Reaction-induced hierarchical fracturing for the recovery of hydrogen, energy, and minerals from geological environments

Abstract

Presented herein are systems and methods for the production of hydrogen, geothermal energy (heat), amorphous silica, rare earth minerals, and / or other resource(s) from geological environments such as subsurface geologic (e.g., rock) formations. In certain embodiments, presented herein are systems and methods that employ controlled, chemically-induced hierarchical fracturing of rock to increase rock surface area and increase the production and recovery of geologic hydrogen from in-situ sites.

Description

Atty. Docket No.: GEO-003PCT-8022-00401REACTION-INDUCED HIERARCHICAL FRACTURING FOR THE RECOVERY OF HYDROGEN, ENERGY, AND MINERALS FROM GEOLOGICAL ENVIRONMENTSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to U. S. Provisional Application No. 63 / 722,036 filed on November 18, 2024 and entitled, “REACTION-INDUCED HIERARCHICAL FRACTURING FOR RECOVERY OF HYDROGEN, ENERGY, AND MINERALS FROM GEOLOGICAL ENVIRONMENTS”, the entire content of which is incorporated herein by reference in its entirety.FIELD

[0002] This invention relates generally to systems and methods for (e.g., in situ) production, stimulation, and / or recovery of hydrogen, geothermal energy, amorphous silica, rare earth minerals, metals, and / or other resources from subsurface geologic (e.g., rock) formations and / or other geological environments.SUMMARY

[0003] In some embodiments, a process for in-situ generation of hydrogen gas from a subsurface geologic formation comprises: injecting fluid comprising a brine into the subsurface geologic formation through a plurality of wells, extracting hydrogen gas produced by interaction of the fluid with the subsurface geologic formation, and maintaining a pressure throughout the subsurface geologic formation site via the plurality of wells to keep a fracture network open and active.

[0004] In some embodiments, a method of producing resources from a geological formation comprises initiating production from the geological formation having one or more wells drilled into the geological formation, and applying, during the production, a composite waveform pressure signal P(t) to the geological formation through at least one of the one or more wells. The composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a second frequency component. The first frequency component performs a first function and the second frequency component performs a second function different from the first function, and the first frequency component has a period that is at least 2 times as long as a period of the second frequency component.

[0005] In some embodiments, a system for producing resources from a subsurface geological formation comprises one or more wells drilled into the subsurface geological formation, wellhead equipment operatively connected to at least one of the one or more wells, and aAtty. Docket No.: GEO-003PCT-8022-00401control system configured to, during production from the geological formation, cause the wellhead equipment to apply a composite waveform pressure signal P(t) to the geological formation. The composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a second frequency component. The first frequency component performs a first function and the second frequency component performs a second function different from the first function.BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The present teachings described herein will be more fully understood from the following description of various illustrative embodiments, when read together with the accompanying drawings. It should be understood that the drawing described below is for illustration purposes only and is not intended to limit the scope of the present teachings in any way. The foregoing and other objects, aspects, features, and advantages of the disclosure will become more apparent and may be better understood by referring to the following description taken in conjunction with the accompanying drawings, in which:

[0007] FIGS. 1 A-1C illustrate stimulation and optimization of hierarchal fracture networks via reaction-induced fracturing, according to illustrative embodiments of the present disclosure;

[0008] FIGS. 2A-2C illustrates an approach to access surface area in a fracture network, according to illustrative embodiments of the present disclosure;

[0009] FIGS. 3A-3B illustrates reaction progress over time as a comparison of lab data (Fig.3A) and model simulation (Fig. 3B), according to illustrative embodiments of the present disclosure;

[0010] FIGS. 4A-4B illustrates fracturing induced by stress from volume changes, according to illustrative embodiments of the present disclosure;

[0011] FIGS. 5A-5B illustrates hierarchal fracturing in a fracture network, according to illustrative embodiments of the present disclosure;

[0012] FIG. 6 illustrates a simulation of a fracture network at larger length scales using commercially available software (ResFrack), according to illustrative embodiments of the present disclosure;

[0013] FIG. 7 illustrates an embodiment of a composite waveform.

[0014] FIG. 8 illustrates a comparison of Knudsen and self-diffusion (molecular diffusion) for hydrogen in a fracture network as a function of pore size, according to illustrative embodiments of the present disclosure;

[0015] FIGS. 9-10 illustrate crack propagation and brine ejection in a subsurface geologic formation, according to illustrative embodiments of the present disclosure;Atty. Docket No.: GEO-003PCT-8022-00401

[0016] FIG. 11 illustrates governing equations of a model for injection and production wells utilizing a hierarchal fracture network in a subsurface geologic formation, according to illustrative embodiments of the present disclosure;

[0017] FIG. 12 is a block diagram of an example network environment for use in the methods and systems described herein, according to illustrative embodiments of the present disclosure; and

[0018] FIG. 13 is a block diagram of an example computing device and an example mobile computing device, for use in illustrative embodiments of the present disclosure.DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

[0019] Disclosed herein are processes (methods) and systems for producing and extracting hydrogen, and optionally heat and one or more other resource(s) (e.g., mineral(s), such as silica, and / or reaction byproducts), from subsurface geologic formations. Processes may include an initial fracturing performed mechanically, for example by injection of brine under pressure greater than the minimum compressive stress in the formation, as well as by reaction-based fracturing that may result from exothermic reactions that occur in the initial fracture network formed by the mechanical fracturing (e.g., due to serpentinization). In particular, in certain embodiments, presented herein are systems and methods that employ controlled, fluid pressure-induced and / or chemically-induced (e.g., serpentinization reaction-based) hierarchical fracturing of rock to increase rock surface area and increase the production and extraction (e.g., recovery) of geologic hydrogen from in-situ sites, e.g., via injection of fluid (e.g., brine) into a volume of rock (e.g., an olivine matrix). Such controlled, pressure- and chemically-induced fracturing may be performed subsequent to an initial fracturing process, for example by injection of brine under pressure greater than the minimum compressive stress in the formation. A process may include forming a fracture network that may include hierarchal fracturing, for example using reaction-based control to develop a serpentinization front in a subsurface geologic formation.

[0020] Processes may be controlled or optimized for hydrogen production. As discussed further subsequently, such control or optimization may occur at the site-level (e.g., well pad level) instead of on a well-by-well basis. In this way, injection and production wells may be used individually or in tandem to enhance hydrogen production from a process. Levers that may be used (alone or in combination) for hydrogen production enhancement include:• Pad Design - optimized or controlled number of injection and production wells with offset well depths, and geometrical arrangement to support migration of theAtty. Docket No.: GEO-003PCT-8022-00401serpentinization front, frequency of fracks per well and duration of fracks. Generally short fracks may be used to ‘“kick start” the self-sustaining chemofracture process. • Sequenced Multi-welL Multi-stage Fracturing Operation - a program of drilling, fracturing, injecting and producing that is distinct from an oil and gas program in that it may have a plurality of fracks per well at different depths over time to access more rock, relieve stress and clear blockages over many years to obtain improved or optimal production.• Hydrogen Extraction (e.g., Recovery) - increase hydrogen flow to the surface by maintaining and increasing fracture connectivity with pressure and proppants. Reactive proppants may be used (e.g., olivine sand) to provide energy for further reaction-based control. Hydrogen’s buoyancy can also be leveraged to move hydrogen laden fluid (e.g., brine) to the surface [e.g., with shallower production (e.g., recovery) wells]. Phase separation membranes may also be used (e.g., down hole) to maintain fluid and pressure at depth while allowing hydrogen to migrate upwards.• Fluid (e.g., Brine) Circulation - maintain pressure throughout the system to keep the fracture network open and active, and conserve enthalpy and maintain high flow rates, including the continuous replenishment of w ater.• Fluid (e.g., Brine) Composition - the use of one or more additives to reduce viscosity of the flowing fluid (e.g., brine), plus surfactants to increase contact area in small pores. Alternatively, or additionally, one or more additives may be used to reduce hydrophobicity and suppress bubble formation. Salt may be removed to maintain the salinity level within a range that is conducive to serpentinization.• Fluid (e.g., brine) pH - maintain the pH in the (slightly basic) optimal range, for example by adding acid during injection and / or circulation, or removing alkalinity as the serpentinization reaction drives pH upward.• Reaction Conditions - maintain the temperature, composition, and other properties of the fluid and / or formation to improve or control the reaction conditions. For example, a temperature of the formation can be controlled using heating (e.g., electrical heating, injecting heated fluid or brine, etc.).• Pressure Control - Applying a controlled pressure modulation to the formation. For example, one or more pressure modulations can be used to control fluid movement within the formation, stressing the formation to create fractures, or the like.

[0021] Processes may use many wells at one or more given sites (e.g., one or more well pads) of a subsurface geologic formation simultaneously (e.g., instead of serially). Reactions mayAtty. Docket No.: GEO-003PCT-8022-00401be controlled or optimized across a given site and / or multiple sites of a subsurface geologic formation. For example, a number of wells that may be used (e.g., simultaneously) at a given site may be 1-1000 wells. A number of given sites (e.g., well pads) that may be used (e.g., simultaneously) may be 1-100 sites (e.g., depending on extent of a subsurface geologic formation). Wells and / or sites may be fractured repeatedly over time (e.g., in stages) in order to achieve desired rate of production until an entire deposit is ultimately substantially consumed. Models disclosed herein may be used to control such processes. A given well may produce at a rate of 0.1 to 50 kT of Fb per year with 1-5 kT being typical. The total production from one or more given sites (e.g., well pad(s)) of a subsurface geologic formation may be in the range of a few kT / year to a few MT / year depending on the number of wells, and the rate of production.

[0022] Presented herein are systems and methods for the production (e.g., in situ production) of geologic hydrogen, geothermal energy (heat), amorphous silica, rare earth minerals, metals, and / or other resource(s), e.g., from geological environments such as subsurface rock formations. A geological environment may include ultramafic rock, such as peridotite, mafic rock containing olivine, such as troctolite, banded iron formations (BIFs), and other Fe2+-rich geological formations including but not limited to formations rich in minerals such as Olivine (Mg, Fe)2SiO4, Orthopyroxene (Mg, Fe)SiO3, Clinopyroxene (Ca, Na)(Mg, Fe, Al, Ti)(Si, Al)2Oe, Hedenbergite CaFeSi2O6, Pyrite FeS2, Ilmenite FeTiCh, Hercynite (FeA12O4), Siderite (feCOs). Magnetite (FesOr). Grunerite (Fe? SisO22(OH)2), Lepidocrocite FeO(OH), Glauconite (K. Na)(Mg, Fe. Al)2(Si. Al)40io(OH)2, Chamosite (Mg, Fe)5Al(AlSi30io)(OH)s, Greenalite (Fe2+, Fe3+)2-3Si2Os(OH)4, Minnesotaite (Fe, Mg)3Si40io(OH)2, Vivianite Fe2(PO4)28H2O, and rock formations such as dunites, peridotites, basalts, kimberlites, lamproites, banded iron formations, and greywackes. A geological environment may be suitable for performing serpentinization, for example to form hydrogen from iron-rich rock (e.g., ultramafic rock, including, for example, peridotite, or mafic rock containing olivine and / or pyroxene, including, for example, basalt).

[0023] In particular, in certain embodiments, presented herein are systems and methods that employ controlled fluid pressure and / or chemically-induced (e.g.. serpentinization reactionbased) hierarchical fracturing of rock to increase rock surface area and increase the production and recovery' of geologic hydrogen from in-situ sites, e.g., via injection of fluid (e.g., brine) into a volume of rock (e.g., an olivine matrix). Such controlled, fluid pressure and / or chemically -induced fracturing may be performed subsequent to an initial fracturing process,Atty. Docket No.: GEO-003PCT-8022-00401for example by injection of brine under pressure greater than the minimum compressive stress in the formation.

[0024] For example, presented is a method that includes fracturing by injection of brine under pressure greater than the minimum compressive stress in the formation to create an initial fracture network and then relies on an ongoing fluid pressure variations and / or chemical reaction (e.g., serpentinization) to create further stress and thereby propagate the front controllably, for example according to the fluid (e.g., brine) injection rate and composition. Exothermic chemical reactions (e g., serpentinization) can release energy to produce (or assist) the fracturing. In certain embodiments, an exogenous source such as a pump or heat source (such as an electrically heated wire or other form of injected energy, for example) may be used to control rate of propagation and hydrogen production.

[0025] In certain embodiments, in addition to reaction-based fracturing of rock, the method employs mechanical fracturing (e.g., drilling) as well (e.g., for initial fracturing). Hydraulic fracturing (fracturing) techniques may be employed for such mechanical fracturing, for example as are found in the oil and gas arts.

[0026] The current state of the art for generating fractures in the subsurface to control fluid flow is hydrofracturing. In conventional hydrofracturing, a mixture of fluid and / or solids is injected into the subsurface at a pressure high enough to overcome the preexisting stress caused by the weight of the overburden, as well as the fracture strength of the rock formation (i.e., the formation breakdown pressure). Fluid pressures can reach as high as ~ 100 MPa in hydrofracturing.

[0027] In certain embodiments, disclosed herein is a new method for controlled fracturing of rock that results from a combination of injection of brine under pressure greater than the minimum compressive stress in the formation with the pressure resulting from volume changes that accompany the reaction of water with iron-rich rocks in the subsurface, that is, “reactionbased” or “reaction-induced” fracturing (for example, as shown in FIG. 1). The volume changes associated with these reactions can be very large, for example up to ~ 50% increase in volume in some serpentinization reactions. The accompanying crystallization pressures can be 200 - 1500 MPa in amplitude - far greater than the pressures driving conventional hydrofracturing. These pressures are generated locally, not far away at the well head as in hydrofracturing. Controlled injection of brine under pressure greater than the minimum compressive stress in the formation and controlled reaction-induced fracturing is both more powerful and more controllable than hydrofracturing, providing a new process for controlling fracturing in the subsurface. Reaction-induced fracturing may produce fracturing withAtty. Docket No.: GEO-003PCT-8022-00401different characteristics than mechanical fracturing, for example having different characteristic channel dimensions (e.g., smaller diameter).

[0028] For serpentinization at the scale of individual source rock (e.g., olivine) grains, hierarchical reaction-induced fracturing is known to be a mechanism by which water penetrates into and reacts with grains (e.g., due to loosened grain boundaries), accompanied by an exponentially increasing reactive surface area. In the method outlined in FIG. 2, an initial change in stress and temperature acting on the mineral grains in the rock formation dilates the grain boundaries. Flow of fluid into the grain boundaries sets up chemical reactions that lead to further perturbations in stress and temperature. In certain embodiments, the method includes controlling the dimensions, strengths, volume changes, and orientations of hydrofractures and the temperature and chemistry of the fluid used to promote stimulation in order to tune the rate at which fractures occur and the rate at w hich the resulting surface area produces hydrogen and grow s (FIG. 2).

[0029] Fluid pressure and reaction-induced volume changes in localized stimulated regions have large effects on the state of stress in the surrounding regions. By controlling the shapes of these localized stimulated regions, the method controls the fracture propagation between and among these regions, providing control of the fracture pattern and fluid flow paths to and from the stimulated regions.

[0030] In addition to the reactions between water and certain minerals (e. g., olivine and pyroxene) that result in large volume increases, certain other hydrogen-producing reactions between water and different minerals (e. g., minnesotaite) result in large volume decreases. Engineering such volume decreases via stimulation of a localized region is equivalent to providing negative pressures in hydrofracturing, opening up an entirely new mechanism for generation and control of fractures. It is therefore possible to control the rates and surface areas resulting by engineering the fluid composition, temperature, and the like.

[0031] Other reactions that do not involve production of hydrogen can also lead to large changes in volume, both expansion and contraction. Stimulating these other reactions provides an additional mechanism for controlling fracturing.

[0032] FIGS. 2A through 4B depict modeling fracturing via a mathematical model to control and / or optimize fracture growth and hydrogen production from the site. Note, in FIGS. 3A-3B, there is a period of exponential growth of fractures. FIG. 4A show s a stress profde along a penny-shaped fracture, an example showing extensional microfractures created by volume changes with extension parallel to serpentinite crystals, and an example showing extensional microfractures w ith tangential extension at the boundary of approximately spherical grain ofAtty. Docket No.: GEO-003PCT-8022-00401spinel in an olivine matrix.

[0033] In certain embodiments, the method includes alternating fluid (e.g., brine) injection and hydrogen extraction cycles, e.g., akin to a Huff and Puff process. For example, in certain embodiments, high and low pH fluid (e.g., brine(s)) are alternately injected into a mineral deposit (geologic site) to enhance the dissolution of minerals from the rock (e.g., for cyclic leaching).

[0034] In certain embodiments, a geologic site for production of hydrogen can have multiple wells. In certain embodiments, it is advantageous to stage the various wells of the site such that certain wells are being fractured (e.g., via the hydrofracturing methods described herein) while others are being used for hydrogen production / harvesting. For example, in certain embodiments, there may be multiple stages of fracks performed such that not all the fractures will be completed at once, due to very high stresses that occur during serpentinization.

[0035] In certain embodiments, first a subset (e.g., one or more) of wells at a site are hydraulically fractured to a stage of fracturing (e.g., a first stage, second stage, or third stage) less than a final stage (e.g., fifth or more stage), then those wells may be used resource (e.g., hydrogen) production / harvesting. Subsequently, or simultaneously, to the resource production / harvesting another subset of the wells may be hydraulically fractured. Thus, unlike many conventional resource extraction processes (e.g., natural gas extraction) where a well is fully fractured and resource extraction performed before moving on to another well at a site, in some embodiments, a well of a plurality of wells at a site is partially fractured and then resource extraction / production is performed (e g., before further fracturing the well), optionally, before, during, and / or after one or more others of the plurality of wells undergo a similar partial fracturing and subsequent resource extraction / production process. Such resource extraction / production processes may be used to control fracture formation (e.g., hierarchical fracture formation) based on chemical-reaction-based control. In this way, energy generation, resource extraction, and rock formation stability' can be optimized.

[0036] In some embodiments, a single well may be used for injection and production, for example in a ‘low cost” mode. Such injection and production may occur in a reciprocating sequence. Such injection and production may effect quasicontinuous production, for example in a huff and puff mode. A set of such wells may be operated individually (e g., with little or no interaction in a subsurface geologic formation) (e.g., simultaneously).

[0037] Wells at a site may be fractured in stages, where one or more stages are performed using mechanical fracturing (e.g., by hydraulic fracturing by injecting brine at pressure greater than the formation breakdown pressure or, alternatively, by fracturing the formation vary ing brineAtty. Docket No.: GEO-003PCT-8022-00401pressure between values greater than the minimum compressive stress in the formation but less than the breakdown pressure) and one or more subsequent stages are performed using reactionbased controlled fracturing (e.g., using energy from an exothermic reaction, such as, for example, a resource production reaction, such as, for example, serpentinization). Different wells at a site may be simultaneously fractured at different stages at the same time. Different wells may be in different stages of fracturing at a given time. Multiple wells may be simultaneously fractured at different stages at the same time. Multiple wells may be in different stages of fracturing at a given time. In this way, a site may be used for resource extraction in a non-serial manner, that is, without first exhausting a first well before moving on to a subsequent well.

[0038] In certain embodiments, the fluid (e.g.. brine) itself is used as an underground hydrogen storage medium. For example, hydrogen may be dissolved in the fluid (e.g., brine) and stored in a dissolved state, for later extraction from the fluid (e.g., brine) (e.g., upon bringing the fluid (e.g., brine) to the lower pressure near the surface). In certain embodiments, the production and / or extracting (e.g., harvesting) of hydrogen and the production and / or extraction (e.g., harvesting) of heat are staged in the various wells of a given site of a subsurface geologic formation.Hydrogen Production

[0039] Fracturing rocks to stimulate hydrogen production is a significantly different problem than shale gas. The following paragraphs describe some significant differences.

[0040] For shale gas, access to the rock volume where the shale gas is present is provided by conventional hydrofracturing, with brine injected extremely rapidly into the formation at rates sufficiently high that the breakdown pressure of the formation is exceeded and a quasi-planar fracture propagates rapidly through the formation. Such conventional hydrofracturing could be used in the process of producing hydrogen. An additional method disclosed here is the slower fracturing of the rock formation by injecting brine at pressures greater than the minimum compressive stress in the rock formation but less than the breakdown pressure. The pressure is then varied with time at a combination of various formation-specific pressures such that a more complicated fracture pattern, with much greater surface area grows over time.

[0041] Shale gas exists in the rock volume before that volume is accessed. It is distributed volumetrically, so the volume of rock accessed is the product of fracture area and the distance perpendicular to a fracture that shale gas is adverted and / or diffused into the fractures. For shale gas, the flux into a fracture network of area A(t) is typically modeled initially by a hyperbolic decline:Atty. Docket No.: GEO-003PCT-8022-00401W)=gCt= °W)1(1 + bd(t = ti)t)bWhere b is the hyperbolic decline constant, and d is the initial decline rate.For shale gas, if fracture area is constant (no refracturing), production decreases over time. For a characteristic timescale of a year, shale gas diffuses a distance of ~ 1 m. Thus, for every square meter of fracture area created, shale gas is produced from a volume of ~ 1 cubic meter.

[0042] In contrast, for stimulated hydrogen production, there is negligible hydrogen production before water is introduced to a fracture. Once water comes into contact with the rock formation, hydrogen production in the region in contact with water is governed by the rate, R, at which the water reacts with the rock formation. For serpentinization of olivine, the reaction occurs at the surfaces of the olivine mineral grains and the reaction rate depends on, at least, T, P, and pH. The rate at which hydrogen is produced on a surface of areaNf / J is QH(C) = CHv(t)A(t where CH is a constant relating the mass of hydrogen to the volume of rock converted and v(t) is the velocity of the reaction front corresponding to R t) acting on surface area A(t). This equation shows that if R(t) and Aft) are constant, the hydrogen production rate will not show the decrease with time that is typical of production of shale gas and geothermal heat. An experimentally measured rate at which the serpentinization progresses (McCollom, et al., 2020) is 2*1 O'12m / s or 60 microns / y. This rate is large enough to completely react an olivine grain of diameter 150 microns in one year.

[0043] An important additional consideration for hydrogen stimulation is that the reaction that produces hydrogen may result in large volume changes. For example, serpentinization of olivine leads to a volume increase of up to about 50%. This volume increase is associated with a large reaction pressure that may lead to reaction-induced fracturing. Furthermore, such a reaction may be exothermic, leading to large temperature increases in a subsurface geologic formation. These temperature changes may result in thermal fracturing. If water is introduced into the new fractures, additional reacting surface area will be produced, leading to increased production. These result in positive feedback that can lead to hierarchical fracturing at a rate that increases exponentially with time.

[0044] Inert proppants are commonly used in hydraulic fracturing for shale gas to keep fractures from closing and may be used for hydrogen production as well. In contrast, in some embodiments of the present disclosure, one or more reactant proppants (e.g., small-diameter reactant mineral grains with large ratios of surface area to mass) may be used. In some embodiments, mafic or ultramafic sand (e.g., containing olivine or another Fe2+containingAtty. Docket No.: GEO-003PCT-8022-00401mineral) may be used as a proppant. Alternatively, or additionally, application of hydraulic pressure (e.g., continuous hydraulic pressure) to one or more wells at a given site and / or a fracture network of a subsurface geologic formation may be used to keep fractures open during hydrogen production. In some embodiments, application of hydraulic pressure is preferred to use of inert or reactive proppants.

[0045] Total reaction rate during serpentinization is proportional to area of the reacting surface. Increasing initial surface area (e.g., by varying brine pressure with time or by using one or more proppants) may kick-start an exothermic reaction that heats adjacent rock in subsurface geologic formation, produces volume increases to accelerate continued fracturing, and produces hydrogen. Injecting particles small enough to lodge in between mineral grains of walls of a fracture can lead to loosening and damaging of grain boundaries, increasing their permeability and allowing water to stimulate a larger volume. By controlling location of where these reactant materials are placed in an initial fracture and controlling their reactant properties, initial sites of nucleation of hierarchical fracturing can be engineered.

[0046] The state of stress adjacent to and within a region undergoing volume change caused by controlled fluid pressure variations or by volume changes associated with chemical reactions during hydrogen production can be strongly influenced by geometries, orientations and interactions of such a region. Controlling these stress fields can provide increases in A(t). In some embodiments, in-situ distribution of sizes, shapes, and orientations of mineral grains in fracture walls, as well as their anisotropic thermal and elastic properties can be used to design temperature and stress perturbations (e. g., by controlled fluid pressure that increases and decreases over time) to increase the rate of propagation of damage into a subsurface geologic formation, increasing its permeability and decreasing its fracture strength.

[0047] At a larger scale, geometries, sizes, orientations, and volume changes of stimulated regions may be used to engineer the state of stress outside these regions. In particular, the magnitude and direction of the principal stresses can be manipulated to control the formation of additional fracturing. Such control can guide the fracturing that assists transport of fluids with dissolved hydrogen to one or more production wells. Such control may also be used to guide geometries, orientations and sizes of new reacting zones.

[0048] The rate of reaction that produces hydrogen may be augmented by tuning of the chemistry of the injected fluid (e.g., brine). Thus, controlling R(t) provides a mechanism for both direct production of hydrogen on existing surfaces and production of reactants that lead to further increases in A(t) via reaction-induced fracturing.

[0049] Starting with one or more mechanical fractures (e.g., hydrofractures) to access sourceAtty. Docket No.: GEO-003PCT-8022-00401rock containing Fe2+, an engineered system can be developed to induce hierarchical fracturing at a rate that may accelerate with time. Injection of one or more proppants (e.g., small-diameter solid reactive grains) may provide substantial additional surface area that accelerates a reaction (e.g., serpentinization), which may provide heat and a source of stress to accelerate initial growth of a fracture network of a subsurface geologic formation. Reaction rate may be increased by manipulating chemistry of an injected fluid (e.g., brine). Sequencing of mechanical fracturing (e.g., by brine pressure variations) in a subsurface geologic formation for the development of a producing hydrogen field may differ significantly from the sequencing for shale gas fields.

[0050] At scales of tens to hundreds of meters, hydrofracturing for shale gas is typically modeled using planar fractures in pre-specified locations. For example, the commercial software ResFrack (https: / / www.resfrac.com / software) represents fractures as long planar features that are built into the mesh, as shown in FIG. 6. Alternatively, in the Discrete Fracture Network (DFN) (e.g., Neil et al., 2024), fractures are pre-specified as planes of arbitrary location. Neither of these approaches allow spontaneous fracturing with locations and orientations determined by the chemomechanics of reaction-induced fracturing. Natural serpentinization at oceanic spreading centers has been observed (e. g., Roumejon & Cannat, 2014). In this context, Fe2+-rich peridotite rocks consisting mainly of olivine and pyroxene have been observed to be completely transformed into serpentinite over geologic time. The current understanding is that seawater is introduced into the rock via faults and fractures. Once the reaction begins, peridotite bodies are progressively fractured as the result of the volume increases accompanying serpentinization to dimensions of as small as microns and completely transformed to serpentinite. This process is called hierarchical fracturing. Although this process is completed, there are not good constraints from geologic observations regarding reaction kinetics or progression.

[0051] The geometry and rates of serpentinization of hierarchical reaction-induced fracturing at the grain scale (tens of microns to centimeter) has been modeled (e.g., FIG. 2, based on Malvoisin et al., 2017) and can lead to rapidly increasing surface area as the crystal is shattered by reaction-induced expansion. In these models, fractures are initiated by stresses from reaction-induced volume increases at etch pits at sub-grain surfaces. These fractures grow away from their initiation sites, with reaction-induced volume increases within these fractures wedging them open and extending their lengths.

[0052] In order to produce hydrogen at commercial rates it is necessary to access many more mineral grains than those that are intersected by the initial fractures created by injection ofAtty. Docket No.: GEO-003PCT-8022-00401brine into the wellbore and initial fractures. The volume of the formation must be accessed by additional fractures via hierarchical fracturing. Growth and propagation of reaction-induced fracturing at the meter scale has been modeled using continuum models using the phase field approach (Evans, et al., 2020). In this approach, the phase field represents a damage function, approximating a collection of discrete microfractures as a continuous damage function. Increase in the damage function corresponds to the aggregation of microfractures into a fracture. These models show fractures initiating and propagating, see FIG. 5A. Secondary fractures spontaneously initiate at and approximately perpendicular to the primary fracture surface and grow away from it. Tertiary fractures spontaneously initiate at and approximately perpendicular to the secondary fracture surface and grow away from it. The fracture network geometries in this model bear a striking resemblance to field observations, as shown in FIG.5B. Thus, hierarchical fracturing of rock formations by reaction-induced fracturing exists in nature. This continuum model of behavior at the meter scale also gives fracture geometries very similar in topology to those produced by the discrete fracture models at the 50-micron scale discussed in the previous paragraph.

[0053] Because observations of power law distributions of fracture dimensions are extremely common in nature, the present disclosure recognizes that results at meter scale may be generalizable over several orders of magnitude in either direction. Reaction-induced fracturing will generate fracture networks on all scales from the km scale of the stimulated field to the micron scale of sub-grains. The following describes ways in which to accelerate, control, and model such processes.Application of Composite Waveform Pressure Variations

[0054] The present disclosure provides systems and methods for applying composite waveform pressure modulation to geological formations to enhance fracturing, weathering, and resource recovery. The composite waveform can be applied during the completion phase during which the well is being established prior to starting production from the well as well as during the production phase of a well. A composite waveform comprises multiple pressure variation signals at different amplitudes and frequencies, where each frequency component performs a distinct function. This approach enables simultaneous and independent control of different physical processes occurring at different length scales and depths within the formation.

[0055] As used herein, a “composite waveform” is a time-dependent pressure signal P(t) comprising a defined set of frequencies or waveforms that add together to create a complex pressure variation pattern. In some embodiments, the composite waveform can be constructedAtty. Docket No.: GEO-003PCT-8022-00401by superimposing multiple frequency components, each targeting specific physical processes or operational objectives. In some embodiments, the composite waveform can be constructed by sequentially applying one or more frequency components over time, with each frequency component of the one or more frequency components targeting specific physical processes or operational objectives. Waveforms may be described by various mathematical expressions, (e.g., Fourier components (sines and cosines or complex exponentials), wavelets, etc ). The time-dependent pressure P(t) applied to the formation through one or more wells is constructed as a composite waveform. As an example, expressing the pressure variation using Fourier sine components, a waveform can have the form:P(t) = P₀ + P₁ [1+ sin(2π x f₁ x t + φ₁)] + P₂[1+ sin(2π x f₂ x t + φ₂)] +... + Pₙ [1+sin(2π x fₙ x t + φₙ)]

[0056] where Po is the static or baseline pressure maintained in the well, Pi, P2,... Pnare the amplitudes of additional periodic pressure modulations, fi. f2,... fnare the corresponding frequencies of pressure modulations (the defined set of frequencies), φ₁, φ₂,... φₙ are phase angles for each frequency component, and t is time. The constant “1” is included within the square brackets defining each component so that the value of each component varies between zero and Pnand has a mean value of Pn / 2. In a simple example form, the composite waveform comprises:P(t) = P₀ + P₁ [1+sin(2π x f₁ x t)] + P₂ [1+sin(2π x f₂ x t)]+ P₃ [1+sin(2π x f₃ x t)]

[0057] The additive nature of these frequency components creates a complex pressure signal where multiple physical processes are stimulated simultaneously. Within these functions, the amplitude can also be represented as a function of time, where some of the frequency components may have a zero or substantially zero amplitude at certain times. Alternatively, any of the frequency components described herein can be applied alone in some aspects.

[0058] Each frequency component within the composite waveform can perform a different function in the overall system. The static pressure Po represents the baseline pressure maintained in the well. This component provides the reference pressure level above which modulations are added. Initially, before there are fractures in the formation, this static pressure Po may be set as the hydrostatic pressure provided by the weight of the brine at formation depth in the borehole. This relatively low value of Po allows maximum additional time dependent pressure variations to be exerted at the wellbore to initiate breakup of the formation. Once fractures extend a distance comparable to the wellbore diameter into the formation, this staticAtty. Docket No.: GEO-003PCT-8022-00401pressure Po may be set to a value equal to or greater than the value of the least compressive stress in the formation, which is the pressure level needed to keep fractures open in the rock formation and allow flow from the well bore into and out of the rock formation. Alternatively, as is typical for hydrofracturing for shale gas, the wellbore pressure may be greater than the breakdown pressure of the rock at the specified depth.

[0059] As an example, the time varying frequency components can comprise three components. The first component can be chosen to provide variable stress conditions to generate an initial fracture network. A second (low frequency) component can be used to control the pressure with respect to brine injection and production from the wellbore, and a third, higher frequency component can be used to stress or weather the formation to create microfractures.

[0060] The first frequency modulation component can be used initially to establish transmissive fractures in the formation. The stress variations induced in the formation by pressure variations decrease with distance, r, away from the borehole center as (R / r)2, where R is the radius of the borehole. These initial pressure variations can initially have an amplitude Pi equal to the difference between the breakdown pressure, Pb, and the initial value Po, the hydrostatic brine pressure at the formation depth. This large amplitude pressure swing maximizes the damage done to the formation within a distance comparable to the diameter of the wellbore. The period of this pressure swing should be as short as possible given pump constraints (minutes to hours), in order to subject the formation to as many cycles as possible, as implied by the Paris failure formulation of cyclic fatigue. Once pressure cycling in the wellbore establishes fractures with length comparable to the diameter of the w ellbore in the formation surrounding the w ellbore, fatigue of the formation may be accomplished over the larger distances that can be stressed by cycling pressure within the fractures. The frequency of pressure cycling in this stage can be tuned to a lower value that is commensurate with injecting and withdrawing brine into the fractures, loading the formation by deformation of the fracture walls, as well as by further extending the fracture lengths. At this point, the static pressure Po is raised to the value of the minimum compressive stress in the formation in order to keep the fractures open,

[0061] There are a number of competing physical mechanisms that can be balanced to determine the amplitude and frequency of this component for a given rock formation. Consider a one dimensional fracture of aperture t and length a. The flux of fluid per unit width, q. into and along the fracture is given by the formula q = — where μ is the fluid viscosity, p isAtty. Docket No.: GEO-003PCT-8022-00401the pressure and w is the distance along the fracture. For a planar fracture in an elastic medium filled with a fluid at excess pressure p. the width of the fracture is proportional to p and variesaccording to w(x) = - V a2— x2where E. is the Y oung’s modulus of the medium and v is Poisson’s ratio. The maximum fracture aperture occurs at the intersection of the fracture with the borehole at x = 0. The pressure gradient dp / dx is inversely proportional to the fracture length, a. The volume of the fracture per unit out-of-plane thickness is proportional to the product (wa), with w proportional to a, and is equal to V = 4(1 — v²)pa² / E* An estimate of the time that it takes to fill or empty a fracture can be obtained by dividing V by the flux q and assuming that a typical pressure gradient is approximated by p / a. Because both V and q are 2 37r [f 1 proportional to the sq—T7 uare of the fracture length, the characteristic timescale r -1!—is independent of a, but depends inversely on the cube of the pressure. Thus, maximizing Pi both maximizes the stress and minimizes the characteristic time associated with filling fractures. Using the constraint that the total maximum pressure is the breakdown pressure, Pb relates Po and Pi by Pi = Pb-Po. In order that fractures remain open, the amplitude for Po is just above the minimum compressive stress and Pi = (Pf - Po). Choosing representative parameters for crystalline rock formations and depths results in a characteristic time T ~ 0.01 second. Because the flux depends on the cube of the fourth power of P₁, significant flux into and out of the fracture occurs only over a small fraction of the period. In addition, because the aperture of the fracture decreases with distance away from the wellbore, the flux decreases still further. Taking these into account, the minimum period of this component should be about 1 second. As fractures increase with length over time, the volume provided by pumps increases, limiting the rate at which brine can be injected into the fractures and lengthening the period of oscillation. The frequency fi is typically in the range of 1 Hz to about 2×10⁻⁶ Hz (period 1 second to 1 month), or with periods between about 1 day and about 1 week.

[0062] The second frequency component f₂ can control production and injection operations by withdrawing injection / production fluid (e.g.. hydrogen-laden brine or other resourcecontaining fluids) from one or more wells, driving fluid movement and exchange over long distances ranging from meters to hundreds of meters, coordinating fluid circulation between injection and production wells. This can facilitate large-scale circulation patterns within the fracture network, and control the timing and rate of production cycles. The relatively long period allows pressure changes to propagate through the formation and coordinate field-scale fluid management. At the initial stages, this second component would be the same as the firstAtty. Docket No.: GEO-003PCT-8022-00401component in the paragraph above. Once the length of the fracture network is established, the first component would be removed and replaced by this second component. As described in the paragraph above, the period would be limited by the capacity of the pumps, so the minimum period would increase as the complexity of the fracture network evolves continuously. The maximum period would be constrained by how frequently the brine in the medium needs to be replaced in order to extract the hydrogen created by the oxidation of Fe²⁺ and to inject water to allow additional rock to be reacted.

[0063] The third component can comprise a high-frequency modulation component having an amplitude P₃ and a frequency f₃ typically in the range of about 0.5 second to about 1 hour, or between about 1 minute and about 30 minutes. In some aspects, a ratio of the frequency f₁ or f₂ to the frequency component f₃ can be at least about 5, at least about 10, or at least about 20. This component can serve to stress or weather the rock by weakening rock through mechanical fatigue and stress cycling, inducing weathering and micro-fracturing at a length scale of microns to millimeters, creating and propagating micro-cracks at grain boundaries and within mineral grains, and / or enhancing permeability and reactive surface area at fine scales. The ability to apply stress cycles can operate independently of chemical reactions, though the presence or use of such reactions may amplify the production of the fractures. The rapid cycling induces repeated stress-strain cycles causing mechanical fatigue and progressive micro-fracture development. The selection of the specific frequency can be based on various factors such as one or more parameters descriptive of the formation (e.g.. the permeability, the degree of serpentinization, the depth, mineral composition, temperature, or any combination thereof. When combined with the low frequency component, the low frequency component can open new, larger fractures, and the high frequency component can then create additional surface area around the larger fractures through the creation of microfractures.

[0064] In certain embodiments, an ultra-low frequency component (e.g., a component with a frequency below that of the low frequency component) with frequency fo (potentially even lower than fi) can be included with a frequency f₀ typically in the range of 1 / week to 1 / month (periods of weeks to months). This ultra-low frequency component can function to control the depth of penetration into the formation, affecting processes at distances of hundreds of meters to kilometers through slowly varying pressure gradients that drive long-term advancement of the reactive front or fracture network deeper into the formation. This component allows strategic control over how far into the formation the reactive and fracture zones extend over the life of the production operation.

[0065] Additional frequency components may optionally be included for specialized functions.Atty. Docket No.: GEO-003PCT-8022-00401For example, a mid-frequency component with frequency f₄ typically in the range of 1 / hour to 1 / day may function to fracture the formation at intermediate scales, affecting fracture propagation at distances of centimeters to meters, and creating and extending macro-fractures while maintaining fracture network connectivity. This component targets the intermediate scale between micro-weathering and field-scale circulation.

[0066] The frequencies used to form the composite waveform can overlap in both time and space, creating temporal overlap where all frequency components are present simultaneously in the pressure signal, the resulting pressure at any instant is the sum of all components, and complex interference patterns arise from the interaction of multiple frequencies. This process is shown schematically in FIG. 7 where a lower frequency can overlap with intermediate and higher frequencies to form the composite signal. The frequencies also create spatial overlap where different frequency components affect different length scales, but these scales overlap and interact, micro-fractures created by high-frequency modulation connect to macro-fractures influenced by lower frequencies, and field-scale circulation driven by low frequency transports fluids through networks created by higher frequencies. There is also functional overlap where, while each frequency component has a primary function, the functions interact synergistically such that rock weathering (high frequency) creates pathways for fluid circulation (low frequency), production / injection cycles (low frequency) expose fresh rock surfaces to weathering (high frequency), and depth control (ultra-low frequency) expands the volume affected by all other components.

[0067] The composite waveform can produce an output at each point in time through careful selection of amplitude ratios, frequency ratios, and phase relationships. The relative magnitudes of Pi, P2, P3, etc. determine the balance between different functions (weathering, fracturing, circulation, depth control). The relationships between fi, f2, fa, etc. can be selected to avoid destructive interference and promote constructive interaction. The phase angles φ₁, φ₂, φ₃, etc. can be tuned to create specific interference patterns that enhance desired outcomes. Exemplary configurations can include a high P₃ / P₂ ratio that emphasizes rock weathering over circulation (early-stage formation development), a high P₂ / P₁ ratio that emphasizes production over new fracture generation (mature production phase), and specific phase relationships that may create periodic "pulses" where all components constructively interfere to exceed breakdow n pressure.

[0068] In some embodiments, the total instantaneous pressure P(t) of the composite waveform may be less than the breakdown pressure at certain times in the cycle, greater than the breakdown pressure at other times in the cycle, or may cyclically cross the breakdown pressureAtty. Docket No.: GEO-003PCT-8022-00401threshold. This behavior depends on the sum of all components at each instant such that when components constructively interfere (all in phase), P(t) may significantly exceed Po and surpass breakdown pressure, when components destructively interfere (out of phase), P(t) may fall below Po and below breakdown pressure, and the frequency of breakdown pressure crossing is determined by the beat frequencies created by the overlapping signals.

[0069] In some embodiments, the total instantaneous pressure P(t) of the composite waveform may be less than the breakdown pressure for the entire the cycle. Maintaining the pressure below the breakdown pressure can allow the fracture formation to be controlled and avoid undesired fracturing. For example, the fracturing can be controlled to avoid interactions with faults or aquifers around the wellbore.

[0070] The composite waveform system provides multiple control parameters that may be adjusted independently or in combination, including amplitude parameters comprising values of Po (static baseline pressure), P₁ (low-frequency amplitude for production / injection control), P2 (high-frequency amplitude for rock weathering), and Pa,... Pn(additional component amplitudes for fracturing, depth control, etc.), frequency parameters comprising values of fi (low frequency for production / inj ection, approximately 1 / day to 1 / week) and f₂ (high frequency for weathering, approximately 1 / second to 1 / hour), and optionally, fo, fa,... fn(additional frequencies for specialized functions), phase parameters comprising current values of φ₁, φ₂,... φₙ (relative phase angles controlling interference patterns); and time-evolution functions describing how each amplitude, frequency, and phase evolves as P₁(t), f₁(t), φ₁(t). etc., including tuning schedules and adaptation algorithms.

[0071] A feature of the composite waveform approach is that the waveform can be tuned over time and changes over time to adapt to evolving formation conditions and operational objectives. As the formation develops and production progresses, the composite waveform parameters can be adjusted such that the baseline pressure Po(t) may increase or decrease based on formation response, individual component amplitudes Pi(t), P₂(t). Pn(t) are adjusted independently, frequencies f₁(t), f₂(t). fn(t) may be shifted to target different length scales as formation characteristics change, and phase relationships φ₁(t), φ₂(t), φₙ(t) are adjusted to optimize interference patterns.

[0072] For example, during the early stage of formation development, the composite waveform can focus on rock weathering (large P₂), high emphasis on fracturing (large P₃ if present), moderate circulation (moderate Pi), and a focus on building reactive surface area and permeability. During the middle stage of production ramp-up, there can be balanced amplitudes across all components, a balancing of all functions simultaneously, fine-tuning ofAtty. Docket No.: GEO-003PCT-8022-00401phase relationships for maximum production. During the late stage of mature production, there can be an emphasis on circulation (large Pi), lower weathering intensity (reduced P2), possible increase in depth control (increased Po or ultra-low frequency component), and a focus on sustained production from established fracture network. During an extension stage for depth advancement, there can be an introduction or enhancement of ultra-low frequency component, adjusted baseline pressure Po, modified frequency ratios to push reactive front deeper.

[0073] The composite waveform may be tuned in response to measured hydrogen production rates, formation pressure responses, seismic monitoring indicating fracture growth, chemical composition changes in produced fluids, temperature measurements, digital twin model predictions, machine learning optimization recommendations, and predetermined operational schedules.

[0074] The mechanism of rock weathering induced by the high-frequency component of the composite waveform does not depend on volume-changing reactions. In some aspects, the process can begin with a mechanical fracturing (e.g., hydrofracturing) and continue with the formation of fractures using applied cyclic stress. This weathering mechanism operates through purely mechanical processes including cyclic stress, fatigue, and progressive damage accumulation, functions effectively with or without chemical reactions occurring in the formation, and may be amplified by the existence of volume-changing reactions (such as serpentinization as described herein), but is also useful without any metamorphic reactions. Because the weathering mechanism is reaction-independent, the composite waveform approach is applicable to reactive formations (e g., olivine-rich rocks for hydrogen production), non-reactive formations (e.g., granite for enhanced geothermal systems), any geological setting requiring enhanced permeability, and any resource recovery application.

[0075] While the embodiments described herein can use two or three frequency components, the composite waveform may include four or more frequency components that can combine to create the composite waveform, where each targets a specific function: fo for ultra-low frequency depth control, fi for low frequency production / inj ection control, f₂ for mid frequency formation fracturing (centimeters to meters); f₃ for high frequency rock weathering (microns to millimeters); and f₄, fₙ for additional frequencies for specialized applications. Advanced waveform construction may use the form:P(t) = P₀(t) + Σᵢ Pᵢ(t) sin(2π x fᵢ(t) x t + φᵢ(t)), where amplitudes, frequencies, and phases may all be time-dependent functions, creating a dynamically evolving composite waveform that adapts continuously throughout the productionAtty. Docket No.: GEO-003PCT-8022-00401lifecycle.

[0076] In single-well embodiments, the complete composite waveform can be applied at the wellhead, and all frequency components can be superimposed in the injection fluid pressure. The formation can respond to the overlapping signals simultaneously, and different processes (weathering, fracturing, circulation) occur concurrently at different scales. In multi-well embodiments, different wells may apply different composite waveforms, composite waveforms may be coordinated across wells to create spatial interference patterns. For example, some frequency components (e.g., ultra-low frequency for depth control) may be synchronized across all wells, other components (e.g., high frequency for weathering) may be applied independently at specific wells, and the overlapping of waveforms from multiple wells creates complex three-dimensional pressure fields.

[0077] The composite waveform may be implemented using various physical components such as computer-controlled variable-speed pumps, multiple pump systems for independent frequency generation, fast-response pressure modulation valves, hydraulic accumulators for waveform shaping, digital control systems that execute the mathematical composite waveform function P(t), signal generators that create the defined set of overlapping frequencies, and realtime monitoring and feedback control systems.

[0078] In some aspects, the composite waveform pressure modulation approach described herein may be applied to geologic hydrogen production from olivine-rich or other formations, enhanced geothermal systems in any rock type (reaction-independent weathering), mineral and rare earth element recovery, metals, hydrocarbon production from tight formations, in-situ mineral processing, underground storage development, CO2 sequestration with enhanced mineralization, and any application requiring controlled fracture network development and fluid circulation in geological formations.

[0079] In some embodiments, subsurface geologic formations (e.g., comprising or made of crystalline rocks) are fractured in a manner that leads to the establishment of a quasi-fractal fracture network, analogous to the fractal distribution of tectonically active faults. The fractures zones are not discrete surfaces of discontinuity, but rather are surrounded by damage zones, with damage decreasing with distance away from the main fracture. Mechanical fracturing (e.g., by varying the pressure in the brine with time) may be used to establish an initial large-scale structure of a quasi-fractal network of damage zones. These can bring fluid (e.g., water, e.g., in brine) to a finite thickness zone of Fe2+-rich rocks, resulting in reactions that change the volume of reacted rock. The stresses resulting from these volume changes can lead to reaction-induced fracturing that results in hierarchical fracturing at an ever-increasingAtty. Docket No.: GEO-003PCT-8022-00401rate.

[0080] Initial mechanical fractures (e.g., by varying the pressure in the brine with time), for example as shown in FIG. 1A are introduced to connect injection and / or production wells to a subsurface geologic formation. Sufficient fluid (e.g., brine) may be injected (by increasing brine pressure) to both react with a subsurface geologic formation to produce hydrogen and flush (by lowering the brine pressure) the hydrogen produced and present in the brine to production well(s).

[0081] Permeability of initial fracture walls can be engineered by controlling damage to such surfaces. Initial mechanical fracturing (e.g., by varying the pressure in the brine with time) of crystalline rocks will introduce large changes in stress and temperature. Because mineral grains in and near the wall of a mechanical fracture are generally irregular in size and shape and are typically anisotropic, with different elastic moduli and thermal expansion coefficients, stress and temperature changes will loosen the grains, forming a damage zone. Within the damage zone, there will be increased permeability, Mineral grains may have a power law or other distribution of size, giving a range of spatial scales. Larger grains dominate the transfer of stress heterogeneity away from a fracture. Smaller grains dominate the increase in surface area that drives reactive fluxes. By controlling stress (e.g., through the use of pressure modulation to create cyclic stress, etc.) and / or temperature changes accompanying mechanical fracturing, the rate at which reactive surface area can be increased can be controlled.

[0082] FIG. 4B is an example showing extensional microfractures with tangential extension at the boundary of an approximately spherical grain of spinel in an olivine matrix. The damage caused by the differences in elastic moduli as the rock experienced stress changes illustrates how these differences promote damage.

[0083] FIG. 4A shows a stress profile along a penny-shaped fracture, an example showing extensional microfractures created by volume changes with extension parallel to an ellipsoidal region experiencing a volume increase. This extensional stress explains the hierarchical fracture pattern shown in FIGS. 5A-5B.

[0084] The extensional fractures between the serpentinized olivine grains in FIG. 1C show how fracture propagation outside the reacting regions is controlled by the volume changes inside and geometries of the reacting areas. The production sequence of wells at a given site (e.g., well pad) can be used to manage a fracture network that transmits fluid from the injecting wells into the reacting regions and the fracture network that transmit fluids from the reacting regions to the producing wells.

[0085] Controlling and optimizing mechanical fracturing (e.g., by varying the pressure in theAtty. Docket No.: GEO-003PCT-8022-00401brine with time) process can done prior to production and / or in majority during resource (e.g., hydrogen) production and / or done at the scale of an entire well pad. not on a per well basis. In this way the creation of free surface area (e.g. by mechanical (e.g., by varying the pressure in the brine with time fracturing and subsequent growth of the hierarchical fracture network using reaction-based control) can be coupled to optimization of physical and chemical conditions of fluid (e.g., brine) circulation into an overall integrated optimally engineered hydrogen generation and flow process. Controlling available free surface area and the overall ”water-to-rock ratio” is only part of a hydrogen production and extraction process. Chemical and physical properties of fluid (e.g., brine) used may also be important as they can stimulate and / or enhance fluid flow in a fracture network and / or transport of hydrogen away from the reaction area to one or more production well(s).

[0086] Hydrogen flow away from its local site of production may be in tiny fractures within which diffusion length of hydrogen is much longer than a characteristic lengths of a fracture or pore network. Thus, diffusion may be controlled by Knudsen diffusion and that only after some distance away from the serpentinization front the existing fracture network is such that molecular (self) diffusion becomes the main diffusion process. Hence, chemical and physical properties of the fluid (e.g., brine) may be optimized for both hydrogen production (e.g., generation) process as well as fluid flow process towards a production well into an optimal injection and production process involving several wells of a given site (e.g., well pad).

[0087] The present disclosure further provides models of physics governing gas transport in hydrogen production in subsurface geologic formations. Such models may be used as or in a digital twin, for example to assist in controlling hydrogen (e.g., and heat and / or other resource) production. A digital twin may be implemented using a machine-learning module, for example that employs a Kolmogorov-Arnold Network (KAN) model. Models may consider resistance to flow as, for example, done in Dusty Gas Model (DGM) as a unifying framework. DGMs integrate the contributions of Knudsen diffusion, molecular diffusion, and Darcy flow, providing insights into how these mechanisms operate individually and interactively in porous fractured media. Such models also highlight the role of fracture-induced surface area in enhancing production of hydrogen by improving and prolonging Knudsen diffusion early in transport and postponing transitioning to Darcy flow until later.

[0088] A DGM may be used to describe hydrogen production in a subsurface geologic formation. In some embodiments, hydrogen is produced (e.g., generated) during the reaction of water with olivine, forming serpentine and magnetite. This reaction creates stresses that drive fracturing, exponentially increasing the reactive surface area. Early transport may beAtty. Docket No.: GEO-003PCT-8022-00401dominated by Knudsen diffusion in nanopores, but as fractures grow, transport may transition to Darcy flow. Hierarchical fracture network growth, which may be observed during serpentinization, may significantly enhance production, particularly in the Knudsen regime, where fracture connectivity strongly impacts diffusion efficiency.

[0089] In tight formations, diffusion occurs in tw o primary regimes: Knudsen diffusion and molecular diffusion.

[0090] Knudsen diffusion dominates when pore radius (rp) is smaller than mean free path ( ) of gas molecules (e.g., hydrogen). In this regime, gas molecules collide more frequently with pore walls than with each other. The Knudsen diffusion coefficient is given by:where: rpPore radius, R Universal gas constant, T: Temperature, and M: Molar mass of the gas.

[0091] Knudsen diffusion is particularly relevant in nanopores (e.g.. at a serpentinization front) (e.g., in new fractures formed in a fracture network) (e.g., along grain boundaries in a subsurface geologic formation), such as those found in early-stage reaction zones during serpentinization.

[0092] Molecular diffusion dominates when pore size is larger than mean free path of gas molecules (e.g., hydrogen), and collisions between molecules govern transport. The molecular diffusion coefficient is expressed as:v-. 4where: k. Boltzmann constant, T: Temperature, / : Gas viscosity, rmoi: Molecular radius.

[0093] In porous systems, the effective diffusion coefficient accounts for the impact of porosity ((j>) and tortuosity- (r ) on transport:where D can represent either DK„ or / Jm„i.

[0094] Tortuosity (r ) is a parameter that quantifies the complexity of the pathways gas or fluid travels through in a porous medium. It is defined as the ratio of the actual path length (Tactual) to the straight-line distance (Tstraight) between two points in the medium:Atty. Docket No.: GEO-003PCT-8022-00401

[0095] For a highly tortuous medium, the pathways are more convoluted, leading to a larger value of r. In simple geometries, T = 1 when the pathways are perfectly straight. Tortuosity affects transport properties in porous media, such as diffusion and permeability. For diffusion, the effective diffusion coefficient ( / Jen) is reduced due to tortuosity:where: (f> is the Porosity and D Bulk diffusion coefficient in free space.

[0096] A high tortuosity indicates more resistance to flow or diffusion, as the pathways are longer and more complex. Higher porosity and lower tortuosity improve the effective diffusion rate, which is useful in fractured systems. Tortuosity is often estimated using empirical relationships that relate T to porosity (^):

[0097] Examples of Tortuosity values are:• Straight tubes or channels: r = 1,• Granular packings (e.g., sand): 1.3 < r < 2.5,• Highly porous networks (e g., shale): r > 5,• Tight porous systems (e.g., nanopores in shale gas reservoirs): r > 10.

[0098] The transition times between different flow regimes in porous media, such as Knudsen diffusion, molecular diffusion, and Darcy flow, can be expressed using the material properties of the medium. These times depend on the diffusion coefficients, pore structure, and fracture development.

[0099] In the early stages of (e.g., hydrogen) production, gas transport is dominated by diffusion mechanisms (Knudsen or molecular diffusion). The transition time from diffusion-dominated flow to a mixed regime is governed by the characteristic diffusion length scale L, defined as the distance gas molecules must travel to reach fractures or larger connected pores. The transition time for diffusion-dominated flow can be given by:UAwhere: L: Diffusion length scale (distance between nanopores and fractures), Deff. Effective diffusion coefficient which is either the Knudsen diffusion coefficient or the molecular diffusion coefficient.

[0100] As fractures grow and connect, the flow regime transitions to a mixed regime involving both diffusion and Darcy flow enabled by lining-up of fractures increasing permeability and therefore lowering the tortuosity. Put another way, fractures can straighten transport. TheAtty. Docket No.: GEO-003PCT-8022-00401transition time for this phase depends on the fracture aperture (a) and permeability (k):g / Fwhere: k oc «2: Permeability (related to fracture aperture), [T. Fluid viscosity, V: Pressure gradient driving the flow

[0101] The final transition occurs when fractures fully develop, and pressure-driven Darcy flow dominates. The transition time (tDaicy) is related to the time required to establish sufficient fracture connectivity:where VDarcy is the Darcy velocity, given by:;. AAFWare? / ■<

[0102] To assess the relative importance of diffusion and Darcy mechanisms one sometimes uses the so-called Peclet-number (Pe):

[0103] If Pe « 1 then diffusion dominates and if Pe » 1 then Darcy flow dominates.

[0104] There are practical implications to the above discussed flow behaviors, including:• Early -Time Diffusion: Optimize fracture placement to minimize L and enhance Deft.• Mixed Flow Regime: Enhance permeability by growing fractures (ka2) to accelerate the transition to Darcy flow.• Darcy Flow Dominance: Maintain pressure gradients (AP) to sustain production during late stages.

[0105] In principle the above leads to a coupled system of partial differential equations that upon solving would give precise descriptions how the different flow regimes are linked and when they transition separated and are transitioning. This is in practice very unwieldy hence a simplified model has been defined based on the principle that flow meets resistance from the medium and when flow regimes start to overlap “competition” in path ways will arise which would be similar in electronic circuits with multiple parallel resistors. This analogy' has led to the so-called Dusty Gas Model, where pores are viewed as inert “dust” for each of the competing path ways.Atty. Docket No.: GEO-003PCT-8022-00401

[0106] The benefit of the Dusty Gas Model (DGM) is that it provides a unified framework for analyzing gas transport in systems where Knudsen diffusion, molecular diffusion, and Darcy flow overlap. It is particularly useful for tight formations where multiple mechanisms coexist. DGMs express the total flux as:Examples of Tortuosity values are where Joarcy is the flux due to Darcy flow, given by:=. -w>.with k as permeability and / as gas viscosity. Here Jinis the Knudsen diffusion flux, and Jmoi is the molecular diffusion flux.

[0107] DGMs capture the transitions between flow regimes, providing a comprehensive model for gas transport in fractured tight formations.

[0108] Gas transport transitions between diffusion-dominated and Darcy flow regimes as a fracture networks develops. These transitions are governed by a number of stages. Initially, transient diffusion-dominated flow can occur. In the early stages, gas transport is dominated by diffusion, as fractures are sparse and pore connectivity is limited. The time to transition from this regime is determined by:£sh:::IMwhere L is the characteristic diffusion length. The flow can then transition to pseudo-steady state in which there is mixed diffusion and Darcy flow. As fractures grow and connect isolated pores, the system transitions to a mixed regime where both diffusion and Darcy flow contribute to transport. Tortuosity decreases, enhancing the effective diffusion coefficient and enabling pressure-driven flow. In the late stages, fractures dominate transport, and pressure gradients drive Darcy flow. The permeability increases with fracture aperture (a) as:k <r

[0109] Fractures enhance transport by increasing surface area, which amplifies gas desorption and Knudsen diffusion, reducing tortuosity, improving Deff, and enhancing permeability, facilitating pressure-driven Darcy flow.

[0110] The impact of fractures is most pronounced in the Knudsen regime, where improved connectivity significantly boosts diffusion rates. Understanding the fundamental flow regimes and their transitions is useful for optimizing production in tight formations. Fracture-induced surface area enhancements are particularly useful for systems dominated by Knudsen diffusion,Atty. Docket No.: GEO-003PCT-8022-00401such as hydrogen production (e.g., generation) during serpentinization. In the Knudsen regime, the effective diffusion coefficient (Deff, Kn) improves with reduced tortuosity and enhanced pore connectivity. This early-stage enhancement explains why Knudsen diffusion benefits the most from fracture growth. The transition to Darcy flow occurs when the fractures mature, connecting the matrix and enabling pressure-driven transport. In some embodiments, production strategies should focus on maximizing fracture connectivity to optimize both early diffusion-driven flow and postponing late Darcy flow. The Knudsen diffusion coefficient can be two to three orders larger than the molecular diffusion coefficient, hence facilitating production from hydraulic fractures relatively much more than later stage Darcy flow - even on absolute time scales the transition time to mixed flow or Darcy flow is relatively short.[OlH] Dusty Gas Models provide a robust framework for predicting decline curves in shale gas wells, such as those in the Barnett Shale, and the present disclosure recognizes that this model can be used in modeling hydrogen production (e.g., by serpentinization) in a subsurface geologic formation. By integrating multiple transport mechanisms, including Knudsen diffusion, molecular diffusion, and Darcy flow, the DGM captures the transitions between flow regimes that govern production rates over time. DGMs may combine the following transport mechanisms:

[0112] Early -Time Diffusion-Dominated Flow: Knudsen diffusion dominates due to nanopore structures. The production rate is proportional to the effective Knudsen diffusion coefficient:This regime typically lasts 100 - 200 days in Barnett wells.

[0113] Mixed Flow Regime: As fractures grow and connect, molecular diffusion and Darcy flow contribute:):- 'f ’ "f.This phase slows the production decline and persists until 300 days.

[0114] Late-Time Darcy Flow: Pressure-driven Darcy flow dominates in connected fractures. The production rate follows:This regime governs boundary-dominated flow.

[0115] The production decline curve combines contributions from all regimes:• Early-Time Decline (Diffusion-Dominated):Atty. Docket No.: GEO-003PCT-8022-00401• Intermediate Decline (Mixed Flow): also known as the hyperbolic decline curve used in practice... t >......• Late-Time Decline (Darcy Flow):1

[0116] Fracture-induced transport enhancements in the Knudsen regime are important for systems with nanoporous matrices, serpentinizing rock formations (e.g., of olivine) as the Knudsen diffusion may be much larger than the molecular diffusion relevant at later stages. Dusty Gas Models enable precise modelling of flow regime transitions, allowing for better prediction of production rates over time and better control of production during production (e.g.. using a digital twin). Optimizing fracture growth dynamics (e.g., hydraulic fracturing in shale or maintaining pressure gradients in serpentinization systems) can maximize production efficiency.

[0117] The chemistry of serpentinization can lead to a self-sustaining, exponentially progressing fracturing process driven by the large volume increase from reaction of the host rock (e.g., olivine) and the exothermic property of the reaction producing significant amount of heat at the interface where the reaction takes place. As described elsewhere in describing an effective medium model for this autocatalytic fracture growth process, these fractures can occur at microscopic scales at grain boundaries of (e.g., olivine) granules of a subsurface geologic formation. Hence fracture spacing may be dense (on the order of 40 micron) but initially not adding much in terms of free surface. However, as fracture lengths become of the order of the size of the individual granules, surface area can start to grow exponentially as the rock gets “shattered’' by the densely growing fractures.

[0118] At the onset of the first moment of exponential growth, the transport of hydrogen may be characterized by Knudsen diffusion. At and near a serpentinization front, brine and hydrogen flow may be governed by Knudsen diffusion. Knudsen diffusion depends on:• Pore Size and Geometry: For serpentinized systems, pore sizes range from 10 nmto 100 nm.Atty. Docket No.: GEO-003PCT-8022-00401• Molecular Weight of Hydrogen: Hydrogen (M = 2.016 g / mol) diffuses faster than heavier brine components.• Temperature: At 275°C (548 K), molecular velocity is increased, enhancing diffusion.• Concentration Gradients: Sharp gradients drive transport, essential in porous serpentinized rocks.• Pore Connectivity and Tortuosity: High tortuosity (r ~ 3.0) reduces effective transport efficiency.

[0119] Knudsen diffusivity' (Dk) for hydrogen is calculated as:

[0120] Taking dp= 10 nm (generally there are small pores at a serpentinization front), R = 8.314 J / (mol ■ K), T = 548 K, andAl= 2.016 g / mol = 2.016 x 10’3kg / mol, yields aDk of 6.74 x IO-6m2 / s.

[0121] The mean free path (A) of hydrogen is calculated as:

[0122] Taking ks = 1.38 x 10”23J / K (Boltzmann constant), T= 548 K, dm= 2.89 x 10”10m (hydrogen molecular diameter), and C = 100 bar = 107Pa, yields a A of about 10 nm

[0123] Since / . ~ dp. Knudsen diffusion dominates at the serpentinization front. The effective diffusion coefficient (£>eff) incorporates porosity (e) and tortuosity (r):

[0124] Assuming e = 0.10 (porosity of partially serpentinized rock), t = 3.0, and Dk = 6.74 x 10-fim2 / s, then:

[0125] The transition from Knudsen diffusion to mixed molecular-Knudsen flow occurs as Kn = dpapproaches 0.01. For hydrogen atP = 100 bar and T= 275°C:• Kn = 1 when dp= 10 nm.• Kn = 0.01 when dp= 1000 nm.Atty. Docket No.: GEO-003PCT-8022-00401

[0126] Therefore, DGMs can be used to characterize hydrogen production in subsurface geologic formations. The transition in flow regime may occur as pore size increases from 10 nm to 1000 nm, typically over a distance of 10-50 m behind a serpentinization front.

[0127] To increase reaction rates at a serpentinization front and flow to and from the serpentinization front, a production model of a well pad comprising between 10 and 1000 wells may be used as a digital twin. Such wells may act in alternating cycles as production or injection wells. Each well may have hydraulic fractures organized in up to ten fracture stages each having possibly up to 10 fractures, but the hydraulic fracturing is done as part of the optimization of production over time which also includes optimal brine circulation and chemistry to enhance production of entire well pad. Hydrogen production and optimization may be done at the well pad level, not at individual well level. This is in contrast to shale gas optimization or geothermal heat extraction optimization. A digital twin, that is continuously fed by well and production data to estimate optimization of further fracture network enlargement, fluid (e.g., brine) circulation and fluid (e.g., brine) chemistry, may be implemented, for example using a machine learning module, for example based on a KAN model.

[0128] Levers that may act at well pad level include, for example mechanically by hydraulic stimulation, brine circulation, brine chemistry, prevention of silica and carbonate precipitation, and / or optimizing hydrogen transport.

[0129] For mechanical control by hydraulic stimulation, the injection of pressurized water to create new fractures or widen existing ones, increasing surface area. Stimulation may start in a new area by creating a hydraulic fracture creating a large free surface of olivine where fresh brines start the serpentinization process, in particular starting the growth of a self-sustained autocatalytic fracture network. It may be important to not complete all fracture stages up front, but rather start stimulation with a small number of fracture stages and fractures first. Subsequent stages would be determined by the location of a serpentinization front as it moves into fresh rock (e.g., olivine). We argue that we simultaneously fracture in several injection wells and hence optimize later frack stages both at times as well as location along the well by optimal positioning following from fracturing a serpentinization front, monitoring hydrogen production as well as salinity’ of the brines. This may be best done by considering an optimal design for an entire well pad (e.g. 10 wells) upfront starting with an initial set of optimally placed injection wells and subsequent drilling production wells optimally positioned with respect to a serpentinization front. Thus, a well pad may have a set of simultaneously injectionAtty. Docket No.: GEO-003PCT-8022-00401well and simultaneously production wells but such that fracture stages are optimally positioned.

[0130] Brine circulation enables hierarchical fracture growth by varying the pressure of the brine in the formation in the range greater than the least compressive stress to less than the formation breakdown pressure at a composite of a variety of periods. Longer periods (days to months can be used to extend the fracture network over distances of tens to hundreds of meters, while periods of hours to days can be used to disrupt the formation on spatial scales of grain dimensions to meters. Circulation maintains pressures so that fractures remain open, but such that there is pressure gradient towards production well(s). Apply controlled heating and cooling to induce thermal stress and crack growth. For given well pairs of injection and production, the hydraulic fracture stages in both may start to interact so that production and injection cycles may be implemented. The period of these cycles may be on the order of days / weeks, though some frequency components can be on the order of minutes to hours, as described in more detail herein.

[0131] Brine chemistry can be controlled to maintain high eater flow rates and sustain hierarchical fracture growth. Use high water fluxes to ensure continuous replenishment of fresh water at a serpentinization front, avoiding saturation with reaction products like magnesium or silica. Design reactor-like flow conditions in engineered or natural systems by ensuring strong hydraulic gradients. Use one or more additives to modify water properties to reduce water viscosity with temperature adjustments to improve infiltration into tight pore spaces. Note that in Knudsen diffusion viscosity has only an indirect effect as opposed to molecular diffusion. Hydrophobic or bubble suppression may have a large effect. Introduce surfactants to lower interfacial tension and enhance water penetration along grain boundaries.

[0132] Silica and carbonate precipitation can be prevented to avoid clogging of fractures with precipitates (e.g., silica or carbonates) by controlling water chemistry. This can be accomplished by maintain pH at controlled or optimal levels (neutral to slightly basic), and preventing oversaturation with dissolved silica by removing reacted fluid periodically to manage salinity

[0133] Hydrogen transport can be improved or optimized to increase fracture connectivity through micro-fracturing and induced thermal stress. Buoyancy effects can be used to move hydrogen vertically in fractures. Hence typical injection and production wells may sometimes be drilled above each other. Phase-separating membranes can be installed in production wells to enhance gas recovery.

[0134] The Knudsen diffusion coefficient, Dkn. is given by:Atty. Docket No.: GEO-003PCT-8022-00401where: rP: Pore radius (m), R: Universal gas constant (8.314 J / mol K), T: Temperature (K), and M: Molar mass of the gas (kg / mol).

[0135] For hydrogen self-diffusion, where the gas interacts only with itself, the diffusion coefficient. Dseif, is approximately:where T is the temperature (K) and P is the pressure (Pa). At T = 300K and P = 1 atm, Dseif ≈ 7 x 10-5m2 / s.

[0136] The transition between Knudsen and molecular diffusion can be described using the Bosanquet equation:>... i....:::....;..:where D is the effective diffusion coefficient. For small pores (rP« X, where X is the mean free path),approaches Dn, while for large pores (rP» X), Deff approaches Dseif.

[0137] FIG. 8 shows the relationship between Knudsen diffusion, self-diffusion, and the effective diffusion coefficient as a function of pore radius.

[0138] In the Knudsen regime, where diffusion is slower due to wall collisions, strategies to enhance hydrogen flow include:• Increasing temperature: Both Knudsen and molecular diffusion coefficients increase with temperature.• Applying pressure gradients: Use pressure differences to drive hydrogen transport. • Utilizing catalytic coatings: Apply catalytic and hydrophobic materials on fracture walls to facilitate to reduce gas-wall interactions.

[0139] The following fluid (e.g.. brine) parameters may be used to impact production of hydrogen:1) Temperature and pressure at the serpentinization front. Both temperature and pressure are controlled by injection and production through wells accessing fractured areas (e.g., a fracture network). In particular, heat should be managed, at least locally, to ensure maintaining temperature within optimal serpentinization temperature ranges, e.g., between 250 °C < T < 350 °C for olivine serpentinization. Disclosed effective medium theoretical models relating fracture density with hydrogen production (e.g., serpentinization) may be used to indicate if and by how much heat may need to beAtty. Docket No.: GEO-003PCT-8022-00401recovered from a serpentinization front via fluid (e.g., brine) circulation to maintain optimal temperature. Pressure may need to be maintained at values above that of the minimum compressive stress to ensure fractures (especially those with small size) remain open and high enough fluid-to-rock (e.g., water-to-rock) ratios can be maintained.2) Specific to hydrogen production process would be additional control of both salinity and pH of fluid (e.g., brine) as these may have major impact on serpentinization. 3) Specific for initial hydrogen flow process away from a serpentinization front into already converted (to serpentinite) regions formed earlier in the process, are additives to improve Knudsen like diffusion if applicable. The detrimental effect caused by much smaller Knudsen diffusion coefficient compared to molecular (self) diffusion is for example shown in FIG. 8. Disclosed effective medium models (including adaptation for Dusty Gas Model) may give first order estimates based on production data gathered at a well (e.g., at a head of the well) if and how much this effect could be addressed. Typical ways to enhance Knudsen dominated diffusion in enhancing hydrogen flow in serpentinization include:a. Surfactants to reduce gas-wall interactions; andb. Increasing temperature and pressure-gradients in as much that does not suppress hydrogen generation.

[0140] Processes disclosed herein use a sustainable reaction front driven by the stress created by reacting rock after kick-starting the reaction with fracturing by injection of high-pressure brine, and sustaining the reaction with continued injection of water while manipulating the evolving stress field. The “exponentiaf' increase of active surface area created by the stress generated by the injection of brine at sufficiently high pressure and the large volume changes resulting from the reaction referred to elsewhere may rather be, in various embodiments, geometric, or follow another functional form that may vary within an actual formation and over time.

[0141] A subsurface geologic formation will often be largely unknown at microscopic and macroscopic length scales. So, in some embodiments, manipulation of the rate of reaction may not depend on having a detailed knowledge of mineralogy, grain size, the stress field, faults, cracks, etc. In some embodiments, there may only be an overall macroscopic understanding, which may not be physically verifiable. Thus, in some embodiments, certain models are useful for modelling behavior but certain models (e.g., effective medium models) may be preferredAtty. Docket No.: GEO-003PCT-8022-00401for using to assist in controlling processes (e.g., in a digital twin). Models disclosed herein depend on controllable parameters such as injection rate, fluid composition, T. P, pH etc., for example as to A(t) and R(t) described elsewhere herein.Initiation and Control of Self-Sustaining Stimulation of Geologic Hydrogen Production

[0142] A comprehensive approach to commercial production of geohydrogen and, optionally, geothermal energy may involve integration of the following steps:1) Machine learning (ML)-based aggregation and analysis of geophysical data for the selection of most commercially optimal hot, dry, rock formations;2) Accessing specific formations using drilling methods (e.g., adapted from the geothermal and / or natural gas fracturing arts) and from site-specific mineral and physical data invoking ML-assisted modeling to design site-specific brine formulations for optimum productivity;3) Delivering brine formulation to the formation to promote hydrogen formation; and 4) Extraction of hydrogen and, optionally, heat and / or byproducts as commercial products.

[0143] Disclosed herein are processes that enable the rate of hydrogen production to be maximized by enabling a self-sustaining hydrogen producing reaction which promotes autostimulation of hydrogen production that may be used in such a comprehensive approach.

[0144] Hydrogen may be produced (e.g., generated) in a subsurface geologic formation (e.g., of mafic rock) by exothermic surface mediated reaction of water with solid minerals containing Fe2+; for example, in olivine (e.g., olivine (Fo90)), the reaction produces silicates and hydroxides including Fe2+containing Fe(OH)2 which decomposes and oxidizes Fe2+by endothermic Schikorr Reaction:'kJ ' kJ 3Fe(OH)2< - Fe3O4+ H2+2H2O AH° =36 AG°= -24 mole H2J mole H2J

[0145] The overall rate of hydrogen production depends on the areal rate, r”(moles / m2-s) of the overall reaction and the surface area of unreacted rock face contacted by the fluid (e.g., brine), A(m2). The exothermic formation of the iron hydroxide is thought to be relatively fast compared to the endothermic Schikorr reaction which is rate limiting. Provided the temperature is low enough that the formation of the hydroxide is favorable, equilibrium constraints will limit the reaction rate for hydrogen production (e.g., generation) by:Atty. Docket No.: GEO-003PCT-8022-00401r" = koxeRT(1-AD)M)=^ =where the activity of hydrogen is approximately the vapor pressure of the dissolved hydrogen in the high pressure, high temperature subsurface aqueous environment and, y, is the mole fraction of iron hydroxide in the specific mineral formation. Measurements of r” in Ferroan brucite (Fe(OH)2) have found r”~ 1 O’8(moles H2 / m2-day) [Geochem. Persp. Let. (2024) 29, 27-32 | https: / / doi.org / 10.7185 / geochemlet.24081. When fluid (e.g., water containing brine) enters a fracture of length, a, the surface oxidation reaction results in a volume expansion, AV, which produces stresses within the formation and a mismatch between native rock in a formation and the reaction-formed oxide. The volume expansion will reduce the fracture open volume and force out the liquid brine containing the hydrogen product, as shown in FIG. 9.

[0146] Stresses within the rock in a subsurface geologic formation may act to increase lengths of cracks at a rate described by the Paris-Erdogan relationship:^ = c(y< TWV^))“increasing crack length increases the available reaction surface area which is approximately proportional to the square of the crack length, A(t)=a*a(t)2.

[0147] The reaction rate is proportional to the rate of volume change which in turn creates the changing stress:dV— = r”A(t)AK = r" a a(t)2ΔVdt— = k— = h-''A(f)AV = (kr" AVa) a(t)2dt dtthe coupling of the stress and crack length and the stress and total reaction rate through these two equations can give rise to an exponential increase in total crack length and the rock surface area, which results in an overall rate of hydrogen generation, R, increasing exponentially in time.XO ■RtW'’. XAtty. Docket No.: GEO-003PCT-8022-00401

[0148] Without intervention and control, in a closed system the equilibrium limited surface reaction would simply stop as P(T)D1 due to the saturation of hydrogen within the local aqueous environment and the brine composition and pH varying from design optima due to secondary processes with other mineral components which may precipitate. Further, the overall exothermic reaction at high rates can increase the formation temperature. Temperature control is important since hydrogen solubility is temperature dependent and will decrease with increasing T. Although the endothermic rate of iron hydroxide decomposition will tend to increase with increasing temperature, the exothermic equilibrium limited reaction of water with a host subsurface geologic formation (e.g., host mafic rock) will stop producing iron hydroxide as temperature is increased. Thus, heat and mass transport which were ignored above, are important to control if optimum hydrogen production is to be achieved.

[0149] Disclosed herein are methods to maintain fluid (e.g., brine) conditions at a new fracture surface face that enhance (e.g., maximize) hydrogen production rate from a subsurface geologic formation. For a given rock composition in a formation there will be an optimal temperature, and pH that maximizes the overall reaction rate. From site specific modeling, optimal conditions may be determined. It may be desirable to remove produced hydrogen as fast as possible to minimize (T) while maintaining a near isothermal condition at the production maximum. To maintain isothermal conditions requires movement of sufficient water containing brine through the formation to remove the reaction heat:RAH =r" A(t)AH = rnm(t)cp(Tout(t) - Tm(t))Thus, control of inlet temperature and brine delivery may be important elements of a process.

[0150] Overall rate of reaction within a subsurface geologic formation as a whole may be enhanced (e.g., optimized) by controlling liquid mass transport, temperature, and composition delivered to fracture surface(s) of a fracture network (e.g.. at a serpentinization front) in the formation to maintain a high (e.g., highest) reaction rate, and similarly liquid mass transport away from the fracture surface(s) and out of the formation to carry away produced hydrogen, and optionally process heat maintaining preferred (e.g., optimal) formation temperature. Such a process may be achieved, for example, by controlling combinations of the following:1) The time dependent liquid pressure within the formation, P(t), which allows to induce pulsatile flow to and from fracture networks as well as to facilitate inter-fracture liquid flow.Atty. Docket No.: GEO-003PCT-8022-004012) The rate of fluid (e.g., brine) delivery to the formation and the temperature of the fluid (e.g., brine) feed will be controlled for maintaining both a low fracture surface hydrogen concentration and a near optimal isothermal formation temperature.3) The addition of fluid (e.g., brine) one or more components to control pH, facilitate flow, and increase reaction rate including one or more acids (e.g. organic acids, HC1, H2SO4,), one or more surfactants, one or more catalysts (Cu, Ni, Mn, and other transition metals), or a combination thereof.

[0151] The present disclosure recognizes that when accessing a large formation by a well (e.g., through a feed borehole of the well) and generating a fracture network pressure and capillary driven fluid (e.g., brine) flow will deliver the reactant (water) to the fracture surface. As described previously, the reaction will initiate a volume expansion and generate stress within bulk rock of a subsurface geologic formation which will create an effective bulk pressure, Pb, which will act to close fractures and drive liquid containing the hydrogen product (and heat) out of the fractures while also generating new fractures. Processes disclosed herein make use of this reaction induced ‘liquid pump” to remove and refresh brine at the rock fracture surface (e.g., of a serpentinization front). By manipulation of fluid (e.g., brine) hydrostatic pressure (P(t)=P0+p(t)), a process may, by design, drop pressure to facilitate egress of the fluid containing the reaction products from the fractures then upon raising the pressure drive fresh brine into the stress induced fracture network, for example as illustrated in FIG. 10.

[0152] Through our fracture / reaction model for specific geological sites optimum time dependent hydrostatic pressure can be delivered, inlet temperature, and inlet brine mass flow for maximum product extraction, for example as illustrated in FIG. 11.Fracture Surface Wetting

[0153] Rock wetting facilitates certain reactions (e.g., serpentinization). Fracture characteristics (e.g., geometry, permeability, porosity, and pore size) dictate the viscous resistance and flow of a working fluid (e.g., brine). Non-uniformities in a fracture network can lead to preferential flow paths. Utilization of a rock surface can be maximized with optimal wetting. Interfacial properties play a key role in maintaining rock wetting and the flow of a working fluid (e.g., brine). These properties depend on both surface chemistry and surface morphology. One or more interfacial modifiers, such as, for example, surfactant(s), nanoparticle(s), one or more charged species. pH modifier(s), emulsion(s), or a combination thereof, may be used to achieve optimal rock wetting.

[0154] Imbibition of fluid into a porous medium and wetting of fractured rock may beAtty. Docket No.: GEO-003PCT-8022-00401influenced by local wetability. Depending on interfacial interactions, either a fully spreading or a partially spreading scenario can occur. This behavior is governed by the spreading coefficient Sws(g)= ysg— yws— ywgwhere ys represent the interfacial tensions between different phases, with subscripts w (water), s (rock), and g (gas or a third phase).

[0155] The following are criteria that may be used to design the formulations for fluid (e.g., brine).

[0156] Complete intrinsic weting: when the spreading coefficient S) is positive, complete weting of the material can occur.Ssw(g) 0 f) sw(g)=0.

[0157] Case of partial wettingSsw(g) 0 0 sw(g) A 0.

[0158] In this case interfacial modifiers will be designed to ensure the effective Spreading coefficient S*™^) > 0; 0* = 0.

[0159] Based on the fracture parameters (e g., permeability, porosity) and fracture surface morphology, addition of one or more interfacial modifiers can be used to achieve the following condition: Qsw(g> < cos-1[(l -(|)) / (%-(|))], where <|) is the surface solid fraction and / is the overall solid fraction, and 9 is the contact angle.

[0160] A further breakdown of surface chemical interactions can be described in terms of Lifshitz-van der Waals (non-polar) and the polar Lewis acid-Lewis base interactions. These interactions are characterized by the work of adhesion:y(l + cos0*) - 2(fyfvyALW+ Jy+yr + Jy^ys+)where A, / r, and A are the Lifshitz -van der Waals. (Lewis) acid, and (Lewis) base parameter of surface energy respectively. These parameters provide a direct link between the surface chemistry and wetability, so can be used to select one or more interfacial modifiers for ensuring an effective positive spreading coefficient (or an effective contact angle of zero).

[0161] Fluid chemistry may be used to enhance weting while avoiding any precipitation reactions that passivate or block fracture pathways. Fluid pH window may be selected to enhance ionization of surface charged species of rock surfaces of a subsurface geologic formation. The pH window may be preferably in a range of neutral to mildly basic. Fluid chemistry may be selected in tandem with one or more ionic surfactants to enhance their surface activity and avoid any local precipitation / passivation of rock surfaces. pH can also be altered in-situ in a subsurface geologic formation using local-release mechanisms that are triggered byAtty. Docket No.: GEO-003PCT-8022-00401local conditions (e.g., temperature, pressure, or both).

[0162] Fracture geometry (e.g.. permeability, porosity and pore size) will dictate viscous resistance and flow of working fluid (e.g., brine). Hence to ensure bulk flow through a majority of a fracture network of a subsurface geologic formation, generally, and without wishing to be bound by any particular theory, surface tension forces will need to overcome viscous resistance. The condition for this requires that APvis< PST, which results in scaling relation between geometric parameters of a fracture network and flow and wetting parameters.

[0163] Apart from ensuring an effective positive spreading coefficient using one or more interfacial modifiers, one or more proppants may be used to ensure fracture pore-scale can allow for bulk flow. A proppant may be sized according to the pressure condition in the preceding paragraph. Additionally, this approach allows for preventing short circuiting of flow, and uniform wetting of fracture pathways.Model for Geologic Hydrogen Production by Stimulating Fracture Network Growth Driven by Serpentinization

[0164] Disclosed herein is, inter alia, an effective medium model for geologic hydrogen production by stimulating fracture network growth driven by serpentinization. Serpentinization, which involves the creating of serpentinite typically having a density that is up to about 50% less than original olivine, leads naturally to the formation of fractures (e.g., “shattering” olivine grains). In some embodiments, this effect is an exponential process: per unit time the increase in free fracture surface grows proportional to the instantaneous available free surface. As a result, more and more water may get in contact with olivine accelerating the serpentinization reaction. Without wishing to be bound by theory, this may be (partly) explained by the exothermic property of the reaction which w ould lead to a self-sustaining reaction process until completion and / or termination (e.g., all available source rock, e.g., olivine, has been converted to serpentinite). Such a reaction may slow down continuously as the amount of surface area relative to the volume of remaining olivine becomes so large that reaction would slow and possibly cease altogether.

[0165] As serpentinization consumes significant volumes of water, remaining fluid (e.g., brine(s)) will become more saline. Salinity increase may trigger precipitation of serpentinization reaction products like brucite that potentially would then clog a fracture network. Thus, fluid (e.g., brine) composition and chemistry may be used to control or stimulate serpentinization. It should be noted though that, in thin sections showing relatively small bodies of olivine, the “clogging” has been rarely seen and hence may not occur in practice, however, such clogging may occur at much larger scales. Several thin sections haveAtty. Docket No.: GEO-003PCT-8022-00401shown that all olivine has reacted and no blockage of fracture networks has been observed. In any case, water availability, salinity and pH all may impact on rate of serpentinization.

[0166] In an exemplary model disclosed herein, a factor, ksup, that collectively describes reaction suppression effects which thereby directly affects sustained hydrogen production is introduced. Such a model can reproduce experimental results in Malvoisin, B. et al. Control of serpentinization rate by reaction-induced cracking. Earth and Planetary Science Letters, 476, 143-152 (2017). Such a model may be used as or in a digital twin model, for example to derive conditions under which significantly more hydrogen will be produced. Such a model may be used for system and / or process optimization for hydrogen extraction, for example by optimizing stress management as stresses build up as a result of density changes caused by serpentinization. Such optimization may impact drilling and fracturing of further wells or in later frack stages after serpentinization has started. Such a model may additionally or alternatively be used to estimate heat production at a serpentinization front and hence provide ways to optimize heat management in particular to keep temperature at the serpentinization front in an optimal range of 250-350 °C.

[0167] A serpentinization effective medium model may have the form(1)- A -■ 1-1 W / Z - JhA(2)Here, H is the amount of hydrogen released, A is the effective area of fractures, where the reaction takes place, J is the serpentinization rate, kfracis the rate with which new7fractures are created, and ksupis the suppression rate (as discussed previously), u is the Heaviside (unit step) function, and Hfcis a reference amount of released hydrogen (for example the total hydrogen produced at the end of the field life ). H(0) = 0 may be assumed and also that neither fracturing nor suppression occurs until H reaches the value Hfc. The fracture area A remains therefore constant initially and H increases linearly as• (3)To describe the system behavior at t > Hrc / (AJ), the following normalized variables are introduced:Atty. Docket No.: GEO-003PCT-8022-00401h - ( H. H. A. - M.. y T - « M(4)where Ao is the initial area of fractures, HO is the reference amount of hydrogen, and tO = H0 / (A0J) is the time required to release the amount of hydrogen equal to HO from the surface area AO. With these normalizations, Eqs. (1) and (2) takes the form(5)d.<~~ —:::: <' S / ' A. / .dr- CS)whereft JA;, ASolution of model equations (5) and (6) is given by the relationsIn what follows a > 0 is assumed and that all the effects resulting in a decrease of the effective area of fractures are described by the second term on the right side of Eqs. (2) and (6). The total normalized amount of produced hydrogen at t > Hfc / (AoJ) is equal to h+ for a > 0 and to h for a < 0. From Eq. (8) it follows that the effective area and hence the hydrogen production rate reaches its maximum at h = a / where:Equation (9) at large time gives:Equation (12) shows that the fracturing increases the hydrogen production (2T) 1 / 2 times for aAtty. Docket No.: GEO-003PCT-8022-00401fixed clogging rate 0. In the regime with f » 1 solution (9) reduces to:I -r (F / 2) exp( •■«:?■) ' '(|3)

[0168] FIG. 3B illustrates combined solution given by Eqs. (3) and (9), where it is assumed that 20 % of the hydrogen is produced during the linear stage, H& = 0.2(Hfc+ h+Ho) or Hfc= O.25h+Ho. The time variable is ar. With this normalization, the curves with different values of 0 and the same values of T almost overlap. The value T = 10 (red curve in FIG. 3B) fits best to the data of Malvoisin, et al. At time 5at0, the value H is equal to 0.25hmaxH0 = O.5(a / 0)HO (see Eq. (13)). This value of H is achieved in linear growth regime (3), which gives the condition O.5(o / 0)Ho = 5AoJato, or 0 = 0.1 and hence a = 1. The value h / hmax increases to 90% at time lOato in FIG. 3B and are about 12000 hours in Malvoi sin’s paper. This gives to = 1200 hours or 1.4 years, and k&acJ = 0.7 year1. The value ksupcannot be derived from Malvoisin’s data. FIG. 3B show simulation of hydrogen production with the k&acJ = 0.7 for the case where the initial fracture area is equal to 10 [km2] for different values of ksup.

[0169] The foregoing effective medium model is described in terms of a normalized fracture rate (alpha) and a suppression rate (beta) in Eq. 7. These are the basis of equations of a normalized rate of hydrogen production (Eq. 5) and the rate of change of a fracture area (in a fracture network) (Eq. 6) where Eq. 5 has the form of Malvoisin’s experimental observation. This demonstrates that a process for hydrogen production can be described by fracturing rate, which can be controlled with macroscopic variables (e.g., including suppressed). Described herein, including in the Summary section, are examples of macroscopic controls available affect net rate of production and extraction (e.g., recovery) - they affect the rate of fracturing and the rate of reaction suppression. Using a digital twin model, for example based on an effective medium model can inform drilling, fracturing and resource production operations in a process. Other (non-effective-medium) models are possible, for example as disclosed herein elsewhere. A production process may be viewed macroscopically as an interaction between the injected fluid (e.g., brine) and rock, and controlled by macroscopic variables that affect alpha and beta in an effective medium model.Software, Computer System, and Network Environment

[0170] Certain embodiments described herein make use of computer algorithms in the form of software instructions executed by a computer processor. In certain embodiments, the softwareAtty. Docket No.: GEO-003PCT-8022-00401instructions include a machine learning (ML) module, also referred to herein as artificial intelligence (Al) software. As used herein, a machine learning module refers to a computer implemented process (e.g., a software function) that implements one or more specific machine learning techniques, e.g., artificial neural networks (ANNs), e.g., convolutional neural networks (CNNs), random forest, decision trees, support vector machines, and the like, in order to determine, for a given input, one or more output values. In certain embodiments, the input comprises image data and / or alphanumeric data which can include 2D and / or 3D datasets, numbers, words, phrases, or lengthier strings, for example. In certain embodiments, the one or more output values comprise image data (e.g. 2D and / or 3D datasets) and / or values representing numeric values, words, phrases, or other alphanumeric strings.

[0171] In certain embodiments, machine learning modules implementing machine learning techniques are trained, for example, using datasets that include categories of data described herein. Such training may be used to determine various parameters of machine learning algorithms implemented by a machine learning module, such as weights associated with layers in neural networks. In certain embodiments, once a machine learning module is trained, e.g., to accomplish a specific task such as identifying certain response strings, values of determined parameters are fixed and the (e.g., unchanging, static) machine learning module is used to process new data (e.g., different from the training data) and accomplish its trained task without further updates to its parameters (e.g., the machine learning module does not receive feedback and / or updates). In certain embodiments, available input data includes training data and validation data, e.g., where the validation data is separate and non-overlapping with the training data. For example, in certain embodiments, training data is used during the training process to optimize a model, whereas validation data is used to check the accuracy of the model while operating on previously unseen data. In certain embodiments, training data is divided into batches (e.g., portions) that is sequentially used (e.g., in random order) as sets of inputs to train a model. In certain embodiments, a model is trained multiple times (e.g., epochs) on the entire set of training data. In certain embodiments, machine learning modules may receive feedback, e.g., based on user review of accuracy, and such feedback may be used as additional training data, to dynamically update the machine learning module. In certain embodiments, two or more machine learning modules may be combined and implemented as a single module and / or a single software application. In certain embodiments, two or more machine learning modules may also be implemented separately, e.g., as separate software applications. A machine learning module may be software and / or hardware. For example, a machine learning module may be implemented entirely as software, or certain functions of an ANN module may beAtty. Docket No.: GEO-003PCT-8022-00401carried out via specialized hardware (e.g., via an application specific integrated circuit (ASIC) and / or field programmable gate arrays (FPGAs)).

[0172] In certain embodiments, machine learning modules implementing machine learning techniques may be composed of individual nodes (e.g. units, neurons). A node may receive a set of inputs that may include at least a portion of a given input data for the machine learning module and / or at least one output of another node. A node may have at least one parameter to apply and / or a set of instructions to perform (e.g., mathematical functions to execute) over the set of inputs. In certain embodiments, node instructions may include a step to provide various relative importance to the set of inputs using various parameters, such as weights. The weights may be applied by performing scalar multiplication (e.g., or other mathematical function) between a set of inputs values and the parameters, resulting in a set of weighted inputs. In certain embodiments, a node may have a transfer function to combine the set of weighted inputs into one output value. A transfer function may be implemented by a summation of all the weighted inputs and the addition of an offset (e.g., bias) value. In certain embodiments, anode may have an activation function to introduce non-linearity into the output value. Non-limiting examples of the activation function include Rectified Linear Activation (ReLu), logistic (e.g., sigmoid), hyperbolic tangent (tanh), and softmax. In certain embodiments, anode may have a capability of remembering previous states (e.g., recurrent nodes). Previous states may be applied to the input and output values using a set of learning parameters.

[0173] In certain embodiments, the machine learning module comprises a deep learning architecture composed of nodes organized into layers. For example, a layer is a set of nodes that receives data input (e.g., weighted or non-weighted input), transforms it (e.g., by carry ing out instructions, e.g., applying a set of functions e.g., linear and / or non-linear functions), and passes transformed values as output (e.g.. to the next layer). In certain embodiments, the set of nodes in a particular layer may share the same parameters and instructions without interacting with each other. A machine learning module may be composed of at least one layer (e.g., ordered). Examples of types of layers include convolutional layers (e.g., layers with a kernel, a matrix of parameters that is slid across an input to be multiplied with multiple input values to reduce them to a single output value); fully connected (FC) layers (e.g. all nodes are connected to all outputs of the previous layer); recurrent layers, long / short term memory (LSTM) layers, gated recurrent unit (GRU) layers (e.g., nodes with the various abilities to memorize and apply their previous inputs and / or outputs); batch normalization (BN) layers (e.g., layers that normalize a set of outputs from another layer, allowing for more independent learning of individual layers); activation layers (e.g., layers with nodes that only contain anAtty. Docket No.: GEO-003PCT-8022-00401activation function); and / or (un)pooling layers [e.g., layers that reduce (increase) dimensions of an input by summarizing (splitting) input values in defined patches).

[0174] In certain embodiments, the performance of a machine learning module may be characterized by its ability to produce an output data with specific accuracy. To achieve specific accuracy, a training process is performed to find optimal parameters, such as weights, for each node in each layer of the machine learning module. In certain embodiments, the training process of a machine learning module may involve using output data to calculate an objective function (e g., cost function, loss function, error function) that needs to be optimized (e.g., minimized, maximized). For example, a machine learning objective function may be a combination of a loss function and regularization parameter. The loss function is related to how well the output is able to predict the input. The loss function may take various forms, like mean squared error, mean absolute error, binary cross-entropy, categorical cross-entropy, for example. The regularization term may be needed to prevent overfitting and improve generalization of the training process. Examples of regularization techniques include LI Regularization or Lasso Regression, L2 Regularization or Ridge Regression, and Dropout (e.g., dropping layer outputs at random during training process).

[0175] In certain embodiments, objective function optimization of a machine learning module may involve finding at least one (e.g., all) of the present global optima (e.g., as opposed to local optima). In certain embodiments, the algorithm for objective function optimization follows principles of mathematical optimization for a multi-variable function and relies on achieving specific accuracy of the process. Examples of objective function optimization algorithms include gradient descent, nonlinear conjugate gradient, random search, Levenberg-Marquardt algorithm, limited-memory Broyden-Fietcher-Goldfarb-Shanno algorithm, pattern search, basin hopping method, Krylov method, Adam method, genetic algorithm, particle swarm optimization, surrogate optimization, and simulated annealing.

[0176] In certain embodiments, the machine learning modules comprise neural networks, e.g., graph neural networks (GNNs), with nodes (vertices) and edges. In certain embodiments, the machine learning modules comprise one or more Multi-Layer Perceptrons (MLPs), e.g., neural networks w ith fixed activation functions on nodes and learnable weights on edges. In certain embodiments, the machine learning modules comprise one or more Kolmogorov-Arnold Networks (KANs), e.g., neural networks with learnable activation functions on edges and sum operation on nodes.

[0177] Illustrative embodiments of systems and methods disclosed herein were described above with reference to computations performed locally by a computing device. However,Atty. Docket No.: GEO-003PCT-8022-00401computations performed over a network are also contemplated. FIG. 12 shows an illustrative network environment 1100 for use in the methods and systems described herein. In brief overview, referring now to FIG. 12, a block diagram of an illustrative cloud computing environment 1100 is shown and described. The cloud computing environment 1100 may include one or more resource providers 1102a, 1102b, 1102c (collectively, 1102). Each resource provider 1102 may include computing resources. In some implementations, computing resources may include any hardware and / or software used to process data. For example, computing resources may include hardware and / or software capable of executing algorithms, computer programs, and / or computer applications. In some implementations, illustrative computing resources may include application servers and / or databases with storage and retrieval capabilities. Each resource provider 1102 may be connected to any other resource provider 1102 in the cloud computing environment 1100. In some implementations, the resource providers 1102 may be connected over a computer network 1108. Each resource provider 1102 may be connected to one or more computing device 1104a, 1104b, 1104c (collectively. 1104), over the computer network 1108.

[0178] The cloud computing environment 1100 may include a resource manager 1106. The resource manager 1106 may be connected to the resource providers 1102 and the computing devices 1104 over the computer network 1108. In some implementations, the resource manager 1106 may facilitate the provision of computing resources by one or more resource providers 1102 to one or more computing devices 1104. The resource manager 1106 may receive a request for a computing resource from a particular computing device 1104. The resource manager 1106 may identify one or more resource providers 1102 capable of providing the computing resource requested by the computing device 1104. The resource manager 1106 may select a resource provider 1102 to provide the computing resource. The resource manager 1106 may facilitate a connection between the resource provider 1102 and a particular computing device 1104. In some implementations, the resource manager 1106 may establish a connection between a particular resource provider 1102 and a particular computing device 1104. In some implementations, the resource manager 1106 may redirect a particular computing device 1104 to a particular resource provider 1102 with the requested computing resource.

[0179] FIG. 13 shows an example of a computing device 1200 and a mobile computing device 1250 that can be used in the methods and systems described in this disclosure. The computing device 1200 is intended to represent various forms of digital computers, such as laptops, desktops, workstations, personal digital assistants, servers, blade servers, mainframes, andAtty. Docket No.: GEO-003PCT-8022-00401other appropriate computers. The mobile computing device 1250 is intended to represent various forms of mobile devices, such as personal digital assistants, cellular telephones, smartphones, and other similar computing devices. The components shown here, their connections and relationships, and their functions, are meant to be examples only, and are not meant to be limiting.

[0180] The computing device 1200 includes a processor 1202. a memory 1204, a storage device 1206, a high-speed interface 1208 connecting to the memory 1204 and multiple highspeed expansion ports 1210, and a low-speed interface 1212 connecting to a low-speed expansion port 1214 and the storage device 1206. Each of the processor 1202, the memory 1204, the storage device 1206, the high-speed interface 1208, the high-speed expansion ports 1210, and the low-speed interface 1212, are interconnected using various busses, and may be mounted on a common motherboard or in other manners as appropriate. The processor 1202 can process instructions for execution within the computing device 1200, including instructions stored in the memory 1204 or on the storage device 1206 to display graphical information for a GUI on an external input / output device, such as a display 1216 coupled to the high-speed interface 1208. In other implementations, multiple processors and / or multiple buses may be used, as appropriate, along with multiple memories and types of memory. Also, multiple computing devices may be connected, with each device providing portions of the necessary7operations (e.g., as a server bank, a group of blade servers, or a multi-processor system). Also, multiple computing devices may be connected, with each device providing portions of the necessary7operations (e.g., as a server bank, a group of blade servers, or a multi-processor system). Thus, as the term is used herein, where a plurality of functions are described as being performed by “a processor”, this encompasses embodiments wherein the plurality of functions are performed by any number of processors (e.g., one or more processors) of any number of computing devices (e.g., one or more computing devices). Furthermore, where a function is described as being performed by ’‘a processor”, this encompasses embodiments wherein the function is performed by any number of processors (e.g., one or more processors) of any number of computing devices (e.g., one or more computing devices) (e.g., in a distributed computing system).

[0181] The memory 1204 stores information within the computing device 1200. In some implementations, the memory71204 is a volatile memory7unit or units. In some implementations, the memory 1204 is a non-volatile memory unit or units. The memory 1204 may also be another form of computer-readable medium, such as a magnetic or optical disk.

[0182] The storage device 1206 is capable of providing mass storage for the computing deviceAtty. Docket No.: GEO-003PCT-8022-004011200. In some implementations, the storage device 1206 may be or contain a computer-readable medium, such as a hard disk device, an optical disk device, a flash memory’ or other similar solid state memory device, or an array of devices, including devices in a storage area network or other configurations. Instructions can be stored in an information carrier. The instructions, when executed by one or more processing devices (for example, processor 1202), perform one or more methods, such as those described above. The instructions can also be stored by one or more storage devices such as computer- or machine-readable mediums (for example, the memory 1204, the storage device 1206, or memory on the processor 1202).

[0183] The high-speed interface 1208 manages bandwidth-intensive operations for the computing device 1200, while the low-speed interface 1212 manages lower bandwidthintensive operations. Such allocation of functions is an example only. In some implementations, the high-speed interface 1208 is coupled to the memory 1204, the display 1216 (e.g., through a graphics processor or accelerator), and to the high-speed expansion ports 1210, which may accept various expansion cards (not shown). In the implementation, the low -speed interface 1212 is coupled to the storage device 1206 and the low-speed expansion port 1214. The low-speed expansion port 1214, which may include various communication ports (e g., USB, Bluetooth®, Ethernet, wireless Ethernet) may be coupled to one or more input / output devices, such as a keyboard, a pointing device, a scanner, or a networking device such as a switch or router, e.g., through a netw ork adapter.

[0184] The computing device 1200 may be implemented in a number of different forms, as shown in the figure. For example, it may be implemented as a standard server 1220, or multiple times in a group of such servers. In addition, it may be implemented in a personal computer such as a laptop computer 1222. It may also be implemented as part of a rack server system 1224. Alternatively, components from the computing device 1200 may be combined with other components in a mobile device (not shown), such as a mobile computing device 1250. Each of such devices may contain one or more of the computing device 1200 and the mobile computing device 1250, and an entire system may be made up of multiple computing devices communicating with each other.

[0185] The mobile computing device 1250 includes a processor 1252, a memory 1264, an input / output device such as a display 1254, a communication interface 1266, and a transceiver 1268, among other components. The mobile computing device 1250 may also be provided with a storage device, such as a micro-drive or other device, to provide additional storage. Each of the processor 1252, the memory 1264, the display 1254, the communication interface 1266, and the transceiver 1268, are interconnected using various buses, and several of the componentsAtty. Docket No.: GEO-003PCT-8022-00401may be mounted on a common motherboard or in other manners as appropriate.

[0186] The processor 1252 can execute instructions within the mobile computing device 1250, including instructions stored in the memory 1264. The processor 1252 may be implemented as a chipset of chips that include separate and multiple analog and digital processors. The processor 1252 may provide, for example, for coordination of the other components of the mobile computing device 1250, such as control of user interfaces, applications run by the mobile computing device 1250, and wireless communication by the mobile computing device 1250.

[0187] The processor 1252 may communicate with a user through a control interface 1258 and a display interface 1256 coupled to the display 1254. The display 1254 may be, for example, a TFT (Thin-Film-Transistor Liquid Crystal Display) display or an OLED (Organic Light Emitting Diode) display, or other appropriate display technology. The display interface 1256 may comprise appropriate circuitry for driving the display 1254 to present graphical and other information to a user. The control interface 1258 may receive commands from a user and convert them for submission to the processor 1252. In addition, an external interface 1262 may provide communication with the processor 1252, so as to enable near area communication of the mobile computing device 1250 with other devices. The external interface 1262 may provide, for example, for wired communication in some implementations, or for wireless communication in other implementations, and multiple interfaces may also be used.

[0188] The memory 1264 stores information within the mobile computing device 1250. The memory 1264 can be implemented as one or more of a computer-readable medium or media, a volatile memory' unit or units, or a non-volatile memory' unit or units. An expansion memory' 1274 may also be provided and connected to the mobile computing device 1250 through an expansion interface 1272, which may include, for example, a SIMM (Single In Line Memory Module) card interface. The expansion memory 1274 may provide extra storage space for the mobile computing device 1250, or may also store applications or other information for the mobile computing device 1250. Specifically, the expansion memory' 1274 may include instructions to carry out or supplement the processes described above, and may include secure information also. Thus, for example, the expansion memory 1274 may be provided as a security module for the mobile computing device 1250, and may be programmed with instructions that permit secure use of the mobile computing device 1250. In addition, secure applications may be provided via the SIMM cards, along with additional information, such as placing identifying information on the SIMM card in a non-hackable manner.

[0189] The memory may include, for example, flash memory and / or NVRAM memory (nonAtty. Docket No.: GEO-003PCT-8022-00401volatile random access memory), as discussed below. In some implementations, instructions are stored in an information carrier and, when executed by one or more processing devices (for example, processor 1252), perform one or more methods, such as those described above. The instructions can also be stored by one or more storage devices, such as one or more computer-or machine-readable mediums (for example, the memory 1264, the expansion memory 1274, or memory on the processor 1252). In some implementations, the instructions can be received in a propagated signal, for example, over the transceiver 1268 or the external interface 1262.

[0190] The mobile computing device 1250 may communicate wirelessly through the communication interface 1266, which may include digital signal processing circuitry’ where necessary'. The communication interface 1266 may provide for communications under various modes or protocols, such as GSM voice calls (Global System for Mobile communications), SMS (Short Message Service), EMS (Enhanced Messaging Sendee), or MMS messaging (Multimedia Messaging Senice), CDMA (code division multiple access), TDMA (time division multiple access), PDC (Personal Digital Cellular), WCDMA (Wideband Code Division Multiple Access), CDMA2000, or GPRS (General Packet Radio Service), among others. Such communication may occur, for example, through the transceiver 1268 using a radio-frequency. In addition, short-range communication may7occur, such as using a Bluetooth®, Wi-Fi™, or other such transceiver (not shown). In addition, a GPS (Global Positioning System) receiver module 1270 may provide additional navigation- and location-related wireless data to the mobile computing device 1250, which may be used as appropriate by applications running on the mobile computing device 1250.

[0191] The mobile computing device 1250 may also communicate audibly using an audio codec 1260, which may receive spoken information from a user and convert it to usable digital information. The audio codec 1260 may likewise generate audible sound for a user, such as through a speaker, e.g., in a handset of the mobile computing device 1250. Such sound may include sound from voice telephone calls, may include recorded sound (e.g., voice messages, music files, etc.) and may also include sound generated by applications operating on the mobile computing device 1250.

[0192] The mobile computing device 1250 may be implemented in a number of different forms, as shown in the figure. For example, it may be implemented as a cellular telephone 1280. It may also be implemented as part of a smart-phone 1282, personal digital assistant, or other similar mobile device.

[0193] Various implementations of the systems and techniques described here can be realized in digital electronic circuitry, integrated circuitry, specially designed ASICs (applicationAtty. Docket No.: GEO-003PCT-8022-00401specific integrated circuits), computer hardware, firmware, software, and / or combinations thereof. These various implementations can include implementation in one or more computer programs that are executable and / or interpretable on a programmable system including at least one programmable processor, which may be special or general purpose, coupled to receive data and instructions from, and to transmit data and instructions to, a storage system, at least one input device, and at least one output device.

[0194] These computer programs (also known as programs, software, software applications or code) include machine instructions for a programmable processor, and can be implemented in a high-level procedural and / or object-oriented programming language, and / or in assembly / machine language. As used herein, the terms machine-readable medium and computer-readable medium refer to any computer program product, apparatus and / or device (e.g., magnetic discs, optical disks, memory, Programmable Logic Devices (PLDs)) used to provide machine instructions and / or data to a programmable processor, including a machine-readable medium that receives machine instructions as a machine-readable signal. The term machine-readable signal refers to any signal used to provide machine instructions and / or data to a programmable processor.

[0195] To provide for interaction with a user, the systems and techniques described here can be implemented on a computer having a display device (e.g., a CRT (cathode ray tube) or LCD (liquid crystal display) monitor) for displaying information to the user and a keyboard and a pointing device (e.g., a mouse or a trackball) by which the user can provide input to the computer. Other kinds of devices can be used to provide for interaction with a user as well; for example, feedback provided to the user can be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user can be received in any form, including acoustic, speech, or tactile input.

[0196] The systems and techniques described here can be implemented in a computing system that includes a back end component (e.g., as a data server), or that includes a middleware component (e.g., an application server), or that includes a front end component (e.g., a client computer having a graphical user interface or a Web browser through which a user can interact with an implementation of the systems and techniques described here), or any combination of such back end, middleware, or front end components. The components of the system can be interconnected by any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include a local area network (LAN), a wide area network (WAN), and the Internet.

[0197] The computing system can include clients and servers. A client and server are generallyAtty. Docket No.: GEO-003PCT-8022-00401remote from each other and typically interact through a communication network. The relationship of client and server arises by virtue of computer programs running on the respective computers and having a client-server relationship to each other.

[0198] Having described various systems, methods, and deployments, certain aspects can include, but are not limited to:

[0199] In a first aspect, a process for in-situ generation of hydrogen gas from a subsurface geologic formation (e.g., and, optionally, production of geothermal heat and / or amorphous silica and / or a rare earth mineral and / or metals), said process comprising injecting fluid (e.g., brine) into the subsurface geologic formation and extracting hydrogen gas produced by interaction of the fluid (e.g., brine) with the subsurface geologic formation (e.g., mafic rock in the formation) (e.g., by serpentinization) [e.g., wherein the process comprises (and / or is designed and / or controlled via) one or more steps selected from steps (a) to (f) as follows: (a) pad design, wherein the pad design comprises designing (e.g., optimizing a design of) one or more wells (e.g., a plurality of wells) at the subsurface geologic formation site by selecting a geometrical arrangement of one or more injection wells and / or one or more production wells (e.g., and / or selecting corresponding offset well depths) (e.g., a combination injection and production well (e.g., operated in a huff and puff mode) (e.g., operated to produce hydrogen gas quasicontinuously), and / or by selecting a scheduling of each of a plurality of wells to operate in either injection mode or hydrogen production mode at various times at the subsurface geologic formation site, to support one or more of (i) to (iv) as follows: (i) a controlled migration of a serpentinization front, (ii) a frequency of fracks per well (e.g., wherein a frack is a period of hydraulic fracturing of rock, e.g., fracturing rock by pumping / injecting a high-pressure aqueous solution, e.g., brine), (iii) a duration of fracks, and (iv) use of short fracks to ‘kick start’ a self-sustaining chemofracture process from the well; (b) sequenced multi-well multi-stage fracturing operation, wherein the fracturing operation comprises determining a program of performing one or more of (i) to (iv) at each of the plurality of wells at the subsurface geologic formation site: (i) drilling (e.g., mechanical drilling of rock), (ii) fracturing, (iii) injecting (e.g., injecting brine) (e.g., injecting a fluid that does not necessarily fracture rock, e.g., for dissolution of species to promote serpentinization, and / or for waste disposal, and / or for other purposes), and (iv) producing and / or extracting (e.g., harvesting) hydrogen, (e.g., wherein the program comprises a plurality of fracks per well at different depths over time, e.g., to access more rock and / or relieve stress and / or clear blockages over time (e.g., many years) to increase (e.g., maximize) resource (e.g., hydrogen and / or mineral) production); (c) hydrogen extraction (e.g., recovery) from one or more of the plurality of wells, wherein theAtty. Docket No.: GEO-003PCT-8022-00401hydrogen recovery comprises increasing hydrogen flow to the surface by maintaining and / or increasing fracture connectivity with pressure and / or one or more proppants (e.g., wherein the one or more proppants comprises olivine sand, e.g., wherein the one or more proppants provides energy); (d) brine circulation, wherein the brine circulation comprises maintaining a pressure throughout the subsurface geologic formation site via the plurality of wells to keep a fracture network open and active, and / or conserving enthalpy throughout the subsurface geologic formation site, and / or maintaining high flow rates throughout the subsurface geologic formation site (e g., including continuous replenishment of water / brine); (e) controlling brine composition, wherein controlling brine composition comprises using one or more additives to reduce viscosity of flowing brine and / or using one or more surfactants to increase contact area in small pores of the subsurface geologic formation site medium, and / or using one or more additives to reduce hydrophobicity and / or to suppress bubble formation, and / or using one or more additives to remove salts to maintain a salinity level within a range that is conducive to serpentinization; and (f) controlling brine pH, wherein controlling brine pH comprises maintaining pH of the brine within an optimal range (e.g., slightly basic) by adding acid and / or otherwise removing alkalinity as serpentinization drives the pH higher).

[0200] A second aspect can include the process of the first aspect, further comprising: performing hierarchical fracturing of rock in the subsurface geologic formation.

[0201] A third aspect can include the process of the first or second aspect, comprising utilizing energy from an exothermic reaction of the fluid (e.g., brine) and the subsurface geologic formation to control fracturing of rock in the subsurface geologic formation.

[0202] A fourth aspect can include the process of any one of the first to third aspects, wherein the process comprises establishing a plurality of wells at a given site (e.g., well pad) of the subsurface geologic formation, and staging fracturing and hydrogen extraction (e.g., harvesting) at the wells (e.g., such that some wells are fractured while others are used for active H2 production and extraction, e.g., not all fracks are performed for a given well at once, e.g., not all stages of fracturing are performed for a given well before moving on to another well).

[0203] A fifth aspect can include the process of any one of the fourth to third aspects, wherein the process comprises staging fracturing and hydrogen extraction (e.g., harvesting) at a plurality of wells at a given site (e.g., well pad) of the subsurface geological formation.

[0204] A sixth aspect can include the process of any one of the first to fifth aspects, wherein the process comprises staging mechanical fracturing (e.g., fracturing) and hydrogen production (e.g., and extraction) at a plurality of wells at a given site (e.g.. well pad) of the subsurface geological formation.Atty. Docket No.: GEO-003PCT-8022-00401

[0205] A seventh aspect can include the process of any one of the first to sixth aspects, comprising first performing mechanical fracturing (e.g., hydraulic fracturing (fracturing)) of the subsurface geologic formation and subsequently controlling fracture formation using reaction-based fracturing [e.g., using energy released from an exothermic chemical reaction occurring (e.g., induced) in the subsurface geologic formation (e.g., using fluid (e.g., brine))].

[0206] An eighth aspect can include the process of any one of the first to seventh aspects, wherein there are a plurality of wells associated with a given site (e.g., well pad) of the subsurface geologic (e.g., rock) formation and the process comprises site-level optimization of hydrogen production (e.g., collectively across all wells) (e.g., across all wells simultaneously).

[0207] A ninth aspect can include the process of any one of the first to eighth aspects, wherein there are a plurality of wells associated with a given site (e.g., well pad) of the subsurface geologic (e.g., rock) formation and the process comprises optimizing hydrogen production (e.g., stimulated by the fluid (e.g., brine)) at a level greater than a level of individual wells.

[0208] A tenth aspect can include the process of any one of the first to ninth aspects, wherein there are a plurality of wells associated with a given site of the subsurface geologic (e.g., rock) formation and the process comprises (e.g., initially) mechanically fracturing one or more of the wells while extracting hydrogen at one or more other of the wells.

[0209] An eleventh aspect can include the process of the tenth aspect, wherein mechanically fracturing the one or more of the w ells comprises injecting fluid (e.g., brine).

[0210] A twelfth aspect can include the process of the eleventh aspect, wherein injecting the fluid (e.g., brine) at the one or more of the wells applies pressure to the subsurface geologic formation such that hydrogen production and / or extraction at the one or more other of the wells is stimulated by the pressure.

[0211] A thirteenth aspect can include the process of any one of the first to twelfth aspects, comprising drilling one or more well locations at a given site of the subsurface geologic formation for mechanical fracturing of the formation; subsequently drilling one or more well locations at the given site for hydrogen production and / or extraction.

[0212] A fourteenth aspect can include the process of the thirteenth aspect, comprising injecting fluid (e.g., brine) at the one or more well locations for mechanical fracturing and extracting hydrogen (e.g., in the fluid (e.g., brine)) at the one or more well locations for hydrogen production and / or extraction (e.g., simultaneously with the injecting).

[0213] A fifteenth aspect can include the process of any one of the first to fourteenth aspects, comprising injecting fluid (e.g., brine) at one or more well locations for mechanical fracturing of the subsurface geologic formation and extracting hydrogen (e.g., in the fluid (e.g., brine)) atAtty. Docket No.: GEO-003PCT-8022-00401one or more well locations for hydrogen production and / or extraction (e.g., simultaneously with the injecting) of the subsurface geologic formation.

[0214] A sixteenth aspect can include the process of any one of the first to fifteenth aspects, comprising developing a serpentinization front at a given site (e.g., well pad) in the subsurface geologic formation (e.g., a front that moves into fresh olivine); determining one or more (e.g., existing and / or to-be-formed) well locations (e.g., well(s)) at the given site at which to fracture the subsurface geologic formation (e.g., at which to perform a further stage of fracturing) based on a location of the serpentinization front; and performing (e.g., a further stage of) fracturing of the subsurface geologic formation at the one or more well locations (e.g., at well(s) at the location(s)) using fluid (e.g., brine).

[0215] A seventeenth aspect can include the process of the sixteenth aspect, wherein determining the one or more well locations is further based on one or more current hydrogen production characteristics at the given site.

[0216] An eighteenth aspect can include the process of the sixteenth or seventeenth aspect, wherein determining the one or more well locations is further based on a current fluid (e.g., brine) salinity.

[0217] A nineteenth aspect can include the process of any one of the first to eighteenth aspects, comprising developing a serpentinization front at a given site (e.g., well pad) in the subsurface geologic formation (e.g., a front that moves into fresh olivine); determining a time at which to fracture the subsurface geologic formation (e.g., at which to perform a further stage of fracturing) at one or more (e.g., existing and / or to-be-formed) well locations (e.g., well(s)) at the given site based on a location of the serpentinization front; and performing (e.g., a further stage of) fracturing of the subsurface geologic formation at the one or more well locations (e.g., at well(s) at the location(s)) using fluid (e.g., brine).

[0218] A twentieth aspect can include the process of the nineteenth aspect, wherein determining the time is further based on one or more current hydrogen production characteristics at the given site.

[0219] A twenty first aspect can include the process of the nineteenth or twentieth aspect, wherein determining the time is further based on a current fluid (e.g., brine) salinity.

[0220] A twenty second aspect can include the process of any one of the fifteenth to twenty first aspects, wherein the one or more well locations is a plurality of well locations and performing the fracturing comprises simultaneously fracturing the subsurface geologic formation at the plurality of well locations.

[0221] A twenty third aspect can include the process of any one of the fifteenth to twentyAtty. Docket No.: GEO-003PCT-8022-00401second aspects, wherein the determining (e.g., of time and / or location(s)) is performed using a digital twin model that receives current (e.g., real time) data about the subsurface geologic formation [e.g., well and / or resource (e.g., hydrogen) production data],

[0222] A twenty fourth aspect can include the process of the twenty third aspect, wherein the digital twin model comprises a machine-learning model.

[0223] A twenty fifth aspect can include the process of the twenty fourth aspect, wherein the machine-learning model comprises a Kolmogorov-Arnold Network (KAN) model.

[0224] A twenty sixth aspect can include the process of any one of the first to twenty’ fifth aspects, comprising controlling a serpentinization front in the subsurface geologic formation using a combination of the fluid (e.g., brine) injection and heat generated from the hydrogen gas production.

[0225] A twenty seventh aspect can include the process of any one of the first to twenty sixth aspects, comprising controlling pore size in the subsurface geologic formation (e.g., at or near a serpentinization front) using a combination of the fluid (e.g., brine) injection and heat generated from the hydrogen gas production.

[0226] A twenty eighth aspect can include the process of any one of the first to twenty seventh aspects, wherein the fluid (e.g., brine) comprises a proppant (e.g., a reactive proppant) (e.g., a mineral proppant) (e.g., wherein the proppant is olivine sand).

[0227] A twenty ninth aspect can include the process of any one of the first to twenty eighth aspects, comprising accelerating hydrogen production by providing a reactive proppant (e.g., mineral proppant) in the fluid (e.g., brine).

[0228] A thirtieth aspect can include the process of any one of the first to twenty ninth aspects, comprising loosening grain boundaries in the subsurface geologic formation using a proppant provided in the fluid (e.g., brine) thereby facilitating water permeation into the subsurface geologic formation (e.g., at a serpentinization front).

[0229] A th i rty first aspect can include the process of any one of the twenty eighth to thirtieth aspects, wherein the proppant is sized to promote bulk flow of the fluid (e.g., brine) into a fracture network in the subsurface geologic formation (e.g., into a serpentinization front) (e.g., into a smallest set of fractures propagating in the fracture network).

[0230] A thirty second aspect can include the process of any one of the first to thirty first aspects, comprising estimating heat production at a serpentinization front in the subsurface geologic formation using a digital twin model and controlling temperature at the serpentinization front (e.g., using the fluid (e.g., brine)) based on the estimated heat production (e.g., to maintain temperature at the front in a range of from 250-350 °C).Atty. Docket No.: GEO-003PCT-8022-00401

[0231] A thirty third aspect can include the process of any one of the first to thirty second aspects, wherein (i) injecting the fluid (e.g., brine) comprises injecting the fluid (e.g., brine) into one or more reacting regions a fracture network of the subsurface geologic formation from one or more first wells (e.g., injection wells) at a given site (e.g., well pad) of the subsurface geologic formation and (ii) extracting the hydrogen gas comprises flowing the fluid (e.g., brine) from the one or more reacting regions to one or more second wells (e.g., production wells), different from the one or more first wells, at the given site (e.g., wherein the injection well(s) are later used as production well(s) and / or the production well(s) are later used as injection well(s)).

[0232] A thirty fourth aspect can include the process of the thirty third aspect, wherein one or more of the one or more first wells and one or more of the one or more second wells overlap vertically (e.g., are on top of each other).

[0233] A thirty’ fifth aspect can include the process of the thirty third or thirty fourth aspect, wherein the injecting and the extracting occurs simultaneously (e.g., over a period of one or more days to one or more weeks).

[0234] A thirty sixth aspect can include the process of any one of the first to thirty fifth aspects, wherein the injecting and the extracting occurs simultaneously (e.g., over a period of one or more days to one or more weeks).

[0235] A thirty seventh aspect can include the process of the thirty sixth aspect, wherein the injecting and the extracting occur at different wells at a given site of the subsurface geologic formation.

[0236] A thirty eighth aspect can include the process of any one of the first to thirty’ seventh aspects, comprising increasing fracture connectivity in a fracture network in the subsurface geologic formation through micro-fracturing (e.g., resulting from injecting fluid (e.g., brine)).

[0237] A thirty ninth aspect can include the process of any one of the first to thirty eighth aspects, comprising increasing fracture connectivity in a fracture network in the subsurface geologic formation through induced thermal stress resulting from a chemical reaction (e.g., serpentinization).

[0238] A fortieth aspect can include the process of any one of the first to thirty ninth aspects, wherein the fluid (e.g., brine) is injected such that Knudsen diffusion of produced hydrogen (e.g., by serpentinization) is prolonged.

[0239] A forty first aspect can include the process of any one of the first to fortieth aspects, wherein extracting the hydrogen gas comprises capturing buoyant hydrogen moving vertically through a fracture network of the subsurface geologic formation using one or more productionAtty. Docket No.: GEO-003PCT-8022-00401wells.

[0240] A forty second aspect can include the process of any one of the first to forty first aspects, wherein extracting the hydrogen gas is performed using one or more phase-separating membranes in one or more production wells.

[0241] A forty third aspect can include the process of any one of the first to forty second aspects, comprising providing circulation of the fluid (e.g., brine) to maintain pressures so that fractures remain open while maintaining a pressure gradient towards a production well.

[0242] A forty fourth aspect can include the process of any one of the first to forty fourth aspects, the injecting and the extracting are performed with a plurality of wells at a given site (e.g., well pad) of the subsurface geologic formation.

[0243] A forty fifth aspect can include the process of any one of the first to forty fourth aspects, wherein hydraulic fracture stages of ones of the plurality of wells are interacting.

[0244] A forty sixth aspect can include the process of any one of the first to forty fifth aspects, comprising performing production and injection cycles using the ones of the plurality of wells (e.g., with a period having an order of one or more days to one or more weeks).

[0245] A forty seventh aspect can include the process of any one of the first to forty sixth aspects, wherein the fluid (e.g., brine) comprises one or more viscosity reducing additives.

[0246] A forty' eighth aspect can include the process of any one of the first to forty' seventh aspects, comprising changing a temperature of the fluid (e.g., brine) (e g., when in the subsurface geologic formation) (e.g., by pre-heating the fluid (e.g., brine)) [e.g., using reaction control of a downhole reaction (e.g., serpentinization)] thereby enhancing fluid (e.g., brine) infiltration into pores in a fracture network in the subsurface geologic formation.

[0247] A forty ninth aspect can include the process of any one of the first to forty eighth aspects, wherein the fluid (e.g., brine) has a pH in a range of neutral to mildly basic.

[0248] A fiftieth aspect can include the process of any one of the first to forty ninth aspects, comprising controlling pH of the fluid (e.g., brine) (e.g., using one or more additives) to maintain the pH in a range of from neutral to mildly basic.

[0249] A fifty first aspect can include the process of any one of the first to fiftieth aspects, comprising controlling saturation of dissolved silica in the fluid (e.g., brine) via periodic removal of reacted fluid (e.g., brine) (e.g., from one or more wells at a given site of the subsurface geologic formation).

[0250] A fifty second aspect can include the process of any one of the first to fifty first aspects, comprising flushing precipitates from fractures (e.g., at a serpentinization front) of the subsurface geologic formation using the fluid (e.g., brine) (e.g., by controlling chemistry of theAtty. Docket No.: GEO-003PCT-8022-00401fluid (e.g., brine)).

[0251] A fifty third aspect can include the process of any one of the first to fifty second aspects, comprising providing one or more interfacial modifiers (e.g., surfactant(s), nanoparticle(s), charged species, pH modifier(s) emulsion(s), or combination thereof) in the fluid (e.g., brine) thereby lowering interfacial tension and promoting water penetration along grain boundaries in the subsurface geologic formation as fracturing occurs in the subsurface geologic formation.

[0252] A fifty fourth aspect can include the process of any one of the first to fifty third aspects, comprising optimizing rock wetting in the subsurface geologic formation during hydrogen production using one or more interfacial modifiers (e.g., surfactant(s), nanoparticle(s), charged species, pH modifier(s) emulsion(s), or combination thereof) in the fluid (e.g., brine).

[0253] A fifty fifth aspect can include the process of the fifty third or fifty fourth aspect, wherein the one or more interfacial modifiers are provided such that a condition of q.™yg) < cos'J[(l-f) / (c-f)] is maintained (e.g., as determined using a digital twin model), where f is surface solid fraction, c is overall solid fraction, qis contact angle, and subscripts s, w, and g are rock, water, and gas or third phase, respectively.

[0254] A fifty sixth aspect can include the process of any one of the fifty third to fifty fifth aspects, wherein the one or more interfacial modifiers have been selected to provide an effective positive spreading coefficient (e.g., based on Lifshitz-van der Waals, (Lewis) acid, and / or (Lewis) base parameters of surface energy).

[0255] A fifty seventh aspect can include the process of any one of the fifty third to fifty sixth aspects, wherein the one or more interfacial modifiers are non-precipitating in the subsurface geologic formation.

[0256] A fifty eighth aspect can include the process of any one of the fifty third to fifty' seventh aspects, wherein the fluid (e.g., brine) has a pH that enhances ionization of surface charged species of surfaces of the subsurface geologic formation.

[0257] A fifty ninth aspect can include the process of any one of the fifty third to fifty’ eighth aspects, wherein the fluid (e.g., brine) comprises one or more ionic surfactants that mitigate any local precipitation / passivation of rock surfaces in the subsurface geologic formation.

[0258] A sixtieth aspect can include the process of any one of the first to fifty- ninth aspects, comprising altering pH of the fluid (e g., brine) in-situ using one or more local-release mechanisms that are triggered by local conditions in the subsurface geologic formation (e.g., temperature and / or pressure).

[0259] A sixty first aspect can include the process of any one of the first to sixtieth aspects, wherein the formation comprises an olivine matrix.Atty. Docket No.: GEO-003PCT-8022-00401

[0260] A sixty second aspect can include the process of any one of the first to sixty first aspects, wherein the formation is iron-rich (e.g.. comprises olivine and / or peridotite) (e.g., comprises or is made of mafic rock).

[0261] A sixty third aspect can include the process of any one of the first to sixty second aspects, wherein the formation comprises a banded iron formation (BIF) (e.g., iron-rich hematite and / or magnetite, with adjacent silica-rich layers).

[0262] A sixty fourth aspect can include the process of any one of the first to sixty third aspects, wherein the process further comprises (e.g., simultaneously) recovering heat produced from exothermic reaction of the fluid (e.g., brine) with the subsurface geologic formation, recovering amorphous silica with the fluid (e.g., brine), or both.

[0263] A sixty fifth aspect can include the process of any one of the first to sixty fourth aspects, wherein the process comprises applying pressure modulated hydraulics and geochemical control for enhanced chemical and heat recovery' (e.g., by facilitating dissolution of Fe(2+) from the rock formation).

[0264] A sixty sixth aspect can include the process of any one of the first to sixty fifth aspects, comprising pumping at least a portion of the fluid comprising generated hydrogen gas dispersed (e.g., dissolved) therein out of fractures (e.g., of a fracture network) in the subsurface geologic formation using reaction-induced bulk stress and / or pressure.

[0265] A sixty seventh aspect can include the process of any one of the first to sixty sixth aspects, wherein extracting the hydrogen gas comprises retrieving at least a portion of the fluid comprising the hydrogen gas dispersed (e.g., dissolved) therein out of fractures (e g., of a fracture network) in the subsurface geologic formation using reaction-induced bulk stress and / or pressure.

[0266] In a sixty eighth aspect, a process for in-situ generation of hydrogen gas from a subsurface geologic formation (e.g., and, optionally, production of geothermal heat and / or amorphous silica and / or a rare earth mineral and / or metals), said process comprising injecting brine into the subsurface geologic formation and recovering generated hydrogen gas (e.g., according to any one of the first to sixty seventh aspects).

[0267] In a sixty eighth aspect, a method of producing resources from a geological formation, comprises: initiating production from the geological formation having one or more wells drilled into the geological formation; and applying, during the production, a composite waveform pressure signal P(t) to the geological formation through at least one of the one or more wells, wherein the composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a secondAtty. Docket No.: GEO-003PCT-8022-00401frequency component, wherein the first frequency component performs a first function and the second frequency component performs a second function different from the first function, and wherein the first frequency component has a period that is at least 5 times as long as a period of the second frequency component.

[0268] A sixty ninth aspect can include the method of the sixty eighth aspect, wherein the composite waveform pressure signal has the form:P(t) = Po + Pi sin(2jr x fi x t + e i) + P2sin(27t x f2x t + q>2) where Po is a static baseline pressure. Pi and P2are amplitudes of the first and second frequency components respectively, fi and f> are frequencies of the first and second frequency components respectively, q>i and q>2are phase angles, and t is time.

[0269] A seventieth aspect can include the method of the sixty ninth aspect, wherein: the first frequency component has a frequency fi in a range of 1 / day to 1 / month; and the second frequency component has a frequency f> in a range of 1 / second to 1 / hour, wherein the second frequency component induces weathering and micro-fracturing of the geological formation.

[0270] A seventy first aspect can include the method of the seventieth aspect, wherein the second frequency component induces weathering through mechanical fatigue and stress cycling.

[0271] A seventy- second aspect can include the method of the seventieth or seventy first aspect, wherein the composite waveform pressure signal further comprises a third frequency component having a frequency fo in a range of 1 / week to 1 / month.

[0272] A seventy third aspect can include the method of any one of the sixty eighth to seventy second aspects, wherein the composite waveform pressure signal is tuned over time during production by adjusting at least one parameter selected from the group consisting of: Po, Pi, P2, fi, f>, e i, and q>2.

[0273] A seventy fourth aspect can include the method of the seventy third aspect, wherein the tuning is performed in response to at least one measurement selected from the group consisting of: production rates, formation pressure responses, seismic monitoring data, chemical composition of produced fluids, and temperature measurements.

[0274] A seventy fifth aspect can include the method of any one of the sixty’ eighth to seventy fourth aspects, wherein the total instantaneous pressure P(t) of the composite waveform cyclically crosses a breakdown pressure threshold of the geological formation such that P(t) is greater than the breakdown pressure at certain times and less than the breakdown pressure atAtty. Docket No.: GEO-003PCT-8022-00401other times.

[0275] A seventy’ sixth aspect can include the method of any one of the sixty eighth to seventy fifth aspects, wherein the overlapping of the first and second frequency components creates interference patterns, and wherein phase relationships between the first and second frequency components are tuned to create constructive interference at selected times during production.

[0276] A seventy seventh aspect can include the method of any one of the sixty eighth to seventy sixth aspects, wherein the resources produced comprise at least one member selected from the group consisting of: hydrogen gas, geothermal energy, minerals, metals, rare earth elements, and amorphous silica.

[0277] In a seventy eighth aspect, a system for producing resources from a subsurface geological formation comprises: one or more wells drilled into the subsurface geological formation; wellhead equipment operatively connected to at least one of the one or more wells; and a control system configured to, during production from the geological formation, cause the wellhead equipment to apply a composite waveform pressure signal P(t) to the geological formation, wherein the composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a second frequency component, wherein the first frequency component performs a first function and the second frequency component performs a second function different from the first function.

[0278] A seventy’ ninth aspect can include the system of the seventy eighth aspect, wherein the composite waveform pressure signal has the form:P(t) = Po + P₁ sin(2π x f₁ x t + φ₁) + P2sin(2π x f2x t + φ2) where Po is a static baseline pressure, Pi and P2are amplitudes of the first and second frequency components respectively, fi and fi are frequencies of the first and second frequency components respectively, q>i and (p2are phase angles, and t is time.

[0279] An eightieth aspect can include the system of the seventy ninth aspect, wherein: the first frequency component has a frequency fi in a range of 1 / day to 1 / month; and the second frequency component has a frequency fi in a range of 1 / second to 1 / hour and is configured to induce weathering and micro-fracturing of the geological formation.

[0280] An eighty first aspect can include the system of any one of the seventy eighth to eightieth aspects, wherein the wellhead equipment comprises at least one component selected from the group consisting of: computer-controlled variable-speed pumps, fast-responseAtty. Docket No.: GEO-003PCT-8022-00401pressure modulation valves, hydraulic accumulators, and signal generators.

[0281] An eight)’ second aspect can include the system of any one of the seventy eighth to eighty first aspects, wherein the control system is further configured to: monitor at least one parameter selected from the group consisting of: production rates, formation pressure responses, seismic activity, chemical composition of produced fluids, and temperature measurements; and dynamically adjust the composite waveform pressure signal during production based on the monitored parameter by changing at least one characteristic of the first frequency component or the second frequency component.

[0282] It is contemplated that systems, devices, methods, and processes of the disclosure encompass variations and adaptations developed using information from the embodiments described herein. Adaptation and / or modification of the systems, devices, methods, and processes described herein may be performed by those of ordinary skill in the relevant art.

[0283] Throughout the description, where articles, devices, and systems are described as having, including, or comprising specific components, or where processes and methods are described as having, including, or comprising specific steps, it is contemplated that, additionally, there are articles, devices, and systems according to certain embodiments of the present disclosure that consist essentially of, or consist of, the recited components, and that there are processes and methods according to certain embodiments of the present disclosure that consist essentially of, or consist of, the recited processing steps.

[0284] It should be understood that the order of steps or order for performing certain action is immaterial so long as operability is not lost. Moreover, two or more steps or actions may be conducted simultaneously. As is understood by those skilled in the art, the terms “over”, “under”, “above”, “below”, “beneath”, and “on” are relative terms and can be interchanged in reference to different orientations of the layers, elements, and substrates included in the present disclosure. For example, a first layer on a second layer, in some embodiments means a first layer directly on and in contact with a second layer. In other embodiments, a first layer on a second layer can include another layer there between.

[0285] Headers are provided for the convenience of the reader and are not intended to be limiting with respect to the claimed subject matter.

[0286] Certain embodiments of the present disclosure were described above. It is, however, expressly noted that the present disclosure is not limited to those embodiments, but rather the intention is that additions and modifications to what was expressly described in the present disclosure are also included within the scope of the disclosure. Moreover, it is to be understood that the features of the various embodiments described in the present disclosure were notAtty. Docket No.: GEO-003PCT-8022-00401mutually exclusive and can exist in various combinations and permutations, even if such combinations or permutations were not made express, without departing from the spirit and scope of the disclosure. The disclosure has been described in detail with particular reference to certain embodiments thereof, but it will be understood that variations and modifications can be effected within the spirit and scope of the claimed invention.

Claims

Atty. Docket No.: GEO-003PCT-8022-00401CLAIMSWhat is claimed is:

1. A process for in-situ generation of hydrogen gas from a subsurface geologic formation, the process comprising:injecting fluid comprising a brine into the subsurface geologic formation through a plurality of wells:extracting hydrogen gas produced by interaction of the fluid with the subsurface geologic formation; andmaintaining a pressure throughout the subsurface geologic formation site via the plurality of wells to keep a fracture network open and active.

2. The process of claim 1, further comprising:designing one or more wells of the plurality of wells at the subsurface geologic formation site by selecting a geometrical arrangement of one or more injection wells and one or more production wells to support one or more of: (i) a controlled migration of a serpentinization front, (ii) a frequency of fractures per well, (hi) a duration of fractures, or (iv) use of short fractures to start a self- sustaining chemofracture process from the well.

3. The process of claim 1, further comprising:determining a program of performing one or more of (i) to (iv) at each of the plurality of wells at the subsurface geologic formation site: (i) drilling, (ii) fracturing, (iii) injecting the fluid, or (iv) producing the hydrogen.

4. The process of claim 1, further comprising:increasing hydrogen flow to the surface by maintaining fracture connectivity with pressure and one or more proppants, wherein the one or more proppants comprises a reactive proppant.

5. The process of claim 1, further comprising controlling a composition of the fluid, wherein controlling the fluid composition comprises using one or more additives to reduce viscosity of flowing brine, using one or more surfactants to increase contact area in small pores of the subsurface geologic formation site medium, using one or more additives to reduce hydrophobicity or to suppress bubble formation, or using one or more additives to remove salts to maintain a salinity’ level within a range that is conducive to serpentinization.

6. The process of claim 1, further comprising:Atty. Docket No.: GEO-003PCT-8022-00401controlling a pH of the fluid, wherein controlling the pH of the fluid comprises maintaining pH of the brine within a basic pH.

7. The process of claim 1, further comprising:performing hierarchical fracturing of rock in the subsurface geologic formation.

8. The process of claim 1, further comprising:utilizing energy from an exothermic reaction of the fluid and the subsurface geologic formation to control fracturing of rock in the subsurface geologic formation or the rate of reaction between the brine and the geologic formation.

9. The process of claim 1, further comprising:establishing a plurality of wells at a given site of the subsurface geologic formation;andstaging fracturing and hydrogen extraction at the wells such that some wells are fractured while others are used for active H2 production and extraction.

10. The process of claim 1, further comprising:performing mechanical fracturing of the subsurface geologic formation; and subsequently controlling fracture formation using reaction-based fracturing.

11. The process of claim 1, wherein there are a plurality of wells associated with a given site of the subsurface geologic formation and the process comprises controlling sitelevel hydrogen production collectively across all wells.

12. The process of claim 11, further comprising:mechanically fracturing one or more of the wells while extracting hydrogen at one or more other of the w ells, wherein mechanically fracturing the one or more of the wells comprises inj ecting the fluid.

13. The process of claim 1, wherein injecting the fluid mechanically fractures the subsurface geologic formation, and wherein extracting the hydrogen gas occurs in the fluid recovered from the subsurface geologic formation.

14. The process of claim 1, further comprising:developing a serpentinization front at a given site in the subsurface geologic formation; determining one or more wellbore locations based on a location of the serpentinization front, one or more current hydrogen production characteristics at the given site, a fluid salinity, or one or more parameters of the subsurface geological formation; andperforming fracturing of the subsurface geologic formation at the one or more wellbore locations using fluid.Atty. Docket No.: GEO-003PCT-8022-0040115. The process of claim 1, further comprising:developing a serpentinization front at a given site in the subsurface geologic formation; determining a time at which to fracture the subsurface geologic formation at one or more wellbore locations at the given site based on a location of the serpentinization front, one or more current hydrogen production characteristics at the given site, a current fluid salinity, or any combination thereof; and performing fracturing of the subsurface geologic formation at the one or more wellbore locations using fluid.

16. The process of claim 15, wherein the one or more well wellbore locations is a plurality of wellbore locations and performing the fracturing comprises simultaneously fracturing the subsurface geologic formation at the plurality of well wellbore locations.

17. The process of claim 15, wherein the determining of the time is performed using a digital twin model that receives current data about the subsurface geologic formation.

18. The process of claim 1, further comprising:controlling a serpentinization front in the subsurface geologic formation using a combination of the fluid injection and heat generated from the chemical reactions associated with hydrogen gas production.

19. The process of claim 1, further comprising:controlling permeability in the subsurface geologic formation using a combination of the fluid injection and heat generated from the chemical reactions associated with hydrogen gas production.

20. The process of claim 1, further comprising:accelerating hydrogen production by providing a reactive proppant in the fluid.

21. The process of claim 1, further comprising:estimating heat production at a serpentinization front in the subsurface geologic formation using a digital twin model; andcontrolling temperature at the serpentinization front based on the estimated heat production to maintain temperature at the front in a range of from 250-350 °C.

22. The process of claim 1, wherein (i) injecting the fluid comprises injecting the fluid into one or more reacting regions in a fracture network of the subsurface geologic formation from one or more first wells at a given site of the subsurface geologic formation, and (ii) extracting the hydrogen gas comprises flowing the fluid from the one or more reacting regions to one or more second wells, different from the one or more first wells, at the given site.Atty. Docket No.: GEO-003PCT-8022-0040123. The process of claim 1, wherein the injecting and the extracting occurs simultaneously.

24. The process of claim 1, further comprising:increasing fracture connectivity in a fracture network in the subsurface geologic formation through at least one of: (i) micro-fracturing, (ii) induced thermal stress resulting from a chemical reaction, or (iii) any combination thereof.

25. The process of claim 1, wherein extracting the hydrogen gas comprises capturing buoyant hydrogen moving vertically through a fracture network of the subsurface geologic formation using one or more production wells.

26. The process of claim 1, wherein extracting the hydrogen gas is performed using one or more phase-separating membranes in one or more production wells of the pl urality of wells.

27. The process of claim 26, further comprising:performing production and injection cycles using one of the plurality of wells.

28. The process of claim 1, wherein the fluid comprises one or more viscosity reducing additives.

29. The process of claim 1, further comprising:controlling a pH of the fluid to maintain the pH in a range of from neutral to mildly basic.

30. The process of claim 1, further comprising:flushing precipitates from fractures of the subsurface geologic formation using the fluid.

31. The process of claim 1, further comprising:providing one or more surfactant(s), nanoparticle(s), charged species, pH modifier(s) emulsion(s), or combination thereof in the fluid, or increasing rock wetting in the subsurface geologic formation during hydrogen production using one or more surfactant(s), nanoparticle(s), charged species, pH modifier(s) emulsion(s), or combination thereof in the fluid.

32. The process of claim 1, wherein the subsurface geologic formation is ultramafic or mafic rock.

33. The process of claim 1, wherein the subsurface geologic formation comprises a banded iron formation (BIF).

34. The process of claim 1, wherein the process comprises applying pressure modulated hydraulics and geochemical control for enhanced chemical and heat recovery.

35. A method of producing resources from a geological formation, the method comprising:Atty. Docket No.: GEO-003PCT-8022-00401initiating production from the geological formation having one or more wells drilled into the geological formation; andapplying, during the production, a composite waveform pressure signal P(t) to the geological formation through at least one of the one or more wells, wherein the composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a second frequency component, wherein the first frequency component performs a first function and the second frequency component performs a second function different from the first function, and wherein the first frequency component has a period that is at least 2 times as long as a period of the second frequency component.

36. The method of claim 35, wherein the composite waveform pressure signal has the form:P(t) = Po + Pi sin(2jt x fi x + e i) + P2sin(2jr x f2x t + q>2)where Po is a static baseline pressure, Pi and P2are amplitudes of the first and second frequency components respectively, fi and fi are frequencies of the first and second frequency components respectively, >i and q>2are phase angles, and t is time.

37. The method of claim 36, wherein:the first frequency component has a frequency fi in a range of 1 Hz to about 2×10⁻⁶ Hz;andthe second frequency component has a frequency fi in a range of 2 / second to 1 / hour, wherein the second frequency component induces weathering and microfracturing of the geological formation.

38. The method of claim 37, wherein the composite waveform pressure signal further comprises a third frequency component having a frequency fo in a range of 1 / week to 1 / month.

39. The method of claim 36, wherein the composite waveform pressure signal is tuned over time during production by adjusting at least one parameter selected from the group consisting of: Po, Pi, P2, fi, fi, (pi, and cp2, and wherein the tuning is performed in response to at least one measurement selected from the group consisting of: production rates, formation pressure responses, seismic monitoring data, chemical composition of produced fluids, and temperature measurements.Atty. Docket No.: GEO-003PCT-8022-0040140. The method of claim 35, wherein the total instantaneous pressure P(t) of the composite waveform cyclically crosses a breakdown pressure threshold of the geological formation such that P(t) is greater than the breakdown pressure at certain times and less than the breakdown pressure at other times.

41. The method of claim 35, wherein the total instantaneous pressure P(t) of the composite waveform cyclically remains below a breakdown pressure threshold of the geological formation during production.

42. The method of claim 35, wherein the resources produced comprise at least one member selected from the group consisting of: hydrogen gas, geothermal energy, minerals, metals, rare earth elements, and amorphous silica.

43. A system for producing resources from a subsurface geological formation, the system comprising:one or more wells drilled into the subsurface geological formation;wellhead equipment operatively connected to at least one of the one or more wells; and a control system configured to. during production from the geological formation, cause the wellhead equipment to apply a composite waveform pressure signal P(t) to the geological formation, wherein the composite waveform pressure signal comprises a defined set of superimposed or sequentially applied frequencies including at least a first frequency component and a second frequency component, wherein the first frequency component perforins a first function and the second frequency component performs a second function different from the first function.

44. The system of claim 43, wherein the composite waveform pressure signal has the form:P(t) = Po + Pi sin(27i x fi x t + e i) + P2sin(2n x f2x t + q>2)where Po is a static baseline pressure, Pi and P2are amplitudes of the first and second frequency components respectively, fi and f2are frequencies of the first and second frequency components respectively, (pi and (p2are phase angles, and t is time, wherein:the first frequency component has a frequency fi in a range of 1 Hz to about 2xl0-6Hz;andAtty. Docket No.: GEO-003PCT-8022-00401the second frequency component has a frequency 12 in a range of 1 / second to 1 / hour and is configured to induce weathering and micro-fracturing of the geological formation.

45. The system of claim 43, wherein the wellhead equipment comprises at least one component selected from the group consisting of: computer-controlled variable-speed pumps, fast-response pressure modulation valves, hydraulic accumulators, and signal generators.

46. The system of claim 43, wherein the control system is further configured to:monitor at least one parameter selected from the group consisting of: production rates, formation pressure responses, seismic activity, chemical composition of produced fluids, and temperature measurements; anddynamically adjust the composite waveform pressure signal during production based on the monitored parameter by changing at least one characteristic of the first frequency component or the second frequency component.

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