Methods of enhanced geologic gas extraction

Abstract

The disclosed subject matter relates to methods of enhanced geologic gas extraction, such as methods of enhanced geologic hydrogen extraction from iron-bearing rocks. For example, disclosed herein are methods for enhanced geologic gas extraction, the method comprising: contacting a carrier gas with an aqueous phase comprising a dissolved geologic gas, wherein the carrier gas is miscible with the geologic gas; wherein the geologic gas was produced by a geologic formation; such that the carrier gas contacts the aqueous phase and at least a portion of the geologic gas exsolves from the aqueous phase and partitions into the carrier gas via thermodynamic phase partitioning; thereby enhancing the extraction of the geologic gas. Also disclosed herein is a process for enhanced generation of the geologic gas by enhanced extraction of the geologic gas. Also disclosed herein is a process for shifting a geochemical reaction equilibrium via enhanced extraction of the geologic gas.

Description

[0001] 10046-669WO1; 8626 SON METHODS OF ENHANCED GEOLOGIC GAS EXTRACTION CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of priority to U. S. Provisional Application No.

[0002] 63 / 750,106 filed January 27, 2025, U.S. Provisional Application No. 63 / 750,108 filed January- 27, 2025, U. S. Provisional Application No. 63 / 750,123 filed January 27, 2025, and U. S.

[0003] Provisional Application No. 63 / 750,116 filed January 27, 2025, each of which is hereby- incorporated herein by reference in its entirety.

[0004] STATEMENT OF GOVERNMENT SUPPORT

[0005] This invention was made with government support under Grant no. DE-AR0001873 and DE-AC05-76RL01830 awarded by the Department of Energy. The government has certain rights in the invention.

[0006] BACKGROUND

[0007] Geologic hydrogen, both natural and stimulated, is a carbon-free fuel capable of providing hundreds of year's of global energy at current consumption rates. While laboratory and field studies are recently underway to enable geologic H₂ production and extraction, two key challenges bar their feasibility. First, despite the low solubility of H₂ in brine (~ ppm), H₂ saturation concentrations at geologic conditions are still greater than the reaction equilibrium concentration for H₂-generating reactions (e.g., serpentinization). In other words, geologic H₂ exists primarily as a dissolved phase, the extraction of which would require co-producing up to -1 million times its mass in water. Second, the low reaction equilibrium concentration limits the rate of H₂ generation reactions. Approaches to extract dissolved H₂ without brine co-production and those that shift the reaction equilibrium in favor of continued H₂ generation are needed for geologic H₂ to be viable. The compositions, devices, and methods discussed herein address these and other needs.

[0008] SUMMARY

[0009] In accordance with the purposes of the disclosed compositions, methods, and systems as embodied and broadly described herein, the disclosed subject matter relates to methods of enhanced geologic gas extraction, such as methods of enhanced geologic hydrogen extraction from iron-bearing rocks.

[0010] For example, disclosed herein are methods for enhanced geologic gas extraction, the method comprising: contacting a carrier gas with an aqueous phase comprising a dissolved geologic gas, wherein the carrier gas is miscible with the geologic gas; wherein the geologic gas was produced by a geologic formation, such as by a reaction said geologic formation; such that the carrier gas contacts the aqueous phase and at least a portion of the geologic gas exsolves10046-669W01; 8626 SON from the aqueous phase and partitions into the carrier gas via thermodynamic phase partitioning; thereby enhancing the extraction of the geologic gas.

[0011] In some examples, the geologic gas is naturally occurring.

[0012] In some examples, the geologic gas is generated via stimulation.

[0013] In some examples, the geologic gas comprises hydrogen (H₂), helium (He), methane (CH₄), argon (Ar), or a combination thereof.

[0014] In some examples, the geologic gas comprises hydrogen (e.g., wherein the geologic gas comprises geologic hydrogen). In some examples, the geologic hydrogen was produced by reaction between iron from an iron-bearing rock and water or hydrogen bearing compounds, and the aqueous phase is proximate to the iron-bearing rock.

[0015] In some examples, said contacting occurs in situ within the geologic formation.

[0016] In some examples, the method comprises injecting the carrier gas into the geologic formation.

[0017] In some examples, the geological formation comprises iron-bearing rock. In some examples, the iron-bearing rock comprises olivine. In some examples, the iron-bearing rock comprises (ultra)mafic rock.

[0018] In some examples, the geologic formation comprises a basaltic formation.

[0019] In some examples, the geologic formation comprises an aquifer.

[0020] In some examples, the geologic formation is a geothermally-active formation.

[0021] In some examples, the aqueous phase comprises brine.

[0022] In some examples, the carrier gas comprises air, CH4, N2, shale gas, CO2, waste gas, flue gas, steam, or a combination thereof. In some examples, the carrier gas comprises air, CH₄, N₂, CO₂, steam, or a combination thereof. In some examples, the carrier gas comprises nitrogen. In some examples, the carrier gas comprises methane. In some examples, the carrier gas comprises carbon dioxide. In some examples, the carrier gas comprises a mixture of gases.

[0023] In some examples, the carrier gas comprises processed or unprocessed shale gas from wells, fugitive gas from various wells (e.g., oil and gas reservoirs), waste gas from various industrial applications (e.g., mining operations, power plants, etc.), or a combination thereof.

[0024] In some examples, the carrier gas is in the form of a gas in water emulsion with a surfactant.

[0025] In some examples, the carrier gas is in the form of a foam. In some examples, the foam is stabilized by a stabilizer comprising surfactants, particles, or a combination thereof.

[0026] In some examples, the foam is a Pickering foam. In some examples, the Pickering foam further comprises a Pickering foaming agent. In some examples, the Pickering foaming agent10046-669WO1; 8626 SON comprises a plurality of particles. In some examples, the plurality of particles comprise silica nanoparticles, natural fine particles (e.g., clays, talc, etc.), mine tailings, proppants, industrial waste particulates (e.g., coal ash), iron-rich particulates, fine particulates in the geologic formation (e.g., talc, smectite, clays, etc.) that were pre-existing and / or produced autogenically during reaction stimulation, or a combination thereof. In some examples, the plurality of particles comprise Kaolinite In some examples, the plurality of particles comprise Silica nanoparticies. In some examples, the plurality of particles comprise Functionalized silica nanoparticles, such as PEG-functionalized silica nanoparticies. In some examples, the ratio of Pickering foaming agent to aqueous and gas phases is selected to optimize extraction of the geologic hydrogen and stability of the foam.

[0027] In some examples, the foam is substantially free of surfactants, such as sodium dodecyl sulfate (SDS), Tween, and cetyltrimethylammonium bromide (CTAB).

[0028] In some examples, the foam maximizes interfacial area between the aqueous phase and the carrier gas phase.

[0029] In some examples, the high surface area to volume ratio of the foam further enhances the extraction of the geologic gas by promoting partitioning and extraction of the geologic gas into the carrier gas phase of the foam.

[0030] In some examples, the foam further increases the effective viscosity thereby enabling conformance control and increasing the volume of the geologic formation contacted for reaction. In some examples, the increase in effective viscosity decreases the likeliness of viscous fingering in the geologic formation, increases overall sweep efficiency, or a combination thereof.

[0031] In some examples, the foam self-stabilizes flow through porous media, such as the geologic formation.

[0032] In some examples, the foam is stable under harsh geologic conditions in situ.

[0033] In some examples, the method comprises injecting a stabilizer, such as a Pickering foaming agent, and generating the foam in situ.

[0034] In some examples, the carrier gas comprises steam that is generated in situ, for example when the geologic formation is geothermally active.

[0035] In some examples, extracting the geologic gas shifts the geologic gas generation reaction equilibria forward, thereby further enhancing the rate of geologic, gas generation. In some examples, the geologic gas comprises geologic hydrogen, and extracting the geologic hydrogen shifts the geologic hydrogen generation reaction equilibria forward, thereby further enhancing the rate of geologic hydrogen generation.

[0036] In some examples, the methods further comprise collecting the carrier gas with the10046-669WO1; 8626 SON dissolved geologic gas and optionally storing the carrier gas with the dissolved geologic gas.

[0037] In some examples, the carrier gas is in the form of any of the foams disclosed herein, and separating comprises deconstructing the foam into a solution phase and a gas phase by inducing changes in the pH, salinity, and / or temperature of the foam, wherein the gas phase comprises the carrier gas with the dissolved geologic gas. In some examples, the methods further comprise reusing the solution phase in any of the methods disclosed herein.

[0038] In some examples, the methods further comprise separating the geologic gas from the carrier gas and optionally storing the geologic gas and / or carrier gas after separation. In some examples, separating the geologic gas from the carrier gas comprises distillation, membrane separation, pressure swing adsorption, temperature swing adsorption, or a combination thereof.

[0039] In some examples, the methods further comprise after separating the geologic gas from the carrier gas, reusing the carrier gas in any of the methods disclosed herein.

[0040] In some examples, the methods further comprise using the collected geologic gas.

[0041] In some examples, the method does not include water and / or brine co-production.

[0042] Also disclosed herein is a process for enhanced generation of the geologic gas by¬ enhanced extraction of the geologic gas via any of the methods disclosed herein.

[0043] Also disclosed herein is a process for shifting a geochemical reaction equilibrium via enhanced extraction of the geologic gas using any of the methods disclosed herein.

[0044] Additional advantages of the disclosed compositions, systems, and methods will be set forth in part in the description which follows, and in part will be obvious from the description. The advantages of the disclosed compositions, systems, and methods will be realized and attained by means of the elements and combinations particularly pointed out in the appended claims. It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the disclosed compositions, systems, and methods, as claimed.

[0045] The details of one or more embodiments of the invention are set forth in the accompanying drawings and the description below. Other features, objects, and advantages of the invention will be apparent from the description and drawings, and from the claims.

[0046] BRIEF DESCRIPTION OF THE FIGURES

[0047] The accompanying figures, which are incorporated in and constitute a part of this specification, illustrate several aspects of the disclosure, and together with the description, serve to explain the principles of the disclosure.

[0048] Figure 1. Schematic illustration of methods disclosed herein.

[0049] Figure 2. Schematic illustration of mobilizing trapped H₂ and catalyzing geologic H₂10046-669WO1; 8626 SON generation via the compositions, systems, and methods disclosed herein.

[0050] Figure 3. A benchmark is to achieve 5 vol.% H₂ in effluent using inert gas-water or foam injection to measured using a residual gas analyzer (RGA).

[0051] Figure 4. Partitioning of H₂ from an H₂-saturated aqueous phase into the inert gas / foam. Figure 5. Schematic illustration of HiPVT apparatus for gas solubility testing.

[0052] Figure 6. Photographs of high-pressure reactors.

[0053] Figure 7. Silica nanopartide functionalization.

[0054] Figure 8. FTIR results for silica nanoparticle functionalization.

[0055] Figure 9. UV-vis results for silica nanoparticle functionalization.

[0056] Figure 10. Pickering foam stability.

[0057] Figure 11. Pickering foam stability.

[0058] Figure 12. Pickering foam generation.

[0059] Figure 13. Pickering foam characteristics.

[0060] Figure 14. Pickering foam characteristics.

[0061] Figure 15. Schematic illustration of low surface coverage (LSC) PEG coated silica particles and high surface coverage (HSC) PEG coated silica particles.

[0062] Figure 16. Pickering foam stability at 5 wt.% brine.

[0063] Figure 17. Pickering foam stability at 10 wt.% brine.

[0064] Figure 18. Pickering foam stability at 20 wt.% brine.

[0065] Figure 19. Schematic illustration of the device used for high pressure foam testing. Figure 20. Solubility of H₂ and N₂ in water. Adapted from Wiebe R and VL Gaddy, JACS, 1935, 27.8, 1487-1488.

[0066] Figure 21. Solubility of H₂ and N₂ in water. Adapted from Zhiwei et al. Energies, 2022, 5021.

[0067] Figure 22. Solubility of a gas mixture.

[0068] Figure 23. Bulk H₂ solubility.

[0069] Figure 24. Stripping reactor design for kinetic experiment.

[0070] Figure 25. Stripping experiment results.

[0071] Figure 26. Stripping experiment results.

[0072] Figure 27. Batch reactor design for ambient pressure H₂ partitioning.

[0073] Figure 28. Theoretical modeling of [H₂] in gaseous and aqueous phases after ambient pressure partitioning.

[0074] Figure 29. Experimental H₂ partitioning results under ambient conditions using batch reactor.10046-669W01; 8626 SON Figure 30. Glass micromodel fabrication for high pressure H - partitioning.

[0075] Figure 31. High pressure H₂ partitioning.

[0076] Figure 32. High pressure H2 partitioning.

[0077] Figure 33. High pressure H partitioning.

[0078] Figure 34. H₂ partitioning.

[0079] Figure 35. In situ H2(aq) quantification.

[0080] Figure 36. In situ H2(aq) quantification.

[0081] Figure 37. In situ H2(aq) quantification.

[0082] Figure 38. Micromodel.

[0083] Figure 39. High pressure real -rock microfluidics.

[0084] Figure 40. Proof of concept study here shows effective H2(aq) removal from brine into inert gas.

[0085] Figure 41. Hydrogen uses.

[0086] Figure 42. Types of hydrogen.

[0087] Figure 43. Hydrogen underground.

[0088] Figure 44. Schematic illustration of methods disclosed herein.

[0089] Figure 45. Experimental setup.

[0090] Figure 46. Hydrogen partitioning into gas.

[0091] Figure 47. Dissolution.

[0092] Figure 48. H2 partitioning into the gas phase.

[0093] Figure 49. H₂ concentration in the gas phase.

[0094] Figure 50. H₂ concentration in water.

[0095] Figure 51. Partitioning coefficient.

[0096] Figure 52. New photomask for partitioning coefficient quantification.

[0097] Figure 53. H₂ concentration in the gas phase.

[0098] Figure 54. Background on nanoparticle foam stability.

[0099] Figure 55. System components.

[0100] Figure 56. Methodology.

[0101] Figure 57. UV-Vis absorption spectra for nanoparticle characterization.

[0102] Figure 58. DLS Zetasizer testing results for nanoparticle characterization.

[0103] Figure 59. Bubble size analysis.

[0104] Figure 60. Average bubble size diameter of PEG-NP in 10% brine foam.

[0105] Figure 61. Foam stability testing (ambient air) at varying brine percent (5%, 10%, and

[0106]

[0107] 10046-669WO1; 8626 SON Figure 62. Talc in Brine (left) and Talc + PEG-NP in DI (right).

[0108] Figure 63. Talc + 2 pmol PEG-NP in 20% brine.

[0109] Figure 64. Average bubble diameter results for PEG-NP in 20% brine foam.

[0110] Figure 65. Schematic illustration of different surface coverage by ligands.

[0111] Figure 66. PEG grafting density at the silica surface measured by TGA plotted as a function of PEG-silane added to the reaction. The black line fits the data to a Langmuir adsorption model with a maximum coverage of 2.37 μmol / m2[3].

[0112] Figure 67. Representation of the process of extracting geologic H2 using Pickering foams.

[0113] Figure 68. Variations in equilibrium H2 concentration with depth during olivine serpentinization. The dashed lines indicate the solubility limits of H? in water (black, at 30 °C) and 1 M NaCl brine (red, at 40 °C) under varying depth conditions. Here, depths were calculated by proxy of hydrostatic pressures using P =pbrinegh with average brine density pbrine ~ 1023.6 kg / m3. The influence of temperature variations with depth is neglected here. Previous experimental studies consistently show that, across all laboratory conditions, the final molecular H2 concentrations produced by the serpentinization process are significantly lower than the corresponding solubility limits (Berndt et al., 1996; McCollom et al., 2001, 2011, 2016, 2020; Neubeck et al., 2011; Allen et al., 2003; Jones et al., 2010).

[0114] Figure 69a-Figure 69c. Hydrogen partitioning dynamics and recovery behavior in the micromodel. (Figure 69a) Time -lapse brightfield images showing bubble growth driven primarily by molecular H? transfer from pre-saturated water into trapped N?. bubbles. Here, the pressure was maintained at 7.58 MPa. (Figure 69b) Comparison between measured (symbols) and simulated (curves) II2 mole fractions inside the trapped bubbles at 3.45 and 7.58 MPa. A rapid initial enrichment followed by stabilization was observed as the bubble and liquid phases approached equilibrium. 'The lower steady-state mole fraction at 7.58 MPa reflects the lower H₂:N₂ ratio of the initial inlet water. (Figure 69c) Hydrogen recovery behavior as a function of bubble numbers, k. Right (symbols): Cumulative hydrogen recovery increased sharply with bubble count. A near-complete extraction was calculated for the case with -85 bubbles within five minutes, highlighting the dominant control of interfacial area in controlling mass transfer. Left (curves): Outlet H2 concentration decreased with time and bubble population, linking microscale partitioning dynamics to macroscopic hydrogen depletion in the effluent water.

[0115] Figure 70a-Figure 70b. The mole fractions of II2 and N2 of the injected gases, gas phases after partitioning, and the percent of recovered II2 from aqueous phase (Figure 70a) without10046-669WO1; 8626 SON kaolinite, and (Figure 70b) with kaolinite. Kaolinite-stabilized gas / brine interfaces are denoted in orange.

[0116] Figure 71a-Figure 71c. Preparation and investigation of N2 inert carrier foams. (Figure 71a) Schematic diagram of high-pressure foam generation and in-situ observation setup.

[0117] Swagelok tube packed with ~ 180 pm spherical glass beads was used as bead pack to mix well between N2 and NP solution for foam generation. A view cell was connected downstream of the bead pack to assess the stability of generated foams. The pressure was stabilized using a back pressure regulator. (Figure 71b) Foams generated under different flow rate ratios (R = gas flow rate / solution flow rate) show that increasing the gas flow rate results in foams with more uniform and smaller bubble diameters. The insert optical image are the foams obtained under a value of R = 1:1. The scale bar length is 100 pm. (Figure 71c) The stability of the generated foams was carefully investigated. Over an 8-hour observation period, no significant changes in foam size were observed, indicating excellent foam stability.

[0118] Figure 72a-Figure 72b. (Figure 72a) Dimensional information of the prepared micromodel. (Figure 72b) Schematic diagram of the experimental setup for the hydrogen (H2) partitioning investigation.

[0119] Figure 73a-Figure 73b. Experimental setup for static H2 partitioning experiments. (Figure 73a) Schematic diagram of the high-pressure cell, inlets and outlets, and monitoring; (Figure 73b) detailed schematic of high-pressure cell.

[0120] Figure 74. The preparation of functionalized NPs for N2 foam generation. (Left) Functionalization process for Si NPs. (Right) FTIR spectra of bare Si NPs and PEG functionalized Si NPs.

[0121] DETAILED DESCRIPTION

[0122] Before the present compositions, methods, and systems are disclosed and described, it is to be understood that the aspects described below are not limited to specific synthetic methods or specific reagents, as such may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular aspects only and is not intended to be limiting.

[0123] Also, throughout this specification, various publications are referenced. The disclosures of these publications in their entireties are hereby incorporated by reference into this application in order to more fully describe the state of the art to which the disclosed matter pertains. The references disclosed are also individually and specifically incorporated by reference herein for the material contained in them that is discussed in the sentence in which the reference is relied upon.10046-669WO1; 8626 SON In this specification and in the claims that follow, reference will be made to a number of terms, which shall be defined to have the following meanings.

[0124] Throughout the description and claims of this specification the word “comprise” and other forms of the word, such as “comprising” and “comprises,” means including but not limited to, and is not intended to exclude, for example, other additives, components, integers, or steps. As used in the specification and in the claims, the term “comprising” can include the aspects “consisting of” and “consisting essentially of.”

[0125] As used in the description and the appended claims, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a composition” includes mixtures of two or more such compositions, reference to “an agent” includes mixtures of two or more such agents, reference to “the component” includes mixtures of two or more such components, and the like.

[0126] “Optional” or “optionally” means that the subsequently described event or circumstance can or cannot occur, and that the description includes instances where the event or circumstance occurs and instances where it does not.

[0127] Ranges can be expressed herein as from “about” one particular value, and / or to “about” another particular value. By “about” is meant within 5% of the value, e.g., within 4, 3, 2, or 1% of the value. When such a range is expressed, another aspect includes from the one particular' value and / or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another aspect. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint.

[0128] “Exemplary” means “an example of” and is not intended to convey an indication of a preferred or ideal embodiment. “Such as” is not used in a restrictive sense, but for explanatory purposes.

[0129] Values can be expressed herein as an “average” value. “Average” generally refers to the statistical mean value.

[0130] By “substantially” is meant within 5%, e.g., within 4%, 3%, 2%, or 1%.

[0131] It is understood that throughout this specification the identifiers “first” and “second” are used solely to aid in distinguishing the various components and steps of the disclosed subject matter. The identifiers “first” and “second” are not intended to imply any particular order, amount, preference, or importance to the components or steps modified by these terms.

[0132] References in the specification and concluding claims to parts by weight of a particular element or component in a composition denotes the weight relationship between the element or10046-669WO1; 8626 SON component and any other elements or components in the composition or article for which a part by weight is expressed. Thus, in a compound containing 2 parts by weight of component X and 5 parts by weight component Y, X and Y are present at a weight ratio of 2:5, and are present in such ratio regardless of whether additional components are contained in the compound.

[0133] A weight percent (wt. %) of a component, unless specifically stated to the contrary, is based on the total weight of the formulation or composition in which the component is included.

[0134] The term “or combinations thereof’ as used herein refers to all permutations and combinations of the listed items preceding the term. For example, “A, B, C, or combinations thereof’ is intended to include at least one of: A, B, C, AB, AC, BC, or ABC, and if order is important in a particular context, also BA, CA, CB, CBA, BCA, ACB, BAC, or CAB.

[0135] Continuing with this example, expressly included are combinations that contain repeats of one or more item or term, such as BB, AAA, AB, BBC, AAABCCCC, CBBAAA, CABABB, and so forth. The skilled artisan will understand that typically there is no limit on the number of items or terms in any combination, unless otherwise apparent from the context.

[0136] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.

[0137] Compositions, Systems, and Methods

[0138] Disclosed herein are compositions, systems, and methods. For example, disclosed herein are methods of enhanced geologic gas extraction, such as methods of enhanced geologic hydrogen extraction from iron-bearing rocks.

[0139] For example, disclosed herein are methods for enhanced geologic gas extraction, the methods comprising: contacting a carrier gas with an aqueous phase comprising a dissolved geologic gas, wherein the carrier gas is miscible with the geologic gas; wherein the geologic gas was produced by a geologic formation, such as by a reaction said geologic formation; such that the carrier gas contacts the aqueous phase and at least a portion of the geologic gas exsolves from the aqueous phase and partitions into the carrier gas via thermodynamic phase partitioning; thereby enhancing the extraction of the geologic gas.

[0140] In some examples, the geologic gas is naturally occurring and / or the geologic gas is generated via stimulation. In some examples, the geologic gas is naturally occurring. In some examples, the geologic gas is generated via stimulation.

[0141] In some examples, the geologic gas comprises hydrogen (H2), helium (He), methane (CH₄), argon (Ar), or a combination thereof.

[0142] In some examples, the geologic gas comprises hydrogen (e.g., wherein the geologic gas10046-669WO1; 8626 SON comprises geologic hydrogen). In some examples, the geologic hydrogen was produced by reaction between iron from an iron-bearing rock and water or hydrogen bearing compounds, and the aqueous phase is proximate to the iron-bearing rock.

[0143] In some examples, said contacting occurs in situ within the geologic formation.

[0144] In some examples, the method comprises injecting the carrier gas into the geologic formation.

[0145] In some examples, the geological formation comprises iron-bearing rock.

[0146] In some examples, the iron-bearing rock comprises (ultra)mafic rock. As used herein the term “(ultra)mafic” includes mafic, ultramafic, or combinations thereof. As used herein the term “mafic” includes rocks that contain more than 10% mafic minerals (e.g., minerals containing significant amount of Fe and / or Mg, such as olivine, pyroxene, amphibole, chlorite, epidote, micas, or a combination thereof), whereas ultramafic rocks contain more than 85% mafic minerals. This definition includes altered forms of these rocks, such as metamorphosed variants (e.g., greenschist, amphibole, greenstone) and / or sedimentary and volcaniclastic variants.

[0147] In some examples, the iron-bearing rock comprises (ultra)mafic peridotite, (ultra)mafic pyroxenite, (ultra)mafic hornblendite, (ultra)mafic dunite, or a combination thereof.

[0148] In some examples, the iron-bearing rock comprises (ultra)mafic peridotite, (ultra)mafic pyroxenite, (ultra)mafic basalt, Archaean banded iron formations, (ultra)mafic dunite, or a combination thereof.

[0149] In some examples, the iron-bearing rock comprises mafic rock.

[0150] In some examples, the iron-bearing rock comprises olivine, pyroxene, amphibole, fayalite, or a combination thereof.

[0151] In some examples, the iron-bearing rock comprises olivine.

[0152] In some examples, the geologic formation comprises a basaltic formation.

[0153] In some examples, the geologic formation comprises an aquifer.

[0154] In some examples, the geologic formation is a geothermally-active formation.

[0155] In some examples, the aqueous phase comprises brine.

[0156] In some examples, the carrier gas comprises air, CH4, N2, shale gas, CO2, waste gas, flue gas, steam, or a combination thereof. In some examples, the carrier gas comprises air, CH₄, N₂, CO₂, steam, or a combination thereof. In some examples, the carrier gas comprises nitrogen. In some examples, the carrier gas comprises methane. In some examples, the carrier gas comprises carbon dioxide. In some examples, the carrier gas comprises a mixture of gases. In some examples, the carrier gas comprises processed or unprocessed shale gas from wells, fugitive gas from various wells (e.g., oil and gas reservoirs), waste gas from various industrial applications10046-669W01; 8626 SON (e.g., mining operations, power plants, etc.), or a combination thereof.

[0157] In some examples, the carrier gas is in the form of a gas in water emulsion with a surfactant.

[0158] In some examples, the carrier gas is in the form of a foam. In some examples, the foam is stabilized by a stabilizer comprising surfactants, particles, or a combination thereof.

[0159] In some examples, the foam is a Pickering foam. In some examples, the Pickering foam further comprises a Pickering foaming agent. In some examples, the Pickering foaming agent comprises a plurality of particles. In some examples, the plurality of particles comprise silica nanoparticles, natural fine particles (e.g., clays, talc, etc.), mine tailings, proppants, industrial waste particulates (e.g., coal ash), iron-rich particulates, fine particulates in the geologic formation (e.g., talc, smectite, clays, etc.) that were pre-existing and / or produced autogenically during reaction stimulation, or a combination thereof. In some examples, the plurality of particles comprise Kaolinite In some examples, the plurality of particles comprise Silica nanoparticles. In some examples, the plurality of particles comprise Functionalized silica nanoparticles, such as PEG-functionalized silica nanoparticles.

[0160] In some examples, the ratio of Pickering foaming agent to aqueous and gas phases is selected to optimize extraction of the geologic hydrogen and stability of the foam.

[0161] In some examples, the foam is substantially free of surfactants, such as sodium dodecyl sulfate (SDS), Tween, and cetyltrimethylammonium bromide (CTAB).

[0162] In some examples, the foam maximizes interfacial area between the aqueous phase and the carrier gas phase.

[0163] In some examples, the high surface area to volume ratio of the foam further enhances the extraction of the geologic gas by promoting partitioning and extraction of the geologic gas into the carrier gas phase of the foam.

[0164] In some examples, the foam further increases the effective viscosity thereby enabling conformance control and increasing the volume of the geologic formation contacted for reaction. In some examples, the increase in effective viscosity decreases the likeliness of viscous fingering in the geologic formation, increases overall sweep efficiency, or a combination thereof.

[0165] In some examples, the foam self-stabilizes flow through porous media, such as the geologic formation.

[0166] In some examples, the foam is stable under harsh geologic conditions in situ.

[0167] In some examples, the method comprises injecting a stabilizer, such as a Pickering foaming agent, and generating the foam in situ.

[0168] In some examples, the carrier gas comprises steam that is generated in situ, for example10046-669W01; 8626 SON when the geologic formation is geothermally active.

[0169] In some examples, extracting the geologic gas shifts the geologic gas generation reaction equilibria forward, thereby further enhancing the rate of geologic gas generation. In some examples, the geologic gas comprises geologic hydrogen, and extracting the geologic hydrogen shifts the geologic hydrogen generation reaction equilibria forward, thereby further enhancing the rate of geologic hydrogen generation.

[0170] In some examples, the methods further comprise collecting the carrier gas with the dissolved geologic gas and optionally storing the carrier gas with the dissolved geologic gas.

[0171] In some examples, the carrier gas is in the form of any of the foams described herein, and separating comprises deconstructing the foam into a solution phase and a gas phase by inducing changes in the pH, salinity, and / or temperature of the foam, wherein the gas phase comprises the carrier gas with the dissolved geologic gas. In some examples, the methods further comprise reusing the solution phase in any of the methods disclosed herein.

[0172] In some examples, the methods further comprise separating the geologic gas from the carrier gas and optionally storing the geologic gas and / or carrier gas after separation. In some examples, separating the geologic gas from the carrier gas comprises distillation, membrane separation, pressure swing adsorption, temperature swing adsorption, or a combination thereof. In some examples, the methods further comprise after separating the geologic gas from the carrier gas, reusing the carrier gas in any of the methods disclosed herein.

[0173] In some examples, the methods further comprise using the collected geologic gas.

[0174] In some examples, the methods do not include water and / or brine co-production.

[0175] Also disclosed herein are processes for enhanced generation of the geologic gas by entranced extraction of the geologic gas via any of the methods disclosed herein.

[0176] Also disclosed herein are processes for shifting a geochemical reaction equilibrium via enhanced extraction of the geologic gas using any of the methods disclosed herein.

[0177] A number of embodiments of the invention have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the invention. Accordingly, other embodiments are within the scope of the following claims.

[0178] The examples below are intended to further illustrate certain aspects of the systems and methods described herein, and are not intended to limit the scope of the claims.

[0179] EXAMPLES

[0180] The following examples are set forth below to illustrate the methods and results according to the disclosed subject matter. These examples are not intended to be inclusive of all aspects of the subject matter disclosed herein, but rather to illustrate representative methods and10046-669WO1; 8626 SON results. These examples are not intended to exclude equivalents and variations of the present invention which are apparent to one skilled in the art.

[0181] Efforts have been made to ensure accuracy with respect to numbers (e.g., amounts, temperature, etc.) but some errors and deviations should be accounted for. Unless indicated otherwise, parts are parts by weight, temperature is in °C or is at ambient temperature, and pressure is at or near atmospheric. There are numerous variations and combinations of measurement conditions, e.g., component concentrations, temperatures, pressures and other measurement ranges and conditions that can be used to optimize the described process.

[0182] Example 1

[0183] Disclosed herein are compositions, systems, and methods. For example, disclosed herein are compositions, systems, and methods for gas extraction from aqueous solutions.

[0184] Disclosed herein is a scheme to produce gases from geologic formations, including those dissolved in aqueous solutions and those existing as a separate phase. Geologic gases of economic importance (e.g., H2, He, CH4, Ar, etc.) are generated and accumulated in water-saturated environments. These gas species tend to have low water solubility (i.e., low concentrations in aqueous phase), and as a result, require the co-production of enormous volumes of brine that renders their recovery uneconomic.

[0185] The subject matter disclosed herein uses a carrier gas (e.g., air, N2, CH4, shale gas, CO2, waste gas, etc.) that is miscible with the geologic gas of interest to extract the geologic gas. Phase equilibria is leveraged to partition dissolved molecules from the aqueous phase into the injected gas or gas mixture. The target, gas species could be pre-existing accumulations (e.g., natural H2) or those generated via stimulation (e.g., geologic H2or H-bearing species resulting from engineered fluid-rock reactions). In all cases where economic gases are dissolved in water, equilibration of the water / brine with the injected phase causes the gases (e.g., H2(aq)to exsolve from the aqueous solution and partition into the gas.

[0186] Details:

[0187] - Target resource is geologic gas of economic importance (e.g., H2, He, CH4, Ar, etc.) o Could be dissolved gases or separate gas phase (trapped gas, gas bubbles, etc.) o Could be other H-bearing species of economic interest that is present in geologic formations

[0188] - 'Target resource could be

[0189] o existing accumulations of gases dissolved in water;

[0190] o natural systems where gases are being generated as a result of geochemical reactions (e.g., serpentinization); and / or10046-669WO1; 8626 SON o engineered systems where geochemical reactions are stimulated and gas generation rates are catalyzed / enhanced / accelerated.

[0191] - Phase equilibrium is leveraged to partition gas molecules dissolved in aqueous solutions into a miscible gas or gas mixture (or the phase of the extraction mixture in geologic conditions, including liquid and supercritical).

[0192] - The operation of a carrier gas injection can be combined with the water injection that may or may not carry other stimulants (e.g., acid and base).

[0193] Example 2 - Foam-enhanced hydrogen production

[0194] Described herein is a foam injection scheme to enhance the production and generation of natural hydrogen (also known as geologic hydrogen). Here, generation is defined as the creation of H2 molecules at the rock surface from water / mineral reactions, and production is defined as the mobilization of 11? molecules out of the pore fluid and to the surface. Deep in the Earth’s crust (~ 15 km), water reacts with mafic minerals (e.g., olivine) to produce II2 naturally in a process known as serpentinization. Specifically, the reaction requires dissolution of mafic minerals to donate Fe2+to the surrounding pore waters, and environments that enable simultaneous Fe2+oxidation and H2O reduction to generate H2(aq). Mafic minerals, favorably, occur throughout the crust (e.g., basalts, which comprise ~ 50 to 60% of Earth’s crust) and provide an enormous resource potential for clean H generation. Key challenges in practice, however, stem from the slow reaction kinetics in these natural systems where the equilibrium concentration of H2is lower than H2solubility in water.

[0195] The methods disclosed herein injects gas (e.g., air, vented gas from shale oil production, etc.) into basaltic formations to catalyze the rate of H2 generation and to enable II2 production from the pore fluids. Specifically, the methods disclosed herein leverage the thermodynamics of phase equilibria, where the H2(aq)that is generated at the mineral / water interface is partitioned into the gas phase. In doing so, the approach mobilizes the H2that is dissolved in the aqueous phase, and thereby reduces the dissolved H2 concentration to shift the H2generation reaction forward.

[0196] To maximize the effect of H2partitioning, the methods disclosed herein includes injecting gases as a foam to increase the gas / water interface. Particle-stabilized foams (i.e., Pickering foams) leveraging materials such as functionalized silica nanoparticles, clays, and other fine particulates with heterogeneous surface charge distributions maintain foam stability under extreme geologic conditions (e.g., high pressure, temperature, salinity, etc.). Particles that catalyze the serpentinization reaction (e.g., clays) that alter the reaction pathway are also included.10046-669WO1; 8626 SON Disclosed herein are:

[0197] Al. A method for the recovery of geologically derived hydrogen from aquifers comprised of injection of a second gas into the subsurface to contact hydrogen containing aqueous phase.

[0198] A2. The method in claim Al where the at levels above its solubility in the mass of water contacted

[0199] A3. The method in claim Al where the gas is nitrogen

[0200] A4. The method in claim Al where the gas in methane

[0201] A5. The method in claim Al where the gas is carbon dioxide

[0202] A6. I'he method in claim Al where a mixture of gases is introduced

[0203] A7. 'The method in claim 1 where the second gas (or mixture) is stabilized as a gas in water Pickering emulsion (subsequent claims on stabilizing particles)

[0204] A8. The method in claim A l where the second gas (or moisture ) is stabilized as a gas in water emulsion with a surfactant, (subsequent claims on different surfactants)

[0205] A9. The withdrawal of the second gas phase or emulsion with minimal water

[0206] A 10. The method in claim A9 in which after separation of the Hydrogen from the second gas (or mixture ) the non hydrogen components are reinjected to contact the hydrogen containing water

[0207] Al l. A process for the acceleration of hydrogen production by the removal of hydrogen in the aqueous phase by the method in claim Al, where the removal of hydrogen when its solubility at a given temperature and pressure is above its equilibrium concentration.

[0208] Example 3

[0209] Disclosed herein are compositions, systems, and methods. For example, disclosed herein are compositions, systems, and methods for shifting geochemical reaction equilibrium via gas exsolution.

[0210] Disclosed herein is a scheme to enhance the production and generation rates of natural hydrogen (also known as geologic hydrogen). Here, generation is defined as the creation of H molecules at the rock surface from water / mineral reactions (e.g., serpentinization), and production is defined as the mobilization of Fb molecules out of the pore fluid and to the surface. Deep in the Earth’s crust (~ 15 km), water reacts with mafic minerals (e.g., olivine) to produce H2 naturally (for example, serpentinization). Mafic minerals, favorably, occur throughout the crust (e.g., basalts, which comprises ~ 50 to 60% of Earth’s crust) and provide an enormous resource potential for clean H2generation. The H2 generation reaction dissolves Fe-bearing minerals to donate Fe2+to the surrounding pore waters, where simultaneous Fe2+oxidation and10046-669W01; 8626 SON H2O reduction generates H2(aq). In geologic settings where pressures are elevated, however, the equilibrium concentration of lb during this generation reaction is less than the solubility of H in water. As a result, the kinetics of H2generation are limited by the concentration of H2 dissolved in water.

[0211] The compositions, systems, and methods disclosed herein accelerate the rate of H2generation by leveraging le Chatelier’s principle and the thermodynamics of phase equilibria. An inert gas phase (e.g., air, vented gas from shale oil / gas production, flue gas, N2, CO2, CH4, etc.) that is miscible with H2is injected into the H2-generating formation. Equilibration of Hz-bearing water / brine with the gas phase causes H2(aq)to exsolve from the aqueous solution and partition into the gas. In doing so, the approach mobilizes the H2that is dissolved in the aqueous phase, and thereby reduces the dissolved H2concentration to shift the H2generation reaction forward.

[0212] Details:

[0213] - Reducing the aqueous concentration of H2shifts the H2generation reaction (e.g., serpentinization) forward to accelerate the rate of geologic H2(or H-bearing species) generation.

[0214] - Aqueous H2(or H-bearing molecular species) concentrations are decreased by exposing the H2-bearing brine to a second carrier gas that is miscible with H2. The dissolved H2partitions into the carrier gas phase according to phase equilibria. This decreases the dissolved concentration of H2, and forces the redox reaction to accelerate.

[0215] - Foams are one approach to deliver the carrier gas to shift the reaction equilibria.

[0216] Disclosed herein are

[0217] Bl. A method for the recovery of geologically derived hydrogen, CH4 or He from aquifers comprised of injection of a second gas or a second gas mixture into the subsurface to contact hydrogen containing aqueous phase.

[0218] B2. 'The method in claim B 1 where the injected gas is at levels above its solubility in the mass of water contacted.

[0219] B3. The method in claim B 1 where the gas is nitrogen.

[0220] B4. The method in claim B 1 where the gas in methane.

[0221] B5. The method in claim B 1 where the gas is carbon dioxide.

[0222] B6. The method in claim B 1 where a mixture of gases is introduced.

[0223] B7. Ihe method in claim Bl where the gas is processed or unprocessed shale gas from wells, fugitive gas from various wells (e.g., oil and gas reservoirs), and waste gas from various industrial applications (e.g., mining operations, power plants, etc.).

[0224] B8. A process for the acceleration of hydrogen production by the removal of hydrogen in the aqueous phase by the method in claim one, where the removal of hydrogen10046-669WO1; 8626 SON when its solubility at a given temperature and pressure is above its equilibrium concentration.

[0225] Example 4 - Foam-stabilization of gases

[0226] Disclosed herein are compositions, systems, and methods. For example, disclosed herein are compositions, systems, and methods for foam-stabilization of gases.

[0227] Disclosed herein is a scheme to stabilize carrier fluids (e.g., air, N2, CH4, CO2, flue gas, vented gas from shale oil / gas, etc.) used for extracting geologic gases (e.g., H2, He, etc.) dissolved in brine. Carrier gases partition dissolved gas species from aqueous solutions via phase equilibria (see U.S. Provisional Application No. 63 / 750,106), which can also accelerate the rate of their generation from fluid-rock reactions by shifting the reaction equilibrium forward (see U.S. Provisional Application No. 63 / 750,108). To maximize gas partitioning from brine to carrier gas, it is important to maximize the water-gas interfacial areas available for exchange.

[0228] Here, the carrier gas is injected as a foam to maximize the interfacial area between brine and the carrier gas. The presence of foam bubbles increases the contact area between brine and the extraction gas, and creates a massively parallelized gas partitioning reactor. Importantly, foams self-stabilize with flow through porous media, and increases the apparent viscosity of the injection fluid to maximize access of the carrier gas with the reservoir fluids. Specifically, injection of foams decreases the likeliness of viscous fingering in porous geologic reservoirs, and increases the overall sweep efficiency (i.e., volume of reservoir contacted for gas extraction).

[0229] Foams here can be stabilized by surfactants, particles, and / or combinations. Pickering foams stabilized with particles are favorable because of their stability in harsh geologic environments (high pressure, high temperature, high salinity, complex mineral surface physicochemistry, etc.).

[0230] To maximize the effect of H2partitioning, the methods disclosed herein include injecting gases as a foam to increase the gas / water interface. Particle-stabilized foams (i.e., Pickering foams) leveraging materials such as functionalized silica nanoparticles, clays, and other fine particulates with heterogeneous surface charge distributions maintain foam stability under extreme geologic conditions (e.g., high pressure, temperature, salinity, etc.). Particles that catalyze the serpentinization reaction (e.g., clays) that alter the reaction pathway are also included.

[0231] Details:

[0232] - A gas (or mixture) is stabilized as a gas-in-water Pickering emulsion (i.e., foam) using particles or particle / surfactant mixtures as below.

[0233] - A gas (or moisture) is stabilized as a gas-in -water emulsion with a surfactant.10046-669WO1; 8626 SON - Foams increase the interfacial areas available for aqueous / gas interaction. This maximizes the ability for inert carrier gases to interact with and extract dissolved gas species (e.g., H2(aq)from the aqueous solution.

[0234] - Foams will self-stabilize during flow through porous materials and maintain interfaces. - Foams increase the effective viscosity of the carrier gas and increases the sweep efficiency of the process (i.e., increases the contacted volume of the porous system).

[0235] - Foams reduce the buoyant separation of the carrier extraction gas from the aqueous phase to increase volumetric sweep and controllability in the reservoir.

[0236] - Pickering foams are stabilized with particles, and are advantageous because they are stable under extreme pressure, temperature, and salinity conditions encountered in the subsurface (unlike surfactants).

[0237] - Particles with mixed surface charge distributions (e.g., clays) enable strong Pickering foam stability.

[0238] - Gas could be:

[0239] o Air;

[0240] o N2;

[0241] o CH4;

[0242] O CO.

[0243] o Vented and / or flared gas from shale oil / gas production;

[0244] o Waste gases from a wide range of industrial sources (e.g., mining operations, power plants, etc.) and / or

[0245] o Some combination thereof.

[0246] - Stabilizing agent could be:

[0247] o Surfactants;

[0248] o Nanoparticles (e.g., silica, etc.);

[0249] o Functionalized nanoparticles (e.g., silica functionalized with PEG silane, GPTMS, etc. of various molecular weights and at a range of surface coverage densities);

[0250] o Natural fine particulates (e.g., clays, talc, etc.);

[0251] o Mine tailings;

[0252] o Industrial waste particulates (e.g., coal ash);

[0253] o Iron-rich particulates;

[0254] o Fine particulates in the geologic formation (e.g., talc, smectite / clays, etc. ) that are pre-existing;10046-669W01; 8626 SON o Fine particulates in the geologic formation (e.g., talc, smectite / clays, etc.) that are produced autogenically during reaction stimulation; and / or

[0255] o Some combination thereof

[0256] - Operation includes injection of foam, or cyclic approach with alternating injections of foam and stimulating agents for target gas generation (e.g., acids, bases, others).

[0257] Disclosed herein are:

[0258] C 1. A method for the recovery of geologically derived hydrogen, CH4 or He from geologic reservoirs comprised of injection of a foam.

[0259] C2. The method in claim Cl where the foam is stabilized by surfactants.

[0260] C3. The method in claim Cl where the foam is stabilized by nanoparticles, including natural (clays, talc) and / or synthetic (e.g., silica, functionalized nanoparticles)

[0261] C4. The method in claim Cl where the foam is stabilized by particles already present in the geologic formation.

[0262] C5. The method in claim C 1 where the foam is comprised of a second gas or gas mixture including nitrogen, methane, carbon dioxide, and / or air.

[0263] C6. The method in claim Cl where the gas is processed or unprocessed shale gas from wells, fugitive gas from various wells (e.g., oil and gas reservoirs), and waste gas from various industrial applications (e.g., mining operations, power plants, etc.).

[0264] C7. The method in claim C l where the second gas (or mixture) is stabilized as a gas in water Pickering emulsion (subsequent claims on stabilizing particles).

[0265] C8. The method in claim Cl where the second gas (or moisture) is stabilized as a gas in water emulsion with a surfactant (subsequent claims on different surfactants).

[0266] C9. The operation of foam can be combined with the water injection that may or may not carry other stimulants (e.g., acid and base).

[0267] Example 5 - Separation and recycling of geologic gases from carrier phases Disclosed herein are compositions, systems, and methods. For example, disclosed herein are compositions, systems, and methods for separation and recycling of geologic gases from carrier phases.

[0268] To extract geologic gases (e.g., H2, He, CH4, Ar, etc.) and / or to enhance their generation, carrier gas or gas mixtures can be injected into the subsurface where phase equilibria enables the reaction product (e.g., geologic gas) to partition from aqueous solutions into the carrier gas (U.S. Provisional Application No. 63 / 750,106), shifting the reaction forward (e.g., increasing the reaction rate of product gas generation, U.S. Provisional Application No. 63 / 750,108). Here, the gas may be stabilized as a surfactant- and / or particle-based foam to maximize the water / gas10046-669W01; 8626 SON interface available for phase partitioning (U. S. Provisional Application No. 63 / 750,123). Foams are important to maintaining high water-gas interface areas for gas partitioning, and for ensuring maximum volumetric contact in the subsurface. Importantly, foams also control the amount of the water phase in the reservoir during gas production and extraction.

[0269] Described herein is the fate of the H₂-laden foams that are produced at the surface or in-situ in the subsurface. Herein, the foam is deconstructed into the brine / stabilizing agent solution (e.g., surfactants, clays, nanoparticles, or combinations thereof as in U. S. Provisional Application No. 63 / 750,123) and the gas contained within the foam by inducing changes in the pH, salinity, and / or temperature of the foam environment. The brine / stabilizing agent solution is reinjected into the subsurface and reused for further gas extraction. The gas mixture (i.e., carrier gas and extracted geologic gas) is treated independently. For the case where the carrier gas is CH4 and the extracted gas is H₂, this mixture can be injected into pipelines for direct transport and use without extensive processing. In the cases where that is not true, then the carrier gas (e.g., N₂, air, CO₂, etc.) is separated from the extracted gas prior to reuse. Separation techniques include distillation, membrane, pressure swing adsorption, temperature swing adsorption, etc.).

[0270] Details:

[0271] - Foams that are laden with geologic gases of economic value (e.g., H₂, He, CH₄, Ar, etc.) are produced at the surface.

[0272] o Foams could comprise a carrier gas (e.g., produced gas from shale oil / gas reservoirs, N₂, air, CO₂, CH₄, etc.) and water, stabilized with surfactants and / or natural or synthesized micro / nanoparticles (see U. S. Provisional Application No. 63 / 750,123) - The second gas phase or emulsion is withdrawn with minimal water

[0273] - The foams are collapsed to separate brine / stabilizing agents (e.g., surfactants, particles, etc. as in U. S. Provisional Application No. 63 / 750,123) from the gas phase (carrier gas and extracted gas, e.g., CH₄+H₂).

[0274] o Foams are destabilized by shifting the pH, temperature, and / or salinity,

[0275] o Stabilizing agents will be washed into the aqueous phase for reuse.

[0276] - The brine and stabilizing agents are captured and reused for subsequent cycles.

[0277] - If the carrier gas is CH4and the extracted gas is II2, then the mixture can be used directly. - Otherwise, the carrier gas is separated from the extracted gas (e.g., distillation, membranes, pressure / temperature swing, etc.)

[0278] - After separation of the product gas (e.g., H₂, He, CH₄, etc.) from the second gas (or mixture) the carrier gas(es) are reinjected to contact the target gas containing water.10046-669W01; 8626 SON Example 6 - Gas extraction from aqueous solutions, Shifting geochemical reaction equilibrium via gas exsolution, Foam-stabilization of carrier gases, and Separation and recycling of geologic gases from carrier phases

[0279] Disclosed herein are compositions, systems, and methods for gas extraction from aqueous solutions, shifting geochemical reaction equilibrium via gas exsolution, foam¬ stabilization of carrier gases, and separation and recycling of geologic gases from carrier phases.

[0280] The team has expertise in flow through porous media and geochemistry, colloidal and interfacial science, and geochemical microfluidics. The technology herein relates to inert nanoparticle-stabilized Pickering foams to capture and transport H₂ in the reservoir and foam-assisted conformance control to maximize sweep efficiency and H₂ extraction (Figure 1).

[0281] The compositions, systems, and methods disclosed herein can enable production of 33,437 metric tons Wyear at a cost of < $0.62 / kgH2 with minimal water use. The compositions, systems, and methods disclosed herein can provide pathways to accelerate rates of geologic H₂ generation by shifting the brine composition.

[0282] Objectives include, but are not limited to:

[0283] 1. IF transfer from water phase and II2 bubbles to CH4phase

[0284] 2. Foam generation

[0285] 3. Foam Characterization

[0286] 4. In situ wettability and its alteration with foam injection 5. Packed bed reactor experiments

[0287] 6. Reservoir modeling.

[0288] A schematic illustration of mobilizing trapped H₂ and catalyzing geologic H₂ generation via the compositions, systems, and methods disclosed herein is shown in Figure 2.

[0289] Go / No Go Target. The concept feasibility of hydrogen extraction using an inert gas or dry inert gas-foams is tested. A benchmark is to achieve 5 vol.% H₂ in effluent using inert gaswater or foam injection to measured using a residual gas analyzer (RGA) (Figure 3). The target of 5 vol.% proves the concept of feasibility and exceeds any measurement errors associated with the resolution of the RGA. Secondarily, the partitioning of H₂ from an H₂-saturated aqueous phase into the inert gas / foam is examined (Figure 4).

[0290] Reactor system development. A high-pressure reactor system will be developed to enable imaging of H₂ dissolution and foam generation. Pressures up to 1200 psi will be needed to simulate reservoir conditions for the Tamarack formation. A test cell will be built using Hydex with a series of sampling ports and viewing windows (minimum 1) to provide imaging data on the transfer mechanisms and rates of dissolved and separate phase H₂ to an inert gas.10046-669WO1; 8626 SON HiPVT apparatus for gas solubility testing. A schematic illustration of HiPVT apparatus for gas solubility testing is shown in Figure 5. The apparatus is capable of working up to 1000 psia and at temperatures between 20-80°C. The apparatus can handle both pure gases as well as gas mixtures. Gas chromatography is used for in situ head space gas composition measurements.

[0291] High-pressure reactors. Photographs of high-pressure reactors are shown in Figure 6. More experiments will be conducted to understand the transport and equilibrium behaviors at higher pressures and temperatures.

[0292] Nanoparticle surface modification. Select and generate three surface modification systems for nanoparticles to generate inert foams for testing. To begin with, a bare silica nanoparticle base will be used and varying grafting densities of ligand additives, such as polyethylene glycol (PEG) and sodium dodecyl sulfate (SDS), at a range of surface coverages (e.g., 2, 4, 8, 12, and 16 μmol / m²) and surfactant concentrations (e.g., 0.1, 0.5, 1, and 2 wt.%) will be tested.

[0293] Silica nanoparticle functionalization. Silica nanoparticle functionalization is shown schematically in Figure 7, with FTIR results in Figure 8 and Table 1, and UV-Vis results in Figure 9. Characteristic adsorption peaks were observed from FTIR spectroscopy (Figure 8 and Table 1). Characteristic adsorption peaks belonging to PEG-silane are observed for the treated nanoparticles (NPs) (Figure 8 and Table 1). This observation denotes the successful chemical bonding between silica nanoparticles and PEG-silane.

[0294] Table 1. FTIR results for silica nanoparticle functionalization (Figure 8).

[0295] Position (cm-1) Bonds

[0296] 2940-2860 C-H stretching vibration

[0297] 1455 CH2 bending vibration

[0298] 1350 CH3 bending vibration

[0299] 1000-1250 Si-O-Si and -C-O-C- 945 Stretching vibration of C-O-C

[0300] 785 Vibration of C-H bonds in aromatic rings

[0301]

[0302] Pickering foam stability. Pickering foam stability testing and results are shown in Figure 10-Figure 11.

[0303] Foam generation. Inert nanoparticle-stabilized gas / water foams are generated. The stability of the foams are tested at a range of temperatures (between 20-40°C), pressures10046-669W01; 8626 SON (between 1 atm to 1200 psi), and brine compositions. Foam stability as a function of nanoparticle loading and aqueous phase concentrations (e.g., dryness) can be measured by tracking the foam size distribution and / or foam column height changes over several days. Effective viscosity of the foam can also be measured to understand the changes in mobility ratios induced by foam injection.

[0304] Pickering foam generation. Pickering foam generation and results are shown in Figure 12.

[0305] Pickering foam characteristics. Pickering foam characteristics are shown in Figure 13 -Figure 14.

[0306] Pickering foam stability. Pickering foam stability was investigated for low surface coverage (LSC) PEG coated silica particles and high surface coverage (HSC) PEG coated silica particles at different brine concentrations (Figure 15 - Figure 18).

[0307] HSC PEG coated particles have a smaller interfacial tension than the LSC PEG coated particles. The lower interfacial tension for the HSC particles can enable more particles to attach to the air / water interface, allowing for stabilization of smaller bubbles.

[0308] Increased PEG-silane density enhances this steric hinderance, preventing nanoparticles from aggregating and leading to the formation of smaller, more uniform foam bubbles.

[0309] High pressure foam testing. A schematic illustration of the device used for high pressure foam testing is shown in Figure 19.

[0310] H2 partitioning into inert foam. The solubility and dissolution rates of H2 in water and inert gas will be quantified. Two-bubble experiments will be performed to determine the critical bubble size ratio needed for gas coalescence. For H₂ bubbles below the critical radius for coalescence, the rate of H₂ diffusion into the gas bubble will be measured across the water film. A phase map of diffusion- and coalescence-dominated mass transfer will be developed.

[0311] Partitioning of H2 with inert foams will be characterized and optimized. The rate at which H₂ diffuses into the gas foam will be measured as a function of particle loading, bubble size ratios, and foam water content. The frequency of H₂ coalescence with foam bubbles will be measured. These data will be compared to baseline rates of H2 mass transfer without the foams.

[0312] Solubility of H2 and N2 in water. Solubility of H2 and N2 in water are shown in Figure 20-Figure 21. The solubility of the mixture gas (75% H2 and 25% N2) obtained by experiments equals to 0.75 solubility of H₂ and 0.25 solubility of N₂ under the specific pressure:

[0313] S(75% H₂ + 25% N₂) = 75% SH2+ 25% SN2

[0314] Under pressure of 500 psi (-34 atm), the solubility of H₂ and N₂ is 51.6 ppm and 47.8 ppm, respectively.10046-669W01; 8626 SON Solubility of a gas mixture. The solubility of a gas mixture is shown in Figure 22. Test conditions for partition study:

[0315] - Cell temperature 35 °C

[0316] - Cell filled with 300 psi of N₂, and then filled with H₂ to required composition - Head space samples from the cell were taken out and analyzed using GC

[0317] - The calculated data is compared with pure H₂ solubility data tested under similar conditions

[0318] Initial Observations:

[0319] - Increasing partial pressure of H₂ seems to show decreased H₂ solubility in water Future work

[0320] - More tests ongoing with different composition of H₂ / N₂

[0321] - CH4 solubility in water is higher than that of N2, it’s possible that II 2 partition might be more apparent in CH4. Future tests planned with CH4 / H2 mixtures.

[0322] Bulk H2 solubility. Bulk H₂ solubility tests and results are shown in Figure 23.

[0323] Stripping reactor design for kinetic experiment. Stripping reactor design for kinetic experiment is shown in Figure 24. Linear reaction design was used to prevent introducing CH4into H2O / H2 / N2 vessel. Flow rates of gas injection and solution dripping will be controlled. Partial pressure of II2 and CH4will be controlled (10, 40 vol% of H2 or CH4balanced with N2).

[0324] Stripping experiments. Stripping experiment results are shown in Figure 25 - Figure 26. As can be seen from Figure 25 - Figure 26, t₉₀ was shorter when 50% CH₄ / N₂ mixture gas (—21 and 19 mins) was used compared to pure N₂ gas (~36 and 28 mins). There was increased hydrogen concentration in the gas effluent with increased aqueous / gas ratio in the case of using 50%’ CH4 / N2 mixture gas.

[0325] Batch reactor design for ambient pressure H2 partitioning. Batch reactor design for ambient pressure H2 partitioning is shown in Figure 27. Liquid volume to gas headspace volumes are gradated at various ratios on reaction flask. Partial pressure of H₂ and CH₄ can be varied by inlet gas (10, 40 vol% of H₂ or CH₄ balanced with N₂). After filling with H₂ containing H₂O, the reaction flask is sealed and agitated before sampling headspace by syringe and analysis by Micro-GC.

[0326] Theoretical modeling of [H2] in gaseous and aqueous phases after ambient pressure partitioning. Theoretical modeling of [H₂] in gaseous and aqueous phases after ambient pressure partitioning is shown in Figure 28.

[0327] Experimental H2 partitioning under ambient conditions using batch reactor.

[0328] Experimental H₂ partitioning results under ambient conditions using batch reactor are shown in10046-669W01; 8626 SON Figure 29.

[0329] Glass micromodel fabrication for high pressure H2 partitioning. Glass micromodel fabrication for high pressure H₂ partitioning is shown in Figure 30.

[0330] High pressure H2 partitioning. High pressure H₂ partitioning results are shown in Figure 31-Figure 34.

[0331] In situ H2(aq) quantification. In situ H2(aq)quantification is shown in Figure 35-Figure 37.

[0332] Tamarack micromodel development. Develop microfluidic visualization platforms (i.e., micromodels) with pore geometry that is representative of Tamarach formation.

[0333] Unconsolidated “sand” geometry will be used here. Spatial resolutions of ~μm are possible here using optical microscopy.

[0334] Micromodel Fabrication and testing update. Completed micromodel fabrication using silicon for improved visualization (Figure 38). Bonding process remains as the next step to be finalized. Conducted system testing under a pressure of 1100 psi.

[0335] High pressure real-rock microfluidics. High pressure real-rock microfluidics are shown in Figure 39.

[0336] Progress to date and future opportunities. Proof of concept study here shows effective H₂(aq) removal from brine into inert gas (Figure 40). Work over the past 6 months demonstrates feasibility for using phase equilibria as a mechanism to accelerate serpentinization reactions for H2 generation. Microfluidics, high pressure reactors, in situ H2 concentration measurements, and gas partitioning concepts developed here provide opportunity for future studies in enhancing rates of geologic H₂ generation at scale.

[0337] Next steps:

[0338] - Measure the effect of gas partitioning on overall H₂ generation kinetics.

[0339] 3Fe2SiO4+ 2H2O → 2Fe3O4+ 3SiO2+ 2H2o Real -rock micromodel: visualization, reactive site characterization.

[0340] o Core-flood: analytical rate measurements, geochemical analyses. o Reservoir modeling: simulations for field deployment.

[0341] - Use of clays to stabilize interface while catalyzing H₂ generation

[0342] o Talc, smectite, kaolinite

[0343] - Impact of foams on overall production

[0344] o Sweep efficiency versus overall H₂ recovery

[0345] o Foam wetness / dryness (e.g., specific surface area available for H₂

[0346] partitioning)10046-669W01; 8626 SON - Other opportunities

[0347] o Use vented gases from Permian basin as inert phase

[0348] o Effect of foam dryness and water film thickness on catalysis Example 7

[0349] Hydrogen uses are shown in Figure 41.

[0350] Types of hydrogen are shown in Figure 42.

[0351] Hydrogen underground is shown in Figure 43.

[0352] Serpentinization. From 5% of the earth’s crust, 100’s of trillions of tons of H2 can be produced by serpentinization:

[0353] Fe(II) + H2O → Fe(III) oxides + H₂ Project. The project disclosed herein is shown schematically in Figure 1 and Figure 44. Setup. A schematic diagram of the experimental setup is shown in Figure 45. The experimental setup involves two main injection processes: for nitrogen injection, valves V2 and V5 are opened while valves VI, V3, and V4 remain closed. To inject deionized (DI) water saturated with nitrogen (N2) and hydrogen (H2), valves V 1, V2, V3, and V4 are opened, with valve V5 closed. For pressure control, DI water is injected by opening valves V6 and V7.

[0354] Steps:

[0355] 1. Injected H₂ (P=112 psi) and N₂ (P=128 psi) simultaneously (53.3% H₂) for 24 hours to saturate water at 500 psi.

[0356] 2. Injected N₂ at 500 psi into the micromodel.

[0357] 3. Injected DI water saturated with both H₂ and N₂ into the micromodel at a superficial velocity of approximately 0.70 cm / min (10 m / day).

[0358] 4. Pressure of the system was maintained at 500 psi during the third step by injecting DI water at 500 psi.

[0359] Hydrogen partitioning into gas. Hydrogen partitioning into gas is shown in Figure 46. Dissolution. As the injection proceeded, tire pressure of the water saturated with H2 and N? decreased, and the DI injection started. This leads to the dissolution of the gas bubble in the end (Figure 47).

[0360] H2 partitioning into the gas phase. There are 40 openings in the micromodel. The volume of hydrogen partitioned was calculated by seeing the difference in bubble size over time (Figure 48).

[0361] H₂ concentration in the gas phase. The size of the nitrogen bubble before H₂ got inside is used to calculate the concentration of H₂ in the gas phase (Figure 49). Results are also shown in Figure 53.10046-669WO1; 8626 SON H2 concentration in water. H2 concentration in water is shown in Figure 50.

[0362] Calculating the partitioning coefficient. The partition coefficient is calculated using:

[0363] Kpartition= cH₂,gas

[0364] ^partition

[0365]

[0366] liquid

[0367] Results are shown in Figure 51 and Table 2 below.

[0368] Table 2. Partitioning coefficient.

[0369] N₂ volume (μm³) VN2tot. in μmodel (mL) N₂ Volume (mL) nN2(moles) xH2vol% pH2(atm) pH2(psi) CH2in gas (mol / L) CH2in water (mol / L) K volume (μm³) μmodel Volume (moles) (atm) (psi) gas water (mL) (mL) (mol / L) (mol / L) 204123 8164920 8.16492 1.12 0.00 0.00 0.00 0.00 0.00

[0370] E-06 E-08 E+00 E+00 E+00 E+00 E+00 204123 8164920 8.16492 1.12 2.33 2.33 7.94 1.17 3.27 2.57 1.27

[0371] E-06 E-08 E-01 E-01 E+00 E+02 E+01 E-02 E+01 204123 8164920 8.16492 1.12 3.40 3.40 1.16 1.70 4.76 2.56 1.86

[0372] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 3.67 3.67 1.25 1.84 5.15 2.56 2.01

[0373] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 3.87 3.87 1.32 1.94 5.42 2.56 2.12

[0374] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 3.88 3.88 1.32 1.94 5.43 2.56 2.12

[0375] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 4.03 4.03 1.37 2.01 5.64 2.56 2.21

[0376] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 4.09 4.09 1.39 2.04 5.73 2.55 2.24

[0377] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01 204123 8164920 8.16492 1.12 4.17 4.17 1.42 2.09 5.85 2.22 2.29

[0378]

[0379] E-06 E-08 E-01 E-01 E+01 E+02 E-01 E-02 E+01

[0380] Quantifying the amount of hydrogen. The new photomask for partitioning coefficient quantification is shown in Figure 52.

[0381] 1. Hydrogen partitions inside the circular ends (quantify that part).

[0382] 2. Then, methylene blue will be introduced and mixed.

[0383] 3. The amount of hydrogen left in the water can then be quantified.

[0384] Example 8 - Nanoparticle foam stability characterization

[0385] Background is shown in Figure 54 [1],

[0386] System components are shown in Figure 55 [2],

[0387] An aim is to develop a stable methane foam, stabilized by surface modified nanoparticles, that can produce geologic hydrogen through miscible displacement.

[0388] Methodology is shown in Figure 56.

[0389] Findings - Nanoparticle characterization. UV-Vis absorption spectra are shown in Figure 57 and DLS Zetasizer testing results are shown in Figure 58. The UV-VS Testing showed10046-669W01; 8626 SON a right shift towards the wavelengths corresponding to PEG, indicating grafting. The nanoparticles samples seem to aggregated for DLS testing, as the results are not very reliable, and there doesn’t seem to be any trend of diameter change with grafting density increase. The increase in measured diameter with brine percent is perplexing, but suggests that salinity increase increases nanoparticle aggregation. The 2 pmol / m2 sample doesn’t have data for high salinities due to the excessive agglomeration (solution is too opaque for DLS at that point).

[0390] Bubble size analysis is shown in Figure 59. Qualitative Observations:

[0391] - The 2 μmol / m² foam seems to have more stable bubbles / foam.

[0392] - There is almost no difference between the 8 and 10 μmol foams in behavior.

[0393] Average bubble size diameter of PEG-NP in 10% brine foam is shown in Figure 60. Findings - Foam Stability Testing (Ambient Air). Results of foam stability testing (ambient air) at varying brine percent are shown in Figure 61.

[0394] Findings - Talc as a foam stabilizing additive (ambient air). Results of tests for Talc as a foam stabilizing additive (ambient air) are shown in Figure 62 and Figure 63. Average bubble diameter results for PEG-NP in 20% brine foam are shown in Figure 64.

[0395] Current conclusions and proposed hypotheses:

[0396] - 2 μmol / m2outperforms 8 and 10 in foam stability.

[0397] - The high surface coverage of the ligand with higher grafting densities causes the steric forces to be too high, causing repulsion to be too high to allow for stable foam formation (Figure 65-Figure 66)

[0003] .

[0398] Next Steps:

[0399] - Explore and characterize the interactions between the PEG-NP and talc that stabilize the foam.

[0400] - Test the NP foam in high-pressure conditions with nitrogen and transition to methane. References

[0401] [1] K Jangir et al. Enhancing the Aqueous foam stability using nanoparticles: A review; World Journal of Chemical Education, 2022, 10(2), 84-90

[0402] [2] https: / / psiberg.com / talc /

[0403] [3] Hatchell, Daniel Dissertation, 2022, Figure 4.2, page 103

[0404] Example 9 - Shifting geochemical reaction equilibrium via particle injection Disclosed herein is a scheme to accelerate the rate of reactions (e.g„ those relevant to geologic hydrogen production and critical minerals extraction) in geothermally-active rock formation. Here, hot rock used for geothermal applications (including enhanced geothermal systems) that are reactive (i.e., mafic, ultramafic) will be targeted for stimulated hydrogen10046-669WO1; 8626 SON production. Reaction kinetics in such environments, however, decrease rapidly and economic rates of production are not sustained.

[0405] These methods inject colloidal systems (e.g., clays, nanoparticles, proppants, etc.) to serve as a nucleation site for water vaporization. Rough surfaces such as those of particles reduce the energy barrier for phase transition, and act as nucleation sites for boiling at temperatures below that of the boiling point. Once a steam bubble is formed, reaction product gases (e.g., Fh) are partitioned into the vapor phase and recovered to the surface. The decrease in dissolved gas concentration, the reaction product, encourages further reactions in the forward direction, thereby shifting the reaction equilibrium.

[0406] Details:

[0407] - Reducing the aqueous concentration of di ssol ved gas species shifts the geochemical reaction (e.g., serpentinization) forward to accelerate the rate of fluid-rock reactions.

[0408] - Colloidal systems such as clays, nanoparticles, and proppants serve as nucleation sites for subcooled vaporization. Bubbles of steam form around the particles in situ.

[0409] - Dissolved reaction product gas species (e.g., H2) will partition into the steam bubbles.

[0410] 0 The vapor bubbles can be transported easily to the surface.

[0411] 0 I'he decrease in dissolved reaction products in the geothermal brine will shift the reaction forward to maintain high rates of fluid-rock reaction.

[0412] Example 10 - Scrubbing H2 out of the Earth: Water-Free Geologic H2 Extraction via Phase Partitioning with Foams

[0413] Abstract. Geologic hydrogen, both natural and stimulated, is a carbon-free fuel capable of providing hundreds of years of global energy at current consumption rates. While laboratory and field studies are recently underway to enable geologic II2 production and extraction, two key challenges bar their feasibility. First, despite the low solubility of IF in brine (~ ppm), H₂ saturation concentrations at geologic conditions are still greater than the reaction equilibrium concentration for Ifc-generating reactions (e.g., serpentinization). In other words, geologic H₂ exists primarily as a dissolved phase, the extraction of which would require co-producing up to ~1 million times its mass in water. Second, the low reaction equilibrium concentration limits the rate of H₂ generation reactions. Approaches to extract dissolved H₂ without brine co-production and those that shift the reaction equilibrium in favor of continued H₂ generation are needed for geologic H₂ to be viable. This paper introduces highly stable and environmentally safe Pickering foam injections to produce a concentrated H₂ stream (~ 50 vol.%) by extracting dissolved H₂ via thermodynamic phase partitioning and discusses its potential to shift the H₂ generation reaction equilibria forward (Figure 67).10046-669WO1; 8626 SON Introduction. Geologic H 2, whether naturally occurring (white, gold) or stimulated (orange) [1], presents a significant opportunity to enable a reliable energy future [2], Estimates suggest potential for geologic fb to achieve < $ 1 / kg [3, 4], while avoiding the need to capture related CO? emissions (i.e., gray into blue hydrogen) or relying on vast quantities of critical mineral resources, electricity, and water (i.e., green hydrogen) [5-9]. Natural geologic II 2 production in the subsurface has been estimated at around 23 Mt / yr, though the fraction that is in accessible reservoirs, rather than being lost through physical or biogeochemical process, remains underexplored [10-12], The resources available for stimulated geologic H2, i.e., the chemical potential that exists in the form of Fe(II) bearing rocks and ores (e.g., olivine) near the surface, presents a much larger opportunity. If fully realized, stimulated approaches could produce approximately 5.6xl06Mt of H >

[0012] , While Ellis el al. note that much of this may be unrecoverable, accessing even 2 % of these resources would meet the projected global energy¬ demand for ~ 200 year's

[0012] , To this end, understanding the conditions for effectively stimulating the primary reaction for the production of subsurface H2, serpentinization

[0013] , as shown in Equation 1 for the Fe(II)-rich olivine-mineral fayalite but which can be extended to other olivine compositions and to mafic rocks more generally, has become an attractive focus for H2 generation studies [14-19],

[0414] 3

[0415]

[0416] 3 Fe2SiO4+ 2 H2O → 2 Fe3O4+ 3 SiO2+ 2 H2(1) Despite the promise of this resource, the technology readiness level (TRL) of geologic hydrogen lags behind other approaches [20, 21]. One area where significant questions remain is in how to recover H2 from the subsurface in an economically feasible manner while maintaining a reasonable H 2 generation rate. There are two main challenges associated with this recovery. First, because 11 exists primarily in the dissolved phase at ppm levels under subsurface conditions, direct extraction of the aqueous phase would require pumping enormous quantities of water (10,000 to 1,000,000 kg of H? O per kg of IE based on reported H? concentrations) to the surface, representing a large economic outlay [14, 22]. Second, even though the solubility of H2 in water is low, serpentinization reactions reach equilibria at sub-saturated II 2 concentrations, drastically slowing the kinetics of further generation. It is observed that even under the optimal experimental conditions, the equilibrium concentrations of molecular H2 in the liquid phase remain well below the solubility limit, and reaction rates slow by orders of magnitude within a short timeframe (~ hours, Figure 68 and Table 3) [14-18, 22-26], Extracting IF from the liquid phase within ultramafic reservoirs hold potential to shift the reaction equilibrium at the mineral¬ fluid interface to facilitate further II 2 generation. However, technologies for efficient II2 extraction, especially at ppm levels, remain in the exploratory stages.10046-669WO1; 8626 SON

[0417] Table 3. Summary of previous studies on olivine serpentinization.

[0418] Rock Fluid Initial R / FaCH2(mmol / Kg)bT (°C) P (MPa) Ref Olivine water 0.95 117 300 300 [SI] — water 25g / 60g 0.21 - 0.63 30 - 70 10100 [S2] -- 0.5 M NaCl 20g / 42.4g 9.8 300 35.2 [S3] -- 0.5 M NaCl 20g / 45g 70.2 300 50 [S4] — 0.5 M NaCl 15.6g / 38.6g 29.9 300 35 [S5] — 0.5 M NaCl 15g / 45.8g 34.4 230 35 [S6] — 0.8 M NaCl 0.25 0.5 400 50 [S7] __ 0.5 M NaCl 0.4 4.8 200 30 [S8] — 0.5 M NaCl 5g / 20.6g 0.01 90 0.1

[0419]

[0420] [S9]aR / F: Rock to fluid mass ratio at start of experiment.bCm: Final molecular H2 concentration in liquid phase.

[0421] Given the urgency of decarbonization and pressing need for cost-effective H2 extraction technologies, proposed herein, for the first time, is the concept of using carrier gas foams (e.g., CH4, N2) to facilitate II 2 extraction. Here, high surface area to volume ratio foams promote the partitioning and extraction of dissolved II2 into a carrier gas phase, resulting in a high-mobility H2-rich gas phase that circumvents the need for water co-production. Specifically, Pickering foams are used to transfer and concentrate dissolved I-I2 (i.e., H aq)) into the carrier gas phase to produce a high concentration (e.g., ~ 40 to 50 mol.%) II2 stream and obviate the need for water co-production. Secondly, removing the reaction product H2 from the brine prevents it from reaching its equilibrium concentration, thereby shifting the reaction forward via Le Chatelier’s principle and maintaining a high reaction rate for subsequent II 2 generation. Pickering foams, while providing the same IF miscibility as direct gas injection (i.e., complete molecular mixing between H? and the gas for partitioning), offer several advantages compared to chemical additives (e.g., surfactants): foams increase the brine / gas interfaces available for mass transfer (i.e., Il2(aq) to H2(g)), foams increase the effective viscosity of the injectant to enable conformance control and maximize the volume of rock contacted for reaction, and, compared to standard surfactant foams, particle-stabilized Pickering foams are chemically stable under harsh geologic conditions (e.g., pressure, temperature, pH, salinity).

[0422] Herein, the feasibility of a foam-assisted partitioning approach for effective IP production from ppm-level brines is demonstrated through proof-of-concept experiments: first, II 2 partitioning from water into an inert gas (e.g., N2) under high-pressure conditions, and10046-669W01; 8626 SON second, accelerating partitioning kinetics using Pickering foams. In addition, as an important carrier medium, the stability of particle-assisted N2 foams was investigated in-situ under reservoir-relevant conditions (e.g., pressure up to - 4.14 MPa and salinity up to 5 wt.%). Finally, the outlook of this approach and the technical developments that are needed for field implementation are discussed.

[0423] Partitioning H2 into the inert gas phase. A series of proof-of-concept experiments were conducted at 3.45 and 7.58 MPa (i.e., 500 and 1100 psi, respectively) to investigate the extractability of dissolved H2(aq) using an inert gas. An etched silicon-glass microfluidic device with a ~ 100 pm x 30 urn x 3.1 cm microchannel with a series of cylindrical cavities (diameter ~ 200 pm) was fabricated in-house and used here for interfacial study (Figure 72a-Figure 72b). To begin, the device was saturated with N2, followed by constant flow rate injection of H2-saturated aqueous solutions comprised of deionized water (DI water) that was pre-saturated with an H2 / N2 mixture (47:53 at 3.45 MPa and 40:60 at 7.58 MPa). During all experiments, the system was maintained at constant pressure. The injected aqueous solution displaces Nzfrom the microchannel and traps small N2 bubbles in the cavities to form a carrier gas bubble. The volume of the trapped gas phase was measured over time to delineate II2 partitioning from the brine into the gas phase.

[0424] Image quantification of the bubble size evolution over time paired with fugacity calculations of gas composition showed rapid increase in 112 concentrations in the gas phase as H 2 is extracted from the injected brine solution (Figure 69a-Figure 69c). Specifically, phase equilibration between the H2-bearing brine in the microchannel with the N2 gas in the cavities resulted in increased bubble volumes within ~ min (Figure 69a), enriching the carrier gas to ~ 50 mol% H2 (Figure 69b). It is noted here that the increase in bubble volume represents a true II2 uptake (i.e., dissolved H partitioning into the 2 gas phase) rather than a pressure-related artifact, as the system pressure was held constant and corresponded to a decrease in dissolved H ■ in the aqueous solution (Figure 69c). Thermodynamic equilibration was rapid (~ 2 min), after which the growth rate of bubble volumes slowed. Gas and aqueous phase H and N?. fugacities, calculated using Henry’s law, matched forward models of H partitioning and gas and brine compositions simulated iteratively and validates the phase equilibration mass transfer framework here (Figure 69b). It is noted that at 7.58 MPa (i.e., 1100 psi), the bubble equilibrated at a lower hydrogen mole fraction than at 3.45 MPa (500 psi) because the injected water was equilibrated with a lower II 2 fraction in the gas mixture, imposing a lower equilibrium hydrogen fugacity in the aqueous phase. In both cases, the end-point hydrogen mole fraction closely matched the equilibrium value imposed by the inlet water composition, demonstrating that gas-phase10046-669WO1; 8626 SON hydrogen enrichment is governed by dissolved hydrogen availability rather than bubble growth kinetics alone.

[0425] The single-bubble analysis was extended to estimate H ■ recovery as a function of bubble count (i.e., brine / gas interfaces available for H?. partitioning, Figure 69c). Increasing the number of bubbles contacted by the brine accelerated H extraction from the liquid phase, as shown by the cumulative recovery curves (Figure 69c, right). For the microchannel-cavity configuration here with a constant H?-brine feed, complete extraction requires ~ 86x the gas / brine interface in Figure 69a. It is noted, however, that the experiments here were performed such that foam bubbles were held in place and fresh IF-rich brine was injected. In other words, the bubble composition is not refreshed, as would be the case in practice. Furthermore, the microchannel¬ cavity configuration represents a wet foam with limited brine / gas interfaces available for mass transfer (i.e., low surface area to volume ratio here). In practice, however, the brine is expected to be the trapped phase with mobile, dry foams that (i) reduce the gas injection volumes needed for H? extraction and (ii) generate an even larger interfacial area per brine volume than the discrete bubbles used here, further increasing the overall hydrogen-stripping efficiency. The microchannel-cavity experiments here offer a conservative configuration where the bubbles remain fixed while fresh H?-laden brine flows past them, representative of the advancing edge of the foam injection where fresh, hydrogen-rich brine is encountered. In the bulk of the reservoir, however, the conditions are reversed: brine is largely immobile while the Ib-poor injected gas (or foam) phase proceeds through the pore space. The foam injectant provides a substantial gas- liquid interfacial area to increase the H? stripping efficiency compared to the station ary -bubble tests here. The systematic decrease in effluent H concentration with increasing bubble population here establishes the feasibility of gas partitioning as a means for II2 production.

[0426] Enhancing Partitioning Kinetics via Foam. After confirming that dissolved H - molecules can partition from aqueous phase into the gas phase and that this process can be promoted by increasing the gas-liquid interfacial area, the experimental scope was expanded to a bulk batch system to enable, realistic foam injection at a substantially larger scale than microfluidic device (Figure 73a-Figure 73b). Kaolinite was selected as a model Pickering foaming agent because of its mixed surface charge characteristics and its environmental and economic viability

[0027] . Total moles of injected H2 and N2 gases were measured, and mole fractions of each gas after partitioning.

[0427] As shown in Figure 70a-Figure 70b, the total moles of gases injected into systems were comparable regardless of the presence of kaolinite, indicating the presence of kaolinite has no significant impact on H2 solubility into water. Notably, however, higher H2 concentration was10046-669WO1; 8626 SON observed in the gas phase after partitioning when foams were used compared to the pure water system. In regards of extraction efficiency, approximately 24.7% of dissolved II 2 was extracted in the kaolinite slurry system, whereas only 3.2% was extracted from the pure water system. This behavior is likely due to the increased gas-water interfacial area due to foam, which promotes the mass transfer of IF. and is consistent with the results observed from the microfluidic experiments where a higher interfacial area successfully enhanced II2 recovery from the aqueous phase into the carrier gas phase. Similar behavior was also found in previous studies where higher interfacial areas can boost the reactions by enhancing the mass transfer of desired materials [28-30], Collectively, these results provide a compelling basis for advancing subsurface recovery strategies that incorporating eco-friendly and economically viable Pickering foam agents and inert gases to extract untapped energy resource, “orange hydrogen”, dissolved in the aqueous phase at low concentrations.

[0428] The batch reactor experiments, however, showed much lower extraction efficiencies than those in microfluidic devices. This discrepancy is likely due to the lower interfacial area per unit volume of the aqueous phase (no porous medium present here), again emphasizing the important role of the relative interfacial area per unit volume of the aqueous phase during the extraction process. In this regard, the interfacial area of the bulk system can be increased via loading a higher content of Pickering foam agent to generate more bubbles. At the same time, excessive amounts of Pickering foam agent can induce armoring effects that hinder mass transfer. Thus, the ratio of Pickering foam agent to aqueous and gas phases is important for scaling the process to a geological setting. Moreover, the physical and chemical properties of the Pickering foam itself are important. For enhanced 11 extraction, the Pickering foam should remain stable during its injection and transportation toward the recovery well to maintain the interfacial area. If bubbles coalesce or collapse, the interfacial area will be reduced, causing a mass transfer limit.

[0429] Therefore, controlling physiochemical properties of foam is important for optimizing overall enhanced II2 recovery performance. In geological formations, groundwater can exist as either confined within the rock matrix or as bulk aquifer water, and is typically saline. These characteristics can affect foam-water interactions. Accordingly, the design and development of Pickering foam agents appropriate for subsurface H2 recovery warrant further investigation.

[0430] Practical steps towards feasible foam-enhanced H2 recovery. Because foam stability under reservoir-relevant conditions (e.g., pressures exceeding 1 MPa and salinities above 1 wt.%) is important for effective H2 recovery, foam stability was evaluated across harsh environments (e.g., pH, salinity, temperature). Bulk experiments demonstrated the important role of foams in accelerating the partition of molecular H?. from the liquid phase to the gaseous phase10046-669WO1; 8626 SON (Figure 70a-Figure 70b). However, coalescence of the kaolinite-stabilized foams was simultaneously observed since the bubbles were not confined in pore spaces and they had maximum contact with each other for coalescences. To create a reservoir-like system, a setup was developed that facilitates efficient liquid-gas mixing and enables m-situ assessment of foam stability (Figure 71a). Here, a Swagelok tube packed with ~ 180 pm spherical glass beads was used to promote effective foam generation. N2 was used as the gas for the foam generation. Since traditional polymers or surfactants such as sodium dodecyl sulfate (SDS), Tween, and cetyltrimethylammonium bromide (CTAB) are prone to degradation

[0031] , retention

[0032] , and environmental concerns, they were excluded from foam preparation [33-35]. Compared with traditional stabilizers, natural nanoparticles (NPs) offer advantages such as low toxicity, limited effects on the environment

[0036] , and minimal retention in porous media

[0037] . Furthermore, NPs can migrate through pore networks without inducing pore plugging, enabling them to withstand reservoir-relevant conditions

[0038] . Therefore, to validate the setup and examine NP-stabilized foam stability under reservoir-relevant conditions, a ~ 5 wt.% brine solution (4:1 NaCl: CaCh by weight) containing ~ 1 wt.% of the functionalized Si NPs was prepared as the aqueous phase. The surface functionalization process and the corresponding characteristics of the Si NPs are provided in Figure 74.

[0431] The setup is efficient in generating foam while enabling in-situ observation. Figure 7 lb shows the foam size is tunable by adjusting the flow-rate ratio between the gas and the aqueous phase (R = Fgas: Faq). Increasing R resulted in smaller and more uniform foam size distributions. Overall, the foam size was distributed at a level of tens of micrometers, compatible with the prepared micromodel dimensions and readily applicable for subsequent micromodel studies such as investigating foam size on H2 partitioning, and others. In addition, foam stability was also studied in Figure 71c. No discernible change in bubble size was observed over the observation period. The high stability of Si NP-stabilized foams indicates the attachment of Si NPs at the gas-liquid interface forms a stable and elastic aqueous film that prevents bubble coalescence and collapse, even under the high- salinity (~5 wt.%) and high-pressure (approximately 4.14 MPa) harsh conditions. These findings point to a promising approach for generating high- tolerance, stable foams using NPs or NP blended with low-cost yet less-effective materials such as kaolinite, minerals, thereby enabling more efficient H2 recovery.

[0432] Outlook. Geologic IF. whether natural or produced via chemical and physical stimulation, will require innovative approaches to extract the generated II 2 without, massive water co-production and to shift the reaction equilibrium. In this work, the concept of using Pickering foams to create high-surface area gas-water interfaces to rapidly partition the IF into10046-669WO1; 8626 SON an inert carrier gas was introduced. These first-of-a-kind experiments have shown that (i) high concentrations of IL. of up to nearly 50% by mole, can be partitioned into the gas phase under reservoir relevant conditions; (ii) tire kinetics of partitioning can be improved by using additives such as kaolinite; and (iii) nanoparticles, including low-cost, environmen tally-benign clay mineral particles, stabilize Pickering foams with exceptional stability under reservoir-relevant conditions. Together, these experiments provide a proof-of-concept for using gas foams (such as N? and CH:) to efficiently extract molecular H2from aqueous phases within ultramafic reservoirs, thereby facilitating continued H2 generation at the mineral-fluid interface. Further research is still needed to develop in-situ measurement techniques for quantifying II2 partitioning, to tailor Pickering foams for enhanced partitioning kinetics, and to optimize the technoeconomic and life-cycle feasibility of the approach based on efficiency, recyclability, and costs. However, based on these proof-of-concept demonstration, the use of Pickering foams to extract and accelerate the generation rate of geologic II2 can open multiple pathways to tap into the enormous potential of geologic H?.

[0433] Supporting Information

[0434] Micromodel fabrication and H2 partitioning investigation. A well-knowm fabrication method was adopted to prepare the micromodel [S10], The micromodel was fabricated by etching a channel network with a width of 100 m and a depth of 30 pm into silicon wafers (Figure 72a). A variable number of circular' cavities were etched to create stable bubble observation sites, connected to the channels by 100 pm throat. The etched silicon wafers were then ionically bonded to a borosilicate glass cover. Deionized (D. I.) water saturated using 40:60 (in volume) H2: N2 was used as the aqueous phase. The micromodel was first pressurized with N2 gas to 3.45 or 7.58 MPa, and the pressure was maintained throughout the experiment.

[0435] Subsequently, the saturated water was introduced to the micromodel at controlled flow rates. At 7.58 MPa, the flow rate was 0.00080 mL / min, giving a volumetric mass-transfer coefficient kua of 5.08 × 10-8L / min; at 3.45 MPa, the flow' rate was 0.002 mL / min (to = 6.998 x 10’* L / min). All experiments were performed at room temperature. The schematic diagram of the experimental setup is shown in Figure 72b. Bubble dynamics were imaged in brightfield mode under 20x magnification and videos were recorded at 1 fps using an optical microscope from Horiba. Frames were extracted with a 20 s interval for subsequent processing and analysis. The changes in bubble volumes were investigated using software ImageJ (NIH).

[0436] Bubble gas composition was inferred from the measured bubble volume evolution using a fugacity-based, volume-constrained calculation. Gas-phase fugacities of N2 within the bubble and of H2and N2 in the inlet water were computed using the Peng-Robinson equation of state.10046-669WO1; 8626 SON These fugacities were related to equilibrium dissolved concentrations at the bubble-liquid interface through Henry’s law. The net moles of H2and N2transferred into or out of the bubble over each time interval were calculated from the difference between inlet and equilibrium dissolved concentrations, scaled by an effective contacting water volume. Nitrogen moles were updated directly from this exchange, and hydrogen moles were subsequently determined as the residual required to satisfy the real-gas relation at the measured bubble volume. Iteration over the full time series yielded the temporal evolution of bubble composition and cumulative hydrogen uptake. In parallel, a forward-simulation model was developed to predict bubble composition without using the measured bubble-volume trajectory. The model takes as inputs the operating pressure and temperature, the initial bubble volume, the inlet gas composition used for water pre-saturation (H2and N2fractions), the water flow rate, and the simulation duration. At each time step, gas-phase fugacities were computed using the Peng-Robinson equation of state and converted to equilibrium dissolved concentrations via Henry’s law. Net gas transfer was then computed using the same effective contacting water volume, and the bubble composition and volume were updated accordingly under constant pressure. The resulting hydrogen mole-fraction trajectories were compared directly with those obtained from the data-driven calculations To quantify H? recovery, the amount of H2partitioned into a single bubble was determined and compared to the total dissolved H2in the injected water during a five-minute period. The fraction was then scaled by bubble count, under the assumption of identical bubble sizes and uniform exposure to the flow. The inlet H2concentration was approximately 24.51 mM. The H? concentration in the effluent, water was also calculated as a function of injected pore volumes using the measured flow rate of water and one pore volume as the liquid-filled volume of the bubble-containing section of the micromodel (width - 100 um, depth - 30 um, length - 31 mm). The H? recovery was normalized relative to either the total H? transported through the system (Cm x Vpassed) or to the initial quantity of H? within the bubble region (Cm x PVregion). The resulting outlet concentration and cumulative recovery curves correspond to the depletion of dissolved H2with successive pore volumes and established a quantitative link between bubble population and H? extraction efficiency.

[0437] Gas solubility and static Hi partitioning at reservoir conditions. Experiments were performed in a custom 316-stainless steel high-pressure reactor equipped with two optical sappliire windows and 2 mm glass frit at the end of inlet (Parr Instruments) (Figure 73a-Figure 73b). The total volume of reactor vessel was 297.36 mL. Gas injected using a Syrixus 500X high-pressure syringe pump (Teledyne ISCO). UHP grade N2(99.999%) and H2(99.999%) gases10046-669WO1; 8626 SON were used. Prior to the solubility and partitioning experiments, leak tests were performed to ensure negligible leakage in the system. Kaolinite was obtained from Sigma Aldrich.

[0438] The solubility of H2and N2were determined under reservoir relevant conditions, 1.72 and 3.45 MPa, respectively. The reactor was filled with 200 mL of DI water and purged with either H2or N2. The reactor was then pressurized to the appropriate target pressure from the syringe pump, while stirring at 650 rpm using the internal impeller. After the pressure stabilized, the aqueous phase was stirred for an additional 10 minutes and allowed to equilibrate for an additional 20 minutes without stirring. After equilibration, the solubility of H2and N2were determined from the total injected volume of each gas at the target pressure under the assumption of ideal behavior for both gases.

[0439] To investigate the partitioning behavior of H2 from the aqueous phase to the gaseous phase, the system was charged with DI water or a kaolinite slurry ( lwt%) in deionized water. The solution was purged with H2, sealed, and pressurized with H2gas to 1.72 MPa, while stirring at 650 rpm using the internal impeller. N2 was then introduced into the reactor at 5.17 MPa until the partial pressure of N2 was 3.45 MPa. The aqueous phase was then stirred for 10 minutes and equilibrated without stirring for an additional 20 minutes, at which point the volume change was measured. A small volume of gas phase was collected, and the composition was analyzed using a micro-GC (Micro GC Fusion, INFICON Inc.). The quantities of H2and N2in the gaseous and aqueous phases were determined from the compositional analysis and mass balance based on the known quantities of injected gas. All experiments were performed in triplicate.

[0440] Nanoparticle synthesis and foam generation. Silica nanoparticles (~6 nm, CAS No.7631-86-9) and 2-[methoxy(polyethyleneoxy)6-9propyl] trimethoxy silane (PEG-Silane, SDS ID: SIM6492.7) were purchased to prepare nanoparticle (NP)-stabilized foams. The resulting solution was stirred at a temperature of 65 °C for around 12 hours. 'The solution obtained was washed using DI water and centrifuged at 4500 rpm for five cycles to remove any unbound polymers (as shown in Figure 74 (left) ). The FTIR results of the dried functionalized NPs are shown in Figure 74 (right). Characteristic absorption peaks were observed at -785 cm'1(C-H vibration in aromatic rings), -945 cm’1(C-O-C stretching), -1350 cm1(CH3 bending), -1455 cm’1(CH2 bending), and enhanced intensity within the range from 1000 to 1250 cm"1(Si- O-Si or -C-O-C -), confirming the successful straightforward functionalization process [S11, S12]. N2 and NP solution was passed through a Swagelok tube (10.5 cm length x 3 mm inner diameter), uniformly packed with -180 um spherical glass beads to generate foams. The NP solution was prepared with a 5wt% brine solution (4: 1 NaCl: CaCh by weight) containing approximately lwt% of the functionalized Si NPs. The foam generation and in-situ investigation10046-669W01; 8626 SON was performed at room temperature. The flow-rate ratio between the gas and the aqueous phases ( =gas:aq) ranged from 1:1 to 3:1, while the total flow rate was maintained at 3 ml / min. The system pressure was kept at 4.14 MPa using a high-accuracy back-pressure regulator.

[0441] References

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[0485] EXEMPLARY ASPECTS

[0486] In view of the described compositions, devices, systems, and methods, herein below are described certain more particularly described aspects of the inventions. The particularly recited aspects should not, however, be interpreted to have any limiting effect on any different claims containing different or more general teachings described herein or that the “particular” aspects are somehow limited in some way other than the inherent meanings of the language and formulas literally used therein.10046-669W01; 8626 SON Example 1: A method for enhanced geologic gas extraction, the method comprising: contacting a carrier gas with an aqueous phase comprising a dissolved geologic gas, wherein the carrier gas is miscible with the geologic gas; wherein the geologic gas was produced by a geologic formation, such as by a reaction said geologic formation; such that the carrier gas contacts the aqueous phase and at least a portion of the geologic gas exsolves from the aqueous phase and partitions into the carrier gas via thermodynamic phase partitioning; thereby- enhancing the extraction of the geologic gas.

[0487] Example 2: The method of any example herein, particularly example 1, wherein the geologic gas is naturally occurring.

[0488] Example 3: The method of any example herein, particularly example 1 or example 2, wherein the geologic gas is generated via stimulation.

[0489] Example 4: The method of any example herein, particularly examples 1-3, wherein the geologic gas comprises hydrogen (IE), helium (He), methane (CH₄), argon (Ar), or a combination thereof.

[0490] Example 5: The method of any example herein, particularly examples 1-4, wherein the geologic gas comprises hydrogen (e.g., wherein the geologic gas comprises geologic hydrogen).

[0491] Example 6: The method of any example herein, particularly example 5, wherein the geologic hydrogen was produced by reaction between iron from an iron-bearing rock and water or hydrogen bearing compounds, and the aqueous phase is proximate to the iron-bearing rock.

[0492] Example 7: The method of any example herein, particularly examples 1-6, wherein said contacting occurs in situ within the geologic formation.

[0493] Example 8: The method of any example herein, particularly examples 1-7, wherein the method comprises injecting the carrier gas into the geologic formation.

[0494] Example 9: The method of any example herein, particularly examples 1-8, wherein the geological formation comprises iron-bearing rock.

[0495] Example 10: The method of any example herein, particularly example 9, wherein the iron-bearing rock comprises olivine.

[0496] Example 11: The method of any example herein, particularly example 9 or example 10, wherein the iron-bearing rock comprises (ultra)mafic rock.

[0497] Example 12: The method of any example herein, particularly examples 1-11, wherein the geologic formation comprises a basaltic formation.

[0498] Example 13: The method of any example herein, particularly examples 1-12, wherein the geologic formation comprises an aquifer.

[0499] Example 14: The method of any example herein, particularly examples 1-13, wherein the10046-669W01; 8626 SON geologic formation is a geothermally-active formation.

[0500] Example 15: The method of any example herein, particularly examples 1-14, wherein the aqueous phase comprises brine.

[0501] Example 16: The method of any example herein, particularly examples 1-15, wherein the carrier gas comprises air, CH4, N2, shale gas, CO2, waste gas, flue gas, steam, or a combination thereof.

[0502] Example 17: The method of any example herein, particularly examples 1-16, wherein the carrier gas comprises air, CH4, N2, CO2, steam, or a combination thereof.

[0503] Example 18: The method of any example herein, particularly examples 1-17, wherein the carrier gas comprises nitrogen.

[0504] Example 19: The method of any example herein, particularly examples 1-18, wherein the carrier gas comprises methane.

[0505] Example 20: The method of any example herein, particularly examples 1-19, wherein the carrier gas comprises carbon dioxide.

[0506] Example 21: The method of any example herein, particularly examples 1-20, wherein the carrier gas comprises a mixture of gases.

[0507] Example 22: The method of any example herein, particularly examples 1-21, wherein the carrier gas comprises processed or unprocessed shale gas from wells, fugitive gas from various wells (e.g., oil and gas reservoirs), waste gas from various industrial applications (e.g., mining operations, power plants, etc.), or a combination thereof.

[0508] Example 23: The method of any example herein, particularly examples 1-22, wherein the carrier gas is in the form of a gas in water emulsion with a surfactant.

[0509] Example 24: The method of any example herein, particularly examples 1-22, wherein the carrier gas is in the form of a foam.

[0510] Example 25: The method of any example herein, particularly example 24, wherein the foam is stabilized by a stabilizer comprising surfactants, particles, or a combination thereof.

[0511] Example 26: The method of any example herein, particularly example 24 or example 25, wherein the foam is a Pickering foam.

[0512] Example 27: The method of any example herein, particularly example 26, wherein the Pickering foam further comprises a Pickering foaming agent.

[0513] Example 28: The method of any example herein, particularly example 27, wherein the Pickering foaming agent comprises a plurality of particles.

[0514] Example 29: The method of any example herein, particularly example 28, wherein the plurality of particles comprise silica nanoparticles, natural fine particles (e.g., clays, talc, etc.),10046-669WO1; 8626 SON mine tailings, proppants, industrial waste particulates (e.g., coal ash), iron-rich particulates, fine particulates in the geologic formation (e.g., talc, smectite, clays, etc.) that were pre-existing and / or produced autogenically during reaction stimulation, or a combination thereof.

[0515] Example 30: The method of any example herein, particularly example 28 or example 29, wherein the plurality of particles comprise Kaolinite

[0516] Example 31: The method of any example herein, particularly examples 28-30, wherein the plurality of particles comprise Silica nanoparticles.

[0517] Example 32: The method of any example herein, particularly examples 28-31, wherein the plurality of particles comprise Functionalized silica nanoparticles, such as PEG- functionalized silica nanoparticles.

[0518] Example 33: The method of any example herein, particularly examples 27-32, wherein the ratio of Pickering foaming agent to aqueous and gas phases is selected to optimize extraction of the geologic hydrogen and stability of the foam.

[0519] Example 34: The method of any example herein, particularly examples 24-33, wherein the foam is substantially free of surfactants, such as sodium dodecyl sulfate (SDS), Tween, and cetyltrimethylammonium bromide (CTAB).

[0520] Example 35: The method of any example herein, particularly examples 24-34, wherein the foam maximizes interfacial area between the aqueous phase and the carrier gas phase.

[0521] Example 36: The method of any example herein, particularly examples 24-35, wherein the high surface area to volume ratio of the foam further enhances the extraction of the geologic gas by promoting partitioning and extraction of the geologic gas into the carrier gas phase of the foam.

[0522] Example 37: The method of any example herein, particularly examples 24-36, wherein the foam further increases the effective viscosity thereby enabling conformance control and increasing the volume of the geologic formation contacted for reaction.

[0523] Example 38: The method of any example herein, particularly example 37, wherein the increase in effective viscosity decreases the likeliness of viscous fingering in the geologic formation, increases overall sweep efficiency, or a combination thereof.

[0524] Example 39: The method of any example herein, particularly examples 24-38, wherein the foam self-stabilizes flow through porous media, such as the geologic formation.

[0525] Example 40: The method of any example herein, particularly examples 24-39, wherein the foam is stable under harsh geologic conditions in situ.

[0526] Example 41: The method of any example herein, particularly examples 24-40, wherein the method comprises injecting a stabilizer, such as a Pickering foaming agent, and generating10046-669WO1; 8626 SON the foam in situ.

[0527] Example 42: The method of any example herein, particularly examples 1-41, wherein the carrier gas comprises steam that is generated in situ, for example when the geologic formation is geothermally active.

[0528] Example 43: The method of any example herein, particularly examples 1-42, wherein extracting the geologic gas sliifts the geologic gas generation reaction equilibria forward, thereby further enhancing the rate of geologic gas generation.

[0529] Example 44: The method of any example herein, particularly example 43, wherein the geologic gas comprises geologic hydrogen, and extracting the geologic hydrogen shifts the geologic hydrogen generation reaction equilibria forward, thereby further enhancing the rate of geologic hydrogen generation.

[0530] Example 45: The method of any example herein, particularly examples 1-44, further comprising collecting the carrier gas with the dissolved geologic gas and optionally storing the carrier gas with the dissolved geologic gas.

[0531] Example 46: The method of any example herein, particularly example 45, wherein the carrier gas is in the form of the foam of any example herein, particularly examples 24-40, and separating comprises deconstructing the foam into a solution phase and a gas phase by inducing changes in the pH, salinity, and / or temperature of the foam, wherein the gas phase comprises the carrier gas with the dissolved geologic gas.

[0532] Example 47: The method of any example herein, particularly example 46, further comprises reusing the solution phase in the methods of any example herein, particularly examples 1-46.

[0533] Example 48: The method of any example herein, particularly examples 1-47, further comprising separating the geologic gas from the carrier gas and optionally storing the geologic gas and / or carrier gas after separation.

[0534] Example 49: The method of any example herein, particularly example 48, wherein separating the geologic gas from the carrier gas comprises distillation, membrane separation, pressure swing adsorption, temperature swing adsorption, or a combination thereof.

[0535] Example 50: The method of any example herein, particularly example 48 or example 49, further comprising, after separating the geologic gas from the carrier gas, reusing the carrier gas in the methods of any example herein, particularly examples 1-49.

[0536] Example 51: The method of any example herein, particularly examples 1-50, further comprising using the collected geologic gas.

[0537] Example 52: The method of any example herein, particularly examples 1-51, wherein the10046-669W01; 8626 SON method does not include water and / or brine co-production.

[0538] Example 53: A process for enhanced generation of the geologic gas by enhanced extraction of the geologic gas via the methods of any example herein, particularly examples 1- 52.

[0539] Example 54: A process for shifting a geochemical reaction equilibrium via enhanced extraction of the geologic gas using the methods of any example herein, particularly examples 1- 52.

[0540] Other advantages which are obvious and which are inherent to the invention will be evident to one skilled in the art. It will be understood that certain features and sub-combinations are of utility and may be employed without reference to other features and sub-combinations. This is contemplated by and is within the scope of the claims. Since many possible embodiments may be made of the invention without departing from the scope thereof, it is to be understood that all matter herein set forth or shown in the accompanying drawings is to be interpreted as illustrative and not in a limiting sense.

[0541] The compositions, systems, and methods of the appended claims are not limited in scope by the specific compositions, system, and methods described herein, which are intended as illustrations of a few aspects of the claims and any methods that are functionally equivalent are intended to fall within the scope of the claims. Various modifications of the compositions, systems, and methods in addition to those shown and described herein are intended to fall within the scope of the appended claims. Further, while only certain representative composition elements, system elements, and method steps disclosed herein are specifically described, other combinations of the composition elements, system elements, and method steps also are intended to fall within the scope of the appended claims, even if not specifically recited. Thus, a combination of steps, elements, components, or constituents may be explicitly mentioned herein or less, however, other combinations of steps, elements, components, and constituents are included, even though not explicitly stated.

Claims

10046-669WO1; 8626 SON CLAIMSWhat is claimed:

1. A method for enhanced geologic gas extraction, the method comprising:contacting a carrier gas with an aqueous phase comprising a dissolved geologic gas, wherein the carrier gas is miscible with the geologic gas;wherein the geologic gas was produced by a geologic formation, such as by a reaction said geologic formation;such that the carrier gas contacts the aqueous phase and at least a portion of the geologic gas exsolves from the aqueous phase and partitions into the carrier gas via thermodynamic phase partitioning;thereby enhancing the extraction of the geologic gas.

2. The method of claim 1, wherein the geologic gas is naturally occurring and / or wherein the geologic gas is generated via stimulation.

3. The method of any one of claims 1-2, wherein the geologic gas comprises hydrogen (H₂), helium (He), methane (CH₄), argon (Ar), or a combination thereof.

4. The method of any one of claims 1-3, wherein the geologic gas comprises hydrogen (e.g., wherein the geologic gas comprises geologic hydrogen).

5. The method of any one of claims 1-4, wherein the method comprises injecting the carrier gas into the geologic formation.

6. The method of any one of claims 1-5, wherein the geological formation comprises iron- bearing rock.

7. The method of any one of claims 1-6, wherein the geologic formation is a geothermally- active formation.

8. The method of any one of claims 1-7, wherein the carrier gas comprises air, CH4, N2, shale gas, CO2, waste gas, flue gas, steam, or a combination thereof.

9. The method of any one of claims 1-8, wherein the carrier gas is in the form of a foam.

10. The method of claim 9, wherein the foam is stabilized by a stabilizer comprising surfactants, particles, or a combination thereof.

11. The method of claim 9 or claim 10, wherein the foam is a Pickering foam.10046-669WO1; 8626 SON 12. The method of any one of claims 9-11, wherein the foam maximizes interfacial area between the aqueous phase and the carrier gas phase; wherein the high surface area to volume ratio of the foam further enhances the extraction of the geologic gas by promoting partitioning and extraction of the geologic gas into the carrier gas phase of the foam; wherein the foam further increases the effective viscosity thereby enabling conformance control and increasing the volume of the geologic formation contacted for reaction, wherein the increase in effective viscosity decreases the likeliness of viscous fingering in the geologic formation, increases overall sweep efficiency, or a combination thereof; wherein the foam self-stabilizes flow through porous media, such as the geologic formation; or a combination thereof.

13. The method of any one of claims 9-12, wherein the method comprises injecting a stabilizer, such as a Pickering foaming agent, and generating the foam in situ.

14. The method of any one of claims 1-13, wherein the carrier gas comprises steam that is generated in situ, for example when the geologic formation is geothermally active.

15. The method of any one of claims 1-14, wherein extracting the geologic gas shifts the geologic gas generation reaction equilibria forward, thereby further enhancing the rate of geologic gas generation.

16. The method of any one of claims 1-15, further comprising collecting the carrier gas with the dissolved geologic gas and optionally storing the carrier gas with the dissolved geologic gas.

17. The method of claim 16, wherein the carrier gas is in the form of the foam of any one of claims 9-12, and separating comprises deconstructing the foam into a solution phase and a gas phase by inducing changes in the pH, salinity, and / or temperature of the foam, wherein the gas phase comprises the carrier gas with the dissolved geologic gas.

18. The method of any one of claims 1-17, further comprising separating the geologic gas from the carrier gas and optionally storing the geologic gas and / or carrier gas after separation.

19. A process for enhanced generation of the geologic gas by enhanced extraction of the geologic gas via the methods of any one of claims 1-18.

20. A process for shifting a geochemical reaction equilibrium via enhanced extraction of the geologic gas using the methods of any one of claims 1-18.

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