating items in a list, “or” or “and / or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of’ or “exactly one of,” or, when used in the claims, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e. “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the claims, shall have its ordinary meaning as used in the field of patent law.

[0321] As used herein in the specification and in the claims, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and / or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.

[0322] As used herein, “wt%” is an abbreviation of weight percentage. As used herein, “at%” is an abbreviation of atomic percentage. As used herein, “vol%” is an abbreviation of volume fraction.

[0323] Some embodiments may be embodied as a method, of which various examples have been described. The acts performed as part of the methods may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include different (e.g., more or less) acts than those that are described, and / or that may involve performing some acts simultaneously, even though the acts are shown as being performed sequentially in the embodiments specifically described above.

[0324] Use of ordinal terms such as “first,” “second,” “third,” etc., in the claims to modify a claim element does not by itself connote any priority, precedence, or order of one claim element over another or the temporal order in which acts of a method are performed, but are used merely as labels to distinguish one claim element having a certain name from another element having a same name (but for use of the ordinal term) to distinguish the claim elements.

[0325] When a portion (e.g., a layer, a structure, a region) is “on”, “adjacent”, “above”, “over”, “overlying”, or “supported by” another portion, it can be directly on the portion, or an intervening portion (e.g., layer, structure, region) may also be present. Similarly, when a portion is “below” or “underneath” another portion, it can be directly below the portion, or an intervening portion (e.g., layer, structure, region) may also be present. A portion that is “directly adjacent”, “directly on”, “immediately adjacent”, “in contact with”, or “directly supported by” another portion means that no intervening portion is present. It should also be understood that when a portion is referred to as being “on”, “above”, “adjacent”, “over”, “overlying”, “in contact with”, “below”, or “supported by” another portion, it may cover the entire portion or a part of the portion.

[0326] In the claims, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of’ and “consisting essentially of’ shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.

Claims

CLAIMSWhat is claimed is:

1. A system, comprising: a source of a mineral comprising a material capable of reacting with water to produce hydrogen; a conduit fluidically connected to the source of a mineral comprising a material capable of reacting with water to produce hydrogen; and a mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to IO’5.

2. The system of claim 1, wherein the system is configured to adjust a property of the mixture to induce the formation of bubbles comprising the hydrogen if the hydrogen flux within a solid domain including the mineral is above a critical hydrogen flux.

3. The system of any one of claims 1-2, wherein the mixture comprises bubbles of hydrogen within the liquid water, the hydrogen within a majority of the bubbles having a spreading coefficient on a surface of a solid domain comprising the mineral of less than zero.

4. The system of any one of claims 1-3, wherein the hydrogen is dissolved in the water.

5. The system of any one of claims 1-4, wherein the hydrogen is gaseous hydrogen.

6. The system of any one of claims 1-5, wherein the mixture comprises a multiphase gas-liquid mixture.

7. The system of any one of claims 1-6, wherein the gaseous hydrogen makes up greater than or equal to 5 vol% of the mixture.

8. The system of any one of claims 1-7, wherein the gaseous hydrogen makes up greater than or equal to 50 vol% of the mixture.

9. The system of any one of claims 1-8, further comprising an interfacial modifier and / or rheology modifier.

10. The system of claim 9, wherein the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant.

11. The system of any one of claims 9-10, wherein the interfacial modifier and / or rheology modifier is configured to facilitate exsolution of bubbles comprising hydrogen gas and / or prevent coalescence of bubbles comprising hydrogen gas and / or prevent adhesion of the bubbles to a solid surface.

12. The system of any one of claims 1-11, wherein the mixture comprises a foam.

13. The system of any one of claims 1-12, wherein the source of a mineral comprising a material capable of reacting with water to produce hydrogen comprises ultramafic rock, mafic rock, and / or sedimentary rock.

14. A method, comprising: contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen such that at least a portion of the water reacts with the material to form hydrogen; and forming a mixture of water and hydrogen, wherein: the mixture is contained within a conduit fluidically connected to the source, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to IO'515. The method of claim 14, further comprising adjusting a property of the mixture to induce the formation of bubbles comprising the hydrogen if the hydrogen flux within the source is above a critical hydrogen flux.

16. The method of any one of claims 14-15, wherein the mixture comprises bubbles of hydrogen within the liquid water, the hydrogen within the bubbles having a spreading coefficient on a surface of a solid domain comprising the source of less than zero.

17. The method of any one of claims 14-16, wherein the contacting water comprises contacting the water and an interfacial modifier and / or rheology modifier with the source of ferrous iron.

18. The method of claim 17, wherein the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant.

19. The method of any one of claims 17-18, wherein the interfacial modifier and / or rheology modifier is configured to facilitate exsolution of bubbles comprising hydrogen gas and / or prevent coalescence of bubbles comprising hydrogen gas.

20. The method of any one of claims 14-19, wherein the hydrogen is dissolved in the water.

21. The method of any one of claims 14-20, wherein the hydrogen is gaseous hydrogen.

22. The method of any one of claims 14-21, wherein the forming a mixture comprises forming a multiphase gas-liquid mixture comprising water and hydrogen.

23. The method of claim 21, wherein the gaseous hydrogen makes up greater than or equal to 5 vol% of the mixture.

24. The method of claim 21 or 23, wherein the gaseous hydrogen makes up greater than or equal to 50 vol% of the mixture.

25. The method of any one of claims 14-24, wherein the mixture comprises a foam.

26. The method of any one of claims 14-26, wherein the source of a mineral comprising a material capable of reacting with water to produce hydrogen comprises ultramafic rock, mafic rock, and / or sedimentary rock.

27. The method of any one of claims 14-27, wherein the hydrogen is generated by a chemical reaction of the water with the source of a mineral comprising a material capable of reacting with water to produce hydrogen.

28. A system, comprising: a concentrator configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

29. The system of claim 28, wherein the concentrator comprises a cyclonic concentrator.

30. The system of any one of claims 28-29, wherein the multiphase gas-liquid mixture comprises gaseous hydrogen and aqueous fluid.

31. The system of any one of claims 28-30, wherein the microscale and / or nanoscale features comprise pores, ridges, spikes, and / or posts.

32. The system of any one of claims 28-31, wherein at least a portion of the surface comprises a metal, a semiconductor, a polymer, a ceramic, and / or any combination thereof.

33. The system of any one of claims 28-32, further comprising a source of gas within the gas -containing bubbles.

34. The system of claim 33, wherein the source of gas is water and a mineral capable of undergoing a chemical reaction with the water to produce hydrogen.

35. The system of any one of claims 28-34, further comprising an electrochemical hydrogen looping apparatus comprising a cathode and an anode, wherein the electrochemical hydrogen looping apparatus is configured to separate hydrogen gas from gaseous impurities in the multiphase gas-liquid mixture.

36. The system of claim 35, further comprising a compressor configured to compress gas removed from the gas bubbles and / or gas produced by the electrochemical hydrogen looping apparatus.

37. The system of any one of claims 28-36, further comprising a plastron layer adjacent the surface.

38. The system of claim 37, wherein the plastron layer comprises hydrogen.

39. The system of any one of claims 37-38, wherein gas from within the gascontaining bubbles is capable of merging with gas within the plastron layer.

40. A method of recovering hydrogen from a multiphase gas-liquid mixture, comprising: concentrating gas -containing bubbles from the multiphase gas-liquid mixture; and exposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

41. The method of claim 40, wherein the concentrating is performed using a cyclonic concentrator.

42. The method of any one of claims 40-41, wherein the multiphase gas-liquid mixture comprises gaseous hydrogen and liquid water.

43. The method of any one of claims 40-42, wherein the microscale and / or nanoscale features comprise pores, ridges, spikes, and / or posts.

44. The method of any one of claims 40-43, wherein at least a portion of the surface comprises a metal, a semiconductor, a polymer, a ceramic, and / or any combination thereof.

45. The method of any one of claims 40-44, further comprising generating the gas within the gas-containing bubbles.

46. The method of claim 45, wherein the generating the gas within the gas -containing bubbles comprises exposing water to a mineral such that a serpentinization reaction occurs.

47. The method of any one of claims 40-46, further comprising separating hydrogen gas from gaseous impurities.

48. The method of claim 47, wherein the separating comprises separating the hydrogen gas from the gaseous impurities using an electrochemical hydrogen looping apparatus.

49. The method of claim 48, further comprising compressing gas removed from the gas bubbles and / or gas produced by the electrochemical hydrogen looping apparatus.

50. The method of any one of claims 40-49, wherein gas from the gas -containing bubbles is merged with gas within a plastron layer adjacent to the surface comprising the microscale and / or nanoscale features.

51. A system for producing hydrogen, comprising: a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; andan injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen.

52. The system of claim 51, further comprising a hydrogen storage location that is the same as the source of aqueous fluid or different from the source of aqueous fluid.

53. The system of claim 52, further comprising a removal conduit that is the same conduit as the injection conduit or a different conduit, wherein the removal conduit is configured to facilitate at the transfer of least a portion of the hydrogen to the hydrogen storage location.

54. The system of claim 53, wherein the removal conduit is fluidically connected to a hydrogen storage location.

55. The system of any one of claims 51-54, wherein the aqueous fluid comprises an interfacial modifier and / or a rheology modifier.

56. The system of any one of claims 51-55, wherein the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant.

57. The system of any one of claims 51-56, wherein the solid domain comprises ultramafic rock, mafic rock, and / or sedimentary rock.

58. The system of any one of claims 51-57, wherein the chemical reaction comprises a serpentinization reaction.

59. The system of any one of claims 51-58, wherein the injection conduit and / or the removal conduit are positioned and / or configured to induce fracturing of the solid domain via hydraulic fracturing.

60. The system of any one of claims 51-59, further comprising fractures in the solid domain fluidically connected to the injection conduit and / or the removal conduit.

61. The system of any one of claims 51-60, wherein the injection conduit and / or the removal conduit are positioned and / or configured to control fracture development in the solid domain via control of a volume change of the solid domain caused by the chemical reaction.

62. The system of any one of claims 51-61, further comprising a sensor.

63. The system of claim 62, wherein the sensor comprises a fluid pressure sensor, a temperature sensor, a rock deformation sensor, and / or a chemical composition sensor.

64. The system of claim 62, wherein the sensor comprises a fluid pressure sensor comprising a piezoelectric, strain gauge, piezoresistive, fiber optic, capacitive, MEMS, and / or mechanical sensor.

65. The system of claim 62, wherein the sensor comprises a temperature sensor comprising a thermocouple, a resistance temperature detector, a microelectromechanical sensor, an infrared sensor, and / or a distributed acoustic sensor employing fiber optic cables.

66. The system of claim 62, wherein the sensor comprises a rock deformation sensor comprising a seismometer, a geophone, a borehole strain gauge, a tiltmeter, a surface deformation sensor, a repeat leveling sensor, a time-dependent gravity sensor, and / or a distributed acoustic sensor employing fiber optic cables.

67. The system of claim 62, wherein the sensor is configured to measure gas generation within the solid domain, a volume change of the solid domain, and / or a local elastic modulus of the solid domain.

68. The system of any one of claims 51-67, wherein the solid domain has a volume of greater than or equal to 1 cubic meter.

69. A method of producing hydrogen, comprising: flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen.

70. The method of claim 69, further comprising directing at least a portion of the hydrogen through a removal conduit to a hydrogen storage location.

71. The method of any one of claims 69-70, wherein the aqueous fluid comprises an interfacial modifier and / or a rheology modifier.

72. The method of claim 71, wherein the interfacial modifier and / or rheology modifier comprises nanoparticles, a viscosifier, a polymer additive, and / or a surfactant.

73. The method of any one of claims 69-72, wherein the solid domain comprises ultramafic rock, mafic rock, and / or sedimentary rock containing ferrous iron.

74. The method of any one of claims 69-73, wherein the chemical reaction comprises a serpentinization reaction.

75. The method of any one of claims 69-74, wherein the flowing of the aqueous fluid induces fracturing of the solid domain.

76. The method of claim 75, wherein the fracturing of the solid domain produces fractures within the solid domain that are fluidically connected to the injection conduit and / or the removal conduit.

77. The method of claim 75, further comprising controlling fracture development in the solid domain by controlling a volume change of the solid domain caused by the chemical reaction.

78. The method of any one of claims 69-77, further comprising measuring gas generation within the solid domain, measuring a volume change of the solid domain, and / or measuring a local elastic modulus of the solid domain.

79. The method of any one of claims 69-78, wherein a volume of the solid domain changes by greater than or equal to 0.5 % and less than or equal to 110 % due to addition of water to and / or generation of hydrogen within the solid domain.

80. The method of any one of claims 69-79, wherein greater than or equal to 200 L of water is delivered to the solid domain.

81. The method of any one of claims 69-80, wherein, prior to the flowing, the solid domain has a volume of greater than or equal to 1 cubic meter.

82. A method of producing and processing hydrogen, comprising: flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; and forming a mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen, wherein: the mixture is contained within the injection conduit, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5.

83. A method of producing and processing hydrogen, comprising: flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; concentrating gas -containing bubbles from multiphase gas-liquid mixture comprising at least a portion of the aqueous fluid and the hydrogen; andexposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

84. A method of generating and processing a multiphase gas-liquid mixture, comprising: contacting water with a source of a mineral comprising a material capable of reacting with water to produce hydrogen such that at least a portion of the water reacts with the material to form hydrogen; forming a multiphase gas-liquid mixture comprising water and hydrogen, wherein: the mixture is contained within a conduit fluidically connected to the mineral, and the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5; concentrating gas -containing bubbles from the multiphase gas-liquid mixture; and exposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

85. A method of producing and processing hydrogen, comprising: flowing an aqueous fluid from a source, through an injection conduit, to a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen such that a chemical reaction between water from the aqueous fluid and the one or more minerals occurs to produce hydrogen; forming a multiphase gas-liquid mixture comprising at least a portion of the water from the aqueous fluid and at least a portion of the hydrogen, wherein the mixture comprises hydrogen in the water in a mole fraction of greater than or equal to 10'5; concentrating gas -containing bubbles from the multiphase gas-liquid mixture; andexposing the gas -containing bubbles to a surface comprising a plurality of microscale and / or nanoscale features such that gas from the gas-containing bubbles is separated from liquid from the multiphase gas-liquid mixture.

86. A system for producing and processing hydrogen, comprising: a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; and a mixture comprising liquid water and hydrogen disposed within the injection conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5.

87. A system for producing and processing hydrogen, comprising: a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; a concentrator configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas comprising at least a portion of the hydrogen within the gas-containing bubbles and a liquid comprising at least a portion of the aqueous fluid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

88. A system for producing and processing a multiphase gas-liquid mixture, comprising: a source of a mineral comprising a material capable of reacting with water to produce hydrogen; a conduit fluidically connected to the source of the mineral; a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5; a concentrator fluidically connected to the conduit and configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

89. A system for producing and processing hydrogen, comprising: a solid domain comprising one or more minerals comprising a material capable of reacting with water to produce hydrogen; a source of aqueous fluid; an injection conduit fluidically connected to the source of aqueous fluid and the solid domain, wherein the injection conduit is configured to deliver aqueous fluid to the solid domain and react with the one or more minerals comprising a material capable of reacting with water to produce hydrogen via a chemical reaction to produce hydrogen; a multiphase gas-liquid mixture comprising liquid water and hydrogen disposed within the conduit, wherein the mixture comprises hydrogen in a mole fraction of greater than or equal to 10'5; a concentrator fluidically connected to the conduit and configured to concentrate gas-containing bubbles from a multiphase gas-liquid mixture, the multiphase gas-liquid mixture comprising gas within the gas-containing bubbles and a liquid; and a surface fluidically connected to the concentrator, wherein the surface comprises a plurality of microscale and / or nanoscale features that allow for selective removal of gas from within the gas bubbles relative to the liquid.

90. A method of producing geologic hydrogen comprising a. promoting chemical cracking of the source ultramafic rock from the serpentinization reaction; and b. enhancing transport of hydrogen in the fracture network via interfacial and rheological additives that foster bubble exsolution and coarsening.

91. The method of claim 90, further comprising: c. designing th-philic membranes for fast and efficient downhole separation.

92. The method of any one of claims 90-91, wherein promoting chemical cracking of the source ultramafic rock from the serpentinization reaction comprises use the ultrasound probes to send known pulses in regular intervals to sample the changes in travel time which will correspond to changes in elastic moduli, to obtain accurate reaction rates at a high temporal resolution.

93. The method of any one of claims 90-92, further comprising using learning methods to distinguish between reactive cracking and bubble nucleation and burst.

94. The method of any one of claims 90-93, further comprising calibrating ultrasound measurements of reaction progress by scanning samples using pCT before and after deformation to quantify the volume of serpentinization and the resultant fracture patterns.

95. The method of any one of claims 90-94, further comprising performing electron microscopy to quantify the effects of serpentinization.

96. The method of any one of claims 90-95, wherein enhancing transport of hydrogen comprises using interfacial modifiers with combinations of gasphilic nanoparticles and surfactants to stabilize the gas-liquid interface and make it unfavorable for bubbles to adhere to walls.

97. The method of any one of claims 90-96, wherein phase-field methods are used to model bubble exsolution and evolution.- I l l -98. The method of any one of claims 90-97, wherein hydrogen evolution is controlled by altering an applied current density.

99. The method of any one of claims 90-98, wherein the H -philic membranes comprise a cyclone separator equipped with a high permeability gasphilic membrane.

100. The method of any one of claims 90-99, wherein the H -philic membranes are configured so that rising bubbles at a central axis are concentrated and defoamed at the top by the gasphilic membrane where the gas is collected, while the liquid is pumped out to be reused.