SYSTEMS AND METHODS FOR PRODUCTION OF LOW CARBON INTENSITY HYDROGEN FROM GEOLOGIC SOURCES

A hydrogen production system for producing a hydrogen gas product includes a geologic hydrogen source configured to provide a feedstock comprising hydrogen, nitrogen, and helium and purification equipment comprising two or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The purification equipment is configured to receive the feedstock from the geologic hydrogen source and produce a hydrogen gas product, and production of the hydrogen gas product exhibits a carbon intensity score less than 3.0 kg CO2 eq/kg H2.

BACKGROUND

The environmental impact of greenhouse gases (GHGs), primarily carbon dioxide (CO2) and methane (CH4), has been the subject of much public debate over the past several decades. More recently, self-imposed private-sector initiatives and government-mandated regulations to reduce the release of greenhouse gases into the environment have begun to be implemented. In addition to the capture and/or sequestration of carbon dioxide and other greenhouse gases to mitigate their atmospheric release, much research and development effort has been focused on the utilization of alternatives to fossil fuels.

Hydrogen (H2) holds promise as both an energy source and chemical feedstock. However, hydrogen has traditionally been produced using fossil fuels (e.g., via natural gas/methane conversion in a steam methane reformer), and therefore hydrogen has not been viewed as an alternative to the use of fossil fuels. For example, in the steam-methane reforming reaction, methane is reacted with steam (i.e., water) to produce hydrogen gas and carbon monoxide. In a subsequent water-gas shift reaction, the carbon monoxide is further reacted with steam to produce carbon dioxide and additional hydrogen gas. Thus, most hydrogen that is produced in refinery operations, for example, produces greenhouse gases.

Alternatively, hydrogen gas may be generated by the electrolysis of water into hydrogen gas and oxygen. However, producing hydrogen via electrolysis requires a substantial amount of electricity. While at least some of the required electricity for hydrogen production via electrolysis may be obtained from renewable sources (e.g., wind, solar, and hydroelectric), in practice the majority of the electricity used for this purpose has traditionally been, and continues to be, produced through the combustion of fossils fuels, which also produces greenhouse gases.

There is a significant focus today on the decarbonization of energy and chemical industries to positively impact climate change. In response, companies and individuals are actively working to produce cost-effective “clean” or “green” hydrogen and other chemicals. Hydrogen is labelled as “green” when its production results in significantly lower greenhouse gas emissions compared to the production of other energy sources. Governments have recently begun to categorize hydrogen by assessing the emissions intensity of the production plant or system from which the hydrogen is sourced. Specifically, a hydrogen gas product is assigned a carbon intensity (CI) score according to the greenhouse gas emissions resulting from the processing plant.

The production of low CI score hydrogen today is primarily provided through the electrolysis of water, but the need for both renewable electricity and hydrogen gaseous storage, coupled with the high capital cost of the nascent electrolyzer technology, establish that there is a substantial cost to produce this low CI score hydrogen.

BRIEF SUMMARY

There exists a need for hydrogen production systems and methods that produce low-cost hydrogen gas products having a low CI score that are available without the need for storage.

The disclosure herein provides example embodiments of hydrogen production systems and methods that address this need. As an alternative to producing hydrogen from natural gas via steam-methane reforming or electrolysis, another less-explored option is natural hydrogen produced from subsurface geologic H2 accumulations. Estimates for the natural H2 flux from the earth vary widely but tend to be of order-of-magnitude 0.1-10 Tg H2/year. Over time, the estimates of H2 flux from the earth have increased, and some estimation methods suggest much larger subsurface production rates and rates of surface hydrogen fluxes are possible. If larger production and flux values are correct, or long-term subsurface accumulation has occurred, natural H2 could provide a significant amount of low-carbon energy. Natural H2 has not been commercially developed at scale to date, and wells have only recently been drilled for purposeful production. In order for natural hydrogen to be a useful part of clean energy systems, natural hydrogen will need to be processed in systems and methods with minimal carbon emissions.

The extraction, separation, and purification of geologic hydrogen solves the cost, storage, and scalable volume of supply challenges for hydrogen described above. Hydrogen reserves relate to accumulations stored in subsurface reservoirs contained within the geologic formations underground, and, with proper analysis and planning, hydrogen that can be extracted from boreholes into the subsurface from wellheads is of a sufficient composition that it can be subsequently separated and/or purified to between about 90% and about 99.9999% purity, meeting the needs of the hydrogen markets. With proper equipment selection and potentially clean on-site power generation, the hydrogen is produced with a low CI score.

Further, many of the gas streams extracted from the targeted wellheads contain helium. With creative gas processing through equipment selection and process design, a helium gas product may also be produced at a low cost and low CI score.

Example embodiments of the present invention set forth herein process feedstock from a geologic hydrogen source to produce a hydrogen gas product with a low CI score. In one or more embodiments, the production of the hydrogen gas product exhibits a carbon intensity score less than 4.0 kg/CO2 eq/kg H2, or less than 3.0 kg/CO2 eq/kg H2.

Additionally, as outlined below, example embodiments described herein demonstrate the production of low CI score helium, neon, krypton, or xenon in addition to low CI score hydrogen. Finally, some example embodiments described herein produce low CI score ammonia, in which low CI score hydrogen is used as feedstock to the ammonia loop, while also producing low CI score helium.

An example hydrogen production system for producing a hydrogen gas product includes a geologic hydrogen source and purification equipment comprising one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The purification equipment is configured to receive feedstock from the geologic hydrogen source and produce a hydrogen gas product, and production of the hydrogen gas product exhibits a carbon intensity score less than 3.0 kg CO2 eq/kg H2.

Further, an example method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source; processing the feedstock using purification equipment; and producing the hydrogen gas product, wherein production of the hydrogen gas product exhibits a carbon intensity score less than 3.0 kg CO2 eq/kg H2.

In another embodiment, a hydrogen production system includes a geologic hydrogen source configured to provide a feedstock and purification equipment. The feedstock comprises hydrogen, nitrogen, and helium, among other components, and has a helium molar fraction greater than 0.1 mol %. The feedstock may also comprise neon, krypton or xenon, and has molar fractions of these additional components greater than 0.05 mol %, greater than 100 parts per million (ppm), or greater than 5 parts per million. The purification equipment includes one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The purification equipment is configured to receive the feedstock from the geologic hydrogen source and produce a hydrogen gas product.

In a further embodiment, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source, wherein the feedstock comprises hydrogen, nitrogen, and helium, and wherein the feedstock has a helium molar fraction greater than 0.1 mol %, greater than 0.5 mol %, greater than 1.0 mol %, greater than 2.0 mol %, greater than 3.0 mol %, greater than 4.0 mol %, or greater than 5.0 mol %; processing the feedstock using purification equipment, and producing the hydrogen gas product. The purification equipment includes one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device.

In another embodiment, a hydrogen production system includes a geologic hydrogen source configured to provide a feedstock comprising hydrogen that is not produced using electrolysis, steam methane reformation, methane pyrolysis, or gasification, and purification equipment comprising one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The purification equipment is configured to receive the feedstock from the geologic hydrogen source and produce a hydrogen gas product.

In a further embodiment, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source, wherein the feedstock comprises hydrogen that is not produced using electrolysis, steam methane reformation, methane pyrolysis, or gasification; processing the feedstock using purification equipment; and producing the hydrogen gas product. The purification equipment comprises one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device.

In various embodiments, a hydrogen production system includes one or more guard beds configured to receive feedstock from a geologic hydrogen source, wherein each guard bed is configured to remove feedstock impurities such as but not limited to water, carbon dioxide, or hydrocarbons, from the feedstock to produce a guard bed effluent, wherein the guard bed effluent comprises geologic hydrogen; a pressure swing adsorption (PSA) device configured to receive the guard bed effluent from the one or more guard beds, wherein the PSA device produces a PSA device effluent and a purge gas stream containing unrecovered hydrogen and helium as well as remaining PSA feedgas components including but not limited to water, nitrogen, carbon dioxide, or hydrocarbons, the PSA device effluent comprising hydrogen and helium, and the purge gas stream comprising unrecovered hydrogen and remaining feedstock components comprising nitrogen, carbon dioxide, or methane; a membrane configured to receive the PSA device effluent from the PSA device and to remove nitrogen, carbon dioxide, and/or methane components from the PSA device effluent, wherein the membrane is configured to produce a membrane effluent comprising hydrogen and helium; and a cryogenic separation device configured to receive the membrane effluent from the membrane and to remove helium from the membrane effluent, wherein the cryogenic separation device is configured to produce a hydrogen gas product comprising hydrogen. Said guard beds are ones that remove feedstock impurities such as sulfur, particulates, metals, or liquid components from the feedstock.

In further embodiments, a method of producing a hydrogen gas product includes: receiving, by one or more guard beds, feedstock from a geologic hydrogen source; removing, by the one or more guard beds, feedstock impurities from the feedstock; receiving, by a pressure swing adsorption (PSA) device, a guard bed effluent from the one or more guard beds, wherein the guard bed effluent comprises geologic hydrogen; producing, by the PSA device, a PSA device effluent and a purge gas stream, the PSA device effluent comprising hydrogen and helium, and the purge gas stream comprising unrecovered hydrogen and remaining feedstock components comprising nitrogen, carbon dioxide, or methane; receiving, by a membrane, the PSA device effluent from the PSA device; removing, by the membrane, nitrogen, carbon dioxide, and/or methane components from the PSA device effluent; producing, by the membrane, a membrane effluent comprising hydrogen and helium; receiving, by a cryogenic separation device, the membrane effluent from the membrane; removing, by the cryogenic separation device, helium from the membrane effluent; and producing, by the cryogenic separation device, a hydrogen gas product comprising hydrogen.

In other embodiments, a hydrogen production system includes one or more guard beds configured to receive feedstock from a geologic hydrogen source, each guard bed configured to remove feedstock impurities from the feedstock, wherein the guard bed effluent comprises geologic hydrogen; a pressure swing adsorption (PSA) device configured to receive guard bed effluent from the one or more guard beds and produce a PSA device effluent and a purge gas stream, wherein the PSA device effluent comprises hydrogen and helium, and wherein the purge gas stream comprises unrecovered hydrogen and remaining feedstock components comprising nitrogen or carbon dioxide or methane; and a reactive membrane configured to receive the PSA device effluent and remove hydrogen from the PSA device effluent, wherein the reactive membrane is configured to produce a first gas stream comprising predominantly hydrogen and a second gas stream comprising predominantly helium.

In further embodiments, a method includes: receiving, by one or more guard beds, feedstock from a geologic hydrogen source; removing, by the one or more guard beds, drier beds, or knock-out vessels, feedstock impurities from the feedstock; receiving, by a pressure swing adsorption (PSA) device, a guard bed effluent from the one or more guard beds, wherein the guard bed effluent comprises geologic hydrogen; producing, by the PSA device, a PSA device effluent and a purge gas stream, the PSA device effluent comprising hydrogen and helium, and the purge gas stream comprising unrecovered hydrogen and remaining feedstock components comprising nitrogen or carbon dioxide or methane; receiving, by a reactive membrane, the PSA device effluent from the PSA device; removing, by the reactive membrane, hydrogen from the PSA device effluent; and producing, by the reactive membrane, a first gas stream comprising predominantly hydrogen and a second gas stream comprising predominantly helium.

In some embodiments, a hydrogen production system includes a wellhead configured to provide a hydrogen feedstock and purification equipment. The purification equipment includes one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The purification equipment is configured to receive the hydrogen feedstock from the wellhead and produce a hydrogen gas product.

In further embodiments, a method of producing a hydrogen gas product includes: receiving hydrogen feedstock from a hydrogen source, wherein the hydrogen source is a wellhead; processing the hydrogen feedstock using purification equipment; and producing the hydrogen gas product. The purification equipment comprising one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device.

In other embodiments, a hydrogen production system includes a geologic hydrogen source configured to provide a feedstock, purification equipment configured to receive the feedstock from the geologic hydrogen source and produce a hydrogen gas product, and a power generation plant powered by hydrogen from one of the feedstock, the purification equipment, or purge gas from the purification equipment. The power generation plant is configured to provide energy to the purification equipment.

In still further embodiments, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source; processing the feedstock using purification equipment; producing, by the purification equipment, the hydrogen gas product; receiving, by a power generation plant, hydrogen from one of the feedstock, the purification equipment, or purge gas from the purification equipment; and providing, by the power generation plant, energy to the purification equipment.

In some embodiments, a hydrogen production system includes a geologic hydrogen source, first-stage purification equipment, and second-stage purification equipment. The first-stage purification equipment includes one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The first-stage purification equipment is configured to receive feedstock from the geologic hydrogen source and produce an effluent. The second-stage purification equipment configured to receive the effluent from the first-stage purification equipment and produce a hydrogen gas product and a noble gas product.

In other embodiments, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source; processing, by first-stage purification equipment, the feedstock; producing, by the first-stage purification equipment, an effluent; processing, by second-stage purification equipment, the effluent from the first-stage purification equipment; and producing, by the second-stage purification equipment, a noble gas product and the hydrogen gas product.

In some embodiments, a hydrogen production system includes a hydrogen source configured to provide a feedstock, first-stage purification equipment, an ammonia synthesis loop, and second-stage purification equipment. The first-stage purification equipment includes one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The first-stage purification equipment is configured to receive the feedstock from the hydrogen source and produce a hydrogen gas product, wherein the hydrogen gas product comprises hydrogen and helium. The ammonia synthesis loop is configured to receive the hydrogen gas product from the first-stage purification equipment and produce an ammonia product and an effluent. The second-stage purification equipment is configured to receive the effluent from the ammonia synthesis loop and produce a helium gas product.

In other embodiments, a method of producing a hydrogen gas product includes: receiving feedstock from a hydrogen source; processing, by first-stage purification equipment, the feedstock; producing, by the first-stage purification equipment, the hydrogen gas product; receiving, by an ammonia synthesis loop, the hydrogen gas product from the first-stage purification equipment; producing, by the ammonia synthesis loop, an ammonia product and an effluent; receiving, by a second-stage purification equipment, the effluent from the ammonia synthesis loop; and producing, by the second-stage purification equipment, a helium gas product. Said helium gas product may comprise other noble gases.

In some example embodiments, a hydrogen production system includes a geologic hydrogen source configured to provide a feedstock and purification equipment configured to receive the feedstock from the geologic hydrogen source and produce a hydrogen gas product. The hydrogen gas product comprises hydrogen, helium, nitrogen, carbon monoxide, carbon dioxide, and methane. A combined hydrogen and helium molar fraction is greater than 95 mol %. For example, the combined hydrogen and helium molar fraction may be greater than 96%, greater than 96%, greater than 97%, or greater than 98%. A nitrogen molar fraction is less than 2 mol %. A combined carbon monoxide and carbon dioxide concentration is less than 50 ppm, and a methane concentration is less than 50 ppm.

In some embodiments, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source; processing the feedstock using purification equipment; producing, by the purification equipment, the hydrogen gas product. The hydrogen gas product comprises: a combined hydrogen and helium molar fraction of greater than 98 mol %; a nitrogen molar fraction of less than 1 mol %; a combined carbon monoxide and carbon dioxide concentration of less than 20 ppm; and a methane concentration of less than 20 ppm.

In other embodiments, a hydrogen production system includes a geologic hydrogen source, a compressor receiving feedstock from the geologic hydrogen source, purification equipment, and/or a power generation plant. The purification equipment comprising one or more of: a pressure swing adsorption (PSA) device; a guard bed; a separation membrane; a reactive membrane; or a cryogenic separation device. The power generation plant is powered by purge gas from the purification equipment and configured to provide energy to one or more of the compressor or the purification equipment. The purification equipment is configured to receive the feedstock and produce a hydrogen gas product.

In still further embodiments, a method of producing a hydrogen gas product includes: receiving feedstock from a geologic hydrogen source; pressurizing the feedstock using a compressor; processing the feedstock using purification equipment to produce the hydrogen gas product; powering a power generation plant using purge gas from the purification equipment; and directing energy from the power generation plant to one or more of the compressor or the purification equipment.

One or more embodiments of this disclosure generally relate to hydrogen production systems and methods that receive feedstock from a geologic hydrogen source, process the hydrogen feedstock to produce a hydrogen gas product. In one or more embodiments, the production of the hydrogen gas product exhibits a carbon intensity score less than 3.0 kg/CO2 eq/kg H2.

In some embodiments, the geologic source is accessed through a wellhead. In various embodiments, the hydrogen feedstock includes hydrogen, nitrogen, and helium and has a helium molar fraction greater than 0.1 mol %. In various embodiments, the hydrogen feedstock comprises hydrogen that is not produced through electrolysis, steam methane reformation, methane pyrolysis, or gasification.

In some embodiments, the hydrogen production system includes a power generation plant that is powered by hydrogen from the hydrogen feedstock or the purification equipment. In some embodiments, the hydrogen production system includes a first-stage purification equipment to produce hydrogen and a second-stage purification equipment to produce one or more noble gas products. In some embodiments, the hydrogen production system includes an ammonia synthesis loop configured to receive the hydrogen gas product and to produce an effluent.

In some embodiments, the hydrogen gas product includes hydrogen, helium, and nitrogen, wherein a hydrogen and helium molar fraction is greater than 98% and a nitrogen molar fraction is less than 2%. In some embodiments, the hydrogen gas product includes less than 50 ppm carbon monoxide and carbon dioxide in combination and/or less than 50 ppm methane.

In further embodiments, any of the features, functionality and alternatives described in connection with any one or more of FIGS. 1 to 14 may be combined with any of the features, functionality and alternatives described in connection with any other of FIGS. 1 to 14.

The foregoing brief summary is provided merely for purposes of summarizing some example embodiments described herein. Because the above-described embodiments are merely examples, they should not be construed to narrow the scope of this disclosure in any way. It will be appreciated that the scope of the present disclosure encompasses many potential embodiments in addition to those summarized above, some of which will be described in further detail below.

DETAILED DESCRIPTION

Some example embodiments will now be described more fully hereinafter with reference to the accompanying figures, in which some, but not necessarily all, embodiments are shown. Because inventions described herein may be embodied in many different forms, the invention should not be limited solely to the embodiments set forth herein; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements.

As used herein, and unless the context dictates otherwise, the following terms have the meanings as specified below.

The term “geologic hydrogen” generally refers to hydrogen produced from a subsurface geological formation.

The term “geologic hydrogen source” generally refers to hydrogen sourced from any subsurface formations via a wellhead connected to a wellbore or any other pathway from the subsurface to the surface by which geologic hydrogen may be transmitted. Notably, this definition includes hydrogen generated by various mechanisms and chemical mixtures, including hydrogen produced by inorganic (e.g., redox, serpentinization) or radioactive processes. For example, a geologic hydrogen source includes hydrogen produced from a geological formation or accumulations, e.g. at young oceanic crust near a mid-oceanic ridge, continental rift, or other reduced iron deposit (e.g., banded iron formation [BIFs]). Geologic formations may include a variety of rock deposits containing complex mixtures or layers of reduced iron mineral phases or organic matter. For example, geologic formations that are suitable for providing a hydrogen feedstock include robust deposits of mafic and ultramafic igneous rock including olivine- and pyroxene-bearing ores. Rock deposits yield abiotic hydrogen through the reaction of water with the rock deposits to mineralize oxygen and release hydrogen. Other organic-rich rock deposits and fluids can undergo pyrolysis and generation hydrogen during graphitization and/or coalification.

The terms “feedstock” or “hydrogen feedstock” generally refers to the gas containing elevated levels of hydrogen received from a geological hydrogen source. In the embodiments described herein, the feedstock of the geological hydrogen source includes hydrogen and helium.

Overview

FIGS. 1-9 illustrate exemplary flow diagrams of hydrogen production systems that produce a hydrogen gas product having a low CI score, and FIGS. 10-13 provide flowcharts and data related to a modeled hydrogen production system in accordance with the embodiments described herein. The CI scores referenced herein are provided in kg CO2 equivalent greenhouse gases per kg H2 produced (kg CO2 eq/kg H2), and the calculation thereof is described in detail with respect to the modeled hydrogen production system described below. The CI score of the hydrogen gas product is influenced by the gas composition of the feedstock from the geologic hydrogen source as well as the well depth, productivity, and other parameters. The CI score is also minimized when the hydrogen production system powers and heats the purification equipment and other components with low-carbon energy sources, such as self-produced hydrogen.

In the present application, the production of the hydrogen gas product provided by the hydrogen production systems and methods described herein exhibits a carbon intensity score less than 3.0 kg CO2 eq/kg H2. In other embodiments, the carbon intensity score is less than 1.5 kg CO2 eq/kg H2, preferably less than 0.45 kg CO2 eq/kg H2, and more preferably less than 0.37 kg CO2 eq/kg H2. The low CI score is achieved by using a starting material having a minimum hydrogen molar fraction of at least 50 mol %, the ordering of purification equipment to minimize power consumption and efficiently improve purity, and the use of a power generation plant that is powered by hydrogen or purge gas from purification equipment and provides power to equipment within the hydrogen production system.

Geologic Hydrogen Source

In the embodiment illustrated in FIG. 1, feedstock is captured at a geologic hydrogen source, such as a wellhead 102 that captures subsurface gas from a wellbore at least partially traversing a rock formation. The wellbore provides a pathway for the recovery of fluids or feedstock therefrom. Generally, rock deposits yield abiotic hydrogen through the reaction of water with the rock deposits to mineralize oxygen and release hydrogen, such as in the serpentinization reaction or radiolysis. In some example embodiments, a two-step reaction is utilized that first generates hydrogen through the injection of a water-based stimulant into the wellbore, and then mineralizes oxygen into the rock formation while liberating hydrogen. Example embodiments can achieve hydrogen recovery by identifying rock formations having suitable characteristics, subsurface depths that optimize the preferred chemical reactions of fluids with rock, and the sequencing and nature of the recovery.

In some embodiments, the wellhead 102 collects feedstock from at least about 300 feet below ground level. In other embodiments, the wellhead collects feedstock from at least about 1,000 feet below ground level. In still further embodiments, the wellhead collects feedstock from between about 2,000 and about 3,000 feet below ground level, or between about 3,000 and about 4,000 feet below ground level, between about 4,000 and about 5,000 feet below ground level, between about 5,000 and about 6,000 feet below ground level, between about 6,000 and about 12,000 feet below ground level, or from at least about 20,000 feet below ground level.

In still further embodiments, the wellhead 102 demonstrates a productivity of at least 1.33 billion standard cubic feet per well. In other embodiments, the well demonstrates a productivity greater than 250 tonnes of hydrogen per year. In still further embodiments, the well demonstrates a productivity greater than 500 tonnes of hydrogen per year, 1,000 tonnes of hydrogen per year, 2,000 tonnes of hydrogen per year, 3,000 tonnes of hydrogen per year, 4,000 tonnes of hydrogen per year, 5,000 tonnes of hydrogen per year, 6,000 tonnes of hydrogen per year, 7,000 tonnes of hydrogen per year, 8,000 tonnes of hydrogen per year, 9,000 tonnes of hydrogen per year, or 10,000 tonnes of hydrogen per year.

In some embodiments, the feedstock includes hydrogen, helium, and nitrogen. A hydrogen molar fraction of the feedstock may be at least about 50 mol %. In other embodiments, the hydrogen molar fraction may be at least about 60 mol %, at least about 70 mol %, at least about 80 mol %, or at least about 85 mol %. In some embodiments, a helium molar fraction of the feedstock may be greater than about 0.1 mol %, about 0.5 mol %, about 1 mol %, about 1.5 mol %, about 2 mol %, about 2.5 mol %, about 3 mol %, or about 5 mol %. A nitrogen molar fraction of less than about 20 mol %, about 15 mol %, about 12 mol %, about 10 mol %, about 8 mol %, about 5 mol %, or about 3 mol %.

The feedstock may also have a methane molar fraction of less than about 1.5 mol % or less than about 1 mol %. The feedstock may have a methane concentration of less than about 10,000 ppm, or preferably less than 1,000 ppm. The feedstock may also have less than about 10,000 ppm hydrocarbons, less than about 1,000 ppm hydrocarbons, or a hydrocarbon molar fraction of up to about 1 mol %.

In some embodiments, the geologic hydrogen source includes one wellhead 102, while in other embodiments, the geologic hydrogen source includes a plurality of wellheads 102. Still further, in certain embodiments, the geologic hydrogen source may be free from hydrogen that is produced using electrolysis, steam methane reformation, methane pyrolysis, or gasification. In other embodiments, the hydrogen production system may receive hydrogen feedstock from other sources in addition to the feedstock from a geologic hydrogen source.

As shown in FIGS. 1 and 4-9, the geologic hydrogen source may be fluidically coupled to a compressor 104, and the feedstock may initially be directed to a compressor 104 to increase the pressure of the feedstock prior to treatment. As used herein, elements described as being “fluidically coupled” are coupled together with an appropriate line or other means to permit the passage of gas therebetween. In the case of multiple wellheads, each wellhead 102 may be fluidically coupled to a respective compressor 104, such that the individual feedstock streams from each wellhead 102 may be directed to a respective compressor 104 before being combined into a single feedstock. In other embodiments, multiple wellheads 102 may be fluidically coupled to one or more compressors 104, such that multiple feedstock streams from multiple wellheads 102 are directed to an arrangement of one or more compressors 104 prior to treatment by a central processing facility 106 that includes purification equipment 108. The one or more compressors 104 may in turn be fluidically coupled to the central processing facility 106 (e.g., to purification equipment 108). Accordingly, the geologic hydrogen source may be fluidically coupled to the central processing facility 106, either indirectly via one or more compressor 104, or directly in embodiments where no compressor 104 is required.

Purification Equipment

The purification equipment 108 of the central processing facility 106 separates specific gas components of the feedstock, purifies the hydrogen to produce a hydrogen gas product 110 (e.g., sale gas), and/or purifies helium or other noble gases to produce a noble gas product. The purification equipment 108 includes components (which, in various embodiments, may be fluidically coupled to each other) that remove impurities, hydrocarbons, nitrogen, and noble gases. FIGS. 2 and 3 illustrate example purification flow diagrams, although the ordering of the purification equipment may be modified or altered.

As shown in FIGS. 2-3, the feedstock may be received by the central processing facility 106 following compression and gathering 202, 302 (e.g., as described previously), For example, the purification equipment 108 may include one or more guard beds or reactor beds 204, 304 to remove impurities such as sulfur, particulates, metals, or liquid components. Example guard beds 204, 304 include an activated carbon guard bed, an adsorbent guard bed, a copper oxide guard bed, or a zinc oxide guard bed, although other suitable guard beds may be used depending on the facility needs and particular feedstock composition. The purification equipment 108 may include any number of guard beds 204, 304 needed as required by the productivity of the geologic hydrogen source. Suitable alternatives for a guard bed include, but are not limited to, a drier bed or a knock-out vessel.

The purification equipment 108 may also include a pressure swing adsorption (PSA) device 206, 306 that removes gases such as nitrogen, carbon dioxide, and methane from the feedstock. These components are typically captured in a purge gas, resulting in the feedstock from the geologic hydrogen source, now the effluent from the PSA device 206, 306, including primarily hydrogen and helium. In some embodiments, the feedstock or PSA device effluent has a hydrogen concentration of at least 70 mol %. As described in greater detail below, the purge gas may be reused within the hydrogen production system.

One or more separation membranes 208 may also be included in the purification equipment 108 to remove additional nitrogen, carbon dioxide, and methane. Example separation membranes 208 include spiral wound membranes, a hollow fiber membrane, or a filtration membrane. In some embodiments, the purification equipment 108 may also include a reactive membrane 308. Said separation membranes or reactive membranes may remove an additional 50% of the nitrogen, carbon dioxide, and methane, or an additional 70% of the nitrogen, carbon dioxide, and methane, or an additional 90% of the nitrogen, carbon dioxide, and methane, or an additional 95% of the nitrogen, carbon dioxide, and methane.

Cryogenic separation devices 210 may also be included in the purification equipment 108 to separate hydrogen, helium, and other gases, resulting in high purity gas streams. Example cryogenic separation devices 210 include distillation systems, heat exchangers, separator vessels, valves, expanders, cryogenic distillation columns, a series of cryogenic distillation columns, or the like.

FIGS. 2 and 3 illustrate example purification processes that increase the purity of hydrogen and helium within the feedstock and then produce both a hydrogen gas product 212 and a helium gas product 214. The hydrogen production systems described herein include equipment to capture and produce a helium gas product 214 as the feedstock from the geologic hydrogen source includes a significant and valuable helium component. In the first embodiment illustrated in FIG. 2, the final phase of the purification process is a cryogenic separation device 210, such as a cryogenic distillation column, that provides a hydrogen gas product 212 and a helium gas product 214. In the second embodiment illustrated in FIG. 3, the final phase of the purification process is a reactive membrane 308 that produces a first gas stream 312 comprised predominantly of hydrogen and a second gas stream 314 comprised predominantly of helium.

In the embodiment of FIG. 2, the feedstock is first directed to one or more guard beds 204 that remove feedstock impurities such as water, carbon dioxide, hydrocarbons, sulfur, particulates, metals, and/or liquid components from the feedstock. The guard bed effluent is then directed to a PSA device 206, which removes components such as water, nitrogen, carbon dioxide, and methane from the guard bed effluent in a purge gas stream. The PSA device may include, for example, layers of adsorbent materials optimally selected to remove said components. Typical adsorbent materials include silica gel, alumina, various zeolites, and activated carbons; a PSA device may include one or more layers of one or more of these adsorbent materials. The PSA device effluent comprises the majority of hydrogen and helium, and the PSA device purge gas stream may comprise a minority of unrecovered hydrogen and helium.

Next, the PSA device effluent is directed to a membrane 208, which could be a separation membrane and/or a reactive membrane. The membrane 208 also removes nitrogen, carbon dioxide, and methane from the feedstock. Then the membrane effluent is directed to a cryogenic separation device 210, such as cryogenic distillation columns. The cryogenic separation device 210 removes helium from the feedstock, producing the hydrogen gas product 212 and the helium gas product 214.

The purification process of FIG. 3 differs from FIG. 2 in that PSA device effluent from the PSA device 306 is directed to a reactive membrane 308 that produces a first gas stream 312 comprised predominantly of hydrogen and a second gas stream 314 comprised predominantly of helium. The process of FIG. 3 may also optionally include a cryogenic separation device 310 upstream of the reactive membrane 308 for separating out gases other than hydrogen and helium. Example cryogenic separation devices 310 include distillation systems, heat exchangers, separator vessels, valves, expanders, cryogenic distillation columns, a series of cryogenic distillation columns, or the like.

The reactive membrane 308 include a membrane within a reactor that in situ separates the hydrogen from the gas stream. The reactive membrane 308 may include, for example, a metallic membrane comprising palladium, a palladium alloy, platinum, rhodium, ruthenium, copper, nickel, silver, titanium, combinations thereof, or another metal. The reactive membrane may also comprise a ceramic material such as alumina, silica, or zirconia.

For example, the reactive membrane may include one or more metallic or ceramic support layers with a hydrogen permeable thin film membrane covered by a protective layer. The thin film may include palladium, a palladium alloy, platinum, or another suitable material that interacts selectively with hydrogen. The protective layer may also include palladium, a palladium alloy, platinum, rhodium, ruthenium, copper, nickel, silver, titanium, combinations thereof, or another metal.

In some examples, the first gas stream 312 has a hydrogen molar fraction of at least about 90 mol %, 95 mol %, 97 mol %, or 99 mol %. The second gas stream 314 may have a helium molar fraction of at least about 90 mol %, 95 mol %, 97 mol %, or 99 mol %.

In some embodiments, reactive membranes provide an improved performance of removing gases other than hydrogen over separation membranes. The performance of the reactive membrane may depend in part on the components upstream thereof. For example, processing the feedstock through a PSA device 306 prior to treatment in the reactive membrane 308 removes certain gases such as nitrogen, carbon dioxide, and methane such that the reactive membrane 308 can more efficiently remove hydrogen from the gas stream. Further, processing the feedstock from the PSA device 306 through a cryogenic separation device 310 prior to treatment in the reactive membrane 308 to remove gases other than hydrogen and helium may also improve performance of the reactive membrane.

In some embodiments, a size selective membrane may selectively remove helium as well as hydrogen from the rest of the components of an incoming gas stream. In some embodiments said size selective membrane can be used in conjunction with a PSA, being positioned on the effluent gas stream comprising hydrogen and helium, coming out of a PSA to further increase the concentration of said hydrogen and helium.

Power Generation

In further embodiments such as the embodiments illustrated in FIGS. 4 and 5, the hydrogen production system also includes a power generation plant 406, 506 that is powered by hydrogen from either of the feedstock from the geologic hydrogen source 402, 502 or the purification equipment 408. In some embodiments, the power generation plant 406, 506 is powered by the feedstock from the geologic hydrogen source 402, 502 only. In such embodiments, operating the power generation plant 406, 506 in this fashion avoids the production of greenhouse gases otherwise required to fuel the power generation plant 406, 506, and thereby further enhances the ability of the hydrogen production system to produce a low-CI score hydrogen gas product 410, 512.

Additionally or alternatively, the power generation plant 406, 506 may be partially or entirely powered by waste or purge gas from one or more of the purification equipment 408, including a reactive membrane 510 (FIG. 5). The purge gas may include various components such as unrecovered hydrogen, nitrogen, carbon dioxide, and methane, and can be used to generate power using a hydrogen gas turbine, a hydrogen engine, a hydrogen reciprocating generator, or other suitable power generator. In some embodiments, a PSA and/or a cryogenic device is provided upstream of the reactive membrane 510.

The power generation plant 406, 506 may include a generator, an engine, a turbine, an oxycombustion power plant, a reciprocating generator, a linear generator, a reciprocating compressor, a fuel cell, an aero-derivatives gas turbine, or another suitable power generator. The power generation plant 406, 506 in the hydrogen production system may be powered by hydrogen, purge/waste gas from the purification equipment 408, 508, or feedstock from the geologic hydrogen source 402, 502, in contrast to conventional power generators that are powered by fossil fuels.

Further, the power generation plant 406, 506 may be configured to provide energy to the compressor 404, 504 or components of the purification equipment 408, 508, including a reactive membrane 510 (FIG. 5). In some embodiments, the power generation plant 406, 506 also produces excess or additional energy that is provided to an independent system (not shown). Independent systems may include a power grid, compressors, datacenters, crypto mining operations, artificial intelligence (AI) processors, or other facilities. For example, crypto and AI datacenters that are optionally islanded may be powered by the power generation plant 406, or 506, resulting in a capacity factor of greater than 80%, greater than 90%, greater than 95%, greater than 99%, or greater than 99.9% without utilizing a grid connection. Said islanded facilities may be optionally connected to the electric grid for use as back-up power. Use of the hydrogen production systems described herein providing low CI-score hydrogen as a source for power generation enables the crypto and AI datacenters to operate at with a significant power consumption with minimal impact on the local power grid. Use of the hydrogen production systems described herein providing low CI-score hydrogen as a source for power generation enables the crypto and AI datacenters to operate at with a significant power consumption with minimal impact on carbon emissions.

In another embodiment, the hydrogen received by the power generation plant 406, 506 is comprised predominantly of hydrogen and helium. When the power generation plant 406, 506 is powered by feedstock from the geologic hydrogen source 402, 502, the feedstock includes noble gases that can be separated and captured. For example, the power generation plant 406, 506 may comprise a fuel cell configured to burn hydrogen and produce an effluent stream comprised predominantly of helium as well as generate power. In contrast, power generation plants configured to be powered by hydrogen from other sources such as electrolysis cannot produce an effluent stream comprising a noble gas.

Noble Gas Production

Referring to FIGS. 6 and 7, further embodiments of the hydrogen production system include a purification process for producing a noble gas product 616, 714. In such embodiments, the hydrogen production system includes first-stage purification equipment 608/610, 708 configured to receive feedstock from the geologic hydrogen source 602, 702 (optionally, following compression 604, 704) and produce an effluent, and second-stage purification equipment 612, 710 configured to receive the effluent from the first-stage purification equipment 608, 708 and produce a hydrogen gas product 614, 712 and a noble gas product 616, 714. The hydrogen production system shown in FIGS. 6 and 7 may, optionally, also be powered by a power generator 606, 706, in the manner described in connection with FIG. 5.

In the illustrated embodiments, the noble gas product 616, 714 comprises at least one of helium, neon, argon, xenon, krypton, or radon. In some embodiments, the noble gas product 616, 714 includes helium having a molar fraction of at least about 90 mol %, 95 mol %, 97 mol %, 99 mol %, or 99.5 mol %. In some embodiments, the second-stage purification equipment 612, 710 produces multiple noble gas products 616, 714. For example, the second-stage purification equipment 612, 710 may include a cryogenic separation device that includes a plurality of columns, which would allow for different gases to be captured.

The second-stage purification equipment may include a liquefier (e.g., liquefier 610), a guard bed, a further pressure swing adsorption (PSA) device, a separation membrane, and/or a reactive membrane. In some embodiments, a liquefier separates the noble gas(es) from the hydrogen. In still further embodiments, the liquefier produces the hydrogen gas product 614, 712 and the additional gases separated therefrom are directed to second-stage purification equipment 612, 710 that purifies and produces the noble gas product 616, 714. In still further embodiments, a separation or reactive membrane 208, 308 may be used to separate the noble gas from the hydrogen. In some embodiments additional cryogenic distillation columns reside in the same cold box as the liquefier and further separate the noble gases from each other.

Ammonia Production

Referring to FIGS. 8A and 8B, the hydrogen production system may also include an ammonia synthesis loop 808 that utilizes the hydrogen gas product 802 from the first-stage purification equipment 108, 408, 508, 608/610, 710 (see FIG. 8B) to produce an ammonia product 812. The hydrogen gas product 802 is first pressurized in a compressor 804 before entering the ammonia synthesis loop 808, which also receives nitrogen from a separate source 818. In other embodiments, the ammonia synthesis loop 808 described herein may be provided separately from the purification equipment 108, 408, 508, 608/610, 710. For example, the hydrogen gas product 802 may be delivered from the purification equipment to the ammonia synthesis loop 808 through a distribution system or other transport (e.g., the purification equipment may be fluidically coupled to the ammonia synthesis loop 808). As shown in FIGS. 8A and 8B, the hydrogen production system may optionally also be powered by a power generator 806 in the manner described in connection with FIG. 5.

The ammonia synthesis loop 808 produces an effluent 814 in addition to the ammonia product 812. The effluent 814 is directed to second-stage purification equipment 810 that produces a noble gas product such as a helium gas product 816. The second-stage purification equipment 810 may include a liquefier, a guard bed, a further pressure swing adsorption (PSA) device, a separation membrane, and/or a reactive membrane.

As shown in FIG. 8B, the ammonia product 812 from the ammonia synthesis loop 808 may be directed to additional components, such as a urea production unit 850. The urea production unit 850 may produce urea or a further ammonia product 852 as well as an ammonia product stream 854 that was not used to generate urea. Other components that utilize ammonia may be included downstream of the ammonia synthesis loop 808 as well. One embodiment of a urea production unit is a reactor wherein the Bosch-Meiser process takes place, ammonia and carbon dioxide react to form ammonia carbamate, which subsequently decomposes to urea and water.

In some embodiments, gases such as carbon dioxide and/or nitrogen removed from the feedstock in the first-stage purification equipment 108, 408, 508, 608/610, 710 may be used in the ammonia synthesis loop 808 or downstream components such as the urea production unit 850. For example, as shown in FIG. 8B, the urea production unit 850 may receive carbon dioxide purge gas from a PSA device 206, 306 of the first-stage purification equipment. Alternatively, or additionally, nitrogen purge gas from the first-stage purification equipment 108, 408, 508, 608/610, 710 may be directed to the ammonia synthesis loop 808 in addition or as an alternative to the nitrogen from a separate source 818.

FIG. 9 illustrates an alternative embodiment of a hydrogen production system that includes an ammonia synthesis loop 910 with an intermediate purification equipment 908 that further improves the purity of the hydrogen gas product 902 before entering the ammonia synthesis loop 910. The intermediate purification equipment 908 may include a PSA device, a guard bed, a separation membrane, a reactive membrane, or a cryogenic separation device. The ammonia synthesis loop 910 and the intermediate purification equipment 908 may be fluidically coupled to the first-stage purification equipment 108, 408, 508, 608/610, 710 and/or the second-stage purification equipment 912. By integrating the ammonia synthesis loop 910 within the stages of purification equipment, the input into the ammonia synthesis loop 910 is optimized. The hydrogen production system in FIG. 9 may also receive nitrogen from a separate source 918. Additionally, waste or purge gas from the second-stage purification equipment 912 may be directed to the compressor 904 upstream of the intermediate purification equipment 908, which allows for additional capturing of hydrogen that was unrecovered during the first processing through the ammonia synthesis loop 910.

Further, waste or purge gas from the first-stage purification equipment and the intermediate purification equipment 908 may be directed to the power generation plant 906, and energy from the power generation plant 906 may be directed to the compressor 904, the first stage purification equipment (see FIGS. 1 and 4-8), the intermediate purification equipment 908, the ammonia synthesis loop 910, and the second-stage purification equipment 912. In this way, the hydrogen production system may produce ammonia product 914 and a helium gas product 916, and may do so with lower CI scores than production methods that are not powered in this way.

Hydrogen Gas Product

In some embodiments, the hydrogen gas product 110 includes hydrogen, helium, and nitrogen. The hydrogen gas product 110 may also include carbon monoxide, carbon dioxide, and methane. In some embodiments, the hydrogen gas product 110 has a purity of greater than 90%. In some embodiments, the hydrogen gas product 110 does not include hydrogen that is produced using electrolysis, steam methane reformation, methane pyrolysis, or gasification.

In one example, the combined hydrogen and helium molar fraction is greater than 98 mol %. In further embodiments, the combined hydrogen and helium molar fraction is greater than 99 mol %, greater than 99.5 mol %, or greater than 99.999 mol %.

In some embodiments, the helium molar fraction of the hydrogen gas product 110 is greater than 0.5 mol %, 1 mol %, 2 mol %, 3 mol %, or 5 mol %.

The hydrogen gas product 110 may have a nitrogen molar fraction of less than 5 mol %, less than 4 mol %, less than 3 mol %, less than 2 mol %, or less than 1 mol %, or less than 0.5 mol %. In other embodiments, the nitrogen concentration may be less than 100 ppm, or less than 30 ppm.

The combined carbon monoxide and carbon dioxide concentration may be less than 50 ppm, or 1 ppm. The carbon monoxide concentration may be less than 0.2 ppm, and the carbon dioxide concentration may be less than 2 ppm.

The methane concentration may be less than 50 ppm, 2 ppm, or 1 ppm. The hydrogen gas product 110 comprises less than 1 ppm sulfur, or 0.4 ppm sulfur.

Example Analysis

In one example embodiment, the life cycle analysis of the production of a hydrogen gas product 110 from natural hydrogen was explored using a modified version of an open-source oil and gas greenhouse gas calculation tool, the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) v3.0a. Although the OPGEE model is based on conventional oil and gas production, modifications and extensions were made to represent natural hydrogen production. Key changes include modification of gas processing equipment calculations to account for differing composition of the gas, as well as the addition of a simplified pressure-swing absorption (PSA) unit for gas purification.

Baseline case results are shown in FIGS. 10 and 11. The flow schematic of FIG. 10 for the baseline case shows flows in simulated year 1 of the production process. Self-use of produced clean hydrogen is approximately 8% of gross hydrogen production, while hydrogen lost into the waste gas stream is 10% of gross production. FIG. 11 shows the production-weighted mean emissions for the baseline case in bar form on the left. Production-weighted mean baseline production intensity is 0.37 kg CO2 eq/kg H2 produced over the life of the well. The min-max range in CI is given by the year 1 emissions (min) and year 30 emissions (max), as shown in time trend on the right. Emissions increase over time due to reduced well productivity, resulting in more fugitive emissions per unit of gas produced and due to apportioning embodied emissions across fewer units of gas produced. The effect of productivity on fugitive emissions intensity has been seen in multiple empirical methane leakage studies and is well-supported by reasonable models of fugitive emissions causation. Median CI is slightly above the production-weighted mean. FIG. 12 shows a detailed breakdown of emissions sources for year 1 in the baseline case. The emissions are first partitioned into broad stages, such as drilling, production, separation and boost compression, gas processing, and reinjection. Combustion, venting/flaring/fugitive (VFF) emissions, offsite emissions, and embodied emissions are included within each of these broad stages. For clarity, VFF emissions include all purposeful (vented) and unpurposeful (fugitive) emissions from process units and piping. Offsite emissions are emissions that occur offsite in producing goods, services, energy, or other inputs imported to the site. In the baseline case, this category is mostly due to electricity purchases to run remaining electric loads (e.g., dehydration unit solvent circulation pumps), as well as diesel requirements during initial well drilling. In sensitivity cases where the system is electrically driven or uses imported natural gas, then these offsite emissions are larger. Lastly, embodied emissions refer to emissions associated with steel and cement production for those materials consumed during the construction process. These are mostly due to the drilling stage. Wells contribute the majority of embodied emissions because they require large amounts of steel for multiple layers of casing, as well as cement.

The model assumes that waste gas is reinjected into a waste gas disposal well at a similar pressure to the producing well and does not assume that waste gas is reinjected into the productive deposit. Although that kind of reinjection could be done to provide pressure support in the production formation through volumetric replacement of some of the produced gas, it would also result eventually in the breakthrough of large amounts of waste materials like N2 and CH4. To avoid this outcome, the model assumes that pressure and production in the reservoir decline in a classic depletion model and that the waste gas is disposed of in a disposal formation.

FIG. 12 does not show the miscellaneous emissions that OPGEE refers to as “small sources.” OPGEE recognizes that not all sources will be tracked in any given model. For example, OPGEE does not track energy use in small trucks driven by workers to and from the job site. This term was added to recognize that there are diminishing returns evident in modeling sources and that there are likely a number of small sources that exist but are not captured by the OPGEE model. In the default case, miscellaneous emissions are 10% of estimated direct sources, excluding embodied and offsite emissions.

FIG. 13 shows the results of sensitivity analyses for all studied sensitivity cases defined above, where a fixed value of 0.5 g CO2 equiv/MJ is used. At the bottom are the results for the baseline case. As in FIG. 11 above, the low and high error bars represent year 1 and year 30 emissions intensities as a proxy for variability in emissions from the same project over time. Numerous sensitivity cases have little impact on the CI.

By contrast, some sensitivity cases do end up causing large changes in CI. First, the disposition of the waste gas matters greatly. Although reinjection of waste gas is used in all other cases, dark blue-green bars show cases where (1) the waste gas is used on-site to power systems, then the remainder is reinjected, and (2) a case where waste gas is flared. In the waste gas re-use case, about 30% of the produced waste gas is consumed to power the process, and 70% is reinjected. Because of the carbon content of the waste gas (due to CH4), this results in higher emissions than the baseline case, though note that net H2 output as product does increase due to avoiding self-use of the pure H2 stream, thus reducing the gross-to-net loss of H2.

Also problematic is the flaring of waste gas, which results in large emissions due to both oxidation of the methane to CO2 and due to flare slip (OPGEE default values for flare destruction efficiency are used). Importantly, because the waste gas is simply flared, the equipment must still be powered, and therefore net H2 output to sales is still reduced by the energy requirements of the process. This therefore gives a secondary impact beyond the waste gas consumption case (e.g., the flaring case burns 100% of waste gas rather than 30% and still consumes about 7% of the produced H2 to power the process). Thus, flaring the associated waste gas is emissions intensive compared with other options. This impact of flaring is even larger in cases where the gas composition is rich in CH4 rather than N2 or where the H2 concentration is low.

Next are cases where the operations are powered with carbon-containing energy sources. A few effects result. First, these cases avoid the parasitic self-use of ˜7%-8% of gross H2 production, resulting in higher net output. However, they result in higher emissions in both the “Electric—US Average” and “Natural gas” cases. In fact, in the natural gas case, it is clearly strictly better to burn the produced waste gas: this is due to avoiding the upstream emissions associated with imported natural gas and due to the fact that the 10% H2 slip from the PSA device into the waste gas stream means that per unit heating value, the waste gas from our modeled process has lower CI than US average natural gas from OPGEE.

Next are two cases with gas composition high in CH4 (“High CH4” and “Low H2+CH4”). This increase in CH4 results in a number of noteworthy impacts. First, all fugitive emissions along the production and processing chain are made more GHG-intensive due to a higher volume fraction of CH4 in the fugitive emissions stream. Second, the output of useful clean H2 from the PSA is smaller due to the larger amount of CH4 in the raw gas stream, rendering all upstream drilling, compression, and dehydration emissions larger per unit of useful clean H2 produced. Third, the amount of waste gas to reinject gets larger, necessitating increased parasitic self-use of produced H2 and further reducing net H2 outputs to the consumer. In cases below 75 mol % H2, this effect gets increasingly large as the concentration drops due to these interacting impacts (see FIG. 14).

FIG. 14 sweeps over a wide range of concentrations. Although lower H2 concentrations are certainly found in the literature on gas sample collection, actual economic developers interested in natural H2 as a sustainable energy source would tend to focus on resources with higher H2 concentrations. Because developers will tend to focus on higher grade resources, it is unlikely that accumulations with low H2 concentration would be economic to develop.

The last major driver of emissions is treatment of embodied emissions. The importance of these is illustrated by the low emissions in the “no embodied emissions” case, which has a CI well below that of our baseline case. These impacts are also illustrated by the higher emissions intensity of the low-productivity case, wherein cumulative production per well drops to 25% of the baseline value (0.33 billion standard cubic feet (BCF) per well as compared with 1.33 BCF/well), and therefore embodied steel and cement emissions must be apportioned over a smaller amount of energy produced. In some life cycle models, such as the GREET model from Argonne National Laboratory, embodied emissions from various H2 production processes are not included by default, which would result in figures systematically lower than those produced by OPGEE.

Discussion of Example Analysis

This prospective analysis of a generic natural H2 production process shows that it is possible to extract low-CI H2 under reasonable assumptions about gas compositions, pressures, and production practices. If a clean energy source is used to power production processes (e.g., self-produced H2 or clean power), most of the remaining emissions are due to fugitive emissions of the raw gas during production and processing and embodied emissions. In our baseline case, loss of H2 as fugitive emissions to the transport inlet is modeled to be 0.8% of total wellhead H2 production (year 1 value). Although in line with other values in the literature (e.g., GREET model assumes 0.62%), diligent operators could possibly outperform this value. In addition to the significant uncertainty regarding fugitive emissions from oil and gas systems in general, it is still unclear how closely the fugitive emissions rates in OPGEE-derived from field studies of oil and gas production-will estimate those emissions for H2 production and processing.

Another possibly important factor is to consider the counter-factual case for what would have happened to the H2 in a natural system without extraction. It is possible that long-term interaction between H2 production and natural H2 seeps could exist, such that production and consumption of H2 from the subsurface could result in less natural seepage over time. This would potentially offset leakage impacts from H2 use by avoiding natural seepage. Given the large estimates of natural flux from the earth of 0.1-10 Tg H2/year noted above, atmospheric impacts should account for how much perturbation is provided by any human activity.

It is worthwhile to compare our results to others from the literature for other sources of H2, such as renewable-powered electrolysis or steam methane reforming with CO2 capture. As noted above, the GREET model does not include embodied energy in emissions, so it gives wind- and solar-derived H2 a CI of 0 kg CO2/kg H2. Those results are not comparable to the data here, which do include embodied emissions. Numerous other studies of green and blue H2 have been performed that do include embodied emissions. First, NETL performed detailed analyses of steam methane reforming systems, finding 16.4 kg CO2 equiv/kg H2 for the case without carbon capture and storage (CCS) and 8.9 kg CO2 equiv/kg H2 for the case with CCS. Kanz et al. found an average CI for solar-photovoltaic (PV)-derived H2 of 3.6 kg CO2/kg H2, with a 95% CI on the empirical data of 1.1-6.4 kg CO2 equiv/kg H2 (min-max=0.7-6.6). Numerous other studies exist, but there is little consensus in the literature, with Kanz et al. noting that only 14 of 33 studies could be harmonized due to lack of open data and stating that “Due to the lack of transparency of most LCAs included in this review, full identification of the sources of discrepancies (methods applied, assumed production conditions) is not possible.” Despite this uncertainty, the values estimated here for natural H2 are lower than those of green and blue H2 for most near-term modeling cases (that include embodied emissions).

Importantly, the global warming potential (GWP) of H2 is a matter of some recent debate, with 100-year GWPs in recent studies varying by a factor of 3 or so from the lowest to highest estimates. Shifting from the baseline GWP100 of 5 to a high estimate of 11 does not result in major changes to the GHG intensity (see FIG. 13). Shifting to a GWP20 instead of the OPGEE default of GWP100 would have a larger impact, but in that case, other sources such as natural gas would also have higher GHG intensity.

A key factor in low-CI production is the source of energy to power and heat for compression and gas processing. These results suggest that H2 could be a low-carbon source of energy if the gas is produced responsibly and the system is powered by low-carbon energy sources, either by self-produced clean H2 or by purchased certified green power (e.g., “Electric—RECS” case above, where RECS represents renewable energy certificates representing green attributes of power that can be purchased to offset emissions).

The baseline case has a production-weighted average CI for extraction and processing of ˜3 g CO2 equiv/MJ, or ˜20%-33% the production CI of conventional natural gas sources. Additionally, the end-product H2 has no combustion CI, compared with ˜50 g CO2 equiv/MJ for natural gas. Thus, the overall life cycle CI for natural H2 (including transport and end-use of the gas though not modeled explicitly here) is likely to exhibit a 90%-95% reduction compared with conventional gas.

Importantly, these results can be placed in the context of H2 production incentives. For example, the US Inflation Reduction Act (IRA) incentivizes H2 differently depending on its CI. The most stringent tranche requires a CI of 0.45 kg CO2 equiv per kg of H2 produced, while the decreasing incentives are available up to 4 kg CO2 equiv per kg H2 produced. The production cases modeled here generally fall into the most stringent or second-most stringent CI tranche. The only pathways modeled here that fail to align with these targets are the most CH4-rich cases shown in FIG. 14, which have significant fugitive emissions impacts and larger separation and reinjection losses. These results give a first indication that natural H2 may be competitive for clean H2 production standards.

CONCLUSION