Systems and methods for producing stimulated geologic hydrogen at elevated pressure

Abstract

Systems and methods for producing geologic hydrogen from a subsurface rock formation are disclosed. A method comprises maintaining elevated pressure along at least a portion of a wellbore penetrating an iron-rich subsurface rock formation such that water or brine in contact with the rock formation remains in a substantially liquid state and hydrogen generated by serpentinization dissolves into the water or brine, recovering hydrogen-saturated fluid from the wellbore at a pressure above atmospheric pressure, partially depressurizing the recovered fluid to an intermediate degassing pressure that is less than the wellbore pressure but greater than atmospheric pressure, thereby desorbing a fraction of the dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system, and separating the desorbed hydrogen gas from the partially depressurized fluid.

Description

Aty. Docket No.: GEG-004PCT-8022-00501SYSTEMS AND METHODS FOR PRODUCING STIMULATED GEOLOGIC HYDROGEN AT ELEVATED PRESSURECROSS REFERENCES TO RELATED APPLICATIONS

[0001] The present application claims priority to U. S. Provisional Application No.63 / 780,119, filed on March 28, 2025, and entitled ’‘SYSTEMS AND METHODS FOR PRODUCING STIMULATED GEOLOGICAL HYDROGEN AT ELEVATED PRESSURE,” the entire disclosure of which is incorporated herein by reference.FIELD

[0002] This disclosure 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, and / or other resources from subsurface rock formations and / or other geological environments.BACKGROUND

[0003] Hydrogen is a versatile fuel that produces no greenhouse gas emissions at its point of use, making it a promising clean energy carrier. Current methods of hydrogen production, such as steam methane reforming, emit significant quantities of CO₂ and are energy-intensive. Alternative "green hydrogen" production methods, such as electrolysis of water, remain costly, and challenges associated with hydrogen transportation and storage further limit widespread adoption.

[0004] An emerging area of interest is the harvesting of "geologic hydrogen" or "natural hydrogen," which is produced when water reacts with iron-rich subsurface rock formations through a process known as serpentinization. Efforts to develop geologic hydrogen as a practical energy source face challenges related to identifying suitable geological sites and designing production systems that are technically and economically viable.SUMMARY

[0005] In some embodiments, a method for producing geologic hydrogen from a subsurface rock formation comprises maintaining elevated pressure along at least a portion of a wellbore penetrating an iron-rich subsurface rock formation such that water or brine inAtty. Docket No.: GEG-004PCT-8022-00501contact with the rock formation remains in a substantially liquid state and hydrogen generated by serpentinization dissolves into the water or brine: recovering hydrogen-saturated fluid from the wellbore at a pressure above atmospheric pressure; partially depressurizing the recovered fluid to an intermediate degassing pressure that is less than the wellbore pressure but greater than atmospheric pressure, thereby desorbing a fraction of the dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system; and separating the desorbed hydrogen gas from the partially depressurized fluid.

[0006] In some embodiments, a system for producing geologic hydrogen from a subsurface rock formation comprises a wellbore configured to penetrate an iron-rich subsurface rock formation and to maintain elevated pressure along at least a portion of its length such that hydrogen generated by serpentinization dissolves into water or brine in the wellbore; one or more expanders configured to partially depressurize fluid recovered from the wellbore to an intermediate degassing pressure greater than atmospheric pressure, thereby desorbing dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system; and one or more phase separators configured to separate the desorbed hydrogen gas from the partially depressurized fluid. These and other features will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings and claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:

[0008] FIG. 1 is a schematic diagram of a surface processing loop for high pressure hydrogen recovery in accordance with certain embodiments of the present disclosure.

[0009] FIG. 2A is a comparative diagram illustrating differences between hydrocarbon systems and geologic hydrogen systems in accordance with certain embodiments of the present disclosure.

[0010] FIG. 2B is a schematic diagram illustrating a two-well injection and production configuration and a representative hydrogen production rate curve in accordance with certain embodiments of the present disclosure.

[0011] FIG. 3 A is a photomicrographic image of an unaltered ultramafic rock sample prior to stimulation in accordance with certain embodiments of the present disclosure.Aty. Docket No.: GEG-004PCT-8022-00501

[0012] FIG. 3B is a photomicrographic image of an ultramafic rock sample following initial stimulation in accordance with certain embodiments of the present disclosure.

[0013] FIG. 3C is a photomicrographic image of an ultramafic rock sample at a further stage of stimulation in accordance with certain embodiments of the present disclosure.

[0014] FIG. 4 is a schematic diagram of an open well configuration for geologic hydrogen production in accordance with certain embodiments of the present disclosure.

[0015] FIG. 5 is a schematic diagram of a packer well configuration with a sintered metal phase separator for geologic hydrogen production in accordance with certain embodiments of the present disclosure.DETAILED DESCRIPTION

[0016] Geologic hydrogen can be produced when water contacts iron-rich subsurface rock formations in a process known as serpentinization, which can generate hydrogen in situ at depth under elevated temperature and pressure. Unlike hydrogen produced via steam methane reforming or electrolysis, geologic hydrogen is generated without combustion or electrical input, presenting a potentially low-cost, low-emissions pathway to hydrogen production at scale. However, realizing this potential requires overcoming multiple cost barriers resulting from the subsurface nature of the resource. Large bodies of suitable iron-rich source rock are capable of delivering hydrogen at predictable rates for decades, enabling the long-term capital investment required for commercial-scale production.

[0017] Of considerable interest is the cost of compressing hydrogen from the pressure at which it is produced to a level compatible with shipping it by pipeline, or tube carrier, to a consumer. The cost of compressing one ton of hydrogen gas at room temperature from atmospheric pressure to a typical tube carrier pressure of 500 bar, for example, may be approximately $1,000, or $l / kg. This is a substantial fraction of the cost of producing one kilogram of hydrogen via steam methane reforming, the presently predominant technology. Conventional production approaches fully depressurize the produced fluid to recover hydrogen as a gas at or near atmospheric pressure, after which the hydrogen must be recompressed to pressures suitable for downstream use — discarding pressure energy that was inherently present in the subsurface system and need not have been lost.

[0018] Of further interest is the cost of extracting produced hydrogen from the water or brine in which it is dissolved. At production depths, the pressure at the bottom of a hydrogen well filled with water can be more than 5-10 MPa. The saturation concentration of dissolved hydrogen at these pressures can be on the order of 50 mmol / liter, or approximately 104liters ofAty. Docket No.: GEG-004PCT-8022-00501water per kilogram of hydrogen. Therefore, to extract one ton of hydrogen per day from a single well requires a process capable of handling at least 107liters of water per day, and considerably more if the water is not fully saturated. This requires substantial pumping energy. It would therefore be advantageous to employ a process that does not require lifting the water to the surface, but can instead be carried out in or at the bottom of the well, close to where the hydrogen was produced, that is, at a location where the pressure of the hydrogen is greater than atmospheric pressure.

[0019] The systems and methods disclosed herein address these various issues. Disclosed herein are methods for producing geologic hydrogen that reduce the recompression burden by conserving at least a portion of the pressure at which the geologic hydrogen is dissolved into water or brine, and that achieve separation of hydrogen from water within the well, and ideally close to the bottom of the well, thereby reducing the pumping energy required in the separation process. Rather than fully depressurizing produced fluid to the surface, the systems described herein maintain elevated pressure along the length of the well and through the surface processing loop, partially depressurizing the hydrogen-saturated fluid only to the degree necessary to desorb hydrogen as a gas. The partially degassed fluid can then be reconditioned and reinjected at high pressure for another production pass, and hydrogen can exit the system at elevated pressure (e.g., as compared to atmospheric pressure).

[0020] Additionally, the systems and methods disclosed herein actively manage the geochemical environment of the production zone. By controlling the pH of the injected aqueous liquid, the disclosed methods promote selective dissolution of iron from the rock matrix, consumption of pyroxene and other mineralogical species that would otherwise impede serpentinization, and reaction-induced fracturing of the formation driven by the approximately 30% volume increase associated with serpentinization, thereby progressively increasing the reactive surface area available for hydrogen production over the life of the well. Catalytic species naturally present in the rock matrix can further accelerate these reactions. Cycling between low-pH and high-pH operating conditions may enable hydrogen generation by two distinct mechanisms within a single well system, further improving overall yield.

[0021] A number of different well configurations are disclosed herein. For example, the well configurations can include a high pressure cased well with an active circulation loop, a two-well system comprising spatially separated injection and production wells with a developing serpentinization zone therebetween, an open well system utilizing buoyancy-driven, two-phase annular flow to deliver hydrogen preferentially to the surface, a packer well employing a sintered metal phase separator to selectively extract hydrogen at depth, and a pHAty. Docket No.: GEG-004PCT-8022-00501cycling method applicable across all well configurations. These embodiments may be implemented individually or in combination, and are each described in more detail below.

[0022] Subsurface geologic hydrogen can be produced and dissolved into brine or water at depth under elevated hydrostatic pressure. This pressure represents a valuable energy asset that can be reused or maintained in the systems and methods disclosed herein. Rather than depressurizing the produced fluid at the surface and discarding this energy, the disclosed systems can conserve the subsurface pressure throughout the production cycle, thereby reducing the recompression burden and the energy required to handle and process the large volumes of water associated with hydrogen extraction. As illustrated in FIG. 2B, large bodies of suitable iron-rich source rock are capable of delivering hydrogen at predictable production rates R(t) for significant periods of time (e.g., decades, etc.), enabling the long-term capital investment required for commercial-scale production.

[0023] Presented herein are systems and methods for the production (e.g., in situ production) of geologic hydrogen from geological environments such as subsurface rock formations. In particular, described herein is a method in which high pressure is at least partially maintained along the length of a geothermal well (an opening drilled or otherwise formed or appearing in a subsurface rock formation).

[0024] In certain embodiments, elevated pressure can be maintained along the length (e.g., the full length) of a well drilled into a subsurface rock formation. Produced hydrogen-saturated aqueous liquid (e.g., brine or water) can be cooled to suppress steam formation when pressure is partially relieved to desorb the hydrogen. For example, operating at a hydrostatic pressure of approximately 1,000 bar downhole and then reducing the pressure to a level on the order of 100 bar (e.g., approximately 100 times atmospheric pressure) recovers most of the dissolved hydrogen that the liquid may contain. The partially degassed aqueous liquid (e.g., brine or water) may then be returned to the high-pressure region of the well to absorb more hydrogen, in huff-puff or continuous circulation mode. The process is illustrated schematically in FIG. 1. As shown, an example can be used where the well is operated at illustrative conditions of Pweii = 100 MPa and Tweii = 250°C at the production zone, with the produced fluid cooled to approximately 90°C via a heat exchanger prior to expansion.

[0025] An advantage of this configuration is that the pressurization energy of the hydrogen can be substantially conserved within the system. The hydrogen-containing aqueous liquid (e.g., brine or water) is brought to the surface at high pressure and is only depressurized sufficiently to release a portion or substantial fraction of the hydrogen in the form of a gas. Pressure is then maintained on the partially degassed liquid as it is conditioned and returned toAty. Docket No.: GEG-004PCT-8022-00501the well in a cycle. The energy lost in depressurizing the hydrogen from well pressure (e.g., approximately 20 to 100 MPa) to degassing pressure (e.g., approximately 1 to 10 MPa) is only a fraction (e.g., one twentieth to one fifth, or in some aspects on the order of one-eighth) of the energy that would be lost if the gas were fully depressurized to ambient. The conserved energy therefore results in a substantial cost savings compared to the cost of compressing hydrogen from atmospheric pressure, as in steam methane reforming, electrolysis, or pyrolysis hydrogen production processes, to shipping pressures of 50 MPa or more. The collected hydrogen may be further pressurized as needed for shipping, storage, or downstream industrial use.

[0026] The quantity of hydrogen that can be dissolved into an aqueous liquid at depth is governed by the balance between the chemical potentials of hydrogen in the liquid and vapor phases, and is a function of pressure, temperature, and salinity. Understanding this relationship is useful in designing an effective geologic hydrogen production system, as it determines the concentration of hydrogen available for extraction at a given set of subsurface conditions, the volume of aqueous liquid that must be processed to recover a target quantity of hydrogen, and the degree of partial depressurization required to desorb hydrogen as a gas at the surface.

[0027] H2 solubility in pure water and aqueous NaCl solutions has been modeled by Zhu et al. (2022) across temperatures of 273.15-423.15 K and pressures of 0-1,100 bar for pure water, and across temperatures of 273.15-373.15 K, pressures of 0-230 bar, and NaCl concentrations of 0-5 mol / kg for aqueous NaCl solutions, with a mean absolute percentage error between model predictions and experimental data of less than 1.14%. The model applies the Peng-Robinson equation of state to the vapor phase and the liquid electrolyte solution theory of Pitzer to the liquid phase, and can be extended to predict H₂ solubility in complex brines including seawater containing Na+, K+, Mg2+, Ca2+, CP, and SOU.

[0028] In general, H₂ solubility increases with increasing pressure and decreases with increasing ionic strength. The temperature dependence of H2 solubility is more complex and exhibits two distinct regimes: at low pressures (below approximately 200 bar), H₂ solubility is only slightly dependent on temperature; at high pressures (above approximately 200 bar), solubility decreases and then increases with increasing temperature, with an isobaric minimum solubility occurring at approximately 320 K. and 200 bar. This non-monotonic behavior is an important consideration for site design, as it means that at production depths where pressures commonly exceed 200 bar, both temperature and pressure must be considered to determine the dissolved hydrogen carrying capacity.

[0029] The salting-out effect of dissolved ionic species further reduces H₂ solubility relative to pure water. At fixed temperature and pressure, increasing NaCl concentration fromAty. Docket No.: GEG-004PCT-8022-005010 to 5 mol / kg reduces H2 solubility by approximately 40-60% depending on the operating conditions, following a relationship consistent with the Setschenow equation and the Pitzer specific interaction theory. The model may further be applied to seawater and complex formation brines using a similar approximation approach, wherein the interaction parameters of H2 with multivalent cations (Ca2+, Mg2+) are treated as double those of the corresponding monovalent cation (Na+).

[0030] At representative production depths and temperatures, dissolved hydrogen concentration is sufficiently low relative to the mass of hydrogen sought that large volumes of aqueous liquid can be processed to recover commercially meaningful quantities, as noted in the Introduction above. The relationships described herein, together with the partial depressurization strategy disclosed herein, allow a downhole pressure operating window at which hydrogen is dissolved and the intermediate pressure to which the fluid is reduced to be determined and used to improve hydrogen recovery while conserving at least a portion of the compression energy.

[0031] The practical consequences of dissolved hydrogen transport demand and nearwell buffer saturation timing are different quantities and should not be mixed together. The practical reach on-water requirement is often screened at approximately 250 liters per kilogram of hydrogen produced, giving a make-up water estimate of approximately 0.25 m3per kilogram of hydrogen produced:Qmake ~ 0.25 m3per kg H2 producedIf hydrogen were exported only in dissolved form, the required fluid circulation would instead be governed by the dissolved hydrogen concentration in the working fluid:Qdiss = hlH2 / CH2

[0032] This dissolved-only circulation requirement can be substantially larger than the make-up water requirement because hydrogen solubility is limited and falls further as salinity rises or as hydrogen partial pressure is maintained low at the receiving end. The connected water buffer in the near-well zone is also limited in its capacity. If the connected water buffer has volume Vbuf, the dissolved hydrogen mass that can remain in that buffer at operating pressure and temperature is CH2- Vbuf, and the time to saturation of that buffer at a production rate of m_H2 is estimated as:tsat = (CH2 Vbuf) / rilH2Aty. Docket No.: GEG-004PCT-8022-00501

[0033] This relationship is the primary reason that the systems and methods disclosed herein employ separate stimulation and production clocks, as described in greater detail herein. Minute-scale pressure cycling can create connected reactive damage in the formation, but the local water buffer can still become saturated on a timescale of hours at practical production rates. The production schedule must therefore include a slower take period that removes hydrogen from the near-well buffer before the buffer remains in a fully saturated condition, preventing further hydrogen migration from the rock into the well fluid.

[0034] The illustrative water requirements and buffer saturation timing for a representative shallow- well demonstration operating at production targets of 15 and 20 kg Hz / day are set out in the following tables. These values are illustrative only and are not site-specific commitments.20 kg Production target 15 kgHz / dayHz / day 224 Average gas at surface 168 Nm3 / dayNm3 / day 5.00 Reaction water make-up at 250 L / kg Hz 3.75 m3 / daym3 / day 29.1 Minimum dissolved-only circulation, low-salinity water 21.8 m3 / daym3 / day Minimum dissolved-only circulation, approximately 3.5 67.650.7 m3 / daywt% brine m3 / day Table 1. Illustrative water requirements for a representative shallow-well demonstration.Assumed Hydrogen that can stayTime to saturation Time to saturation connected water dissolved at 275°C and 20at 15 kg / day at 20 kg / day buffer MPa3 cm active halo3.22 kg in low-salinity wateraround the well10 cm active halo5.78 kg in low-salinity water 9.3 haround the wellTable 2. Illustrative near-well buffer saturation timing for a representative shallow-well geometry.

[0035] Even a productive shallow well can saturate its local water buffer in hours, while the mechanical damage clock still runs on a period of minutes. These tables are the primary quantitative basis for the separate-clock operating scheme described herein.

[0036] In some embodiments, hydrogen-containing aqueous liquid produced from the wellbore can be processed through a surface loop designed to extract hydrogen at elevated pressure, recover thermal energy, and recondition the aqueous liquid for reinjection. TheAty. Docket No.: GEG-004PCT-8022-00501process can include cooling the produced fluid to suppress steam formation, expanding the fluid in one or more stages to desorb hydrogen as a gas, separating the hydrogen from residual water vapor, conditioning the degassed liquid for reinjection, and returning it to the well at high pressure. In some embodiments such as the system shown schematically in FIG. 1, the surface processing loop can comprise a heat exchanger 10, a first expander stage 12, a first phase separator 14, a pH adjustment station 16, a compressor 18, an H2O reservoir 20, a cooling tower 22, a high pressure H2O pump 24, a chemical conditioning unit 26, and / or a make-up H2O supply 28.

[0037] A temperature of the water or brine produced from the wellbore 2 can be reduced via the cooling tower 22 at the surface, making subsequent handling easier and safer and maintaining a low water vapor (e.g., steam) pressure. The pressure of the water can then be reduced in one or more stages via one or more pressure reducers such as expanders 12. As shown in FIG. 1, the pressure reduction can occur in an expander, such as a first expansion stage 12, thereby reducing the pressure at a ratio of approximately 2:1 to about 10:1. As an example only, the fluid can be reduced in pressure from approximately 100 MPa at approximately 90°C to approximately 20 MPa to allow the hydrogen to leave the water so that it can be collected. In some aspects, multiple degassing stages make the evolving gas volume easier to manage and may be employed to achieve a suitable operating state.

[0038] The one or more expanders 12 may be employed in the surface processing loop, with suitable types including, but not limited to throttling or Joule-Thomson expansion valves, which perform isenthalpic expansion across a fixed or adjustable orifice and are mechanically simple and well-suited to high inlet pressures, turboexpanders, which perform isentropic expansion and recover a portion of the pressure energy as shaft work that may be directed to drive the compressor 18 or the high-pressure H2O pump 24, positive-displacement expanders such as reciprocating piston, rotary vane, or screw expanders, which tolerate higher liquid fractions in the working fluid and may be preferred at early expansion stages, and staged flash vessels, in which pressure is reduced abruptly in a closed vessel to allow equilibrium degassing, and which can be used for the intermittent huff-puff operating mode as described herein. Two or more of the above types may be combined in series, with the number, type, and arrangement selected based on site-specific conditions including well pressure, fluid composition, flow rate, and target intermediate pressure.

[0039] The hydrogen released in the expander 12 can enter the phase separator 14, which can separate the steam that may be present in the hydrogen stream. The pressure of the hydrogen thus released is less than that of the well, but is still at an elevated pressure. This isAty. Docket No.: GEG-004PCT-8022-00501advantageous because it reduces the amount of energy that must be supplied via the compressor 18 to increase the pressure to a level suitable for downstream operations (e.g., a Haber-Bosch process), storage, transport, or liquefaction.

[0040] Suitable phase separator types include, but are not limited to cyclone or vortex separators, which use centrifugal force to separate the denser liquid water phase from the lighter hydrogen gas by imparting a spinning motion to the inlet stream to direct liquid to the outer wall and downward to a drain while gas exits through a central axial outlet and which are the presently preferred type referenced in the source documents, knock-out drums or gravity separators, in which the two-phase stream enters a vessel of enlarged cross-section causing the liquid phase to settle by gravity while gas exits from an upper outlet, coalescing demisters or mesh pad separators, in which entrained liquid droplets are captured by a wire mesh or fiber bed and coalesce into larger droplets that drain by gravity’, and / or membrane-based gas-liquid separators, in which a hydrophobic porous membrane preferentially passes the hydrogen gas phase while rejecting liquid water, operating on the same selective wetting principle employed by a sintered metal phase separator as described herein. Two or more separator types may be combined in series to achieve a target gas purity and liquid carryover specification. All separator components in contact with the process fluid are fabricated from materials selected for resistance to hydrogen embrittlement at the operating pressure and temperature.

[0041] The water leaving the separator, which remains at close to well pressure following expansion, can then be conditioned at the chemical conditioning unit 26 by the addition of acids or bases, surfactants, and / or catalysts. In some aspects, salinity adjustment can also be included within the chemical conditioning function, which may also include surfactants, catalysts, and other species. The temperature of the water stream may be adjusted using heat absorbed from the heat exchanger 10 or an external heat source, and its pressure can be increased using the high pressure pump 24 so that it returns to the well, effectuating thereby the pressure modulations described in the individual embodiments below. This completes a cycle in which the well pressure is cycled as noted above to repeat the hydrogen extraction process. It is noted that in this configuration it is possible to separate dissolved metals from the produced water at the surface.

[0042] The time delay between the pressurization and production phases to allow the aqueous liquid to absorb hydrogen to near saturation may range from days to weeks, depending on the permeability and reactivity of the formation. Additionally, thermal energy recovered in the heat exchanger 10 may be applied to geothermal power generation, reinjection waterAty. Docket No.: GEG-004PCT-8022-00501preheating, or other industrial processes, providing a source of co-produced energy that improves the overall energy balance of the system.

[0043] In addition to pressure management, the systems and methods disclosed herein can allow for management of the geochemical environment of the production zone. By controlling the pH of the injected aqueous liquid, the disclosed methods selectively promote iron dissolution, consumption of mineralogical species that would otherwise impede serpentinization, and reaction-induced fracturing of the formation each of which contributes to sustained and increasing hydrogen production over the life of the well. The process provides a systematic approach to geochemical stimulation that operates in concert with the pressure modulation methods described herein.

[0044] The pH may be adjusted by introducing an acid solution at an appropriate level to maintain a pH downhole that is optimal for hydrogen production. By intentionally reducing pH to a very low level (e.g., less than 3 or 4), Fe2+is caused to be leached from contacted olivine (or other Fe2+-containing minerals), thus dissolving the Fe2+into the acidic aqueous liquid (e.g., brine or water). This aqueous liquid is then transferred to the surface and reacted with water to produce hydrogen and iron oxide. This mechanism for producing hydrogen is not directly related to the self-fracturing principle associated with serpentinization of the ultramafic rock.

[0045] It is noted that the saturation concentration of Fe2+in water under typical hydrogen well conditions is a strong function of pH. For neutral pH. Fe2+solubility’ is substantially lower than that of hydrogen, and therefore the amount of water that must be lifted to the surface to yield an equivalent mass of hydrogen is substantially greater than it would be for hydrogen-saturated water. However, for pH less than approximately 5.2, the solubility of Fe2+is orders of magnitude greater. Therefore, provided that such a low pH can be tolerated by the components of the production system, under low pH conditions it may be advantageous to dissolve Fe2+in water at depth and produce it to the surface to generate hydrogen from water by reacting it in a suitable high-temperature, high-pressure vessel, or by a pH swing process. For neutral and higher pH, it is preferable to produce hydrogen at depth in the well.

[0046] In addition to its effect on iron solubility, pH management promotes two further geochemical effects of importance. First, catalytic species naturally present in the iron-rich rock matrix including transition metal species associated with olivine and accessory’ minerals are activated under appropriate pH conditions to further accelerate the serpentinization reactions. Second, as described in greater detail herein, low-pH conditions promoteAty. Docket No.: GEG-004PCT-8022-00501consumption of pyroxene, removing a mineralogical pathway that would otherwise retard the serpentinization process.

[0047] The pH management approach described above may be extended into a dynamic cycling method in which the downhole pH is alternated between low- and high values on a controlled schedule. This cycling as illustrated in FIGS. 3A-3C progressively increases the reactive surface area of the formation over time and enables hydrogen generation by two distinct mechanisms within a single well system. The pH cycling method can be applied to all of the embodiments disclosed herein.

[0048] The progressive growth of reactive surface area available for serpentinization described above may be quantified using a first-order engineering framework. The well does not become useful because the original rough wall reacts slightly faster. It becomes useful if pressure cycling creates additional larger fracture area and if each larger surface develops a thin wet halo at grain scale. The larger fracture area sets how much rock can be contacted. The grain-scale halo sets how much reactive area each larger surface carries. The original wall area is estimated from the active interval diameter and length:Ao = nDLLarger fracture area is then estimated by adding the two faces of each connected fracture to the original wall area. A practical engineering form is:Ai ~ Ao + S(2 nshsℓs) + S(2TI n a2)In this expression, nsis the number of short wall fractures of height hsand length fs, and nr is the number of larger contained fractures of radius a. The first sum accounts for short fractures attached to the wall. The second sum accounts for contained penny-shaped fractures or fracture patches away from the wall.

[0049] Each larger surface can be further multiplied by the grain-scale reactive area created in the wet reactive halo surrounding it. The grain-scale surface multiplier M_s is estimated as:Ms=65 / dgThe connected reactive area is therefore estimated as:Ar = t] Ms AfThis relationship explains why a millimeter-scale halo can create very large reactive area once the connected grain size is only tens of microns. For example, if dgis 20-50 pm and 5 is 1-10 mm, the grain-scale surface multiplier M_s is approximately 120-3,000. If only 10-30% ofAty. Docket No.: GEG-004PCT-8022-00501that halo is connected, the net multiplier is still approximately 12-900 relative to the larger fracture area itself. If grain and fragment sizes follow a power-law distribution, the smallest connected size controls the upper bound on local surface-to-volume ratio, approximately 6 / d_min. The practical meaning is that once grain splitting and fine fragment production begin, the smallest connected fragments dominate local reactive area, provided they remain hydraulically connected.Wet halo Grain-scale surface multiplier for Net multiplier if 10-30% of the thickness 20-50 pm grains halo is connected1 mm 120-300x 12-90x3 mm 360-900 x 36-270 x10 mm 1, 200-3, 000x 120-900xTable 3. Illustrative halo multipliers for connected grains of 20-50 pm.

[0050] A first estimate of local halo permeability may be obtained by treating the connected grain boundaries as many parallel thin slots. For such slots, permeability rises strongly with aperture. A compact engineering estimate is:kh= b3 / (12s)where kh is local halo permeability, b is hydraulic aperture of the connected grain-boundary pathways or micro-cracks, and s is the spacing between the pathways. This estimate describes the local halo permeability, not the whole-well transmissivity. Whole-well injectivity rises more slowly because only part of the active interval becomes connected early in the stimulation program. In field terms, the important measurable result is typically a 2-10x rise in injectivity or pressure-volume compliance, not a direct measurement of kh itself.Local k h if spacing is Local k h if spacing is 50 Hydraulic aperture20 pm pm50 nm 5.21 x 10-19m22.08 x 10-19m2100 nm 4.17 x 10-18m21.67 x 10-18m2500 nm 5.21 x 10~16m22.08 x 10~16m21.0 pm 4.17 x 10-15m21.67 x 10-15m2Table 4. Illustrative local halo permeability values for grain-boundary pathways.

[0051] Two hydrogen rate baseline cases are useful for field planning. The strict lower baseline allows reaction only on the rough well wall. The second baseline allows a very thin cracked zone next to the wall to react and shed small grains even without meaningful cyclic damage growth. These baselines matter because they tell the operator what would happen without a true connected damage network. For a time step At, the wall-only case is estimated as:Atty. Docket No.: GEG-004PCT-8022-00501mm, wall ~ Ao xrYH2, with xr= (dg / 2)(At / tr) where xris the one-sided reaction depth over time step At. The second baseline replaces Ao Xr with a thin, weakly connected shell volume. Once a larger connected halo exists, the estimate becomes simpler and more transparent:mm ~ Vr YH2 (At / tr), where Vr = r|5Af

[0052] This form states that hydrogen production over a time step is proportional to the connected reacting rock volume and inversely proportional to the full reaction time of a fully wetted grain or fragment at the chosen chemistry and temperature. Published w ork on olivine serpentinization suggests that fully wetted 20-50 pm grains react on a month timescale, not a day timescale, even near 275-280°C. That is why surface area growth and water access matter so much, and why the systems and methods disclosed herein focus on maximizing connected reactive volume rather than simply maximizing formation contact pressure.

[0053] As shown in FIG. 3, the AWE process operates through the following sequence of mechanisms. First, stress from stimulation including both pressure modulation (AP) and thermal cycling (AT) can loosen grain boundaries between mineral grains and create microfractures. Second, these grain boundary openings and microfractures connect to form permeable pathways through the formation, increasing the effective permeability and enabling water access to previously unreacted mineral surfaces. Third, water reacts with the iron-rich rock via serpentinization, producing serpentinite, hydrogen, and heat with the serpentinization reaction accompanied by a volume increase of approximately 30%, which generates crystallization pressures sufficient to fracture the surrounding rock matrix. Fourth, this reaction-induced fracturing increases the reactive surface area of the formation exponentially over successive cycles. Fifth, production rate grows as the serpentinization front advances until the available iron-rich rock in the stimulated volume is consumed. Sixth, the rate of progress is accelerated by optimizing brine circulation, pH, salinity, and chemistry of the injected fluid. Seventh, catalytic species naturally present in the rock are used to further accelerate the reactions. Eighth, a mathematical model for optimal fracture growth and hydrogen production may be applied to determine the optimal stimulation parameters at a given site.

[0054] It is further noted that at low pH, any pyroxene contained in the contacted deposit is converted to other minerals and thereby consumed, thereby removing a parasitic pathway that would otherwise retard the serpentinization process and associated production of hydrogen by that means. When the pyroxene is consumed in this way, serpentinization isAty. Docket No.: GEG-004PCT-8022-00501favored provided that the pH is in the right range (slightly alkaline), and both the production of hydrogen and the associated reaction-induced fracturing mechanisms ensue. Thus, by alternately cycling the pH downhole between low and high levels, the deposit is caused to progressively weather dissolving and fracturing with ever-increasing surface area with hydrogen produced both in the acid phase of the cycle through dissolution, and in the alkaline phase of the cycle through self-fracturing. This process can proceed to rapidly consume even deposits containing substantial pyroxene, as well as those that do not contain substantial pyroxene.

[0055] The mineralogical progression associated with the process illustrated in FIG. 3, which presents photomicrographic images of the rock matrix at representative stages of stimulation. FIG. 3A shows the initial unaltered ultramafic rock, comprising olivine (01), plagioclase (Pl), and clinopyroxene (Cpx), with a characteristic grain size on the order of 500 pm. FIG. 3B shows the development of microfractures at grain boundaries following initial stimulation. FIG. 3C shows the development of two distinct vein types: type 1 veins and type 2 veins. As serpentinization progresses, with magnetite (Mag) and serpentine (Srp) phases developing along the vein network, and plagioclase (Pl) remaining as a residual phase. The progressive development of this hierarchical vein and fracture network from the sub-grain scale (microns) through the formation scale (hundreds of meters) provides the continuously increasing water-rock contact area that sustains and grows hydrogen production rates over the life of the well.

[0056] The pH cycling method thereby provides a means of geochemical stimulation that complements the mechanical stimulation approaches described in the individual embodiments below. By combining pressure modulation, geochemical control, and pH cycling as embodied in the AWE process, the disclosed systems are capable of sustaining and increasing hydrogen production rates over time in a manner that is not achievable through pressure management alone.

[0057] Returning to FIG. 4, geologic hydrogen can be produced in some aspects from a cased well in which pressure is actively managed through a closed circulation loop. The well can be cased and the casing perforated in one or many places to allow water to fracture and enter the surrounding rock by increasing the pressure via a pump. Hydrogen-saturated aqueous liquid produced from the fractured formation is brought to the surface at elevated pressure, partially depressurized to release hydrogen gas, and reconditioned for reinjection. This configuration allows repeated injection-soak-production cycles that progressively stimulate the formation while conserving the pressure energy inherent in the system. The embodimentAty. Docket No.: GEG-004PCT-8022-00501further encompasses multi-perforation and multi-well architectures, a two-well separated injector / producer configuration, and cold shock injection techniques, each described in detail below.

[0058] In some embodiments, the wellbore 30 may be cased substantially to the bottom. The metal used to provide this casing may optionally be selected to be resistant to hydrogen embrittlement in order to extend its service life. The casing can be perforated at perforations in one or many places to allow water to fracture and enter the surrounding rock by increasing the pressure via a pump.

[0059] The well can be capped and attached in a leak-free manner to the casing via wellhead cap 38. A water fill pipe, e.g., the injector 34, can be provided to introduce pressurized water to the bottom of the well, including both fresh water as well as water that may be recovered from the well as described above in the course of producing hydrogen to the surface. A second pipe, the producer 36, can be included that extends a short distance into (e.g., zero to several inches) the well where hydrogen gas (and other gases including steam and impurity gases) are expected to accumulate. The producer 36 can pass from the well through the cap 38 and be further connected to an adjustable valve, or impedance 40, that is adjusted to maintain pressure in the well. Since the well will typically be filled, or partially filled with water, the pressure close to the top of the well will be less by the hydrostatic head than the pressure at the bottom. The pressure is modulated at one or more frequencies via the injector pipe 34 pressure in a range of from 0 up to 100 MPa.

[0060] In certain embodiments, completion design practices developed for high-temperature thermal wells — including steam-assisted gravity drainage (SAGD) and high-temperature geothermal wells — provide a useful reference for the casing, packer, and wellhead hardware selections described herein. SAGD uses an upper horizontal well to inject steam and a lower horizontal well to produce heated bitumen, with a severe thermal completion challenge: casing, cement, packers, wellheads, control lines, and instrumentation all have to survive repeated high-temperature cycling. That makes SAGD and high- temperature geothermal practice useful references for completion design in the systems and methods disclosed herein. What should be borrowed from such practice is the thermal-completion philosophy, not the reservoir geometry. The systems and methods disclosed herein do not require a copy of a SAGD well pair. Rather, what is needed is reliable high-temperature hardware suitable for an isolated active interval in ultramafic rock. The selective use of SAGD and geothermal completion practice is summarized in the following table.Aty. Docket No.: GEG-004PCT-8022-00501What should not be copied Practice area What is worth borrowingdirectly Thermal-rated casing connections,Do not let the need for thermal Casing, cement, resilient cement, high-temperatureintegrity drive the design toward a packers, and packers, feedthroughs, and stagedlong SAGD-style horizontal pair if wellhead integrity testing are directlythe reservoir objective is different. relevant.High-temperature gauges, protected Do not assume steam-chamber Instrumentation capillaries, gradual heat-up, and operating rules are the right and commissioning disciplined commissioning are reservoir rules for an ultramafic directly relevant. hydrogen well.A slotted liner through the active A cased section above the active interval is often the wrong choice Completioninterval with robust thermal where the design requires direct geometry hardware is useful. hydraulic contact with the reacting rock.Do not use the cost of a long Thermal-well practice is a usefuldirectional SAGD pair as the base Cost benchmarking warning that premium high- estimate for a short shallow temperature hardware is not free.demonstration well.Table 5. Selective use of SAGD and geothermal completion practice.

[0061] In summary: SAGD and geothermal completion practice serves as a completion manual for the hardware selections described herein, not as a reservoir manual.

[0062] Further services may be introduced to the well via the cap 38 via leak-free feedthroughs, including wiring for instruments that may include a variety of sensors, including pressure, pH, gas composition, and temperature sensors. Other services may include heater cables, water fill pipes, water removal pipes, pressure relief valves, and liquid level sensors.

[0063] In FIG. 4, water can be injected via the smaller-diameter injector pipe 34 into the fractured formation 44. The water is returned to the surface via the larger-diameter casing 30. It should be appreciated that the opposite flow is possible, with water injected via the larger-diameter casing 30 and returned via the smaller-diameter injector pipe 34. The latter may be advantageous because it can provide a lower-impedance pathway for high-flow water injection with a suitable choice of inner pipe diameter.

[0064] Pressurized hydrogen containing water can be removed from the well via the producer pipe and impedance, passing through a heat exchanger that reduces the temperature to below the boiling point. The recovered heat may be released to the atmosphere, or used for a variety of purposes, including heating water subsequently injected via the injector pipe or a separate fill pipe, or to provide useful heat to an electricity generator or industrial process. AnyAtty. Docket No.: GEG-004PCT-8022-00501water vapor condensing in the hydrogen-rich line exiting the heat exchanger can be removed via a downstream phase separator, and returned to the well water supply for reuse.

[0065] In some aspects, the liquid in the well can be further externally pressurized with a pump to achieve a pressure at, or preferably below, the fracturing level, S_tensile + S_min, in order to maintain the fractures in the open condition. The pressure is modulated at one or more frequencies to drive water into the fractures, break down the rock, and increase the volume of water in contact with the formation. The well is then allowed to soak for a period of hours to months to take on dissolved hydrogen released by the serpentinization reactions in the fractured rock. The pressure can then be slightly reduced by reducing the pump pressure slightly below S_tensile + S_min to expel some of the water from the fractures, thereby ejecting hydrogen-saturated water to the surface via the well. The inject-soak-eject cycle may be regarded as a low-frequency modulation of the pressure that is superimposed upon the higher-frequency modulation employed to break down the rock.

[0066] The time delay between the pressurization and production phases — to allow the aqueous liquid to absorb hydrogen to near saturation — may range from days to weeks, depending on the permeability and reactivity of the formation. After a suitable soak time, hydrogen generated by the reaction between the water and iron-rich rock partially or fully saturates the water, and the cycle described above in which the water is allowed to flow to the surface and the hydrogen removed is repeated many times.

[0067] In certain embodiments, the composite pressure signal described above may be structured as a set of three distinct operating clocks or timeframes, each addressing a different physical timescale. The well should not attempt to create hydrogen, release hydrogen, and reset chemistry on the same short cycle. The physics happens on different timescales: a short clock creates new surface area, a slower clock takes hydrogen out before the local water buffer saturates, and a still slower clock restores chemistry and updates the diagnostics. These three clocks are described in the following table.Clock Typical period Purpose How it is controlled Use downhole Cycle near approximately 0.7-0.8 ofpressure, injectivity, local breakdown pressure with aDamage, pressure-volume,, ° 10-15 minutes small positive mean pressure so newclock response, and surface area and permeabilitycontainment continue to grow.diagnostics.Start-up Approximately 4 A practical early pattern isUse gas rate, water make-take hours, repeated approximately 3 h make plus 1 hunloading, and theclock through the day take. This prevents the local waterAty. Docket No.: GEG-004PCT-8022-00501Clock Typical period Purpose How it is controlled buffer from remaining saturated measured gas-entry while the damage zone is still threshold. growing.Use stable gas rate, A practical later pattern isSteady Approximately 6-8 stable injectivity, and approximately 4-6 h make plus 2 hmake-take hours once the gas no sign that dissolved take. This reduces switching lossesclock path is stable hydrogen is building after a stable gas path exists.up.Use month-to-month Controlled depressurization, flush,Reset Approximately 1-2 drift in gas rate,tracer update, and a short diagnosticclock days each month injectivity, andoscillation.connected volume.Table 6. The three operating clocks used in single-well make-take operation.

[0068] The formation acts as a distributed flash valve in this operating mode. During the make part of the cycle, hydrogen is generated and partly dissolves in the hot brine near the rock. During the take part, local pressure is lowered enough that hydrogen can leave solution, cross the entry threshold of water-wet throats, and move into the nearby receiving space. The take clock is therefore controlled by the observed gas-entry threshold of the formation, not by surface pressure alone. A practical pressure step-down test run early in the life of the well — in which pressure is reduced in increments and gas response is monitored at the surface or downhole — can be used to identify the gas-entry threshold and calibrate the take clock accordingly.

[0069] Table 7 below sets out simple field criteria for judging whether the make-take concept is turning on during early well operation.Observed early response Likely meaning What to do next Re-check amplitude, Hydrogen stays near the passive No meaningful connecteddownhole pressure baseline and injectivity rises by damage network has yetcalibration, and chemistry less than approximately 1.5x. formed.before extending the test. Hydrogen rises well above the The damaged zone isContinue the growth phase passive baseline and injectivity becoming connected, butand re-test after a reset. rises by approximately 2-3 x. scale-up is not yet proven.Hydrogen rises by orders of The interval is likelymagnitude above the passive creating both larger Advance to production-style baseline and injectivity rises by fracture starters and an make-take operation. approximately 3-1 Ox. active halo.A larger connectedHydrogen remains elevated afterreactive volume is present This is the kind of response refresh and the response israther than a single shortthat supports scale-up. distributed over depth.lived gas show.Table 7. Simple field criteria for judging whether the make-take concept is turning on.Atty. Docket No.: GEG-004PCT-8022-00501

[0070] In certain embodiments, the composite pressure signal applied to the formation comprises multiple superimposed frequency components, each performing a distinct function at a different length scale and timescale. A first, lower-frequency component controls fluid exchange between the wellbore and the formation on a timescale governed by the volume of fluid that pumps can deliver and extract, typically with a period on the order of hours to weeks. A second, higher-frequency component applies cyclic stress to weather and mechanically weaken the rock matrix at shorter length scales, with a period on the order of seconds to hours. The combined effect of these components enables simultaneous and independent control of fluid circulation and formation stimulation. The relative amplitudes, frequencies, and phases of the components may be adjusted over time in response to measured hydrogen production rates, formation pressure responses, and chemical composition of produced fluids.

[0071] In some embodiments such as illustrated in FIG. 2B, the injection and production functions can be performed by spatially separated wells rather than a single well. An injection well 46 and a production well 48 can be drilled into an olivine-bearing ultramafic rock formation and positioned such that the pressurized aqueous liquid injected via the injection well 46 contacts the formation and drives the serpentinization front progressively through the rock toward the production well 48. A zone of serpentinized rock 50 develops between the two wells over time, with hydrogen generated throughout this zone dissolving into the formation water and migrating toward the production well 48 under the combined influence of the hydrostatic pressure gradient and the buoyancy of dissolved and exsolved hydrogen.

[0072] As illustrated in FIG. 2B, large bodies of source rock contacted by this two-well configuration can deliver hydrogen at predictable production rates R(t) for decades, enabling the long-term capital investment required for commercial-scale production — in contrast to natural hydrogen reservoir systems in which rapidly decreasing pressure results in productive lifetimes far shorter than depreciation, as illustrated in FIG. 2A.

[0073] The two-well configuration offers several advantages relative to the single-well huff-puff configuration. First, injection and production may proceed simultaneously and continuously without interruption for soak periods, providing a substantially continuous hydrogen output from the production well 48. Second, the spatial separation between the injection well 46 and production well 48 allows the serpentinization front and the associated zone of elevated hydrogen partial pressure to develop over a larger formation volume, increasing the total reactive surface area available at any given time. Third, the two-well configuration enables independent optimization of the injection and production pressure profiles, which may be controlled independently via separate surface equipment trains.Aty. Docket No.: GEG-004PCT-8022-00501

[0074] In certain embodiments, the pH of the aqueous liquid injected via injection well 46 may be independently controlled from that of the fluid produced at production well 48, enabling the pH cycling method to be implemented in a spatially separated manner across the formation.

[0075] In some aspects, increasing the rate of geologic hydrogen production may be achieved using a plurality of vertically separated small fractures made via perforations along the length of the well, with or without zonal isolation at the surface. This is advantageous relative to using a single large hydrofracture because the area of contact between the rock and water is much greater per unit volume of rock, and the region of the fracture far from the well may not efficiently exchange water with the well, such that hydrogen produced there is not efficiently transported to the well and from there to the surface. In certain embodiments, the regions with optimal source rocks may be small in extent and may be better accessed via multiple fractures from one well.

[0076] The plurality of perforations may be designed to target specific depth intervals having favorable mineralogy, for example, intervals with higher olivine content or more favorable temperature and pressure conditions for serpentinization. In certain embodiments, each perforated interval may be independently isolated by packers to allow zonal pressure control and independent stimulation of different formation intervals.

[0077] In certain embodiments, many identical isolatable wells on a common pad share above-ground pumping and separator equipment such as any of the equipment illustrated in FIG. 1 in order to reduce cost and enable a very large rate of production. In certain embodiments, multiple wells at a given site are operated such that certain wells are being fractured while others are being used for hydrogen production and harvesting. This non-serial approach allows the energy generated by the exothermic serpentinization reaction and the stresses resulting from volume changes in one set of wells to beneficially influence the fracture network in adjacent wells, and allows production to be maintained continuously at the site level without waiting for any individual well to be fully developed. The fracturing and production sequence of the multiple wells at a site may be managed at the well pad level rather than on a per-well basis, with the timing and location of successive fracture stages determined by monitoring hydrogen production rates, formation pressure responses, and brine salinity across all wells simultaneously.

[0078] In certain embodiments, the injected water used during the repressurization portion of each cycle creates a cold shock, thereby accelerating fracturing from temperature and stress changes, and also desorbing hydrogen to accelerate upward flow. It should be notedAty. Docket No.: GEG-004PCT-8022-00501that this thermal shock may occur on multiple length scales, for example, a short length scale corresponding to the size of the mineral grains comprising the rock (microns to millimeters), and a longer length scale corresponding to thermal diffusion in the formation (centimeters to meters).

[0079] At the grain scale, differential thermal contraction between mineral grains of different elastic moduli and thermal expansion coefficients — driven by the introduction of cooler water — loosens grain boundaries, increasing local permeability and promoting access of fresh water to unreacted mineral surfaces, consistent with the grain-boundary loosening mechanism described with respect to the process illustrated in FIGS. 3A-3C. At the formation scale, the thermal shock superimposes a cyclic thermal stress on the existing mechanical pressure modulation, accelerating the growth of the fracture network and improving connectivity between the well and the reactive formation volume. The cold shock may be timed to coincide with the repressurization phase of the inject-soak-eject cycle to maximize its contribution to both fracture propagation and hydrogen desorption.

[0080] Returning to the embodiment illustrated in FIG. 4, geologic hydrogen can be produced from a capped well in which hydrogen preferentially migrates to the surface by buoyancy-driven in some aspects. In this embodiment, two-phase annular flow, substantially without the need to actively circulate the water column along with it can occur. The main benefit of this embodiment is that the expansion of hydrogen bubbles forming and ascending in the well preferentially delivers hydrogen to the top of the well substantially without the need to circulate the water along with it. The well is not connected to an active high-pressure circulation loop. Instead, hydrogen bubbles formed at depth rise through the water column under their own buoyancy, expanding as the hydrostatic pressure decreases along the fluid column, and are collected at the wellhead at elevated pressure via an adjustable pressure valve. This approach eliminates the pumping energy associated with circulating large volumes of water to the surface and provides a mechanically simpler alternative to other embodiments where formation conditions support it.

[0081] The hydrothermal well of this embodiment functions as an effective hydrogen pump, utilizing geothermal energy at depth to drive advective transport of hydrogen to the surface. By transitioning from a static capped state to a managed annular flow regime, the output can be increased to commercial scales. For example, the output can increase from zero to industrial scales exceeding 1,600 metric tons per year for a representative 4-inch bore well at 250°C in some aspects.Atty. DocketNo.: GEG-004PCT-8022-00501

[0082] The system can be defined by a vertical borehole 30 of depth L filled with water, where the bottom of the well can be maintained at an elevated temperature by the geothermal gradient of the formation. As shown in FIG. 4, the well comprises a hydrogen-resistant well casing 30 extending substantially to the bottom of the wellbore, with the lower portion of the wellbore defining an active zone 44 in which water contacts the iron-rich rock formation and hydrogen is generated by serpentinization. The metal used to provide the casing 30 may optionally be selected to be resistant to hydrogen embrittlement in order to extend its service life.

[0083] A hydrogen source at depth such as the serpentinization reaction between water and iron-rich rock can ensure that the water at the base of the well remains in, or approaches, chemical potential equilibrium with dissolved hydrogen at all times. At the bottom boundary (z = L), the temperature can be maintained at Tbot by the geothermal gradient of the formation, and a substantially limitless H2source ensures the water remains at saturation at all times. At the top boundary (z = 0), the well is initially at atmospheric conditions (approximately 20°C, 101.3 kPa), and the adjustable pressure valve 40 is present at the wellhead to regulate flow to downstream surface equipment.

[0084] The wellhead cap 38 is attached to the casing 30 in a sealed, leak-free manner. A producer pipe 36 extends a short distance into the upper portion of the well and into the gas-filled headspace 72. where hydrogen gas and steam accumulate, and passes through the wellhead cap 38 to the adjustable pressure valve 40 at the surface. A water fill pipe and injector 34 is provided to introduce replenishment water to the bottom of the well, replacing water lost to the surface as steam or vapor and maintaining a substantially constant liquid head. A narrow internal replenishment pipe 34 sustains hydraulic continuity within the well, preventing dryout of the water column. The well is filled with brine or water 76 throughout its length, with the gas-filled headspace 72 accumulating at the top of the well beneath the wellhead cap 38.

[0085] In steady-state conduction-convection equilibrium, the temperature profile T(z) along the well, where z is the depth along the axis of the wellbore measured from the surface, is modeled as a linear gradient, assuming substantially constant thermal conductivity of the water column:T(z) = Ttop+ 0.20 + 0.328z

[0086] The pressure at depth z is the sum of atmospheric pressure and the integrated weight of the fluid column. Because the density of water pwis strongly dependent onAtty. DocketNo.: GEG-004PCT-8022-00501temperature, the density variation along the fluid column must be accounted for in computing the pressure profile, with water density dropping from approximately 998 kg / m3at 20°C to approximately 800 kg / m3at 250°C:P(z) = Patmlm+ r p^THTigd?Jo

[0087] Using a mean density p ~ 900 kg / m3for the 700 m water column, the total hydrostatic pressure at the base of the well is:P(700) 101,325 + (900 x 9.81 X 700) w 6.28 MPa ( 62 alm)

[0088] The pressure profile established by the hydrostatic column determines the dissolved hydrogen concentration profile along the well via Henry's Law, as described in the following section.

[0089] The concentration of dissolved hydrogen CH at the base of the well is governed by Henry's Law: C = KH(T) PH2, where KH(T) is the temperature-dependent Henry's Law constant for hydrogen in water and PH2is the partial pressure of hydrogen at that depth. At 250 °C, KH for H2 is higher than at ambient conditions due to the non-polar nature of the solute in high-energy solvent states. The estimated dissolved hydrogen concentration at the base of the well at 250°C and 6.28 MPa is approximately 0.1 g H2 per kilogram of water.

[0090] As fluid rises through the well, the decreasing hydrostatic pressure causes the equilibrium dissolved hydrogen concentration to decrease, driving hydrogen out of solution as bubbles, a process known as exsolution. The exsolved hydrogen forms a gas phase that is carried upward by buoyancy.

[0091] In the absence of convective flow, dissolved hydrogen would migrate toward the surface by molecular diffusion alone, governed by Fick's Law: J = -DVC, where D is the molecular diffusivity of hydrogen in water, approximately 5 x 10-9m2 / s at elevated temperature. The theoretical diffusion-limited hydrogen flux for the representative well is:~ 8.3 × 10-xkg / hr

[0092] This diffusion-limited flux is entirely inadequate for commercial hydrogen production and demonstrates that buoyancy-driven advection, not molecular diffusion, is theAty. Docket No.: GEG-004PCT-8022-00501operative transport mechanism in this embodiment. The hydrostatic pressure drop experienced by rising fluid causes H2 exsolution and bubble nucleation throughout the water column. The buoyancy of these bubbles drives an advective gas-lift effect in which the rising gas phase entrains and accelerates the surrounding liquid, transitioning the system from a diffusion-limited regime to a buoyancy-driven advective regime many orders of magnitude more productive.

[0093] The system exhibits three distinct operational regimes depending on the boundary condition imposed at the wellhead via adjustable pressure valve 40. Each is described below.

[0094] Under open atmospheric conditions at adjustable pressure valve 40, the well behaves as a natural siphon. As hydrogen bubbles nucleate at depth in the active zone 44 and rise through the brine / water column 76, they expand in inverse proportion to the local pressure. For example, a bubble nucleated at the base of the well at approximately 6.28 MPa expands approximately 60-fold before reaching the surface as pressure decreases to atmospheric. At depths where the local pressure P(z) falls below the saturation vapor pressure of water at the local temperature Psat,H2O(T), water flashes to steam, drastically increasing the void fraction a and the upward driving force. In a 4-inch diameter well at the representative conditions, the resulting buoyancy-driven upward velocity of approximately 0.5 m / s carries approximately 11.5 kg / hr of H2 to the surface.

[0095] In certain embodiments, this open-atmospheric operating mode may be used as an initial characterization and startup mode to establish baseline hydrogen production rates and thermal conditions before transitioning to a capped or optimized extraction regime.

[0096] When the adjustable pressure valve 40 is closed, the well acts as a refluxing heat pipe. Steam and hydrogen produced at depth rise to the wellhead and accumulate in the gas-filled headspace 72, while condensed water returns to the brine / water column 76. The total headspace pressure stabilizes at approximately the bottom saturation pressure (e.g, approximately 6.3 MPa in the present example). At the top of the well, the headspace contains a gas mixture in which the partial pressure of hydrogen PH2~ 6.2 MPa and the vapor pressure of water Pvapor~ 0.1 MPa at approximately 100 °C, such that the headspace gas phase is approximately 98.4% H2 by mole. These values are exemplary only and can vary’ based on the actual wellbore and operating parameters.

[0097] The capped static regime demonstrates that the well is capable of sustaining a nearly pure hydrogen atmosphere at its headspace at substantially elevated pressure. ThisAtty. DocketNo.: GEG-004PCT-8022-00501provides the thermodynamic basis for the optimized extraction regime described below, and confirms that the pressure driving force for hydrogen delivery to the surface is inherent to the well system and does not require external mechanical energy input.

[0098] The commercially operating mode can be achieved by managing the adjustable pressure valve 40 to maintain a high-velocity gas core flow in the annular flow regime, maximizing hydrogen throughput while maintaining the driving force for exsolution throughout the water column. In this regime, hydrogen gas forms a continuous annular core flowing upward at high velocity through the wellbore 30, while liquid water occupies the annular periphery, and replenishment water descends through the narrow internal replenishment pipe 34 to maintain liquid head.

[0099] The target gas velocity and managed separation pressure at the wellhead can be selected to: (i) maintain the annular flow regime and avoid slug or chum flow transitions that would reduce efficiency, (ii) provide sufficient kinetic energy for effective cyclone separation of entrained water at phase separator 78; (iii) elevate the effective steam boiling point at the separator to facilitate heat exchange at heat exchanger 10, and / or (iv) preserve a sufficient hydrostatic driving force for hydrogen exsolution throughout the water column. For the example of a representative 4-inch well at 250 °C, a target gas velocity vg= 25 m / s and managed separation pressure of 0.5 MPa at the wellhead can satisfy all four requirements at the same time.

[0100] The hydrogen mass flux in the annular flow regime is governed by the cross-sectional area of the wellbore, the target gas velocity, the void fraction, and the density of hydrogen at the managed separation pressure and temperature. For the example of a representative 4-inch well, A = 0.0081 m2, and at 0.5 MPa and approximately 100°C, ρH2≈ 0.32 kg / m3:ṁH2= A × vg× ρH2(P, T) × αH2= 0.0081 × 25 × 0.32 × 0.8 = 0.0518 kg / sThis can equate to about 186 kg / hr or 1,630 metric tons per year.

[0101] As shown in FIG. 4, the resulting extraction process can use the adjustable pressure valve 40 at the wellhead to regulate flow from the producer pipe 36 and maintain the target extraction backpressure within the well. Hydrogen-saturated gas exiting through adjustable pressure valve 40 passes through heat exchanger 10, which condenses steamAty. Docket No.: GEG-004PCT-8022-00501entrained in the produced hydrogen stream, reduces the temperature of the gas stream, and recovers thermal energy. The recovered heat may be released to the atmosphere or used for a variety of purposes, including heating water subsequently injected via replenishment pipe 34 or water return pipe 80, or to provide useful heat to an electricity generator or industrial process. Any water vapor condensing in the hydrogen-rich line exiting heat exchanger 10 is removed via phase separator 78. including any of the phase separators described herein such as a vortex or cyclone type separator, and returned to the well water supply via water return line 80 for reuse as replenishment water.

[0102] The purified hydrogen stream exiting the phase separator 78 can be stored in pressurized hydrogen storage vessel 82. Replenishment water is supplied from H2O reservoir 20 and delivered to the bottom of the well via replenishment pipe 74 by pump 84, at a flow rate sufficient to replace water lost as steam or vapor at the surface and to maintain a substantially constant liquid head in the brine / water column 76, thereby preventing dry-out of the water column.

[0103] To separate the hydrogen stream, the steam fraction of the produced gas can be condensed at the surface heat exchanger 10 and the phase separator 78. For the example of a representative 4-inch bore, 700 m well at the stated conditions: steam mass flow rate entering the surface equipment: approximately 350 kg / hr, condensation thermal load at heat exchanger 10: Q = ṁsteam• hfg~ 220 kW, and replenishment water flow rate required through replenishment pipe 34 to prevent dry-out: approximately 0.35 m³ / hr

[0104] The surface heat exchanger 10 and the pump 84 sizing must account for these values. The recovered condensation heat of approximately 220 kW may be applied to preheating of replenishment water, geothermal power generation, or other industrial purposes, consistent with the co-production principles described herein.

[0105] In some embodiments, the hydrogen yield of the annular flow regime scales with the cross-sectional area of the wellbore, and therefore with the square of the bore diameter, enabling substantial increases in production rate through selection of a larger bore diameter. Multiple open wells on a common pad may share surface processing equipment such as the heat exchanger 10, the phase separator 78, the hydrogen storage vessel 82, the H2O reservoir 20, and / or the pump 84, consistent with the multi-well pad architecture described herein, enabling large-scale production while reducing per-well capital cost. Computed hydrogen yield values for a range of representative bore diameters at the conditions of this embodiment are presented in Table 8 below.Atty. DocketNo.: GEG-004PCT-8022-00501Diameter (in) Area (m2) Flux (kg / hr) Flux (Metric Tons / Year)1" 0.0005 11.6 1022" 0,0020 46.5 4074" 0.0081 186.0 1,6306" 0.0182 418.5 3,6668” 0.0324 744.0 6,51710" 0.0507 1162.5 10,183Table 8. Extraction Yield vs. Well Diameter

[0106] A benefit of the open well embodiment is that the expansion of hydrogen bubbles forming and ascending in the well preferentially delivers hydrogen to the top of the well substantially without the need to circulate the water along with it. This eliminates the large pumping energy requirement associated with circulating the full water column to the surface, substantially reduces surface infrastructure requirements relative to other configurations, and delivers hydrogen at elevated pressure at the wellhead, thereby conserving the compression energy inherent in the subsurface system in a manner consistent with the general principles described herein.

[0107] The open well embodiment is distinguished from the embodiment of FIG. 1 in that it does not require an active high-pressure circulation pump to drive fluid exchange between the wellbore and the formation. The geothermal energy input at depth, maintained at Tbot by the natural thermal gradient of the formation, provides the driving force for both the serpentinization reaction and the buoyancy-driven advective transport of hydrogen to the surface. The system is therefore self-energizing once the serpentinization reaction is established, requiring only the relatively modest energy inputs of the replenishment pump 84 and the adjustable pressure valve 40 control system for sustained operation.

[0108] In another embodiment illustrated in FIG. 5, geologic hydrogen can be produced from a well in which a mechanical packer isolates a lower hydrogen-producing zone from the upper conduit section of the well, and a phase separator such as a sintered metal phase separator positioned within the isolated zone selectively extracts hydrogen at depth can deliver it to the surface substantially without lifting the surrounding water column. This embodiment likewise provides preferential hydrogen delivery to the surface by means of introducing a packer into the well above the depth at which hydrogen is formed.Atty. Docket No.: GEG-004PCT-8022-00501

[0109] In principle, it would be possible to produce hydrogen formed below the packer by means of a pipe extending from the hydrogen-producing space to the top of the well. However, because the pipe would necessarily be smaller in diameter than the well, the flow of hydrogen-rich water to the surface would be greatly reduced in comparison to the open well embodiment described herein, due to the impedance of the tube. Thus, the rate of hydrogen production would also be greatly reduced. Therefore, in this embodiment, the space below the packer contains a phase separating device connected to the exit pipe that substantially impedes the flow of water into the tube while favoring the flow of hydrogen. Thus, hydrogen preferentially enters the pipe and is produced to the surface at a much higher rate than it would be if it remained dissolved in the water.

[0110] The central design philosophy of this embodiment is to treat the hydrogen-saturated water not as a fluid to be lifted to the surface, but as a high-pressure solvent from which hydrogen, the dissolved solute, is stripped in situ at or near the lower or bottom portion of the well. For example, the hydrogen can be stripped at approximately 600 meters below the surface in the representative example. By moving the phase separation process to depth, the embodiment eliminates the steam burden associated with open-well designs and reduces both the thermal load imposed on surface processing equipment and the surface infrastructure required for operation.

[0111] As shown in FIG. 5, the wellbore 90 is a vertical borehole extending to depth L. The well casing 92 extends substantially to the bottom of the packer 94, leaving the hydrogen-producing rock in the lower portion of the well, the active zone 96, exposed directly to water without casing, thereby providing a larger water-rock contact in the production zone. The metal used to provide the casing 92 may optionally be selected to be resistant to hydrogen embrittlement in order to extend its service life.

[0112] In some embodiments, a protected gas buffer may be positioned within the cased portion of the well immediately above the packer 94 to serve as a nearby gas-receiving space into which exsolved hydrogen can migrate from the active zone 96 without requiring direct transport to the surface. The purpose of the protected gas buffer is to provide a mechanically defined receiving volume close to the active interval so that exsolved hydrogen does not have to travel directly to the surface while still in the micro-network of the formation, thereby reducing the risk of re-dissolution of hydrogen into the surrounding liquid before it can be produced. For a first single-well demonstration, the protected gas buffer is preferably inside the cased part of the well rather than in an unconfined fracture in the formation. A free-gas chamber in the rock may leak laterally into the formation and make the mass balance difficultAty. Docket No.: GEG-004PCT-8022-00501to interpret. A sealed cased chamber or enlarged cased pocket above the packer 94 is mechanically clearer and easier to instrument. It also shortens the path from the reacting interval to a gas-receiving space. Suitable protected gas buffer configurations are set out in the following table.BufferHow it would be built Assessment for a first demonstration optionA short sealed steel chamber orBest first choice. It is mechanically Sealed cased stand-off section inside the caseddefined, limits leakoff into the stand-off gas interval just above the packer, withformation, and can remain open during chamber controlled gas entry' and a dedicatedunderbalanced take.gas line to surface.Enlarged A short enlarged pocket inside thecased pocket cased section above the stimulation Also suitable where completion or milled port, with controlled gas entry and practice allows it.cavity gas take-off.Possible in later field development, but Open fracture A larger fracture is intentionallynot preferred for the first test because used as the created and used as the receivinggas may leak laterally into the rock and gas space space.aperture may be harder to control.Table 9. Buffer options for a single-w ell make-take test.

[0113] The systems and methods disclosed herein separate upstream proof of generation from downstream separation. The first objective is to create hydrogen and deliver it into a protected near-well receiving space. Only after that has been demonstrated does it become useful to optimize gas-liquid separation. A packer-style phase separator, such as the sintered metal phase separator 106 described herein, is one practical downstream option. In plain language, it is a phase-selective insert placed near the active interval or inside the protected buffer so hydrogen can move into a lower-pressure gas path without lifting the entire hot water column. Its separating area scales with diameter and length:Asep= π DsepLsep

[0114] This means that even a short insert can provide square-meter-scale separating area. In many shallow demonstrations, separator area is therefore not the first uncertainty. The first uncertainty is whether the rock is delivering enough hydrogen-rich fluid or gas to the separator in the first place. The following table compares downstream separation approaches in this context.Aty. Docket No.: GEG-004PCT-8022-00501... „, Assessment for the shallow stimulated- Approach Why it may be useful,, >ultramafic concept Keeps most water and heatProtected bufferdownhole; allows staged Most relevant add-on to this concept. It with optionalimprovement of gas-liquid fits the make-take logic and can be added packer-styleseparation after the source has after Phase 1.separatorbeen proven.Less relevant to the shallow stimulated- May produce strong lift if aultramafic concept. It assumes more of Open-well geyser deep, nearly saturatedthe source and phase behavior has or whole-column hydrothermal column alreadyalready been solved and pushes flashing exists and steam handling issubstantially more burden to surface acceptable.handling.Dedicated Separates make from takeproducer well entirely and gives the producer Most robust fallback if a single well with separator on a continuous low-pressure cannot sustain the target rate.the producer side role.Table 10. Comparison of downstream separation approaches.

[0115] The key point is that a packer-style separator is not the main proof-of-generation mechanism. It is a downstream efficiency option. It becomes attractive only after the active interval has already shown that hydrogen reaches a protected receiving space near the well at a repeatable rate. Where a protected gas buffer is employed, the optional phase-selective separator may be positioned at the interface between the active zone 96 and the protected gas buffer, or within the protected gas buffer itself, rather than distributed throughout the full length of the active zone 96.

[0116] A mechanical packer 94 can be positioned at a selected depth within the well, illustratively at z = 600 m in the representative example, creating two hydraulically isolated regions: the active zone 96 below the packer 94, occupying the lower portion of the well (e.g., 100 m of the well from 600 m to 700 m depth in the example), and the conduit zone 98 above the packer 94, occupying the upper portion of the well (e.g., the upper 600 m of the well in the example), through which produced hydrogen can be transported to the surface.

[0117] For purposes of providing an example, the following parameters can be assumed: the borehole is a 4-inch (0.1016 m) diameter vertical shaft extending to a depth of L = 700 m. At the bottom-hole boundary' (z = L = 700 m), the temperature is maintained at Tbot = 250 °C by the geothermal gradient of the formation. A substantially limitless geological hydrogen source, the serpentinization reaction between water and iron-rich rock, and provides a constant hydrogen saturation at the base of the active zone 96. The upper boundary is initially at atmospheric pressure (101.325 kPa) and is subsequently regulated by the wellhead cap 100Atty. DocketNo.: GEG-004PCT-8022-00501and adjustable valve 102 to maintain an extraction backpressure (e.g., of about 0.5 MPa in the example) in the conduit zone 98 and the producer pipe 104.

[0118] The density of water pwis modeled as a function of the local temperature T(z), which follows a gradient of approximately 0.328 °C / m along the well. The pressure at depth z is determined by integrating the weight of the overlying variable-density fluid column:P(z) = Paim+ gwith the representative result Ptotai ~ 6.28 MPa at z = 700 m.

[0119] The vapor pressure of water at the active zone operating temperature of 250 °C is Psat = 3.97 MPa. Because the total hydrostatic pressure at the base of the well (Ptotai ~ 6.28 MPa) exceeds Ps t (3.97 MPa), the water in the active zone 96 remains in the compressed liquid state. This condition is important as it prevents bulk boiling within the active zone 96, which would otherwise disrupt the selective phase separation process at the sintered interface described below.

[0120] The serpentinization source reaction can maintain the w ater in the active zone 96 at or near its saturated hydrogen earn ing capacity, though the production rate and operating parameters may result in the hydrogen carrying capacity being below' saturation. As the pressure is varied during production, including at least at one frequency to breakdown the rock and inject and withdraw water from the formation, the dissolved hydrogen concentration can vary in time. As a result, the rate of production can vary in time corresponding to the pressure modulation, at times being below and at other times above the mean rate.

[0121] The driving force for extraction, referred to herein as the hydrogen fugacity, is the partial pressure of dissolved hydrogen Pn in the active zone liquid, defined as the difference between the total hydrostatic pressure and the vapor pressure of water at the active zone temperature:PH, = PM - P«f, H2o(250°C) « 2.31 MPaThis 2.31 MPa represents the chemical pressure, or fugacity, of the dissolved hydrogen seeking to escape the liquid solvent. It is this fugacity differential between the high-pressure active zone liquid and the lower-pressure gas phase maintained within the producer pipe 104 that drives the transversal phase transition at the sintered interface.Aty. Docket No.: GEG-004PCT-8022-00501

[0122] In some embodiments, a practical phase separating device may comprise, for example, a sintered metal cylinder having a characteristic channel size of less than about 100 microns, less than about 10 microns, less than about 8 microns, or less than 5 microns. The cylinder may be further coated with a hydrophobic film or coating to further reduce the ingress of water from the surrounding well. Suitable hydrophobic coatings include, but are not limited to: fluorinated silane coatings, for example applied by chemical vapor deposition (CVD). such as fluoroalkylsilane (FAS) or perfluoroalkylsilane (PFAS) treatments, which create a high contact-angle surface that resists liquid water penetration while remaining permeable to hydrogen gas, polytetrafluoroethylene (PTFE) coatings applied by dip coating, spray coating, or sintering; fluorinated ethylene propylene (FEP) coatings, diamond-like carbon (DLC) coatings functionalized with fluorine, and silicone-based hydrophobic coatings. In some aspecs, a fluorinated silane coating is applied by CVD to achieve a water contact angle greater than 120°, creating a gas-filled "dry" zone within the pores of the sintered body that substantially prevents liquid water ingress while allowing hydrogen to degas freely into the interior of the separator. To improve the ingress of hydrogen into the pipe, the cylinder should substantially occupy the hydrogen-producing volume.

[0123] As shown in FIG. 5, a sintered metal phase separator 106 can be positioned within the active zone 96 below7the packer 94, configured to substantially occupy the volume of the active zone 96. The sintered metal phase separator 106 is connected to producer pipe 104, which passes upward through the packer 94 and the conduit zone 98 to the surface via the wellhead cap 100, through which extracted hydrogen is transported at near-active zone pressure.

[0124] An FEO fill pipe 108 and injector 110 are provided, as shown in FIG. 5, to introduce pressurized water to the active zone 96, including both fresh water and water that may be recovered from the surface processing loop in the course of producing hydrogen. The injector 110 passes through the packer 94 and the wellhead cap 100 in a sealed, leak-free manner.

[0125] In some aspects, the sintered metal phase separator 106 can be fabricated from sintered stainless steel to provide inherent resistance to hydrogen-induced cracking (HIC) and embrittlement at 250 °C. This material is selected over palladium-silver alloys on the basis of industrial longevity and cost-effectiveness at the required operating conditions. The material can be formed into a cylindrical body by isostatic sintering to achieve a uniform pore size distribution and structural integrity under the hydrostatic pressures present in the Active Zone 96.Aty. Docket No.: GEG-004PCT-8022-00501

[0126] The total interfacial surface area of the sintered phase separator 106 is a function of its outer diameter and active length. The sintered metal phase separator 106 can be characterized by a highly elongated aspect ratio, the ratio of the active length Lactive of the sintered body to its outer diameter Dsinter, that can distinguish it from conventional fdter or separation elements and reflects the geometric constraint imposed by the wellbore. In some embodiments, the length-to-diameter ratio of the sintered metal phase separator 106 can be in the range of approximately 500 to 3,000, with the active length selected based on the depth and extent of the active zone 96 and the bore diameter selected based on the inner diameter of the well casing 92.

[0127] To allow for the ingress of hydrogen into the producer pipe 104, the sintered metal phase separator 106 can occupy the hydrogen-producing volume of the active zone 96. This can be quantified by the ratio of the outer diameter of the sintered body Dsinter to the inner diameter of the wellbore Dwell. In some embodiments, the ratio of the sintered body outer diameter to the wellbore inner diameter can be in the range of approximately 0.70 to 0.95, leaving a sufficient annular clearance for brine circulation and mechanical assembly.

[0128] The wall thickness of the sintered annulus, defined as one-half of the difference between the outer diameter Dsinter and the inner mandrel diameter Dmandrei, governs the balance between hydrogen transport permeability and structural integrity under the hydrostatic pressures present in the active zone 96. In some embodiments, the ratio of the sintered wall thickness to the sintered body outer diameter can be in the range of approximately 0.10 to 0.35, with thinner walls providing lower diffusion path length and higher permeability, and thicker walls providing greater structural integrity at operating pressure.

[0129] The ratio of the total outer interfacial surface area of the sintered metal phase separator 106, the area through which transversal hydrogen desorption occurs, to the total volume of the active zone 96 is a process-engineering parameter analogous to the specific surface area concept used in reactor design, and captures the density with which the separator is packed within the production zone. In some embodiments, the ratio of the sintered interfacial surface area to the active zone volume can be in the range of approximately 15 to 100 m2 / m3, with higher values reflecting denser packing and greater extraction capacity per unit formation volume across varying bore diameters and active zone lengths.

[0130] For the representative example, the sintered metal phase separator 106 can have an outer diameter Dsinter = 3.5 inches (0.0889 m) and an active length Lactive = 100 m, assembled from 3-meter segments joined via high-pressure orbital welds over a central 2-inch mandrel:Atty. DocketNo.: GEG-004PCT-8022-00501^sinter =71' ^sinter ' ^active77’ 0-0389 < 100 « 27.9 m2

[0131] One challenge in operating the sintered metal phase separator 106 in the high-pressure liquid environment of the active zone 96 is preventing the surrounding pressurized water from wetting and fouling the pore network, which would block gas-phase formation within the pores and eliminate the driving force for hydrogen extraction. To address this, the pore surfaces of the sintered separator 106 can be rendered hydrophobic by application of the hydrophobic coating such as a fluorinated silane coating thereby, creating a hydrophobic surface that substantially prevents liquid water ingress.

[0132] The hydrophobic coating creates a non-wetting surface such that liquid water cannot spontaneously enter the pores without overcoming a surface energy' barrier. This barrier is quantified by the Laplace entry pressure, which is the excess pressure that liquid water must apply to displace the gas phase and penetrate a pore of a given characteristic size r:2 cos 6APtrwhere y is the surface tension of water at 250°C, 9 is the contact angle of the hydrophobic surface (> 120°), and d is the characteristic pore diameter (e.g., 2.0 pm in the representative embodiment).

[0133] This creates a gas-filled "dry" zone within the pores of the sintered separator 106. Provided that the Laplace entry pressure APL exceeds the liquid pressure differential across the separator wall under operating conditions, liquid water can be excluded from the pore network and the dry zone is maintained, providing the site at which hydrogen desorbs from the surrounding high-fugacity liquid and accumulates as a gas phase for transport to the surface via producer pipe 104.

[0134] The extraction of hydrogen from the active zone 96 liquid is not a diffusionlimited process in the longitudinal sense. Instead, it is a transversal phase transition at the sintered interface of phase separator 106, a process in which dissolved hydrogen molecules spontaneously degas from the high-fugacity surrounding liquid into the gas-filled pores of the sintered separator 106 to equalize the partial pressure between the liquid phase, at approximately 2.31 MPa hydrogen fugacity in the representative embodiment, and the gas phase maintained inside producer pipe 104 at the extraction backpressure of 0.5 MPa.

[0135] Because the entire sintered surface area of phase separator 106 can participate simultaneously in this transversal desorption process, rather than relying on longitudinalAtty. DocketNo.: GEG-004PCT-8022-00501diffusion along the length of the wellbore, the extraction rate is governed by the total available interfacial area and the hydrogen fugacity differential across the sintered interface, not by the length scale of the diffusion path.

[0136] Thus, hydrogen preferentially enters producer pipe 104 via the sintered metal phase separator 106 and is produced to the surface at a much higher rate than it would be if it remained dissolved in the surrounding water.

[0137] The extraction backpressure maintained within producer pipe 104, the pressure at the inner face of sintered metal phase separator 106, is set at approximately 0.5 MPa in the representative example. This value is selected to simultaneously satisfy four engineering requirements for this example:

[0138] First, avoidance of sonic choking: 0.5 MPa prevents the hydrogen gas velocity in the 2-inch producer pipe 104 from reaching the sonic velocity (Mach 1), which would choke flow and limit the extraction rate.

[0139] Second, phase separation efficiency: 0.5 MPa provides sufficient kinetic energy¬ in the extracted gas stream for effective cyclone separation of any entrained liquid water at the surface phase separator.

[0140] Third, steam condensation temperature: at an extraction backpressure of 0.5 MPa, the effective boiling point of water in the gas stream is elevated to approximately 152 °C, facilitating more efficient thermal management in a surface heat exchanger relative to atmospheric condensation.

[0141] Fourth, preservation of the active zone driving force: 0.5 MPa remains sufficiently below the hydrogen fugacity of 2.31 MPa in the active zone 96 liquid to maintain a pressure differential of approximately 1.81 MPa across the sintered interface, sufficient to sustain the transversal desorption flux at the full industrial extraction rates reported in Table 11. Excessive extraction backpressure would reduce this driving force and collapse the extraction rate.Tbot THz (source) Flux (kg / hr) Metric Tons / Year100 6.73 MPa 173.0 1,515150 6.15 MPa 169.0 1,480200 4.73 MPa 162.0 1,419250 2.31 MPa 156.2 1,368Aty. Docket No.: GEG-004PCT-8022-00501Table 11

[0142] In use, the producer pipe 104 passing through the packer 94 and the conduit zone 98 transports the hydrogen stream, along with a small amount of entrained water vapor, from the active zone 96 to the top of the well and through the wellhead cap 100. The wellhead cap 100 is attached to the casing 92 in a sealed, leak-free manner and further provides a connection to the adjustable valve 102 through which the extraction backpressure of the conduit zone 98 and producer pipe 104 is regulated.

[0143] Further sen ices may be introduced to the well via the wellhead cap 100 through leak-free feedthroughs, including wiring for instruments that may include a variety of sensors such as pressure, pH, gas composition, and temperature sensors. Other services may include heater cables, water fill pipes, water removal pipes, pressure relief valves, and liquid level sensors.

[0144] The hydrogen stream exiting producer pipe 104 through adjustable valve 102 passes through surface phase separator (e.g., separator 78 as shown in FIG. 4), which removes any residual liquid water. Any of the surface equipment described with respect to FIG. 3 can also be present in the embodiment of FIG. 4. The separated water can be returned to FLO reservoir for reuse as injection water. The purified hydrogen stream exiting phase separator can be stored in a pressurized hydrogen storage vessel.

[0145] The pressure of hydrogen exiting the sintered metal phase separator 106 at the packer 94 is maintained at a pressure several MPa less than the liquid pressure at the base of the well, the difference being the hydrogen fugacity driving force. The gas pressure at the top of the well is less than the packer exit pressure by the gravitational pressure exerted by the gas column in the producer pipe 104, which is small compared to the incoming gas pressure. Therefore, the hydrogen pressure is substantially maintained at the top of the well and in the downstream hydrogen storage vessel.

[0146] This means that the packer well embodiment, consistent with the general principles described herein can deliver hydrogen at substantially elevated pressure, well above atmospheric, thereby substantially reducing the downstream compression energy’ required for transport, storage, or industrial use, and conserving the pressure energy inherent in the subsurface system.

[0147] An advantage of the packer well embodiment over the open well embodiment is the reduction in the thermal load imposed on the surface processing equipment. In an openwell system, hydrogen is recovered by allowing the entire water column to flash and be carried to the surface, thereby requiring the management of a condensation thermal load (e.g.,Aty. Docket No.: GEG-004PCT-8022-00501approximately 220 kW and a replenishment water flow rate of approximately 0.35 m3 / hr in the example).

[0148] By contrast, the packer well design moves the phase separation process to depth within the active zone 96, where only the hydrogen gas and a minor fraction of water vapor exits through the sintered metal phase separator 106 and producer pipe 104. The result is a reduction in surface thermal load (e.g., from approximately 220 kW to less than 5 kW, a reduction of greater than 98% in the example), thereby substantially reducing the need for large surface condensers and replenishment pumping infrastructure, and providing an improvement in the net energy ratio of the system relative to an open-well design of equivalent bore diameter and depth.

[0149] The hydrogen yield of the packer well configuration is sensitive to the active zone temperature, which determines the vapor pressure of water, and therefore, the available hydrogen fugacity and the thermal stability of the sintered separator 106 and its hydrophobic coating. The packer well configuration delivers commercially significant hydrogen extraction rates across a broad range of active zone temperatures. Notably, formations at lower active zone temperatures can yield comparable or superior hydrogen fugacity, and therefore extraction rate, relative to higher-temperature formations, provided the total hydrostatic pressure is sufficient to maintain the active zone 96 in the compressed liquid state. This is because lower temperatures reduce the vapor pressure of water, increasing the fraction of total hydrostatic pressure available as hydrogen partial pressure.

[0150] In certain embodiments, the systems and methods disclosed herein may be implemented in a phased field demonstration designed to prove the full chain of generation, mobilization, and surface collection of geologic hydrogen in sequence prior to scale-up. The core objective of such a phased demonstration is to prove three linked steps: first, that pressure cycling can create a connected damaged zone and materially increase permeability; second, that the enlarged reactive volume can generate measurable hydrogen downhole; and third, that the same well can be operated in make-take mode so hydrogen reaches the surface at a controlled and repeatable rate. The base concept uses an isolated active interval, heated and chemically controlled brine, a fast stimulation clock, a slower production clock, a periodic reset clock, and an optional protected gas buffer with optional phase-selective separation, as described herein. The core elements of this concept are summarized in the following table.Aty. Docket No.: GEG-004PCT-8022-00501Core element Purpose Generic form Keeps drilling and completion scope Typically a few hundred meters Relativelymoderate while still allowing a to about 1 km in measured shallow wellmeaningful active interval. depth.Concentrates pressure cycling, tracer Typically 50-500 m in length; Isolated activework, and thermal control on the part of open hole or perforated and intervalthe well that is meant to react. packer-isolated.Provides the reactive iron-bearingOlivine-rich Preferably mostly fresh and mineralogy needed for serpentinization- ultramafic rock only partly serpentinized.driven hydrogen generation.Heated andSupports reaction rate, controls salinity Low-salinity, deoxygenated, chemicallyand redox, and avoids unnecessary alkaline brine whenever controlledoxygen loading. practical.working fluidUsually 10-15 minute pressure Fast stimulation Creates and refreshes connected reactive cycles near local breakdown, clock volume. controlled by downhole interval pressure.Allows hydrogen to leave the rock and Repeated lower-pressure take Slowerenter a receiving space before the local periods lasting hours rather production clockwater buffer becomes saturated. than minutes.Provides a nearby gas-receiving spaceUsually a sealed chamber or Protected gas so exsolved hydrogen does not have toenlarged cased pocket just buffer travel directly to the surface while stillabove the active interval. in the micro-network.Optional hydrophobic or Optional phase- Improves gas-liquid separation after theotherwise phase-selective insert selective upstream source and delivery probleminside the buffer or a producer separator has already been proven.completion.Fixed stimulator-producer pair Multiwell Separates make from take if a singlesharing one or more fracture fallback well cannot hold the target rate.zones.Table 12. Core elements of the generic shallow-well phased demonstration concept.

[0151] In certain embodiments, a downhole heater may be employed to bring the active interval to its target temperature during startup and to maintain the reacting section near that temperature throughout early operation. The heater runs to the bottom of the active interval so the whole reacting section remains near its target temperature during startup, before geothermal heat flux and exothermic serpentinization reactions are sufficient to sustain the required thermal conditions independently. The same heater and pressure-control system used during startup can be used throughout Phase 1 and Phase 2 operation.

[0152] Phase 1 is a mechanism test. Its purpose is to show that pressure cycling creates a connected damaged zone and that hydrogen is then generated and detected downhole in the same interval. If Phase 1 does not succeed, it is too early to discuss surface production. AAty. Docket No.: GEG-004PCT-8022-00501practical Phase 1 completion uses an isolated short subsection inside the larger active interval, typically approximately 10-20 m in length. The subsection is equipped with downhole pressure and temperature gauges, one small capillary sample line for local fluid and gas chemistry, acoustic or microseismic monitoring where available, and the ability to inject short tracer puffs. The same heater and pressure-control system used later in production mode can already be used in Phase 1. The recommended Phase 1 workflow is set out in the following table.What counts as Phase 1 step How it is run What is measuredsuccess Baseline pressureBring the interval to the volume response,The interval is stable Baseline and heattarget temperature. baseline injectivity,and the baseline up (approximately Apply only a very small early tracer return,measurements are 2 days) pressure wobble and one and a clean gasrepeatable.short tracer puff. baseline on the sampleline.Start 10-15 minutecycles near First change inapproximately 0.6 of compliance, first A first producing local breakdown change in injectivity, threshold is found and Week 1 calibrationpressure. Run a short local gas signal, and the interval remains drawdown staircase to any change in small contained.find the first gas -entry crack counts.threshold.Continue 10-15 minutePressure-volumecycles. Move toward The well becomes response, injectivity,Damage-growth approximately 0.7 of easier to deform,tracer-definedperiod (weeks 2-6; local breakdown easier to flow through, connected volume,extend to week 10 pressure, and only test and the local sample local gas chemistry,if needed) approximately 0.8 if line shows hydrogen and acoustic crackcontainment remains above baseline.activity.good.Advance to Phase 2 only if permeability growth, connected- Run one reset and repeat All measurementsDecision gate volume grow th, and the measurement loop. together.downhole hydrogen remain visible afterreset.Table 13. Recommended Phase 1 workflow.

[0153] Phase 1 succeeds only if three things rise together: pressure-volume compliance or injectivity, tracer-defined connected volume, and hydrogen detected in the local sample line.Aty. Docket No.: GEG-004PCT-8022-00501A single gas show without a mechanical response is not sufficient. A mechanical response without hydrogen is likewise not sufficient.

[0154] Phase 2 uses the same well as both stimulator and producer. Pressure cycling is applied from the wellhead. A packer at the top of the active interval directs the pulse to the full interval below it. The heater runs to the bottom of the active interval so the whole reacting section remains near its target temperature during startup. The well is then operated with the three-clock make-take scheme described herein. For a shallow single-well demonstration, a sensible fallback production target is approximately 15 kg / day and a reasonable stretch target is approximately 20 kg / day, provided Phase 1 has already shown clear permeability growth and downhole hydrogen generation. These rates should be judged as sustained and repeatable rates, not as single-event degassing results. Apractical decision rule is as follows: if, after one full reset and one repeated threshold test, the single well cannot hold approximately 15 kg / day with stable make-take operation, the next step is a fixed stimulator-producer pair rather than a more complicated single-w ell workaround, consistent with the multi-well pad architecture described herein.

[0155] The main flow hurdles that may be encountered in a single-well demonstration and the generic design features used to address them are set out in the following table...., <■, Design feature used to _,Main hurdle Why it blocks now Practical consequence overcome itHydrogen may be Use 10-15 minute The key evidence is Too little generated, but if it stays pressure cycling over the rising injectivity, rising connected gason the rough w all or in full active interval to compliance, and bearing rock short dead-end cracks it build a connected increasing connected volume will not flow at useful damaged halo and short tracer volume, not just rates. larger fractures. one gas sample.Run an early pressureHydrogen must cross The production problem step-down test to findNarrow watervery7small water-filled is often an entrythe real gas-entrywet throats openings before it can problem near the well, threshold, then hold takeblock gas entry enter a larger connected not a friction problem in periods below thatpath to the well. the tubing.threshold.The near-wellMinute-scale Use separate make andwater buffer Brine circulation alone stimulation creates take clocks so the wellfills with is not enough at damage but does not by repeatedly unloads gasdissolved practical demonstration itself remove hydrogen before the local bufferhydrogen in rates.fast enough. remains saturated.hoursDissolved-only Use brine mainly forReaction water demand This lowers water export requires chemistry and heatis much smaller than handling compared withtoo much water control, but remove mostAty. Docket No.: GEG-004PCT-8022-00501„„ « Design feature used toMain hurdle Why it blocks flow Practical consequence overcome itdissolved-only transport hydrogen as free gas a dissolved-only demand. during take periods. production scheme. If the well remains fullyUse a protected gasliquid-fdled with no The buffer shortens the Gas needs a buffer close to the activenearby gas space, gas path and makes the nearby interval, with a low- hydrogen can remass balance receiving space pressure gas line todissolve or be pushed interpretable.surface.back into the formation.A single gas Use Phase 1 for proof atOne short event may Success means show does not depth and Phase 2 foronly reflect temporary repeatable rate after prove repeatable surfacedegassing. reset, not one event. production delivery.Even if hydrogen isWater loading, generated, fluid Actively unload watersalinity drift, accumulation or during take periods and The reset clock remains and partial chemistry drift can keep the brine low- part of the design, not resealing can make the well appear salinity, deoxygenated, an afterthought. hide success worse than the rock and alkaline.really is.Table 14. Main flow hurdles and the generic design features used to overcome them.

[0156] The following illustrative worked example is provided to demonstrate the scale of the quantities involved in a shallow-well demonstration of the type described herein. The numbers are included only to show7scale and are not site-specific commitments. The example assumes a single shallow well of approximately 400 m measured depth with approximately 200 m active interval and 6-inch diameter, completed in mostly fresh olivine-rich ultramafic rock that is up to approximately 10% serpentinized. A heater is used to hold approximately 275°C at the reacting rock during startup. The pressure program applies 10-15 minute cycles with peak interval pressure tuned near approximately 0.8 of local breakdown pressure with a small positive mean pressure. The chemistry target is low-salinity, deoxygenated, alkaline brine wherever practical. The full illustrative assumptions are set out in the following table.Input Illustrative value Why it matters One shallow7well; approximately 400 mDefines the original wall Well and interval measured depth; approximately 200 marea and water volume. active interval; 6-inch diameterMostly fresh olivine-rich ultramafic rock; Sets the remaining up to approximately 10% serpentinized hydrogen yield.Supports reaction rate and Heater used to hold approximately 275°CThermal condition keeps the interval in the at the reacting rock during startupintended regime.Aty. Docket No.: GEG-004PCT-8022-00501Input Illustrative value Why it matters 10-15 minute cycles; peak intervalPressure ro ram Pressure tuned near approximately 0.8 of Creates and refreshes ressure program pressure with a small connected reactive volume.positive mean pressureImproves reaction rate and Low-salinity, deoxygenated, alkaline brineChemistry target avoids unnecessary salinitywhenever practicalpenalty.Connected grainControls grain-scale size used in the 20-50 pmsurface-to-volume ratio. estimateRemaining Represents a modest hydrogen yield 1.8-3.6 kg FL per m3rock reduction for prior used in the estimate serpentinization.Full reaction time 3.2-8.1 months in low-salinity- water; 7.5- Shows why grain access for fully wetted 20- 18.8 months in approximately 3.5 wt%and salinity matter.50 pm grains brineIllustrativeApproximately 341 mmol / L in low- Shows why production dissolved FL limitsalinity water; approximately 147 mmol / L cannot rely on dissolved at 275°C and 20in approximately 3.5 wt% brine export alone.MPaTable 15. Illustrative shallow-well assumptions.

[0157] For this worked geometry, the original wall area and open-hole water volume are:Ao = nDL = 95.8 m2Vopen = 7t(D / 2)2L = 3.65 m3

[0158] The illustrative hydrogen output classes across a range of fracture development and halo connectivity scenarios are presented in the following table.Larger- Halo and Connected Hz per month Hz per month in Case fracture connected reacting rock in low-salinity approximately 3.5 area fraction volume water wt% brine „ 0.5 mm halo;5,.vc96 m210% 0.005 m30.001-0.005 kg 0.000-0.002 kg baseline,connected. 1 mm halo;linn halo239 m2 100 / 0.024 m30.005-0.027 kg 0.002-0.011 kg onlv. b b connected„, 3 mm halo;700d479 m220% 0.287 m30.064-0.323 kg 0.028-0.138 kgconnectedAtty. Docket No.: GEG-004PCT-8022-00501Larger- Halo and Connected H2 per month H2 per month in Case fracture connected reacting rock in low-salinity approximately 3.5 area fraction volume water wt% brine 10 mm halo;S,trons95S m230% 2.873 m30.638-3.232 kg 0.275-1.379 kg democonnectedVery' 10 mm halo;strong 1,436 m250% 7.182 m31.596-8.079 kg 0.688-3.447 kgdemo connectedTable 16. Illustrative hydrogen output classes for the worked shallow-well example.

[0159] In certain embodiments, the active length Lactive of sintered metal phase separator 106 may be extended or contracted to adjust the total interfacial surface area Asinter and thereby the extraction rate, independently of the bore diameter of the well. In certain embodiments, multiple sintered separator segments may be deployed at different depth intervals within the active zone 96, connected in parallel to a common producer pipe 104, to increase the total available interfacial area and accommodate variable mineralogy or permeability along the wellbore.

[0160] Having described various systems, processes, and configurations, certain aspect can include, but are not limited to:

[0161] In a first aspect, a method for producing geologic hydrogen from a subsurface rock formation comprises: maintaining elevated pressure along at least a portion of a wellbore penetrating an iron-rich subsurface rock formation such that water or brine in contact with the rock formation remains in a substantially liquid state and hydrogen generated by serpentinization dissolves into the water or brine; recovering hydrogen-saturated fluid from the wellbore at a pressure above atmospheric pressure; partially depressurizing the recovered fluid to an intermediate degassing pressure that is less than the wellbore pressure but greater than atmospheric pressure, thereby desorbing a fraction of the dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system; and separating the desorbed hydrogen gas from the partially depressurized fluid.

[0162] A second aspect can include the method of the first aspect, wherein the intermediate degassing pressure is greater than atmospheric pressure and less than the wellbore pressure.

[0163] A third aspect can include the method of any one of the first or second aspects, further comprising cooling the hydrogen-saturated fluid prior to partial depressurization, and returning partially degassed fluid to the wellbore at elevated pressure.Aty. Docket No.: GEG-004PCT-8022-00501

[0164] A fourth aspect can include the method of the third aspect, wherein cooling comprises passing the fluid through a heat exchanger, and wherein thermal energy recovered in the heat exchanger is applied to one or more downstream processes.

[0165] A fifth aspect can include the method of any one of the third or fourth aspects, wherein partially depressurizing comprises reducing the pressure in two or more sequential stages, each stage desorbing an additional fraction of dissolved hydrogen as a free gas phase.

[0166] A sixth aspect can include the method of any one of the third to fifth aspects, wherein partially depressurizing comprises passing the fluid through one or more devices selected from the group consisting of a throttling valve, a Joule-Thomson expansion valve, a turboexpander, a positive-displacement expander, and a staged flash vessel, or combinations thereof.

[0167] A seventh aspect can include the method of the sixth aspect, wherein at least one expander is a turboexpander that recovers shaft work from the pressure reduction and directs the recovered shaft work to drive a pump or a compressor.

[0168] An eighth aspect can include the method of any one of the third to seventh aspects, wherein separating the desorbed hydrogen gas comprises passing the fluid through one or more devices selected from the group consisting of a cyclone separator, a vortex separator, a knock-out drum, a coalescing demister, a mesh pad separator, and a membrane-based gasliquid separator, or combinations thereof.

[0169] A ninth aspect can include the method of any one of the first to eighth aspects, further comprising adjusting the pH, salinity, temperature, and / or chemical composition of the partially degassed fluid prior to returning it to the wellbore.

[0170] A tenth aspect can include the method of any one of the first to ninth aspects, wherein maintaining elevated pressure and recovering hydrogen-saturated fluid are performed via a single wellbore operated in a cycle comprising an injection phase, a soak phase, and a production phase.

[0171] An eleventh aspect can include the method of the tenth aspect, wherein the injection phase comprises injecting fluid at a temperature substantially below the formation temperature to create a thermal shock in the formation.

[0172] A twelfth aspect can include the method of any one of the tenth or eleventh aspects, further comprising applying a composite pressure signal to the formation comprising at least a first frequency component that controls fluid exchange between the wellbore and the formation, and a second frequency component that applies cyclic mechanical stress to the rock matrix.Aty. Docket No.: GEG-004PCT-8022-00501

[0173] A thirteenth aspect can include the method of any one of the tenth to twelfth aspects, wherein the wellbore casing is perforated at a plurality of vertically separated intervals, and wherein one or more intervals are optionally isolated by packers to allow independent zonal pressure control.

[0174] A fourteenth aspect can include the method of any one of the first to tenth aspects, wherein maintaining elevated pressure and recovering hydrogen-saturated fluid are performed by spatially separated injection and production wells, wherein fluid injected via the injection well drives a serpentinization front progressively through the rock formation toward the production well.

[0175] Afifteenth aspect can include the method of any one of the first to ninth aspects, further comprising alternating the pH of the aqueous liquid contacted with the iron-rich rock formation between a low-pH condition and a high-pH condition, wherein under the low-pH condition Fe2+is leached from the rock formation and hydrogen is generated by iron dissolution, and wherein under the high-pH condition serpentinization is promoted and hydrogen is generated by reaction-induced fracturing.

[0176] A sixteenth aspect can include the method of the fifteenth aspect, wherein the low-pH condition comprises a pH of less than approximately 5.2, and wherein under the low-pH condition pyroxene present in the rock formation is consumed.

[0177] A seventeenth aspect can include the method of any one of the fifteenth or sixteenth aspects, wherein pH cycling progressively increases the reactive surface area of the formation over successive cycles.

[0178] An eighteenth aspect can include the method of any one of the first to tenth aspects, wherein the wellbore comprises a mechanical packer positioned at a selected depth to define a lower active zone below the packer and an upper conduit zone above the packer, the method further comprising: positioning a phase separator within the active zone configured to selectively pass hydrogen gas from the surrounding hydrogen-saturated liquid into a producer pipe extending upward through the packer and conduit zone to the surface, while substantially preventing liquid water from entering the producer pipe.

[0179] A nineteenth aspect can include the method of the eighteenth aspect, wherein the phase separator comprises a sintered metal body having a characteristic pore size of less than about 100 microns.

[0180] A twentieth aspect can include the method of any one of the eighteenth or nineteenth aspects, wherein pore surfaces of the phase separator are treated with a hydrophobicAty. Docket No.: GEG-004PCT-8022-00501coating that creates a non-wetting surface maintaining a gas-filled zone within the pores that substantially prevents liquid water ingress during operation.

[0181] A twenty-first aspect can include the method of any one of the eighteenth to twentieth aspects, wherein one or more geometric ratios of the phase separator are selected from the group consisting of: a ratio of active length to outer diameter in a range of approximately 500 to 3,000; a ratio of outer diameter to wellbore inner diameter in a range of approximately 0.70 to 0.95; a ratio of wall thickness to outer diameter in a range of approximately 0.10 to 0.35; and a ratio of total interfacial surface area to active zone volume in a range of approximately 15 to 100 m2 / m3.

[0182] A twenty -second aspect can include the method of any one of the eighteenth to twenty-first aspects, wherein positioning the phase separator within the active zone at depth reduces the thermal load on surface processing equipment relative to an open-well configuration of equivalent bore diameter and depth.

[0183] A twenty-third aspect can include the method of any one of the eighteenth to twenty-second aspects, wherein a plurality of phase separator segments are deployed at different depth intervals within the active zone and connected in parallel to a common producer Pipe-

[0184] A twenty-fourth aspect can include the method of any one of the first to third aspects, wherein the partial depressurization is effected at least in part by buoyancy-driven advective transport in which dissolved hydrogen exsolves as bubbles as fluid rises in the wellbore and local hydrostatic pressure decreases, the bubbles rising through the water column and delivering hydrogen to a wellhead at an intermediate managed pressure above atmospheric pressure.

[0185] Atwenty-fifth aspect can include the method of the twenty -fourth aspect, further comprising regulating an adjustable pressure valve at the wellhead to maintain an annular flow regime in which hydrogen gas rises through the wellbore while liquid water occupies the annular periphery and replenishment water descends through an internal pipe to maintain a substantially constant liquid head.

[0186] A twenty-sixth aspect can include the method of any one of the twenty -fourth or twenty-fifth aspects, wherein the managed pressure at the wellhead is selected to satisfy one or more of: avoiding sonic choking of the gas flow; providing kinetic energy for separation of entrained liquid water; elevating the effective steam condensation temperature; and maintaining a driving force for hydrogen exsolution throughout the water column.Aty. Docket No.: GEG-004PCT-8022-00501

[0187] A twenty-seventh aspect can include the method of any one of the twenty -fourth to twenty-sixth aspects, wherein geothermal heat at the base of the wellbore provides the driving force for the serpentinization reaction and the buoyancy-driven transport of hydrogen to the surface.

[0188] A twenty -eighth aspect can include the method of any one of the first to twenty seventh aspects, further comprising operating a plurality of wells on a common well pad sharing surface processing equipment, wherein at least one well is in an injection or soak phase while at least one other well is in a production phase.

[0189] A tw enty-ninth aspect can include the method of any one of the first to twentyeighth aspects, further comprising separating dissolved metals or minerals from the partially degassed fluid at the surface.

[0190] In a thirtieth aspect, a system for producing geologic hydrogen from a subsurface rock formation comprises: a wellbore configured to penetrate an iron-rich subsurface rock formation and to maintain elevated pressure along at least a portion of its length such that hydrogen generated by serpentinization dissolves into water or brine in the wellbore; one or more expanders configured to partially depressurize fluid recovered from the wellbore to an intermediate degassing pressure greater than atmospheric pressure, thereby desorbing dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy7inherent in the subsurface system; and one or more phase separators configured to separate the desorbed hydrogen gas from the partially depressurized fluid.

[0191] A thirty -first aspect can include the system of the thirtieth aspect, further comprising a heat exchanger configured to cool fluid produced from the wellbore prior to partial depressurization, and a high-pressure pump configured to return partially degassed fluid to the wellbore at elevated pressure.

[0192] A thirty-second aspect can include the system of any one of the thirtieth or thirty-first aspects, further comprising a conditioning unit configured to adjust the pH, salinity, and / or chemical composition of the partially degassed fluid prior to reinjection.

[0193] A thirty-third aspect can include the system of any one of the thirtieth to thirty -second aspects, wherein the one or more expanders comprise one or more devices selected from the group consisting of a throttling valve, a Joule-Thomson expansion valve, a turboexpander, a positive-displacement expander, and a staged flash vessel, or combinations thereof.

[0194] A thirty -fourth aspect can include the system of any one of the thirtieth to thirty-third aspects, wherein the one or more phase separators comprise one or more devices selectedAtty. Docket No.: GEG-004PCT-8022-00501from the group consisting of a cyclone separator, a vortex separator, a knock-out drum, a coalescing demister, a mesh pad separator, and a membrane-based gas-liquid separator, or combinations thereof.

[0195] A thirty-fifth aspect can include the system of any one of the thirtieth to thirtyfourth aspects, further comprising a compressor configured to increase the pressure of the separated hydrogen gas, and optionally a hydrogen purifier configured to remove trace impurity gases from the hydrogen stream.

[0196] A thirty-sixth aspect can include the system of any one of the thirtieth to thirty fifth aspects, wherein the wellbore comprises a mechanical packer positioned at a selected depth to define a lower active zone and an upper conduit zone, and a phase separator positioned within the active zone and connected to a producer pipe extending upward through the packer and conduit zone to the surface, the phase separator being configured to selectively pass hydrogen gas into the producer pipe while substantially preventing liquid water from entering the producer pipe.

[0197] Athirty-seventh aspect can include the system of the thirty-sixth aspect, wherein pore surfaces of the phase separator are treated with a hydrophobic coating that creates a nonwetting surface maintaining a gas-filled zone within the pores that substantially prevents liquid water ingress during operation.

[0198] A thirty-eighth aspect can include the system of any one of the thirty-sixth or thirty-seventh aspects, wherein one or more geometric ratios of the phase separator are selected from the group consisting of: a ratio of active length to outer diameter in a range of approximately 500 to 3,000; a ratio of outer diameter to wellbore inner diameter in a range of approximately 0.70 to 0.95; a ratio of wall thickness to outer diameter in a range of approximately 0.10 to 0.35; and a ratio of total interfacial surface area to active zone volume in a range of approximately 15 to 100 m2 / m3.

[0199] A thirty -ninth aspect can include the system of any one of the thirtieth to thirty eighth aspects, further comprising an adjustable pressure valve at a wellhead configured to regulate flow and maintain a managed intermediate pressure above atmospheric pressure, wherein the system is configured to utilize buoyancy-driven advective transport of hydrogen exsolved from the rising water column to deliver hydrogen to the surface.

[0200] A fortieth aspect can include the system of any one of the thirtieth to thirty -ninth aspects, comprising a plurality of wellbores on a common well pad sharing one or more of theAty. Docket No.: GEG-004PCT-8022-00501expanders, phase separators, heat exchanger, conditioning unit, and high-pressure pump, wherein individual wellbores are operable in alternating injection, soak, and production phases.

[0201] A forty -first aspect can include the system of any one of the thirtieth to fortieth aspects, further comprising one or more sensors in the wellbore and a control system configured to modulate well pressure, injected fluid pH, injection flow rate, and pressure modulation parameters in response to signals from the one or more sensors.

[0202] A forty-second aspect can include the method of any one of the first to twentyninth aspects, wherein the method comprises a process for in-situ generation of hydrogen gas from a subsurface geologic formation, the process comprising injecting aqueous liquid into the subsurface geologic formation, recovering generated hydrogen gas, and applying pressure modulated hydraulics and geochemical control.

[0203] A forty-third aspect can include the method of the forty-second aspect, comprising increasing the rate of geothermal hydrogen production using a plurality of vertically separated small fractures made via perforations along the length of a well drilled and / or otherwise formed in the subsurface geologic formation, with or without zonal isolation at the surface.

[0204] A forty-fourth aspect can include the method of the forty-second aspect, comprising using a plurality of wells on a common pad with shared above ground pump and separator.

[0205] A forty-fifth aspect can include the method of the forty-second aspect, comprising using injected water during a repressurization part of each of a plurality of cycles to create a cold shock, thereby accelerating fracturing from temperature and stress changes, and also desorbing hydrogen to accelerate upward flow.

[0206] A forty-sixth aspect can include a method for producing geologic hydrogen from a subsurface rock formation, the method comprising: isolating an active interval of a wellbore penetrating an iron-rich subsurface rock formation using a packer positioned at a selected depth, the active interval being in hydraulic contact with the rock formation; applying a composite pressure signal to the active interval comprising a first, higher-frequency component having a period on the order of minutes that creates and grows a connected reactive volume within the rock formation, and a second, lower-frequency component having a period on the order of hours that alternates between a make period in which pressure is maintained at or near a stimulation level and a take period in which pressure is reduced to allow hydrogen generated by serpentinization to migrate from the rock formation into the wellbore; and recovering hydrogen from the wellbore during the take period.Atty. Docket No.: GEG-004PCT-8022-00501

[0207] A forty-seventh aspect can include the method of the forty -sixth aspect, wherein the peak interval pressure during the higher-frequency component is in a range of approximately 0.6 to 0.8 of the local formation breakdown pressure, with a positive mean pressure to sustain connected reactive volume growth.

[0208] A forty -eighth aspect can include the method of the forty -sixth aspect, wherein the take period is timed such that hydrogen is removed from the near-well fluid before the nearwell fluid reaches dissolved hydrogen saturation.

[0209] A forty -ninth aspect can include the method of the forty-sixth aspect, wherein the make period has a duration on the order of hours and the take period has a duration on the order of one to several hours, and wherein the make period and take period are repeated in successive cycles.

[0210] A fiftieth aspect can include the method of the forty-sixth aspect, further comprising injecting aqueous liquid at a temperature substantially below the formation temperature during the make period to create a thermal shock in the formation that loosens grain boundaries at the grain scale and imposes cyclic thermal stress at the formation scale, thereby accelerating fracture network growth and promoting hydrogen desorption during the take period.

[0211] A fifty -first aspect can include the method of the forty-sixth aspect, wherein the higher-frequency component and the lower-frequency component are applied simultaneously such that the lower-frequency make-take cycle is superimposed upon the higher-frequency stimulation cycle.

[0212] A fifty-second aspect can include the method of the forty-sixth aspect, wherein the active interval is perforated at a plurality of vertically separated intervals to create a plurality of fractures in the rock formation, each fracture increasing the reactive surface area available for serpentinization.

[0213] A fifty -third aspect can include the method of the fifty-second aspect, wherein one or more of the perforated intervals are independently isolated by packers to allow independent zonal pressure control.

[0214] A fifty -fourth aspect can include the method of the forty-sixth aspect, further comprising positioning a phase separator within the active interval below the packer, the phase separator being configured to selectively pass hydrogen gas from the surrounding hydrogen-saturated liquid into a producer pipe extending upward through the packer to the surface, while substantially preventing liquid water from entering the producer pipe.Aty. Docket No.: GEG-004PCT-8022-00501

[0215] A fifty-fifth aspect can include the method of the fifty -fourth aspect, wherein the phase separator comprises a sintered metal body having a characteristic pore size of less than about 100 microns, optionally less than about 10 microns, optionally less than about 5 microns.

[0216] A fifty -sixth aspect can include the method of the fifty -fourth aspect, wherein pore surfaces of the phase separator are treated with a hydrophobic coating that creates a nonwetting surface maintaining a gas-filled zone within the pores that substantially prevents liquid water ingress during operation.

[0217] A fifty-seventh aspect can include the method of the forty-sixth aspect, further comprising operating a plurality of wells on a common well pad sharing surface processing equipment, wherein at least one well is in a make period while at least one other well is in a take period, enabling substantially continuous hydrogen recovery at the site level.

[0218] A fifty-eighth aspect can include a method for producing geologic hydrogen from a subsurface rock formation, the method comprising: isolating an active interval of a wellbore penetrating an iron-rich subsurface rock formation using a packer positioned at a selected depth; operating the wellbore according to a three-clock pressure schedule comprising: a damage clock applying pressure cycles having a period on the order of minutes at or near a local formation breakdow n pressure to create and grow a connected reactive volume within the rock formation; a make-take clock alternating between a make period in which pressure is maintained at or near a stimulation level to promote hydrogen generation and a take period in which pressure is reduced below^ a gas-entry threshold to allow- hydrogen to migrate from the rock formation into the wellbore, the make-take clock having a period on the order of hours; and a reset clock applying a controlled depressurization, fluid flush, and diagnostic pressure oscillation on a period of approximately one to two days per month; and recovering hydrogen from the wellbore during the take period.

[0219] A fifty -ninth aspect can include the method of the fifty-eighth aspect, wherein the damage clock applies pressure cycles having a period of approximately 10 to 15 minutes at a peak interval pressure of approximately 0.7 to 0.8 of the local formation breakdown pressure, with a positive mean pressure to sustain connected reactive volume growth.

[0220] A sixtieth aspect can include the method of the fifty-eighth aspect, wherein the make period has a duration of approximately 3 to 6 hours and the take period has a duration of approximately 1 to 2 hours during early operation, transitioning to a make period of approximately 4 to 6 hours and a take period of approximately 2 hours once a stable gas path is established.Atty. Docket No.: GEG-004PCT-8022-00501

[0221] A sixty-first aspect can include the method of the fifty-eighth aspect, wherein the take period is initiated and controlled based on a gas-entry’ threshold determined by a pressure step-down test comprising reducing wellbore pressure in increments and monitoring gas response at the surface or downhole to identify the pressure at which hydrogen crosses water- wet micro-throats and enters the wellbore, and wherein the take period is held at or below the identified gas-entry threshold.

[0222] A sixty -second aspect can include the method of the fifty-eighth aspect, wherein the duration of the take period is selected to remove hydrogen from the near-well fluid buffer before the buffer reaches dissolved hydrogen saturation, the time to saturation being estimated as t_sat = (C_H2 • V_buf) / m_H2, where C_H2 is the dissolved hydrogen concentration at operating pressure and temperature, V buf is the connected water buffer volume near the active interval, and m_H2 is the hydrogen production rate.

[0223] A sixty-third aspect can include the method of the fifty-eighth aspect, further comprising positioning a protected gas buffer within the cased portion of the wellbore immediately above the packer, the protected gas buffer comprising a sealed cased chamber or enlarged cased pocket configured to receive exsolved hydrogen migrating from the active interval and to maintain a gas-receiving space proximate to the active interval such that hydrogen does not re-dissolve into the surrounding liquid before it can be produced to surface.

[0224] A sixty -fourth aspect can include the method of the sixty-third aspect, wherein the protected gas buffer is positioned within the cased portion of the wellbore rather than in an unconfined fracture in the formation, such that the gas-receiving volume is mechanically defined, leakoff into the formation is limited, and the mass balance of produced hydrogen is interpretable at the surface.

[0225] A sixty -fifth aspect can include the method of the sixty -third aspect, further comprising positioning a phase-selective separator at the interface between the active interval and the protected gas buffer, or within the protected gas buffer, the phase-selective separator being configured to pass hydrogen gas into a producer pipe extending to the surface while substantially preventing liquid water from entering the producer pipe, wherein the phase-selective separator is deployed only after the active interval has demonstrated repeatable hydrogen delivery to the protected gas buffer.

[0226] A sixty-sixth aspect can include the method of the fifty-eighth aspect, further comprising operating a downhole heater within the active interval during startup to bring the active interval to a target temperature and to maintain the reacting section near the targetAty. Docket No.: GEG-004PCT-8022-00501temperature until geothermal heat flux and exothermic serpentinization reactions are sufficient to sustain the required thermal conditions independently.

[0227] A sixty-seventh aspect can include a method for producing geologic hydrogen from a subsurface rock formation, the method comprising: in a Phase 1 mechanism test, isolating a subsection of an active interval of a wellbore penetrating an iron-rich subsurface rock formation, the subsection being approximately 10 to 20 meters in length and equipped with downhole pressure and temperature gauges and a capillary sample line for fluid and gas chemistry; applying pressure cycles at or near local formation breakdown pressure: and advancing to Phase 2 only if pressure-volume compliance or injectivity, tracer-defined connected volume, and downhole hydrogen concentration in the capillary sample line all rise together following at least one reset; and in a Phase 2 make-take production operation, operating the full active interval of the wellbore using a damage clock, a make-take clock, and a reset clock as described herein, targeting a sustained and repeatable hydrogen production rate of at least approximately 15 kg / day.

[0228] A sixty-eighth aspect can include the method of the sixty-seventh aspect, wherein Phase 1 compnses: a baseline and heat-up step of approximately two days in which a very small pressure wobble and one short tracer puff are applied to establish repeatable baseline measurements; a Week 1 calibration step in which 10 to 15 minute pressure cycles are started at approximately 0.6 of local breakdown pressure and a pressure step-down staircase is run to find a first gas-entry threshold; a damage-growth period of approximately two to ten weeks in which cycling progresses toward approximately 0.7 to 0.8 of local breakdown pressure subject to containment remaining satisfactory; and a decision gate comprising one reset followed by repetition of the full measurement loop.

[0229] A sixty -ninth aspect can include the method of the sixty-seventh aspect, wherein, if the single wellbore cannot sustain a repeatable production rate of approximately 15 kg / day following one full reset and one repeated threshold test, the method further comprises transitioning to a two-well configuration comprising a spatially separated stimulator well and a producer well sharing one or more connected fracture zones.

[0230] A seventieth aspect can include a method for estimating and maximizing reactive surface area in a geologic hydrogen production well, the method comprising: estimating the grain-scale surface multiplier M_s created by a wet reactive halo surrounding fracture surfaces in an iron-rich subsurface rock formation as M_s = 6δ / dg, where 8 is the average thickness of the wet reactive halo and dgis the representative connected grain size in the reacting halo; estimating the connected reactive area as A = q • M_s • Af, where q is theAtty. Docket No.: GEG-004PCT-8022-00501connected fraction of the halo and Ar is the total larger-scale fracture area in contact with the active fluid; and applying pressure cycling to the wellbore to grow Af and p over successive stimulation cycles, thereby increasing the connected reactive area available for serpentinization-driven hydrogen generation.

[0231] A seventy -first aspect can include the method of the seventieth aspect, further comprising estimating local halo permeability kh as kh ~ b3 / (12s), where b is the hydraulic aperture of connected grain-boundary pathways and s is the spacing between pathways, and monitoring whole-well injectivity as a field proxy for growth in kh, wherein a 2 to 10-fold rise in injectivity or pressure-volume compliance is taken as evidence that local permeability has increased by one or more orders of magnitude.

[0232] A seventy-second aspect can include the method of the seventieth aspect, further comprising estimating a hydrogen production rate M_H2 over a time step At from the connected reacting rock volume as M_H2 ~ Vr ■ Y_H2 • (At / 1), where Vr = T] • 8 • Af, Y_H2 is the hydrogen yield per fully reacted rock volume, and tr is the full reaction time for a fully wetted grain of size dgat the operating chemistry and temperature, and using this estimate to plan stimulation schedules and make-take clock durations.

[0233] A seventy -third aspect can include a system for producing geologic hydrogen from a subsurface rock formation, the system comprising: a wellbore penetrating an iron-rich subsurface rock formation and comprising a packer isolating a lower active interval from an upper conduit zone; a protected gas buffer positioned within the cased portion of the wellbore immediately above the packer, the protected gas buffer comprising a sealed cased chamber or enlarged cased pocket configured to receive exsolved hydrogen from the active interval; a downhole heater positioned within the active interval and configured to bring the active interval to a target reaction temperature during startup; and a control system configured to operate the wellbore according to a damage clock having a period on the order of minutes, a make-take clock having a period on the order of hours, and a reset clock having a period on the order of one to two days per month, wherein the control system modulates wellbore pressure, injected fluid chemistry, and injection flow rate in response to signals from one or more downhole sensors.

[0234] A seventy-fourth aspect can include the system of the seventy-third aspect, wherein the protected gas buffer is in fluid communication with a producer pipe extending upward through the packer and conduit zone to the surface, and wherein a phase-selective separator is optionally positioned at the interface between the active interval and the protected gas buffer and is configured to pass hydrogen gas into the producer pipe while substantiallyAty. Docket No.: GEG-004PCT-8022-00501preventing liquid water ingress, the phase-selective separator being sized such that its separating area Asep scales as AseP= π • D sep • Lsep. where Dsepand Lsep are the outer diameter and active length of the separator, respectively.

[0235] A seventy-fifth aspect can include the system of the seventy-third aspect, wherein completion hardware components comprising one or more of casing connections, cement, packers, feedthroughs, gauges, and wellhead assemblies are selected from thermalrated components developed for high-temperature well applications including steam-assisted gravity drainage or geothermal well construction, and wherein the completion geometry comprises a cased section above the active interval providing direct hydraulic contact between the working fluid and the reacting rock in the active interval without a slotted liner.

[0236] Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to... “. Reference to up or down will be made for purposes of description with “up,” “upper,” “upward,” “upstream,” or “above” meaning toward the surface of the wellbore and with "down." “lower,” “downward,” “downstream,” or “below” meaning toward the terminal end of the well, regardless of the wellbore orientation. Reference to inner or outer will be made for purposes of description with “in,” “inner,” or “inward” meaning towards the central longitudinal axis of the wellbore and / or wellbore tubular, and “out,” “outer,” or “outward” meaning tow ards the wellbore wall. As used herein, the term “longitudinal” or “longitudinally” refers to an axis substantially aligned with the central axis of the wellbore tubular, and “radial” or “radially” refer to a direction perpendicular to the longitudinal axis. The various characteristics mentioned above, as w ell as other features and characteristics described in more detail below will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

[0237] Additionally, the section headings used herein are provided for consistency with the suggestions under 37 C. F. R. 1.77 or to otherwise provide organizational cues. These headings shall not limit or characterize the invention(s) set out in any claims that may issue from this disclosure. Specifically, and by w ay of example, although the headings might refer to a “Field,” the claims should not be limited by the language chosen under this heading to describe the so-called field. Further, a description of a technology in the “Background” is notAty. Docket No.: GEG-004PCT-8022-00501to be construed as an admission that certain technology is prior art to any invention(s) in this disclosure. Neither is the “Summary" to be considered as a limiting characterization of the invention(s) set forth in issued claims. Furthermore, any reference in this disclosure to “invention” in the singular should not be used to argue that there is only a single point of novelty in this disclosure. Multiple inventions may be set forth according to the limitations of the multiple claims issuing from this disclosure, and such claims accordingly define the invention(s), and their equivalents, that are protected thereby. In all instances, the scope of the claims shall be considered on their own merits in light of this disclosure, but should not be constrained by the headings set forth herein.

[0238] Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Use of the term “optionally,” “may,” “might,” “possibly,” and the like with respect to any element of an embodiment means that the element is not required, or alternatively, the element is required, both alternatives being within the scope of the embodiment(s). Also, references to examples are merely provided for illustrative purposes, and are not intended to be exclusive.

[0239] While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify’ subsequent reference to such steps.

[0240] Also, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other systems, modules, techniques, or methods without departing from the scope of the present disclosure. Other items shown or discussed as directly coupled or communicating with each other may be indirectly coupled or communicating through some interface, device, or intermediate component, whether electrically, mechanically, or otherwise. Other examples ofAty. Docket No.: GEG-004PCT-8022-00501changes, substitutions, and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein.

Claims

Aty. Docket No.: GEG-004PCT-8022-00501CLAIMS1. A method for producing geologic hydrogen from a subsurface rock formation, the method comprising:maintaining elevated pressure along at least a portion of a wellbore penetrating a subterranean rock formation, wherein the subterranean rock formation contains iron, and wherein water or brine in a substantially liquid state is in contact with the subterranean rock formation;generating and dissolving hydrogen generated by serpentinization of the subterranean rock formation into the water or brine;recovering hydrogen-saturated fluid from the wellbore at a pressure above atmospheric pressure;partially depressurizing the recovered fluid to an intermediate degassing pressure; desorbing a fraction of the dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system; and separating the desorbed hydrogen gas from the partially depressurized fluid.

2. The method of claim 1, wherein the intermediate degassing pressure is greater than atmospheric pressure and less than the wellbore pressure.

3. The method of claim 1, further comprising:cooling the hydrogen-saturated fluid prior to partial depressurization, andreturning partially degassed fluid to the wellbore at elevated pressure.

4. The method of claim 3, wherein cooling comprises passing the fluid through a heat exchanger, and wherein thermal energy recovered in the heat exchanger is applied to one or more downstream processes.

5. The method of claim 3, wherein partially depressurizing comprises reducing the pressure in two or more sequential stages, each stage desorbing an additional fraction of dissolved hydrogen as a free gas phase.

6. The method of claim 3, wherein partially depressurizing comprises passing the fluid through one or more devices selected from the group consisting of a throttling valve, a Joule-Thomson expansion valve, a turboexpander, a positive-displacement expander, and a staged flash vessel.Aty. Docket No.: GEG-004PCT-8022-005017. The method of claim 6, wherein at least one expander is a turboexpander that recovers shaft work from the pressure reduction and directs the recovered shaft work to drive a pump or a compressor.

8. The method of claim 3, wherein separating the desorbed hydrogen gas comprises passing the fluid through one or more devices selected from the group consisting of a cyclone separator, a vortex separator, a knock-out drum, a coalescing demister, a mesh pad separator, and a membrane-based gas-liquid separator, or combinations thereof.

9. The method of claim 3, further comprising adjusting the pH, salinity, temperature, or chemical composition of the partially degassed fluid prior to returning it to the wellbore.

10. The method of claim 3, wherein maintaining elevated pressure and recovering hydrogen-saturated fluid are performed via a single wellbore operated in a cycle comprising an injection phase, a soak phase, and a production phase.

11. The method of claim 10, wherein the injection phase comprises injecting fluid at a temperature substantially below the formation temperature, and creating a thermal shock in the formation based on the inj ecting.

12. The method of claim 10, further comprising applying a composite pressure signal to the formation comprising at least a first frequency component that controls fluid exchange between the wellbore and the formation, and a second frequency component that applies cyclic mechanical stress to the rock matrix.

13. The method of claim 10, wherein the wellbore casing is perforated at a plurality’ of vertically separated intervals, and wherein one or more intervals are optionally isolated by packers to allow independent zonal pressure control.

14. The method of claim 3, wherein maintaining elevated pressure and recovering hydrogen-saturated fluid are performed by spatially separated injection and production wells, wherein fluid injected via the injection well drives a serpentinization front progressively through the rock formation toward the production well.

15. The method of claim 1, further comprising alternating the pH of the aqueous liquid contacted with the iron-rich rock formation between a low-pH condition and a high-pH condition, wherein under the low-pH condition Fe2+is leached from the rock formation and hydrogen is generated by iron dissolution, and wherein under the high-pH condition serpentinization is promoted and hydrogen is generated by reaction-induced fracturing.Aty. Docket No.: GEG-004PCT-8022-0050116. The method of claim 15, wherein the low-pH condition comprises a pH of less than approximately 5.

2. and wherein under the low-pH condition pyroxene present in the rock formation is consumed.

17. The method of claim 15. wherein pH cycling progressively increases the reactive surface area of the formation over successive cycles.

18. The method of claim 1, wherein the wellbore comprises a mechanical packer positioned at a selected depth to define a lower active zone below the packer and an upper conduit zone above the packer, wherein the method further comprises:positioning a phase separator within the active zone configured to selectively pass hydrogen gas from the surrounding hydrogen-saturated liquid into a producer pipe extending upward through the packer and conduit zone to the surface, while substantially preventing liquid water from entering the producer pipe.

19. The method of claim 18. wherein the phase separator comprises a sintered metal body having a characteristic pore size of less than about 100 microns.

20. The method of claim 18, wherein pore surfaces of the phase separator are treated with a hydrophobic coating that creates a non-wetting surface maintaining a gas-filled zone within the pores that substantially prevents liquid water ingress during operation.

21. The method of claim 18, wherein one or more geometric ratios of the phase separator are selected from the group consisting of: a ratio of active length to outer diameter in a range of approximately 500 to 3,000; a ratio of outer diameter to wellbore inner diameter in a range of approximately 0.70 to 0.95; a ratio of wall thickness to outer diameter in a range of approximately 0.10 to 0.35; and a ratio of total interfacial surface area to active zone volume in a range of approximately 15 to 100 m2 / m3.

22. The method of claim 18, wherein positioning the phase separator within the active zone at depth reduces the thermal load on surface processing equipment relative to an openwell configuration of equivalent bore diameter and depth.

23. The method of claim 18, wherein a plurality of phase separator segments are deployed at different depth intervals within the active zone and connected in parallel to a common producer pipe.

24. The method of claim 1, wherein the partial depressurization is effected at least in part by buoyancy-driven advective transport in which dissolved hydrogen exsolves asAtty. Docket No.: GEG-004PCT-8022-00501bubbles as fluid rises in the wellbore and local hydrostatic pressure decreases, the bubbles rising through the water column and delivering hydrogen to a wellhead at an intermediate managed pressure above atmospheric pressure.

25. The method of claim 24. further comprising regulating an adjustable pressure valve at the wellhead to maintain an annular flow regime in which hydrogen gas rises through the wellbore while liquid water occupies the annular periphery and replenishment water descends through an internal pipe to maintain a substantially constant liquid head.

26. The method of claim 24, wherein the managed pressure at the wellhead is selected to satisfy one or more of: avoiding sonic choking of the gas flow; providing kinetic energy for separation of entrained liquid water; elevating the effective steam condensation temperature; and maintaining a driving force for hydrogen exsolution throughout the water column.

27. The method of claim 24, wherein geothermal heat at the base of the wellbore provides the driving force for the serpentinization reaction and the buoyancy-driven transport of hydrogen to the surface.

28. The method of claim 1, further comprising operating a plurality of wells on a common well pad sharing surface processing equipment, wherein at least one well is in an injection or soak phase while at least one other well is in a production phase.

29. The method of claim 1. further comprising separating dissolved metals or minerals from the partially degassed fluid at the surface.

30. A system for producing geologic hydrogen from a subsurface rock formation, the system comprising:a wellbore configured to penetrate a subsurface rock formation and to maintain elevated pressure along at least a portion of its length such that hydrogen generated by serpentinization dissolves into water or brine in the wellbore;one or more expanders configured to partially depressurize fluid recovered from the wellbore to an intermediate degassing pressure greater than atmospheric pressure, thereby desorbing dissolved hydrogen as a free gas phase while conserving at least a portion of the pressure energy inherent in the subsurface system; andAtty. Docket No.: GEG-004PCT-8022-00501one or more phase separators configured to separate the desorbed hydrogen gas from the partially depressurized fluid.

31. The system of claim 30, further comprising a heat exchanger configured to cool fluid produced from the wellbore prior to partial depressurization, and a high-pressure pump configured to return partially degassed fluid to the wellbore at elevated pressure.

32. The system of claim 31, further comprising a conditioning unit configured to adjust the pH, salinity, and / or chemical composition of the partially degassed fluid prior to reinjection.

33. The system of claim 30, wherein the one or more expanders comprise one or more devices selected from the group consisting of a throttling valve, a Joule-Thomson expansion valve, a turboexpander, a positive-displacement expander, and a staged flash vessel, or combinations thereof.

34. The system of claim 30. wherein the one or more phase separators comprise one or more devices selected from the group consisting of a cyclone separator, a vortex separator, a knock-out drum, a coalescing demister, a mesh pad separator, and a membrane-based gas-liquid separator, or combinations thereof.

35. The system of claim 30, further comprising:a compressor configured to increase the pressure of the separated hydrogen gas, and optionally a hydrogen purifier configured to remove trace impurity gases from the hydrogen stream.

36. The system of claim 30, wherein the wellbore comprises a mechanical packer positioned at a selected depth to define a lower active zone and an upper conduit zone, and a phase separator positioned within the active zone and connected to a producer pipe extending upward through the packer and conduit zone to the surface, the phase separator being configured to selectively pass hydrogen gas into the producer pipe while substantially preventing liquid water from entering the producer pipe.

37. The system of claim 36, wherein pore surfaces of the phase separator are treated with a hydrophobic coating that creates a non-wetting surface maintaining a gas-filled zone within the pores that substantially prevents liquid water ingress during operation.

38. The system of claim 36, wherein one or more geometric ratios of the phase separator are selected from the group consisting of: a ratio of active length to outer diameter in aAtty. Docket No.: GEG-004PCT-8022-00501range of approximately 500 to 3,000; a ratio of outer diameter to wellbore inner diameter in a range of approximately 0.70 to 0.95; a ratio of wall thickness to outer diameter in a range of approximately 0.10 to 0.35; and a ratio of total interfacial surface area to active zone volume in a range of approximately 15 to 100 m2 / m3.

39. The system of claim 30, further comprising an adjustable pressure valve at a wellhead configured to regulate flow and maintain a managed intermediate pressure above atmospheric pressure, wherein the system is configured to utilize buoyancy-driven advective transport of hydrogen exsolved from the rising water column to deliver hydrogen to the surface.

40. The system of claim 30. comprising a plurality of wellbores on a common well pad sharing one or more of the expanders, phase separators, heat exchanger, conditioning unit, and high-pressure pump, wherein individual wellbores are operable in alternating injection, soak, and production phases.

41. The system of claim 30, further comprising one or more sensors in the wellbore and a control system configured to modulate well pressure, injected fluid pH, injection flow rate, and pressure modulation parameters in response to signals from the one or more sensors.

42. A method for producing geologic hydrogen from a subsurface rock formation, comprising:isolating an active interval of a wellbore penetrating an iron-rich subsurface rock formation using a packer positioned at a selected depth;applying a first pressure signal to the active interval at a first frequency having a period on the order of minutes;applying a second pressure signal to the active interval at a second frequency having a period on the order of hours, the second pressure signal alternating between a make period at or near a stimulation pressure and a take period at a pressure below the stimulation pressure; andrecovering hydrogen from the wellbore during the take period.

43. The method of claim 42. wherein the first pressure signal has a peak interval pressure of approximately 0.6 to 0.8 of a local formation breakdown pressure.Aty. Docket No.: GEG-004PCT-8022-0050144. The method of claim 42, wherein the first and second pressure signals are applied simultaneously such that the second pressure signal is superimposed upon the first pressure signal.

45. The method of claim 42, further comprising applying a third pressure signal comprising a controlled depressurization and fluid flush on a period of approximately one to two days per month.

46. The method of claim 42, wherein the make period has a duration of approximately 3 to 6 hours and the take period has a duration of approximately 1 to 2 hours.

47. The method of claim 42, wherein the take period is held at or below a gas-entry threshold determined by reducing wellbore pressure in increments and monitoring gas response at the surface or downhole.

48. The method of claim 42, wherein the duration of the take period satisfies:tsat > (CH2 ' Vbuf) / mH2where tsat is the time to dissolved hydrogen saturation of the near-well fluid buffer, CH2 is the dissolved hydrogen concentration at operating pressure and temperature, Vbuf is the connected water buffer volume near the active interval, and mH2 is the hydrogen production rate.

49. The method of claim 42, further comprising positioning a gas buffer within the cased portion of the wellbore above the packer, the gas buffer comprising a sealed cased chamber or enlarged cased pocket.

50. The method of claim 49, further comprising:positioning a phase-selective separator at the interface between the active interval and the gas buffer, the phase-selective separator passing hydrogen gas into a producer pipe extending to the surface while substantially preventing liquid water ingress.

51. The method of claim 42, further comprising operating a downhole heater within the active interval during startup.

52. The method of claim 42, wherein the active interval is perforated at a plurality of vertically separated intervals, each perforation creating a fracture in the rock formation.Aty. Docket No.: GEG-004PCT-8022-0050153. The method of claim 52, wherein one or more of the perforated intervals are independently isolated by packers.

54. A method for producing geologic hydrogen from a subsurface rock formation, comprising:in a first phase, isolating a subsection of an active interval of a wellbore penetrating an iron-rich subsurface rock formation, the subsection being approximately 10 to 20 meters in length; applying pressure cycles at or near local formation breakdown pressure; and monitoring pressure-volume compliance or injectivity, tracer-defined connected volume, and downhole hydrogen concentration; and in a second phase, operating the full active interval of the wellbore using a first pressure signal at a first frequency having a period on the order of minutes, a second pressure signal at a second frequency having a period on the order of hours alternating between a make period and a take period, and a third pressure signal comprising a periodic depressurization and flush.

55. The method of claim 54, wherein advancement from the first phase to the second phase requires that pressure-volume compliance or injectivity, tracer-defined connected volume, and downhole hydrogen concentration all rise together following at least one controlled depressurization and flush.

56. The method of claim 54, wherein, upon failure to sustain a target production rate following one controlled depressurization and repeated threshold testing in the second phase, the method further comprises transitioning to a two-well configuration comprising a spatially separated stimulator well and a producer well.

57. A method comprising:estimating a grain-scale surface multiplier Msin an iron-rich subsurface rock formation as:Ms= 6δ / dgwhere δ is the average thickness of a wet reactive halo surrounding fracture surfaces and dg is the representative connected grain size in the reacting halo; estimating a connected reactive area as A = q ■ Ms• Af, where η is the connected fraction of the halo and Af is the total fracture area in contact with a working fluid; andAtty. Docket No.: GEG-004PCT-8022-00501applying pressure cycling to a wellbore penetrating the formation over successive cycles.

58. The method of claim 57, further comprising estimating local halo permeability kh as:kh ~ b3 / (12s)where b is the hydraulic aperture of connected grain-boundary pathways and s is the spacing between pathways.

59. The method of claim 57, further comprising estimating a hydrogen production rate MH2 over a time step At as:MH2 ~ Vr • YH2 • (Δt / tr), where Vr = η • δ · Arwhere YH2 is the hydrogen yield per fully reacted rock volume and tr is the full reaction time for a fully wetted grain of size dg.

60. A system for producing geologic hydrogen from a subsurface rock formation, comprising:a wellbore penetrating an iron-rich subsurface rock formation and comprising a packer isolating a lower active interval from an upper conduit zone;a gas buffer within the cased portion of the wellbore above the packer, the gas buffer comprising a sealed cased chamber or enlarged cased pocket;a downhole heater within the active interval; anda control system configured to apply a first pressure signal having a period on the order of minutes, a second pressure signal having a period on the order of hours alternating between a make period and a take period, and a third pressure signal comprising a periodic depressurization and flush on a period of approximately one to two days per month.

61. The system of claim 60, further comprising a phase-selective separator positioned between the active interval and the gas buffer and connected to a producer pipe extending through the packer and conduit zone to the surface, wherein the separator areaAsep satisfies:where Dsep and Lsep are the outer diameter and active length of the separator.Aty. Docket No.: GEG-004PCT-8022-0050162. The system of claim 60, wherein one or more of casing connections, cement, packers, feedthroughs, gauges, and wellhead assemblies are thermal-rated components, and wherein the active interval comprises an open-hole or perforated completion without a slotted liner.

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