System and method for utilization of electrical reservoir stimulation for enhanced natural hydrogen recovery

Abstract

Disclosed embodiments are related to systems and methods for electrohydraulic fracturing of rock formations that generate and / or store naturally occurring hydrogen.

Description

SYSTEM AND METHOD FOR UTILIZATION OF ELECTRICAL RESERVOIR STIMULATION FOR ENHANCED NATURAL HYDROGEN RECOVERYCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of and priority under 35 U.S.C. § 119(e) to U.S. Provisional Application Number 63 / 570,449, filed March 27, 2024, entitled SYSTEM AND METHOD FOR UTILIZATION OF ELECTRICAL RESERVOIR STIMULATION FOR ENHANCED NATURAL HYDROGEN RECOVERY, the contents of which are incorporated herewith by reference in their entirety.FIELD

[0002] Disclosed embodiments are related to systems and methods for electrohydraulic fracturing rock formations, including subterranean formations.BACKGROUND

[0003] Naturally occurring hydrogen (sometimes referred to as “white” hydrogen) is a potential, low-carbon energy source that is currently underutilized. Accordingly, improved systems and methods for extracting naturally occurring hydrogen are desired.SUMMARY

[0004] In one aspect, a method for extracting naturally occurring hydrogen from a subterranean formation is described, the method comprising applying a current to the subterranean formation; fracturing the subterranean formation in response to the applied current to increase a permeability of the subterranean formation to be greater than the permeability of the subterranean formation prior to fracturing; and extracting hydrogen from the subterranean formation.

[0005] In another aspect, a method for extracting naturally occurring hydrogen from a subterranean formation is described, the method comprising applying a current to a portion of subterranean formation having a permeability of less than or equal to 105m2; fracturing the portion of the subterranean formation in response to the applied current such that the permeability of the portion of subterranean formation increases to greater than or equal to 10’14m2; and extracting hydrogen from the subterranean formation.

[0006] In another aspect, a system is described, the system comprising a power source; at least two electrodes connected to the power source; at least one pump; and at least one processor configured to operate the power source and the at least one pump to perform a method as described herein.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The accompanying drawings are not intended to be drawn to scale. In the drawings, each identical or nearly identical component that is illustrated in various figures may be represented by a like numeral. For purposes of clarity, not every component may be labeled in every drawing. In the drawings:

[0008] Fig. 1 depicts a system for rock fracturing using electric stimulation, according to some embodiments;

[0009] Fig. 2 is a flow chart depicting a process for extracting a resource from a rock formation by forming new fractures in the rock formation, according to some embodiments;

[0010] Fig. 3 depicts a schematic diagram showing a rock formation where a reservoir containing hydrogen has low permeability prior to electrohydraulic fracturing, according to some embodiments;

[0011] Fig. 4A is a schematic diagram showing a rock formation with a low permeability between different strata associated with migration of hydrogen within the subterranean formation, according to some embodiments;

[0012] Fig. 4B is a schematic diagram showing the rock formation of Fig. 4A after electrohydraulic fracturing of the rock formation, where electrohydraulic fracturing has increased the permeability of the rock formation relative to Fig. 4A, allowing more hydrogen to be extracted from the rock formation, according to some embodiments;

[0013] Fig. 5A is a schematic diagram showing a rock formation where hydrogen is sealed from a reservoir closer to the surface by a capping layer, according to some embodiments;

[0014] Fig. 5B is a schematic diagram of the rock formation in Fig. 5A, but after electrohydraulic fracturing has fractured the capping layer, allowing natural hydrogen to flow towards the reservoir closer to the surface, according to some embodiments;

[0015] FIG. 6 is a chart depicting hydrogen production data, according to some embodiments;

[0016] FIG. 7 is a chart depicting permeability of a rock formation using electrical reservoir stimulation, according to some embodiments;

[0017] FIG. 8 is a chart depicting permeability rates of various rock samples using various fracturing techniques, according to some embodiments; and

[0018] FIG. 9 is a magnified image comparing a rock formation before and after application of current.DETAILED DESCRIPTION

[0019] The following disclosure describes systems and methods for improving the recovery of naturally occurring hydrogen. Hydrogen can be produced naturally by a variety of natural geologic processes, including serpentinization, cataclasis, and radiolysis within rocks containing radioactive elements such as uranium, thorium, and potassium, among other processes. In addition, many natural stores of hydrogen exist as remnants from the formation of the Earth and remain locked within the Earth due to tightly packed subterranean rock formations that may be sealed or become sealed because of natural geologic changes (e.g., shifting of tectonic plates). In either case, the Inventors have recognized that the extraction of natural hydrogen faces various obstacles, including low reservoir permeability, sealed reservoirs, and / or limitations in migration pathways from a hydrogen source to a reservoir suitable for extraction.

[0020] In view of the above, the Inventors have recognized and appreciated that electric reservoir stimulation, which may also be referred to as electrohydraulic fracturing herein, may increase hydrogen (i.e., H2) recovery and commercial production by increasing subsurface rock formation permeability and / or creating permeability in a rock formation where there is none. Creating and / or increasing permeability of a rock formation for hydrogen migration and / or extraction may advantageously increase the permeability of these natural hydrogen reservoirs, and, hence, hydrogen production can be dramatically increased relative to the same geologic formations prior to electrical reservoir stimulation.

[0021] The systems and method described herein may be advantageous for improving the permeability of rock formations (e.g., subterranean rock formations) that contain and / or are adjacent to natural reservoirs of hydrogen (e.g., reservoirs including H2, hydrogen gas, hydrogen dissolved or dispersed within the natural hydrogen reservoir, etc.). Specifically,hydrogen may occur naturally within Earth, either trapped in hydrogen reservoirs during the formation of the Earth billions of years ago and / or generated in situ within rock formations by hydrogen-forming processes (e.g., serpentinization, cataclasis, radiolysis). Regardless of the formation mechanism, this naturally occurring hydrogen is often trapped between and / or within low permeability (e.g., less than IO5m2) and / or hard rock formations which limits the ability to extract hydrogen from these reservoirs. However, the Inventors have recognized and appreciated that electric stimulation of a natural hydrogen reservoir and / or a rock formation adjacent to a natural hydrogen reservoir may dramatically improve the rate of hydrogen extraction as compared to extraction rates prior to electric stimulation (e.g., at least 2 times, at least 4 times of an increased rate of hydrogen extraction).

[0022] In some embodiments a natural hydrogen reservoir is located in a subterranean formation, two or more wells can be drilled in to or adjacent to the hydrogen reservoir, and one or more wells, or optionally all of the wells, may optionally have a fluid injected into the one or more wells (e.g., a fracturing fluid, a transport fluid comprising proppants to “prop” open new or existing fractures, and / or an electrically conductive fluid) and an electrical potential can be applied across the fluid. This may include injecting and flowing the fluid into both the wells as well as any fractures extending out from and / or between the wells. As described in more detail elsewhere herein, applying the electrical potential across the fluid and / or subterranean formation may cause new fractures in or near the natural hydrogen reservoir and / or may cause existing fractures in or near the natural hydrogen reservoir to further expand and / or propagate. This fracturing may result in an increase in reservoir permeability which may advantageously increase the rate of hydrogen extraction from the natural hydrogen reservoir. This increase in natural hydrogen reservoir permeability may be implemented in a number of different types of rock formations as elaborated on further below.

[0023] Depending on the embodiment, a natural hydrogen reservoir itself need not be electrically stimulated (although in many embodiments, it may be). Rather, subsurface formations adjacent to the hydrogen reservoir may be electrically stimulated such that the rock formation becomes more permeable to the migration of hydrogen into and / or through the formation from the adjacent natural hydrogen reservoir. For example, in one embodiment, a dense low porosity stratum (e.g., capping layer) may be disposed between the naturalhydrogen reservoir and a reservoir closer to the surface relative to the natural hydrogen reservoir. In such an embodiment, electrical stimulation may be provided such that the capping layer is fractured by electric stimulation to allow hydrogen to flow from the natural hydrogen reservoir to the adjacent, closer-to-the surface reservoir. In such an embodiment, the natural hydrogen reservoir and the closer-to-the surface reservoir may have porosities and permeabilities greater than a porosity and permeability of the capping layer. Of course, in some embodiments, the natural hydrogen reservoir and / or the adjacent rock formation (e.g., the reservoir from which the hydrogen is extracted) disposed on opposing sides of the capping layer may be electrically stimulated (e.g., current is passed directly through a fluid within the natural hydrogen reservoir) to increase a permeability of either of these subterranean formations. As noted above, electrohydraulically fracturing, which may also be referred to as electrically stimulating, a subterranean formation may enhance the permeability of the subterranean formation. For example, in some embodiments, a permeability of a subterranean formation prior to electrohydraulic fracturing may be less than or equal to 1045m2. In some embodiments, the permeability of a subterranean formation (e.g., after electrical stimulation) may exhibit an increase in permeability of at least 2, 4, 8, 10, 100 or other appropriate multiple increase in permeability after electrohydraulic fracturing. In some instances, the increase in permeability may be less than 1000, 100, or other appropriate multiple of the original permeability of the formation. For example, a formation may exhibit an increase in permeability between or equal to 2 and 1000 times the original permeability, though other potential increases are possible.

[0024] In some embodiments, a permeability of a rock formation (e.g., a subterranean formation) before electrohydraulic fracturing is relatively low. In some embodiments, the permeability of the rock formation prior to electrical stimulation may be between or equal to 1048m2and 1045m2(e.g., greater than or equal to 108m2, greater than or equal to 107m2, greater than or equal to 1046m2, greater than or equal to 1045m2; less than or equal to 1045m2, less than or equal to 1046m2, less than or equal to 1047m2, less than or equal to 1048m2; combinations are possible). In some embodiments, rock formations exhibiting the above permeability ranges may be considered to be impermeable to diffusion of a desired resource (e.g., hydrogen).

[0025] After electrohydraulic fracturing, the permeability of the rock formation may be relatively high (e.g., relative to before electrical stimulation). In some embodiments, the permeability of a subterranean formation after electrohydraulic fracturing may be between or equal to 1044m2and 10'7m2(e.g., greater than or equal to 1044m2, greater than or equal to 1043m2, greater than or equal to 102, greater than or equal to 101m2, greater than or equal to IO40m2, greater than or equal to 10'9m2, greater than or equal to 10'8m2, greater than or equal to 10'7m2; less than or equal to 10'7m2, less than or equal to 10'8m2, less than or equal to 10'9m2, less than or equal to IO40m2, less than or equal to 101m2, less than or equal to 1042m2, less than or equal to 1043m2,; combinations of the forgoing are possible).

[0026] To measure a permeability of a rock formation (e.g., a subterranean formation, a reservoir), for example, either before or after electrically fracturing, single and cross-well pumping tests may be performed to determine the initial and / or final permeabilities of the rock formation. This includes the injection of water, or other appropriate fluid, in one or more wells, and a measurement of hydraulic pressure responses in the one or more wells.

[0027] Electrically fracturing and / or Joule heating may increase the generation and / or extraction rate of hydrogen. In some embodiments, a rate of hydrogen generation (e.g., from a reaction of water with iron, from a reaction of water with silicon radicals) is greater than 0.0001 nanomoles th / gram rock and less than or equal to 10,000 nanomoles th / gram rock (e.g., greater than or equal to 0.0001 nanomoles th / gram rock, greater than or equal to 0.01 nanomoles th / gram rock, greater than or equal to 1 nanomoles th / gram rock, greater than or equal to 100 nanomoles th / gram rock, greater than or equal to 10,000 nanomoles th / gram rock; less than or equal to 10,000 nanomoles th / gram rock, less than or equal to 100 nanomoles th / gram rock, less than or equal to 1 nanomoles th / gram rock, less than or equal to 0.01 nanomoles th / gram rock, less than or equal to 0.0001 nanomoles th / gram rock; combinations of these ranges are possible). Other ranges are possible as this disclosure is not so limited.

[0028] In some embodiments, the subterranean formation comprises one or more rock types or minerals that may contain natural hydrogen either due to trapping the hydrogen within the formation and / or through generation of the hydrogen in the formation. Subterranean formations that may contain natural hydrogen include, but are not limited to, a peridotite, iron-rich, olivine-rich, mafic, ultramafic, skarn, iron-rich metasomatic rock, layered maficintrusion, and / or massive sulfide (e.g., greater than or equal to 60 wt% sulfides) rock formations. Additional non-limiting examples rock types or minerals include felsic rocks, silicic rocks, mafic rocks, ultramafic rocks, porphyry deposits, both high and low sulfidation epithermal deposits, skarn deposits, orogenic gold deposits, quartzite, sandstone, metapelites, metabasites, rhyolite, dacite syenite, monzonite, and granite. Additional rock formations include, but are not limited to, ultramafic rocks such as iron-rich peridotite, mafic rocks such as basalts, dolerites and gabbros, hydrothermally-altered ultramafic rocks such as serpentinites, other iron-rich formations, such as Banded Iron Formations (BIFs), iron skarns, iron-oxide-copper-gold deposits, Kimberlite Pipes, Fault Zones, potassium-bearing rocks, uranium-bearing rocks, felsic rocks such as radioactive mineral containing igneous rocks, rocks containing radioactive wastes, crystalline basement rocks, sedimentary rocks such as coal, organic -rich shales, sandstone, siltstone, limestone, and dolostone, among others. Other rock and mineral types are described below. Importantly, these formations may contain hydrogen trapped during the formation of the Earth and / or these formations may contain hydrogen generated from natural processes (e.g., serpentinization, subterranean hydrogengenerating microbes). Depending on the specific type of rock formation, the rock formation may act as a generation reservoir where hydrogen is generated and / or the hydrogen may simply be stored in the reservoir. In either case, the disclosed rock formation types may be used to extract hydrogen using the methods and systems disclosed herein.

[0029] Some embodiments are particularly suited for fracturing relatively hard subterranean formations. For example, in some embodiments, the hardness of the subterranean formation is between or equal to 2 on the Mohs scale and 8 on the Mohs scale (e.g., greater than or equal to 2, greater than or equal to 4, greater than or equal to 6, greater than or equal to 8; less than or equal to 8, less than or equal to 6, less than or equal to 4; combinations are possible).

[0030] As was noted above, various embodiments described herein involve electrically fracturing a subterranean formation (or other rock formation) by injecting a fluid (e.g., a fracturing fluid, a transport fluid) into the subterranean formation and applying an electrical potential across the fluid. Without wishing to be bound by any particular theory, it is believed that the application of an electrical potential across the fluid within the subterranean fluid results in Joule heating of the subterranean feature, which may promote fracturing of the subterranean formation. Joule heating is described in more detail below and elsewhere herein.

[0031] As mentioned above, in some embodiments, a fluid is injected into a rock formation (e.g., a subterranean formation). In some such embodiments, the fluid promotes fracturing of the rock formation, and hence is a fracturing fluid. In some such embodiments, the fluid transports materials helpful for promoting fracturing of the rock formation, such as proppants (e.g., conductive and / or non-conductive proppants), which can help form or maintain fractures within the rock formation. A variety of fluids may be used as a fracturing fluid and / or transport fluid. Non-limiting examples include water (e.g., freshwater), brines (i.e., aqueous solutions with excess salt(s)), compressed gas (e.g., liquefied petroleum gas), and / or carbon dioxide (e.g., supercritical carbon dioxide).

[0032] In some embodiments, a transport fluid is present at a particular amount within an electrohydraulic fracturing composition. In some embodiments, the transport fluid is greater than or equal to 10 wt%, greater than or equal to 20 wt%, greater than or equal to 30 wt%, greater than or equal to 50 wt%, greater than or equal to 70 wt%, greater than or equal to 90 wt%, greater than or equal to 95 wt%, or greater than or equal to 99 wt% of the total weight of the hydraulic fracturing composition. In some embodiments, the transport fluid is less than or equal to 99 wt%, less than or equal to 95 wt%, less than or equal to 90 wt%, less than or equal to 70 wt%, less than or equal to 50 wt%, less than or equal to 30 wt%, less than or equal to 20 wt%, or less than or equal to 10 wt% of the total weight of the hydraulic fracturing composition. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 10 wt% and less than or equal to 99 wt%). Other ranges are possible. The remaining portions of the hydraulic fracturing composition may be other components (e.g., additives, proppants). Other components are described elsewhere herein.

[0033] To facilitate electrohydraulic fracturing and / or heating (e.g., Joule heating) of a subterranean formation, a fluid injected into a well (e.g., a hydraulic fracturing fluid) may have a particular electrical conductivity. In some embodiments, the electrical conductivity of the fluid is greater than or equal to 100 pS / cm, greater than or equal to 200 pS / cm, greater than or equal to 500 pS / cm, greater than or equal to 1,000 pS / cm, greater than or equal to 5,000 pS / cm, greater than or equal to 10,000 pS / cm, greater than or equal to 50,000 pS / cm, or greater than or equal to 100,000 pS / cm. In some embodiments, the electrical conductivity of the fluid is less than or equal to 100,000 pS / cm, less than or equal to 50,000 pS / cm, less than or equal to 10,000 pS / cm, less than or equal to 5,000 pS / cm, less than or equal to 1,000pS / cm, less than or equal to 500 |aS / cm, less than or equal to 200 pS / cm, or less than or equal to 100 pS / cm. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 100 qS / cm and less than or equal to 100,000 qS / cm). Other ranges are possible as this disclosure is not so limited. In some embodiments, a fluid comprises additives, such as proppants, to facilitate fracturing. Non-limiting examples of proppants include alumina (AI2O3), silica (SiO2), and / or polymers, such as copolymers (e.g., resin C21H25CIO5).

[0034] In some embodiments, the fluid (e.g., a transport fluid, a fracturing fluid) comprises a conductive proppant. Non-limiting examples of conductive proppant include ceramic particles (e.g., electrically conductive ceramic particles), coated particles (e.g., particles coated with a conductive material such as a conductive metal or other conductive material, conductive composite particles where the composite particles include a non-conductive and conductive material), copolymers and resin, carbon particles (e.g., carbon black, acetylene black, petroleum coke, graphite), and metal particles (e.g., stainless steel shot). Additional non-limiting examples of conductive proppants include porous or sintered metals, such as aluminum or aluminum alloys. Combinations of these additives are also possible (e.g., petroleum coke and another proppant, coated particle and / or uncoated particles). Other conductive proppants are possible.

[0035] In some embodiments, an additive (e.g., a proppant) is present within the fluid (e.g., a fracturing fluid, a transport fluid) at a particular amount or concentration. In some embodiments, a weight percentage of additive within the fluid is greater than or equal to 1 wt%, greater than or equal to 2 wt%, greater than or equal to 3 wt%, greater than or equal to 5 wt%, greater than or equal to 10 wt%, greater than or equal to 15 wt%, greater than or equal to 20 wt%, greater than or equal to 25 wt%, greater than or equal to 30 wt%, greater than or equal to 40 wt%, greater than or equal to 50 wt%, or greater than or equal to 60 wt%. In some embodiments, a weight percentage of additive within the fluid is less than or equal to 60 wt%, less than or equal to 50 wt%, less than or equal to 40 wt%, less than or equal to 30 wt%, less than or equal to 25 wt%, less than or equal to 20 wt%, less than or equal to 15 wt%, less than or equal to 10 wt%, less than or equal to 5 wt%, less than or equal to 3 wt%, less than or equal to 2 wt%, or less than or equal to 1 wt%. Combinations of the foregoing ranges also possible (e.g., greater than or equal to 1 wt% and less than or equal to 60 wt%). Of course, other ranges are possible as this disclosure is not so limited.

[0036] An additive (e.g., a proppant) to the fluid (e.g., a fracturing fluid, a transport fluid) may have a particular size or dimension. In some embodiments, an average maximum transverse dimension of an additive is greater than or equal to 100 pm, greater than or equal to 200 pm, greater than or equal to 300 pm, greater than or equal to 400 pm, greater than or equal to 500 pm, greater than or equal to 600 pm, greater than or equal to 700 pm, greater than or equal to 800 pm, greater than or equal to 900 pm, greater than or equal to 1,000 pm, greater than or equal to 2 mm, or greater than or equal to 3 mm. In some embodiments, an average maximum transverse dimension of an additive is less than or equal to 3 mm, less than or equal to 2 mm, less than or equal to 1,000 pm, less than or equal to 900 pm, less than or equal to 800 pm, less than or equal to 700 pm, less than or equal to 600 pm, less than or equal to 500 pm, less than or equal to 400 pm, less than or equal to 300 pm, less than or equal to 200 pm, or less than or equal to 100 pm. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 100 pm and less than or equal to 3 mm). Other ranges are possible.

[0037] In some embodiments, an additive (e.g., a proppant) within a fluid (e.g., a transport fluid, a fracturing fluid) may include a plurality of porous particles with a particular average porosity. In some embodiments, the average porosity of the additive particles is greater than or equal to 10%, greater than or equal to 15%, greater than or equal to 20%, greater than or equal to 25%, greater than or equal to 30%, greater than or equal to 40%, greater than or equal to 50%, greater than or equal to 60%, or greater than or equal to 70%. In some embodiments, the average porosity of the additive particles is of less than or equal to 70%, less than or equal to 60%, less than or equal to 50%, less than or equal to 40%, less than or equal to 30%, less than or equal to 25%, less than or equal to 20%, less than or equal to 15%, or less than or equal to 10%. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 10% and less than or equal to 70%). Other ranges are possible.

[0038] In some embodiments, an additive (e.g., a proppant) of a fluid (e.g., a fracturing fluid, a transport fluid) has a particular average pore size. For example, in some embodiments, the additive has an average pore diameter of greater than or equal to 50 nm, greater than or equal to 100 nm, greater than or equal to 200 nm, greater than or equal to 250 nm, greater than or equal to 500 nm, greater than or equal to 750 nm, greater than or equal to 1 pm, greater than or equal to 5 pm, greater than or equal to 10 pm, greater than or equal to 20 pm, greater thanor equal to 25 uni. greater than or equal to 50 uni. greater than or equal to 100 uni. greater than or equal to 250 qm, greater than or equal to 500 uni. greater than or equal to 750 uni. or greater than or equal to 1,000 m. In some embodiment, the additive has an average pore diameter of less than or equal to 1,000 qm, less than or equal to 750 qm, less than or equal to 500 qm, less than or equal to 250 qm, less than or equal to 100 qm, less than or equal to 50 qm, less than or equal to 25 qm, less than or equal to 20 qm, less than or equal to 10 qm, less than or equal to 5 qm, less than or equal to 1 qm, less than or equal to 750 nm, less than or equal to 500 nm, less than or equal to 250 nm, less than or equal to 100 nm, or less than or equal to 50 nm. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 50 nm and less than or equal to 1,000 qm). Other ranges are possible as this disclosure is not so limited.

[0039] In any of the embodiment disclosed herein, an additive to a hydraulic fracturing composition comprises a surfactant which may help with the extraction of hydrogen from a reservoir or other formation. Various appropriate surfactants are known, and include anionic surfactants, cationic surfactants, nonionic surfactants, and / or amphiphilic surfactants, without limitation. In some such embodiments, a hydraulic fracturing system includes one or more pump configured to inject the hydraulic fracturing composition into the reservoir, where the hydraulic fracturing composition comprises a transport fluid and a conductive proppant. The system may also include, two or more electrodes positioned in two or more spaced apart bore holes configured to apply a potential across at least a portion of the reservoir and / or a proppant reservoir containing the hydraulic fracturing composition, where the proppant reservoir is in fluidic communication with the hydraulic fracturing pump. When injecting a fluid (e.g., a fracturing fluid, a transport fluid) into a rock formation (e.g., a subterranean formation), the rock formation and / or the surrounding well environment may be under relatively high pressures. In some embodiments, a well environment may be associated with a pressure of greater than or equal to 5 megapascals (MPa), 10 MPa, 25 MPa, 50 MPa, 100 MPa, or other appropriate pressure. In some embodiments, a well environment may be associated with a pressure of less than or equal to 150 MPa, 100 MPa, 50 MPa, 25 MPa, 10 MPa, or other appropriate pressure. Combinations of the above are contemplated including, for example, a pressure between about 5 MPa and 150 MPa. However, pressure ranges both greater than and less than those noted above are also contemplated.

[0040] As described above and elsewhere herein, various embodiments include electrically fracturing a rock formation (e.g., a subterranean formation) to facilitate the extraction of geologic hydrogen. In some embodiments, electricity is provided to the rock formation via direct current (e.g., a DC or an AC current from a power source). In some embodiments, the direct or alternating current has a voltage of greater than or equal to 50 V, greater than or equal to 100 V, greater than or equal to 500 V, greater than or equal to 1 kV, greater than or equal to 5 kV, greater than or equal to 10 kV, greater than or equal to 50 kV, or greater than or equal to 100 kV. In some embodiments, the direct or alternating current has a voltage of less than or equal to 400 kV, 300 kV, 250 kV, 200 kV, 100 kV, less than or equal to 50 kV, less than or equal to 10 kV, less than or equal to 5 kV, less than or equal to 1 kV, less than or equal to 500 V, less than or equal to 100 V, or less than or equal to 50 V. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 50 V and less than or equal to 100 kV). In another embodiment, the voltage may be between or equal to 1 kV and 400 kV. Other ranges are possible as this disclosure is not so limited.

[0041] In some embodiments, a DC or an AC power device provides an electric current to the rock formation (e.g., via two or more electrodes) with a particular amount of power. In some embodiments, the electric current has a power of greater than or equal to 1 MW, greater than or equal to 5 MW, greater than or equal to 10 MW, greater than or equal to 50 MW, greater than or equal to 100 MW, greater than or equal to 500 MW, or greater than or equal to 1,000 MW. In some embodiments, the electric current has a power of less than or equal to 1,000 MW, less than or equal to 500 MW, less than or equal to 100 MW, less than or equal to 50 MW, less than or equal to 10 MW, less than or equal to 5 MW, or less than or equal to 1 MW. Combinations of the above-referenced ranges are also possible (e.g., greater than or equal to 1 MW and less than or equal to 1,000 MW). Of course, other ranges are possible as this disclosure is not so limited.

[0042] In some embodiments, an electric pulse can be administered via a pulsed power device with a particular voltage. In some embodiments, the electric pulse has a peak voltage of greater than or equal to 50 V, greater than or equal to 100 V, greater than or equal to 500 V, greater than or equal to 1 kV, greater than or equal to 5 kV, greater than or equal to 10 kV, greater than or equal to 50 kV, greater than or equal to 100 kV, greater than or equal to 300 kV, greater than or equal to 500 kV, greater than or equal to 700 kV, or greater than or equalto 800 kV. In some embodiments, the electric pulse has a peak voltage of less than or equal to 1000 kV, 800 kV, less than or equal to 700 kV, less than or equal to 500 kV, less than or equal to 300 kV, less than or equal to 100 kV, less than or equal to 50 kV, less than or equal to 10 kV, less than or equal to 5 kV, less than or equal to 1 kV, less than or equal to 500 V, less than or equal to 100 V, or less than or equal to 50 V. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 50 V and less than or equal to 100 kV). In another embodiment, the peak voltage may be between or equal to 1 kV and 100 kV. In another embodiment, the peak voltage may be between or equal to 500 kV and 1000 kV. Other ranges are possible as this disclosure is not so limited.

[0043] In some embodiments, a pulse power device administers an electric pulse with a particular amount of energy. In some embodiments, an electric pulse is delivered with greater than or equal to 1 kJ / pulse, greater than or equal to 5 kJ / pulse, greater than or equal to 10 kJ / pulse, greater than or equal to 25 kJ / pulse, greater than or equal to 50 kJ / pulse, greater than or equal to 75 kJ / pulse, or greater than or equal to 100 kJ / pulse. In some embodiments, an electric pulse is delivered with less than or equal to 100 kJ / pulse, less than or equal to 75 kJ / pulse, less than or equal to 50 kJ / pulse, less than or equal to 25 kJ / pulse, less than or equal to 10 kJ / pulse, less than or equal to 5 kJ / pulse, or less than or equal to 1 kJ / pulse. Combinations of the foregoing ranges are also possible (e.g., greater than or equal to 1 kJ / pulse and less than or equal to 100 kJ / pulse). Other ranges are possible as this disclosure is not so limited.

[0044] In some embodiments, a pulse power device administers an electric pulse with a particular amount of power. In some embodiments, the electric pulse has a peak power of greater than or equal to 1 MW, greater than or equal to 5 MW, greater than or equal to 10 MW, greater than or equal to 50 MW, greater than or equal to 100 MW, greater than or equal to 500 MW, or greater than or equal to 1,000 MW. In some embodiments, the electric pulse has a peak power of less than or equal to 1,000 MW, less than or equal to 500 MW, less than or equal to 100 MW, less than or equal to 50 MW, less than or equal to 10 MW, less than or equal to 5 MW, or less than or equal to 1 MW. Combinations of the above-referenced ranges are also possible (e.g., greater than or equal to 1 MW and less than or equal to 1,000 MW). Of course, other ranges are possible as this disclosure is not so limited.

[0045] It should be appreciated that a power source may be configured to generate (and / or a high voltage cable may be configured to accommodate) electricity of any suitable current, as the disclosure is not limited in this regard. In some embodiments, the power source may be configured to generate a peak current of greater than or equal to 10 amperes (A), 20 A, 50 A, 100 A, 250 A, 500 A, 1 kA, or 10 kA. In some embodiments, the power source may be configured to generate a peak current of less than or equal to lOkA, 1 kA, 500 A, 250 A, 100 A, 50 A, or 20 A. Typical operating ranges may include currents in the range of 10-80 A. However, current ranges both greater than and less than those noted above are also contemplated.

[0046] One or more electrodes (e.g., two electrodes) may be used to electrically stimulate a fracture. The one or more electrodes are operatively associated with one or more power sources to provide power, as described above. In some embodiments, the one or more electrodes are configured to apply an electrical potential (i.e., voltage) between or adjacent to a first portion of the reservoir and a second portion of the reservoir. In some such embodiments, the applied electrical potential heats the reservoir (e.g., via Joule heating) due to the flow of current between the electrodes and through the formation and / or a fluid (e.g., a fracturing fluid) within the formation. Non-limiting examples of appropriate electrodes may include titanium, aluminum, copper, and alloys and / or compounds thereof.

[0047] It will be understood that the one or more electrodes need not be in direct contact with the rock formation. For example, the one or more electrodes may be in contact with a fracture in fluidic communication a portion of the rock formation (e.g., a reservoir within the rock formation), and the electrode(s) may provide energy to the fracture (e.g., a fluid within the fracture and / or in fluidic communication with the reservoir). Thus, electrohydraulic fracturing and / or heating of the reservoir may be conducted even without direct contact with a portion of a subterranean formation including a composition appropriate for forming geologic hydrogen. As noted elsewhere herein and described in more detail below, electrical stimulation of a fluid (e.g., a transport fluid, a fracturing fluid) within a rock formation (e.g., a subterranean formation) can also be used, in some embodiments, to control or maintain the temperature of the rock formation, e.g., by heating the rock formation via Joule heating, where a current is passed through the reservoir and / or a fluid within the reservoir. Joule heating describes the generation of heat by passing of current through an electricallyconductive medium to produce thermal energy, providing heat to the surroundings. Advantageously, the increased temperature of the rock formation facilitated by Joule heating may promote fracturing by expansion (and / or contraction) of portions of a rock formation during heating and cooling. As another advantage, certain reactions are more favorable at certain temperatures, so heating the rock formation may provide temperatures more suitable those certain reactions (e.g., hydrogen generation and / or extraction). Thus, as described in more detail elsewhere herein, electrical stimulation may not only promote additional fracturing of a rock formation via expansion and / or contraction, it may also promote certain reactions to occur more readily and / or may help reduce the reaction rate of certain undesirable reactions. Those certain reactions may generate desirable products (e.g., hydrogen) that can be subsequently extracted.

[0048] Systems and methods described herein may provide heat and / or maintain a temperature of a rock formation (e.g., a subterranean formation, a reservoir within a subterranean formation). In some embodiments, electrically stimulating a rock formation comprises heating at least a portion of the reservoir by greater than or equal to 1 °C, greater than or equal to 2 °C, greater than or equal to 5 °C, greater than or equal to 10 °C, greater than or equal to 50 °C, greater than or equal to 80 °C, greater than or equal to 100 °C, greater than or equal to 200 °C, greater than or equal to 300 °C, greater than or equal to 400 °C, or other appropriate temperature relative to a temperature of the reservoir prior to electrically heating the reservoir. The temperature of the rock formation may also be heated by less than or equal to 400 °C, 300 °C, 200 °C, less than or equal to 100 °C, less than or equal to 80 °C, or other appropriate temperature. Combinations of the above are contemplated including heating a temperature of a formation by between 100 °C and 400 °C relative to a temperature of the rock formation. Other temperatures relative to a temperature of the rock formation prior to injecting the fluid (e.g., a fracturing fluid, a transport fluid) are also possible.

[0049] In some embodiments, the temperature of the rock formation (e.g., a fluid within or adjacent to the rock formation) is controlled or maintained to suppress or eliminate reactions that would consume natural hydrogen. These include (but are not limited) to parasitic oxidation reactions that oxidize hydrogen. In some embodiments, the temperature of the rock formation is controlled or maintained between 80 °C and 200 °C, as described just above andelsewhere herein as this temperature range is associated with reduced reaction rates for these parasitic oxidation reactions with hydrogen.

[0050] As previously noted, in some embodiments, it is desirable to control a temperature of a rock formation (e.g., subterranean formation). In such an embodiment, a temperature, or other parameter related to the rock formation, can be sensed by one or more sensors, for example, positioned downhole within a well formed in the rock formation. The one or more sensors may either be separate from or connected to, for example, a downhole electrode(s) used to apply electrical potentials to the rock formation. In either case, the one or more sensors may sense one or more parameters. Appropriate parameters may include, but are not limited to temperature, pressure, gas composition, and / or other appropriate parameters. The operation of one or more electrodes may then be controlled based on the sensed one or more parameters. For example, in instances where it is desirable to control a temperature of the rock formation, the current, electrical potential, power, and / or other operating parameter applied by the one or more electrodes may be controlled to maintain a temperature of the rock formation to be within a predetermined range of temperatures, as described in more detail elsewhere herein. One or more electrodes may be used to continuously dissipate electric energy as heat (e.g., via Joule heating) through the rock formations and / or fluid within the pores of the rock formation. In some such embodiments, both DC and AC (or a combined DC / AC) stimulation may be used. The electric current can heat the reservoir with power proportional to both voltage and current.

[0051] As used herein a subterranean formation, rock formation, formation, or other similar term may refer to a geologic formation that includes one or more portions (e.g., strata or other arrangements of these different geologic formation) with any appropriate combination of rocks and / or minerals contained therein. These formations may include various types of reservoirs such as hydrogen containing reservoirs (e.g., portions of the subterranean formation that either include trapped hydrogen and / or generate hydrogen due to natural processes) and / or porous reservoirs which may correspond to formations with a desired porosity and / or other property which may result in the reservoir being desirable for use in extracting hydrogen from the subterranean formation due to migration of hydrogen from the hydrogen containing reservoir to the separate porous reservoir. Turning to the figures, specific non-limiting embodiments are described in further detail. It should be understoodthat the various systems, components, features, and methods described relative to these embodiments may be used either individually and / or in any desired combination as the disclosure is not limited to only the specific embodiments described herein.

[0052] Fig. 1 schematically depicts an embodiment of a system that may be used to electrohydraulically fracture and / or stimulate a subterranean formation 101. The depicted system 100 includes a surface power source 102 coupled to two or more downhole tools 110a, and 110b, which are depicted as electrodes disposed on a distal end portion of the cable or drill string, disposed within the wells 112a and 1 lb, respectively. The wells 112a and 112b may be used for the same or different purposes. For example, in one embodiment, both wells 112a and 112b can be used to extract a particular resource (e.g., oil, natural gas, hydrogen). In another embodiment, well 112a is used to provide water (or some other fluid) while well 112b to extract a particular resource. Of course, other combinations are possible, as this disclosure is not so limiting, and those of ordinary skill in the art, in view of this disclosure will be capable of providing a variety of wells for providing a fluid to a subterranean formation and / or extracting resources from the subterranean formation.

[0053] The power source 102 in Fig. 1 is connected to the downhole tools 110a and 110b by separate, high-voltage cables 114a and 114b, respectively, or other electrical conductor, that are configured to transmit power (e.g., direct current, alternating current, pulsed power) from the power source 102 to the downhole tools 110a and 110b to perform the described electrohydraulic fracturing and / or Joule heating of a subterranean formation, and, in some instances tailings. During operation, the power source 102 may be electrically connected to the depicted two or more electrodes disposed in two or more wells, or any other appropriate number of electrodes and wells, to permit the passage of current between the electrodes through a formation as elaborated on further below. Of course, it should be understood that an overall system used to implement any of the methods disclosed herein may be implemented using two or more electrodes, which may either correspond to the system depicted in Fig. 1 and / or may correspond to any appropriate type of electrodes as the disclosure is not limited in this fashion.

[0054] As noted above, the depicted system 100 may also be used maintain the subterranean formation within a predetermined temperature range greater than or equal to 25 °C (e.g., 250 °C) for any of the reasons and for any of the temperature ranges noted previously above. Thismay facilitate the formation and / or extraction of hydrogen from the wells drilled into the subterranean formation.

[0055] In some embodiments, the system 100 also includes at least one processor 103 with associated non-transitory computer readable memory. In some embodiments, the system 100 may also include one or more sensors, such as the sensors 116a and 116b disposed down hole on the downhole tools 110a and / or 110b, configured to sense one or more parameters (e.g., temperature, gas composition, pressure, or other appropriate parameter) related to the formation 101. The one or more sensors may be configured to transmit signals related to the one or more sensed parameters, such as temperature from a temperature sensor in some embodiments, to the one or more processors for performing any of the methods disclosed herein. The non-transitory computer readable memory may include processor-executable instructions that when executed cause the at least one processor 103 to control the system 100 shown in Fig. 1 to perform any of the methods described herein. For example, the processor 103 may be configured to control the power transmitted to the downhole tools 110. Other functions of the at least one processor are also possible and are described in more detail elsewhere herein.

[0056] Fig. 2 presents a schematic flow diagram illustrating a process for extracting a resource from a rock formation. At least two wells are drilled into the rock formation (e.g., a subterranean rock formation) (205), which may produce or otherwise contain the resource (e.g., hydrogen). In some embodiments, fluid may be introduced into the rock formation through one or more of the wells at (210), as mentioned above. This fluid may be a hydraulic fracturing fluid including appropriate additives and / or proppants. One or more electrodes may be placed into each of the wells (215), and an electrical potential is applied between the electrodes (220) causing a current to pass between the electrodes through the fluid and / or subterranean formation itself. In some embodiments, the applied electrical potential causes Joule heating of the fluid and / or the surrounding rock formation, which may result in fracturing, or additional fracturing, of the rock formation (225). Specifically, rapid temperature changes (upon heating and / or cooling of the rock formation), formation of a shockwave, and / or expansion of the fluid and / or the formation during the electrohydraulic fracturing process may lead to increased, or additional, fracturing of the subterranean formation. The permeability of the rock formation may be increased (227), in some cases, asa result of the new and / or additional fracturing formed in the rock formation as compared to the original permeability of the rock formation prior to electrohydraulic fracturing. The relative and / or absolute porosity of both the original formation and the final formation may correspond to any of the appropriate porosity ranges disclosed herein.

[0057] As previously noted, in some embodiments, it may be desirable to control a temperature of the subterranean formation. In such an embodiment, a temperature, or other parameter related to the extraction of a resource from the rock formation (e.g., a hydrogen containing reservoir, a reservoir connected to a hydrogen containing reservoir, or other appropriate rock formation) may be sensed by one or more sensors positioned downhole within a well (e.g., within a rock formation capable of generating and / or releasing geologic hydrogen). The one or more sensors may either be separate from or connected to the downhole electrodes used to apply electrical potentials to the rock formation. In either case, the one or more sensors may sense one or more parameters (230). Appropriate parameters may include, but are not limited to temperature, pressure, gas composition, and / or other appropriate parameters. The operation of the two or more electrodes may then be controlled based on the sensed one or more parameters. For example, in instances where it is desirable to control a temperature of the subterranean formation, the current, electrical potential, power, or other operating parameter applied by the two or more electrodes may be controlled to maintain a temperature of the subterranean formation to be within a predetermined range of temperatures (235). Two (or more) electrodes can be used to continuously dissipate electric energy as heat (i.e., via Joule heating) through the rock formations and / or fluid within the pores of the rock formation. In some such embodiments, both DC and AC (or a combined DC / AC) stimulation may be used. The electric current can heat the reservoir with power proportional to both voltage and current.

[0058] After electrohydraulic fracturing, and optional temperature control, of the rock formation, a resource (e.g., natural hydrogen) may be extracted from the rock formation (240). This may include the extraction of pressurized gas from one or more wells, the pumping of fluid out of one or more wells with the resource dissolved therein, and / or using any other appropriate extraction method for extracting the resource from within the rock formation. In some instances, extracting the resource may include injecting a fluid, such as water and / or other fluid, into the rock formation to either enhance the generation of thenatural hydrogen and / or the extraction of the natural hydrogen from the subterranean formation.

[0059] In Fig. 3, the electrodes shown in Fig. 1 are shown adjacent to and / or within a hydrogen containing reservoir 310 such that at least a portion of the hydrogen reservoir is disposed between the electrodes. In this manner, the electrodes 110a and 110b can electrically stimulate at least a portion, or the entire, hydrogen containing reservoir. For example, such a usage may be useful in which a hydrogen containing reservoir 310 is a tight reservoir with low porosity that either prevents and / or restricts the extraction rates of hydrogen from the hydrogen containing reservoir to rates that are not economical. Thus, electrohydraulic fracturing of this tight rock formation corresponding to the hydrogen containing reservoir may increase the porosity of the formation to a desired porosity and correspondingly increase the rate of hydrogen extraction from the reservoir to a desire extraction rate.

[0060] In the above embodiment, a hydrogen containing reservoir is too tight, i.e., exhibits a low porosity, such that electrohydraulic fracturing of the reservoir is desired. However, in other instances it may be desirable to electrohydraulically fracture one or more other strata within an overall subterranean formation to facilitate the extraction of natural hydrogen. For example, this may include unsealing a hydrogen containing reservoir associated with a capping layer, forming migration paths to more porous strata and / or strata located closer to the surface, or other appropriate considerations as detailed further below.

[0061] In Figs. 4A-4B, a subterranean formation 300 may include various regions that may correspond to different strata with different compositions. For example, the subterranean formation 300 may include a natural hydrogen-containing reservoir 310 and another formation such as the depicted reservoir 320, which may correspond to another rock formation with a desirable property to facilitate hydrogen extraction. For example, reservoir 320 may be closer to the surface, exhibit a desired porosity, and / or may have another property such that migration of hydrogen into reservoir 320 from the natural hydrogen containing reservoir 310 may permit more efficient resource extraction. For example, reservoir 320 may be a more shallow, porous rock formation, such as a porous sandstone formation located above a deeper hydrogen containing reservoir, in some embodiments. For instance, in Fig. 4A, the natural hydrogen-containing reservoir 310 is fluidly connected to thereservoir 320 via an initial fracture 330a. However, due to the limited permeability of fracture 330a, the rate of hydrogen migration from the natural hydrogen-containing reservoir 310 to the other reservoir 320 is low. In addition to the above, in some embodiments, reservoir 320 may be sealed relative to the other surrounding strata included in the illustrated rock formation due to a seal such as a capping layer disposed thereon (not depicted).

[0062] In view of the above, in some embodiments, the electrodes 110a and 110b may be placed at different positions, or depths, relative to the different formations present within the overall subterranean formation 300. For example, in Figs. 4A-4B, the electrodes 110a and 110b are at different depths within the subterranean formation 300 and / or are staggered relative to each other such that the electrodes provide electrical stimulation to different strata within the subterranean formation 300 (i.e., different portions or layers of the subterranean formation). Specifically, in the depicted embodiment, the two or more electrodes are positioned at different depths and / or lateral positions such that a portion of the natural hydrogen containing reservoir 310 and the reservoir 320 used for resource extraction may be disposed between the two or more electrodes. Depending on the scale of the formations, this may either be done using just two wells and electrodes and / or this may be done using multiple sets of wells and electrodes, either simultaneously or sequentially. In either case, upon electrical stimulation, the permeability between the two reservoirs 310 and 320 and / or the permeabilities in the different strata may be increased. For example, in Fig. 4B, the electrical stimulation has created more fractures 330b, increasing the permeability between the natural hydrogen containing reservoir 310 and the reservoir 320 closer to the surface. Thus, the migration rate of hydrogen from the hydrogen containing reservoir 310 to the reservoir 320 is increased, as compared to the migration and extraction rates of hydrogen prior to electrohydraulic fracturing.

[0063] Figs. 5A-5B depict a schematic diagram of another possible scenario in which electrohydraulic fracturing of different strata within an overall subterranean formation may be desired. In the depicted embodiment, a capping layer 340 is disposed between a natural hydrogen containing reservoir 310 and a reservoir 320 that is desired to be used for resource extraction. For example, similar to the embodiment described relative to Figs. 4A-4B, the reservoir 320 may be a porous upper stratum of the subterranean formation 300 that is located closer to the surface than the natural hydrogen containing reservoir 310. The capping layer340 can be a stratum of the rock formation 300 with a particularly low porosity that is significantly less than the porosities of both reservoirs 310 and 320 and that is disposed between the natural hydrogen containing reservoir 310 and the reservoir 320. Accordingly, the capping layer 340 may prevent any significant migration of hydrogen between the natural hydrogen containing reservoir 310 and the reservoir 320. Thus, similar to the above embodiment, the electrodes 110a and 110b may be positioned on opposing sides of the capping layer 340 (e.g., at different vertical positions relative to the surface on the opposing sides of the capping layer 340). In some instances, the electrodes may be positioned such that a portion of the natural hydrogen containing reservoir 310 and the reservoir 320 are disposed between the two or more electrodes. Accordingly, upon electrical stimulation, fractures 330b may be formed in the capping layer 340 to increase a porosity, and correspondingly the permeability, of the capping layer between the two or more electrodes. As shown in Fig. 5B, the fractured capping layer 340 may fluidly connect the natural hydrogen reservoir 310 and the reservoir 320 such that a migration rate of hydrogen between the natural hydrogen reservoir 310 and the reservoir 320 may be increased to provide a desired hydrogen extraction rate. Additionally, in some embodiments, the fractures 330b may extend into one or more of the natural hydrogen reservoir 310 and the reservoir 320 to increase a porosity and permeability of these reservoirs. As noted previously, depending on the size of the different formations, the illustrated fractures extending between the different strata may either be formed using two electrodes and / or multiple sets of electrodes operated simultaneously or sequentially as the disclosure is not limited in this manner.

[0064] While a single capping layer has been illustrated in the above figure between the hydrogen reservoir 310 and the reservoir 320, in some embodiments, reservoir 320 may be sealed relative to the other surrounding strata included in the illustrated rock formation due to a seal such as a capping layer disposed thereon, not depicted.

[0065] Examples: Laboratory Scale Studies

[0066] According to some exemplary embodiments, the inventors have conducted experiments to quantify the amount of generated hydrogen when injecting fluid into a fractured subterranean formation. In particular, experiments were conducted on various samples with various degrees of fracturing as shown in FIG. 6. As used herein, “BT” refers to a fractured rock core sample subjected to a Brazilian test, “PP” refers to a powderedperidotite sample, and “MF” refers to a “maximum fractured” peridotite sample. As shown in FIG. 6, the PP sample yielded the highest hydrogen production, followed by the MF sample and the BT sample in the order from greatest to least in hydrogen production. That is, the sample with the greatest number of fractures (the powdered sample) resulted in the greatest degree of hydrogen production.

[0067] According to some exemplary embodiments, the inventors have conducted experiments to quantify the permeability of samples that undergo electrical reservoir stimulation (ERS). As shown in Fig. 7, the permeability of the rock formations measured in millidarcy (mD) was found to exponentially increase with increases in applied energy (J), which demonstrates that the use of ERS increases permeability of the stimulated rock formations.

[0068] As shown in Fig. 8, the permeability of rock samples was measured for several different rock formations (i.e., “Rocks 1-4”) using several different fracturing techniques including purely hydrofracking (“HF”), ERS, both HF and ERS, and pristine control samples. For the first rock sample, it was found that using both HF and ERS resulted in an increased permeability relative to the HF and control samples. Likewise, for the second, third, and fourth rock samples, the use of ERS resulted in increased permeability relative to the purely HF and / or control techniques. In particular, the use of ERS for the first, second, and fourth rock samples was found to obtain a permeability of less than or equal to 10'15m2. In addition, the inventors have found that the samples fractured using ERS maintain an increased degree of permeability relative to the HF samples at high confining pressures, i.e., as effective pressure increases as shown in FIG. 8. In some embodiments, the inventors have also appreciated that the use of ERS allows for subsequent pulsing to be performed as desired to increase permeability of the rock formations further.

[0069] Fig. 9 shows a comparison between a first state of a rock formation prior to applying a current for fracturing (i.e., ERS) and a second state of the formation after the current has been applied. The first and second states are shown by the left and right images, respectively. The images were captured using MicroCT imaging with the pulsed power applied to the rock formation under pressures representing subsurface conditions (e.g., pore and confining pressures). As shown in FIG. 9, the application of current has resulted in new fractures 410,420 forming in the rock formation in the second state that were not present prior to applying the current in the first state.

[0070] While several embodiments of the present disclosure have been described and illustrated herein, those of ordinary skill in the art will readily envision a variety of other means and / or structures for performing the functions and / or obtaining the results and / or one or more of the advantages described herein, and each of such variations and / or modifications is deemed to be within the scope of the present disclosure. More generally, those skilled in the art will readily appreciate that all parameters, dimensions, materials, and configurations described herein are meant to be exemplary and that the actual parameters, dimensions, materials, and / or configurations will depend upon the specific application or applications for which the teachings of the present disclosure is / are used. Those skilled in the art will recognize or be able to ascertain using no more than routine experimentation, many equivalents to the specific embodiments of the invention described herein. It is, therefore, to be understood that the foregoing embodiments are presented by way of example only and that, within the scope of the appended claims and equivalents thereto, the invention may be practiced otherwise than as specifically described and claimed. The present disclosure is directed to each individual feature, system, article, material, and / or method described herein. In addition, any combination of two or more such features, systems, articles, materials, and / or methods, if such features, systems, articles, materials, and / or methods are not mutually inconsistent, is included within the scope of the present disclosure.

[0071] The indefinite articles “a” and “an,” as used herein in the specification and in the claims, unless clearly indicated to the contrary, should be understood to mean “at least one.”

[0072] The phrase “and / or,” as used herein in the specification and in the claims, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Other elements may optionally be present other than the elements specifically identified by the “and / or” clause, whether related or unrelated to those elements specifically identified unless clearly indicated to the contrary. Thus, as a non-limiting example, a reference to “A and / or B,” when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A without B (optionally including elements other than B); in anotherembodiment, to B without A (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.

[0073] As used herein in the specification and in the claims, “or” should be understood to have the same meaning as “and / or” as defined above. For example, when separating items in a list, “or” or “and / or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of’ or “exactly one of,” or, when used in the claims, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e. “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the claims, shall have its ordinary meaning as used in the field of patent law.

[0074] As used herein in the specification and in the claims, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and / or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.

[0075] Some embodiments may be embodied as a method, of which various examples have been described. The acts performed as part of the methods may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an orderdifferent than illustrated, which may include different (e.g., more or less) acts than those that are described, and / or that may involve performing some acts simultaneously, even though the acts are shown as being performed sequentially in the embodiments specifically described above.

[0076] Use of ordinal terms such as “first,” “second,” “third,” etc., in the claims to modify a claim element does not by itself connote any priority, precedence, or order of one claim element over another or the temporal order in which acts of a method are performed, but are used merely as labels to distinguish one claim element having a certain name from another element having a same name (but for use of the ordinal term) to distinguish the claim elements.

[0077] In the claims, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of’ and “consisting essentially of’ shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.

Claims

CLAIMS1. A method for extracting naturally occurring hydrogen from a subterranean formation, the method comprising: applying a current to the subterranean formation; fracturing the subterranean formation in response to the applied current to increase a permeability of the subterranean formation to be greater than the permeability of the subterranean formation prior to fracturing; and extracting hydrogen from the subterranean formation.

2. A method for extracting naturally occurring hydrogen from a subterranean formation, the method comprising: applying a current to a portion of subterranean formation having a permeability of less than or equal to IO5m2; fracturing the portion of the subterranean formation in response to the applied current such that the permeability of the portion of subterranean formation increases to greater than or equal to IO4m2; and extracting hydrogen from the subterranean formation.

3. The method of any one of the preceding claims, further comprising injecting fluid into the subterranean formation prior to fracturing.

4. The method of any one of claims 1-2, further comprising injecting fluid into the subterranean formation after fracturing.

5. The method of any one of the preceding claims, wherein the subterranean formation includes a hydrogen containing formation.

6. The method of any one of the preceding claims, further comprising fracturing a capping layer disposed between a hydrogen containing reservoir and the subterranean formation, wherein a permeability of the capping layer is less than or equal to 1045m2.

7. The method of any one of the preceding claims, further comprising positioning a first electrode at a first depth and a second electrode at a second depth, different than the first depth.

8. The method of any one of the preceding claims, further comprising fracturing multiple strata of the subterranean formation.

9. The method of any one of the preceding claims, wherein the multiple strata include a hydrogen containing reservoir and a reservoir closer to a surface of the subterranean formation.

10. The method of any one of the preceding claims, wherein extracting hydrogen occurs at a rate of greater than or equal to 0.01 nanomoles th / gram rock.

11. The method of any one of the preceding claims, wherein fracturing comprises forming new fractures within the subterranean formation that were not present prior to applying the current.

12. The method of any one of the preceding claims, wherein fracturing comprises forming new fractures in a first portion of the subterranean formation and increasing a permeability of an adjacent second portion of the subterranean formation.

13. The method of any one of the preceding claims, further comprising Joule heating at least a portion of the subterranean formation.

14. The method of claim 13, further comprising maintaining a temperature of the subterranean formation with Joule heating.

15. The method of any one of the preceding claims, wherein the subterranean formation has a hardness of greater than or equal to 2 Mohs.

16. The method of any one of the preceding claims, wherein the subterranean formation has a weight percentage of iron (Fe) greater than or equal to 1 wt%.

17. The method of any one of the preceding claims, wherein the subterranean formation has a weight percentage of silicon (Si) greater than or equal to 1 wt%.

18. The method of any one of the preceding claims, further comprising increasing a temperature of the subterranean formation between or equal to 0 °C and 500 °C to increase production of hydrogen.

19. A system comprising: a power source; at least two electrodes connected to the power source; at least one pump; and at least one processor configured to operate the power source and the at least one pump to perform the method of any one of the preceding claims.

Images