PROCESS AND SYSTEM FOR PRODUCING FUEL

Abstract

A process and/or system for producing fuel using renewable hydrogen having a reduced carbon intensity. The renewable hydrogen is produced in a hydrogen production process comprising methane reforming, wherein at least a portion of the feedstock for the hydrogen production process comprises upgraded biogas sourced from a plurality of biogas plants. Each of the upgraded biogases is produced in a process that includes collecting biogas comprising methane and carbon dioxide, capturing at least 50% of the carbon dioxide originally present in the collected biogas and producing the upgraded biogas. Storage of the captured carbon dioxide reducing a carbon intensity of the fuel, without having to provide carbon capture and storage of carbon dioxide from hydrogen production.

Claims

1-28. (canceled)

29. A method for producing fuel, the method comprising: providing hydrogen produced from a hydrogen production process comprising methane reforming, at least two upgraded biogases used for producing the hydrogen, each of the at least two upgraded biogases produced in a process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and c) providing the captured carbon dioxide for storage; producing the fuel from a fuel production process using the provided hydrogen, wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces a carbon intensity of the fuel.

30. The method according to claim 29, wherein the fuel production process comprises hydrogenating crude oil derived liquid hydrocarbon with the hydrogen to produce the fuel.

31. The method according to claim 29, wherein the fuel production process comprises hydrogenating a renewable feedstock selected from renewable oil and renewable fat with the hydrogen to produce the fuel.

32. The method according to claim 29, wherein the fuel comprises gasoline, diesel, jet fuel, or any combination thereof.

33. The method according to claim 29, comprising obtaining one or more fuel credits associated with the hydrogen, the fuel, or a combination thereof.

34. The method according to claim 29, wherein carbon dioxide captured from one of the processes is provided for storage at a separate location than carbon dioxide captured from another of the processes.

35. The method according to claim 29, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for geological sequestration.

36. The method according to claim 29, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for enhanced oil recovery.

37. The method according to claim 29, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for sequestration in concrete.

38. The method according to claim 29, wherein step (c) of at least one of the processes comprises compressing the captured carbon dioxide and injecting the captured carbon dioxide into a carbon dioxide distribution system configured to transport the captured carbon dioxide to storage.

39. The method according to claim 29, wherein step (b) of at least one of the processes comprises capturing the carbon dioxide using carbon dioxide capture selected from cryogenic separation, membrane separation, and absorption with amine solvent.

40. The method according to claim 29, wherein step (b) of at least one of the processes comprises capturing at least 70% of the carbon dioxide originally present in the biogas.

41. The method according to claim 29, wherein the hydrogen is produced using the at least two upgraded biogases and fossil based natural gas.

42. The method according to claim 29, wherein the method does not include storing carbon dioxide produced from the hydrogen production process.

43. The method according to claim 29, wherein at least one of the at least two upgraded biogases is derived from organic waste.

44. The method according to claim 29, wherein at least one of the at least two upgraded biogases is derived from manure, the manure selected from swine manure and dairy manure.

45. The method according to claim 29, wherein at least one of the at least two upgraded biogases is obtained from landfill gas.

46. The method according to claim 29, wherein at least one of the at least two upgraded biogases is transported to the facility using a natural gas distribution system.

47. The method according to claim 29, wherein the methane reforming comprises steam methane reforming.

48. The method according to claim 29, wherein the methane reforming comprises autothermal reforming.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0016] FIG. 1 is a simplified process flow diagram of one embodiment of an SMR based hydrogen plant;

[0017] FIG. 2 is a simplified process flow diagram according to an embodiment of the invention; and

[0018] FIG. 3 is a simplified process flow diagram according to an embodiment of the invention.

DETAILED DESCRIPTION

[0019] Certain exemplary embodiments of the invention now will be described in more detail, with reference to the drawings, in which like features are identified by like reference numerals. The invention may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein.

[0020] The terminology used herein is for the purpose of describing certain embodiments only and is not intended to be limiting of the invention. For example, as used herein, the singular forms “a,” “an,” and “the” may include plural references unless the context clearly dictates otherwise. The terms “comprises”, “comprising”, “including”, and/or “includes”, as used herein, are intended to mean “including but not limited to.” The term “and/or”, as used herein, is intended to refer to either or both of the elements so conjoined. The phrase “at least one” in reference to a list of one or more elements, is intended to refer to 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. Thus, as a non-limiting example, the phrase “at least one of A and B” may refer to at least one A with no B present, at least one B with no A present, or at least one A and at least one B in combination. In the context of describing the combining of components by the “addition” or “adding” of one component to another, or the separating of components by the “removal” or “removing” of one component from another, those skilled in the art will understand that the order of addition/removal is not critical (unless stated otherwise). The terms “remove”, “removing”, and “removal”, with reference to one or more impurities, contaminants, and/or constituents of biogas, includes partial removal. The terms “cause” or “causing”, as used herein, may include arranging or bringing about a specific result (e.g., a withdrawal of a gas), either directly or indirectly, or to play a role in a series of activities through commercial arrangements such as a written agreement, verbal agreement, or contract. The term “associated with”, as used herein with reference to two elements (e.g., a fuel credit associated with the transportation fuel), is intended to refer to the two elements being connected with each other, linked to each other, related in some way, dependent upon each other in some way, and/or in some relationship with each other. The terms “first”, “second”, etc., may be used to distinguish one element from another, and these elements should not be limited by these terms. The term “plurality”, as used herein, refers to two or more. The term “providing” as used herein with respect to an element, refers to directly or indirectly obtaining the element and/or making the element available for use. The terms “upstream” and “downstream”, as used herein, refer to the disposition of a step/stage in the process with respect to the disposition of other steps/stages of the process. For example, the term upstream can be used to describe to a step/stage that occurs at an earlier point of the process, whereas the term downstream can be used to describe a step/stage that occurs later in the process. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.

[0021] The term “biomass”, as used herein, refers to organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae). Biomass is a renewable resource, which can be naturally replenished on a human timescale, and which can be used to produce bioenergy, biofuels (e.g., biogas), and/or renewable products (e.g., chemicals).

[0022] The term “biogas”, as used herein, refers to a gas mixture that contains methane produced from biomass. While biogas is predominately produced from the anaerobic digestion (AD) of biomass, it is also possible to produce biogas from the gasification of biomass. For example, the gasification of biomass may produce syngas, which may be cleaned up, and methanated. When produced from the anaerobic digestion of biomass, raw biogas typically includes methane (CH.sub.4), carbon dioxide (CO.sub.2), and can contain water (H.sub.2O), nitrogen (N.sub.2), hydrogen sulfide (H.sub.2S), ammonia (NH.sub.3), oxygen (O.sub.2), volatile organic compounds (VOCs), and/or siloxanes, depending up its source. The term biogas, as used herein, can refer to raw biogas, cleaned biogas, or upgraded biogas.

[0023] The term “raw biogas”, as used herein, refers to biogas as obtained from its source (e.g., anaerobic digester or landfill) before it is treated to remove any chemical components (e.g., CO.sub.2, H.sub.2O, H.sub.2S, O.sub.2, NH.sub.3, VOCs, siloxanes, and/or particulates). Raw biogas can be subjected to biogas cleaning to produce cleaned biogas or subjected to biogas upgrading to produce upgraded biogas.

[0024] The term “biogas cleaning”, as used herein, refers to a process where biogas (e.g., raw biogas) is treated to remove one or more components (e.g., H.sub.2O, H.sub.2S, O.sub.2, NH.sub.3, VOCs, siloxanes, and/or particulates), but does not remove a significant amount of CO.sub.2 and/or N.sub.2 (e.g., the calorific value of the biogas may not change significantly as a result of biogas cleaning).

[0025] The term “biogas upgrading”, as used herein, refers to a process where biogas (e.g., raw or cleaned biogas) is treated to remove one or more components (e.g., CO.sub.2, N.sub.2, H.sub.2O, H.sub.2S, O.sub.2, NH.sub.3, VOCs, siloxanes, and/or particulates), wherein the treatment is selected to increase the calorific value of the biogas. For example, biogas upgrading typically includes removing CO.sub.2 and/or N.sub.2. Biogas upgrading, which can include biogas cleaning, produces upgraded biogas. The term “upgraded biogas”, as used herein, can refer to a partially purified biogas (i.e., requires further treatment in order to meet applicable specifications) or renewable natural gas (RNG). The term “upgraded biogas”, as used herein, can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of upgraded biogas that was injected into the natural gas distribution system (e.g., upgraded biogas that was transported as a fungible batch in a natural gas pipeline).

[0026] The term “renewable natural gas” or “RNG”, as used herein, refers to biogas that has been upgraded to meet or exceed applicable natural gas pipeline specifications, meet or exceed applicable quality specifications for vehicle use (e.g., CNG specifications), and/or natural gas withdrawn from a natural gas distribution system that is associated with the environmental attributes of biogas injected into the natural gas distribution system (e.g., a gas that qualifies as RNG under applicable regulations). For example, the term RNG can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of RNG, upgraded from biogas, that was injected into the natural gas distribution system. Pipeline specifications include specifications required for biogas for injection into a natural gas distribution system. Pipeline quality standards or specifications may vary by region and/or country in terms of value and units. For example, pipelines standards may require the RNG to have a CH.sub.4 level that is at least 95% or have a heating value of at least 950 BTU/scf. The percentages used to quantify gas composition and/or a specific gas content, as used herein, are expressed as mol %, unless otherwise specified. More specifically, they are expressed by mole fraction at standard temperature and pressure (STP), which is equivalent to volume fraction.

[0027] The term “natural gas” or “NG”, as used herein, refers a gas mixture rich in hydrocarbons, where the primary component is CH.sub.4. The term “gas” or “gas mixture”, as used herein, refers to a fluid that is gaseous at standard temperatures and pressures, unless indicated otherwise.

[0028] The term “environmental attributes”, as used herein with regard to a specific material (e.g., biogas), refers to any and all attributes related to the material, including all rights, credits, benefits, or payments associated with the renewable nature of the material and/or the reduction in or avoidance of fossil fuel consumption or reduction in lifecycle GHG gas emissions associated with the use of the material. Some non-limiting examples of environmental attributes include verified emission reductions, voluntary emission reductions, offsets, allowances, credits, avoided compliance costs, emission rights and authorizations, certificates, voluntary carbon units, under any law or regulation, or any emission reduction registry, trading system, or reporting or reduction program for GHG gas emissions that is established, certified, maintained, or recognized by any international, governmental, or nongovernmental agency.

[0029] The terms “capturing and storing”, as used herein with reference to CO.sub.2, refers to capturing the CO.sub.2 and storing the captured CO.sub.2 to prevent the captured CO.sub.2, or an equal quantity of CO.sub.2 displaced physically by the captured CO.sub.2, from being released to the atmosphere. Capturing the CO.sub.2 can include removing CO.sub.2 from a gas mixture (e.g., biogas, syngas) using any suitable separation technology, or if the CO.sub.2 is relatively pure, capturing the CO.sub.2 can simply refer to collecting the CO.sub.2 (e.g., in a pipe). Storing the captured CO.sub.2 can include sequestering it underground (e.g., trapping it in geological formations, such as saline aquifers, or using it for enhanced oil recovery (EOR)), or can include storing the captured CO.sub.2 in one or more products (e.g., using the captured CO.sub.2 as a resource to create valuable products such plastics, concrete, etc.). For example, “capturing and storing CO.sub.2” can be part of one or more processes commonly referred to as “carbon capture and sequestration”, “carbon capture and utilization” or CCU, or “carbon capture, utilization and storage” or CCUS. In general, capturing and storing CO.sub.2 can also include compressing the captured CO.sub.2 (e.g., to produce liquid CO.sub.2 or for injection into a CO.sub.2 distribution system) and transporting the captured CO.sub.2 to storage (e.g., by vehicle and/or a CO.sub.2 distribution system). As will be understood by those skilled in the art, it can be advantageous to store the captured CO.sub.2, using a method recognized by the applicable regulatory authority for reducing GHG emissions and/or mitigating climate change.

[0030] The term “carbon intensity” or “CI” refers to the quantity of lifecycle GHG emissions, per unit of fuel energy, and is often expressed in grams of CO.sub.2 equivalent emissions per unit of fuel (e.g., gCO.sub.2e/MJ or gCO.sub.2e/MMBTU). As will be understood by those skilled in the art, CI and/or lifecycle GHG emissions are often determined using Lifecycle Analysis (LCA), which identifies and estimates all GHG emissions in producing fuel and/or product, from the growing or extraction of raw materials, to the production of the fuel and/or product, through to the end use (e.g., well-to-wheel). Those skilled in the art will understand that CI values and/or lifecycle GHG emissions for a given fuel and/or product can be dependent upon the LCA methodology used (e.g., as required by the applicable regulatory authority). Methodologies for calculating CI values and/or lifecycle GHG emissions according to various regulatory bodies are well known in the art and can be readily calculated by those of ordinary skill in the art. The CI values recited herein are determined using the CA-GREET3.0 model (e.g., see, https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation), unless otherwise specified.

[0031] The present disclosure relates to producing fuel and/or product in a process (e.g., fuel production process) that uses hydrogen and includes carbon capture and storage, wherein the carbon capture and storage includes the carbon capture and storage of CO.sub.2 removed from biogas (e.g., raw biogas).

[0032] Raw biogas produced from the anaerobic digestion of biomass can have a significant CO.sub.2 content (e.g., about 35%), which reduces the calorific value of the biogas (i.e., relative to pure methane). As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings. Alternatively, raw or cleaned biogas can be upgraded (e.g., to RNG) and used as a substitute for fossil based natural gas (e.g., used as a transportation fuel in the form of compressed RNG (bio-CNG) or liquefied RNG (bio-LNG)).

[0033] As a substitute for fossil based natural gas, upgraded biogas (e.g., RNG) may be used to produce renewable hydrogen using any technology suitable for converting natural gas to hydrogen (e.g., methane reforming). Renewable hydrogen, which can be in gas or liquid form, is very versatile as it can be used as fuel, converted into electricity, and/or used as industrial feedstock (e.g., to produce fuel, fuel intermediates, or products). For example, renewable hydrogen can power fuel cell electric vehicles (FCEVs), which emit no tailpipe emissions other than water, can be run through a fuel cell to power the electricity grid, or can be used in oil refining, ammonia production, fertilizer production, methanol production, and/or steel production. As described herein, renewable hydrogen also can be used to produce fuels (e.g., liquid fuel such gasoline, diesel, and/or jet fuel) that are renewable and/or have renewable content.

[0034] Converting upgraded biogas (e.g., RNG) to renewable hydrogen by SMR is advantageous in that it exploits technology that is well established for natural gas. Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations. While the relatively small scale and/or remote locations may be advantageous when the goal is to produce a grid of hydrogen refueling stations for FCEVs (e.g., where multiple geographically spaced small scale hydrogen plants can avoid transport and storage problems with hydrogen), such distributed hydrogen production cannot take advantage of economies of scale (e.g., SMR based hydrogen production is more economical when operated at a large scale), and thus is more expensive. Given the low value of raw biogas, the relatively small scale of many biogas plants, the cost of biogas upgrading, and/or the cost of SMR, it may be challenging to find facility owners willing to collect biogas and convert it to hydrogen, particularly since other uses of biogas are more economical.

[0035] It may be particularly challenging to find facility owners further willing to integrate CCS with such processes. Distributed carbon capture may be considered unfavorable compared to centralized large-scale carbon capture. For example, the cost of CCS is typically scale sensitive, and since distributed hydrogen production is generally small scale, the cost of CCS for distributed hydrogen production may be prohibitive. In addition, a lack infrastructure (e.g., CO.sub.2 pipelines) and/or space-consuming CO.sub.2 purification and capture equipment may be a deterrent for distributed CCS.

[0036] While large-scale CCS has been demonstrated for SMR plants that process fossil based natural gas, it is not cheap, and is not necessarily simple. For example, consider the hydrogen plant illustrated in FIG. 1. A stream of preheated natural gas 1 is desulfurized (not shown) and fed, along with steam 2, into the reactor tubes for the SMR 10, which contain the reforming catalyst. Streams of natural gas 3 and combustion air 4 are fed into the SMR burners, which provide the heat required for the endothermic reforming reaction. The syngas 15 produced from the SMR is fed to water gas shift (WGS) 20 to produce more hydrogen. The resulting syngas 25, which may also be referred to as shifted gas, is cooled (not shown) and purified using pressure swing adsorption (PSA) 30, which produces a stream enriched in hydrogen 32 and a purge stream 34. The purge stream 34, which may contain unconverted CH.sub.4, H.sub.2, CO.sub.2, and/or CO, is fed back to SMR 10, where it is used to provide process heat for the SMR (e.g., fuel the SMR burners). More specifically, the purge stream 34 is combusted together with the stream of natural gas 3.

[0037] In the hydrogen production process illustrated in FIG. 1, there are two sources of CO.sub.2, namely, CO.sub.2 produced from the feedstock 1 for the SMR (e.g., CO.sub.2 in the syngas 25), which can make up about 60% of the total CO.sub.2 produced, and CO.sub.2 produced from the fuel 3 for SMR (e.g., CO.sub.2 in the flue gas 12), which can make up about 40% of the total CO.sub.2 produced, depending upon the configuration of the hydrogen plant. In terms of capturing CO.sub.2, there are various options of how and where the CO.sub.2 may be captured, each with different energy requirements and/or yields. FIG. 1 identifies three possible options.

[0038] The first option, which is labelled A, captures CO.sub.2 from the flue gas 12, and thus captures both CO.sub.2 from the feedstock and CO.sub.2 from the fuel (e.g., may capture up to about 90% of the total CO.sub.2 produced). The second option, which is labelled B, captures CO.sub.2 from the syngas 25, and thus captures only the CO.sub.2 from the feedstock (e.g., about 60% of the CO.sub.2). The third option, which is labelled C, captures CO.sub.2 from the purge gas 34, and thus also captures only the CO.sub.2 from the feedstock. While the first option theoretically can capture more CO.sub.2 from the hydrogen production, capturing carbon dioxide from the syngas 25 (e.g., using vacuum pressure swing adsorption (VPSA) or an absorption amine unit) or from the purge gas 34 (e.g., using an activated amine process) may be more technically and/or economically feasible. For example, relative to the syngas 25, the flue gas may have a relatively low CO.sub.2 concentration (e.g., relatively low partial pressure) and/or may be at a lower pressure (e.g., atmospheric). In addition, the flue gas may contain N.sub.2 (N.sub.2—CH.sub.4 separations may be more challenging than CO.sub.2—CH.sub.4 separations).

[0039] In general, the SMR of fossil based natural gas to produce hydrogen can produce significant GHG emissions. While cooling of the syngas can allow heat recovery back into the process (e.g., steam generation and boiler feed water pre-heating), thereby preventing GHG emissions that would be associated with the heat, the resulting hydrogen can still have a high CI. For example, hydrogen produced from the SMR of fossil based natural gas, which is often referred to as “grey hydrogen,” may have a CI of about 100 gCO.sub.2e/MJ. When CCS is integrated with the SMR of fossil based natural gas, the resulting hydrogen it is often referred to as “blue hydrogen.” As will be understood by those skilled in the art, the CI of blue hydrogen is dependent on both the hydrogen production and how much of the fossil based CO.sub.2 is captured and stored. For example, in the case where only the CO.sub.2 from the feedstock is captured and stored (i.e., not the flue gas), blue hydrogen may have a CI of about 45 gCO.sub.2e/MJ.

[0040] As discussed herein, another approach to reduce the CI of hydrogen is to use a renewable feedstock (e.g., use RNG instead of fossil based natural gas), thereby producing renewable hydrogen. The CI of renewable hydrogen produced by the SMR of RNG can be dependent on the CI of the RNG, which can be dependent upon its source. For example, compared to the CI of fossil based natural gas, which can be about 80 gCO.sub.2e/MJ, RNG produced from a landfill may have a CI of about 46 gCO.sub.2e/MJ, whereas RNG produced from manure may have a CI of about −271 gCO.sub.2e/MJ of CH.sub.4 (e.g., as a result of avoided GHG emissions). Assuming that fossil based natural gas is used to fuel the SMR (e.g., fuel stream 3 is fossil based natural gas), the CI of renewable hydrogen produced by the SMR of landfill based RNG may be about 65 gCO.sub.2e/MJ (e.g., higher than blue hydrogen). If this process is integrated with CCS, wherein only the CO.sub.2 from the feedstock for SMR is captured and stored, the renewable hydrogen may have a CI of about 11 gCO.sub.2e/MJ. Such calculations are discussed in further detail with regard to Table 1. For comparative purposes, the CI of compressed H.sub.2 from electrolysis run with green electricity, which can be referred to as “green hydrogen”, may be less than 10 gCO.sub.2e/MJ.

[0041] The present disclosure relates to at least one process/system wherein at least a portion of the feedstock for hydrogen production and/or the fuel and/or product production is sourced from a plurality of biogas plants. Accordingly, the hydrogen production and/or fuel/product production can benefit from the economies of scale and/or higher efficiency. However, rather than relying on the capture and storage of CO.sub.2 produced from hydrogen production, the carbon capture and storage is distributed (i.e., biogenic CO.sub.2 is captured at a plurality of biogas plants).

[0042] While CCS at a plurality of biogas plants can be more expensive than CCS at a single hydrogen plant, there are various advantages and/or synergistic benefits of the process(es)/system(s) of instant disclosure. For example, it allows the benefits of CCS to accrue to hydrogen plants where CCS is not feasible (e.g., for economic reasons and/or technical reasons, such as extensive distances between the hydrogen plant and the storage site). Another advantage is that it can allow incremental transitioning, where upgraded biogas (associated with the distributed CCS) is co-processed with fossil based natural gas, thereby gradually increasing the production of hydrogen having a low CI. Advantageously, this can be achieved using existing hydrogen plants without modification. Yet another advantage is that it facilitates the aggregation of upgraded biogas from several locations (e.g., several biogas plants) and several CCS storage sites (e.g., basins) into one hydrogen production process.

[0043] One potential synergistic advantage of the process(es)/system(s) disclosure disclosed herein relates to capital efficiency. While the capital cost of distributed CCS from a plurality of biogas plants can be higher than the cost of CCS at a single hydrogen plant, the CI benefits of the capital for the distributed CCS accrues only to the upgraded biogas. In contrast, the CI benefits of the capital for CCS from centralized hydrogen production can accrue equally to all H.sub.2 produced (e.g., the CCS can be conducted on both renewable and fossil based feedstocks, and thus can be conducted on a much larger scale). In circumstances where biofuels are treated differently, this can create special advantages.

[0044] Referring to FIG. 2, there is shown an embodiment of the disclosure. Biomass is converted to biogas via multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv. For example, each of the multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv can include the anaerobic digestion of one or more feedstocks. In general, the feedstock for the multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv can be the same or different. For example, each of the multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv, may be conducted at landfill or anaerobic digester. Each of the multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv produces biogas (e.g., raw biogas) that is treated in respective processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv, to provide upgraded biogas 150.sub.i, 150.sub.ii, 150.sub.iii, 150.sub.iv, at least a portion of each provided to a facility 400a having hydrogen production 200. For example, at least part of the processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv maybe conducted at a biogas plant (e.g., located close to the source of biogas) and may be transported to the facility that has hydrogen production 400a. Hydrogen production 200 converts at least a portion of the upgraded biogas (e.g., RNG) to renewable hydrogen (e.g., via SMR). The renewable hydrogen in the H.sub.2 product 275 is used in a fuel and/or product production process 500 that produces the fuel/product 575 (e.g., a transportation fuel). In addition to biogas upgrading, the processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv also includes carbon capture wherein at least a portion of the CO.sub.2 from each of the biogases (e.g., generated during anaerobic digestion) is captured. The captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv is provided for storage 300.

[0045] In FIG. 2, the facility 400a having hydrogen production 200 is separate from the fuel and/or product production facility (e.g., is commercial hydrogen plant). In FIG. 3, the facility 400b having hydrogen production 200 is the fuel and/or product production facility.

[0046] In general, the upgraded biogas 150.sub.i, 150.sub.ii, 150.sub.iii, 150.sub.iv may be transported to hydrogen production 200, the captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv may be transported to storage 300, and/or the hydrogen product 275 may be transported to the fuel and/or product production facility, using any suitable mode of transportation, including transport by a commercial distribution system (e.g., pipeline) and/or vehicle (e.g., ship, rail car, and/or truck). For example, each of the upgraded biogases 150.sub.i, 150.sub.ii, 150.sub.iii, 150.sub.iv, each of the captured streams of CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv, and/or the hydrogen product 275 may be provided as segregated batch and/or a fungible batch. In one particularly advantageous embodiment, one or more of the upgraded biogases 150.sub.i, 150.sub.ii, 150.sub.iii, 150.sub.iv is injected into a natural gas distribution system near the corresponding processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv and is withdrawn from the same natural gas distribution system for hydrogen production 200 (e.g., is transported as a fungible batch to the hydrogen plant and/or fuel and/or product production facility).

[0047] In general, the captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv can be stored at one or more locations. For example, since the processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv may be conducted at different locations (e.g., different states or provinces), in some embodiments at least two of the captured streams CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv are provided for storage in different geological formations. In one embodiment, all of the captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv is stored in the same storage 300. In one embodiment, each of the captured CO.sub.2 gases 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv is stored at respective storage sites 300.sub.i, 300.sub.ii, 300.sub.iii, 300.sub.iv. In one embodiment, at least one of the CO.sub.2 gases 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv is used for CCSU, while another is used for CCS. In another example, all of the CO.sub.2 gases 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv are provided for geological sequestration, but are sequestered in more than one geological formation (e.g., based on proximity of the storage to processing).

[0048] Although this process relies on multiple CO.sub.2 capture steps, which are often considered to be energy-consuming steps, there are various advantages and/or synergetic benefits of using this process for producing fuel having renewable content and/or renewable hydrogen.

[0049] For example, compare the process discussed with reference to FIGS. 2 and 3 to the gasification of biomass. Biomass gasification may offer large scale centralized hydrogen production, facilitates collecting the biogenic carbon dioxide from one point source, and avoids some intermediate steps (e.g., the conversion of biomass to biogas and biogas upgrading). Nevertheless, there are challenges to hydrogen production via biomass gasification, many of which relate to the costs associated with capital equipment and biomass feedstocks. A facility producing 100 tonnes of hydrogen per day may be very large (e.g., require 1,350 dry tonnes of biomass feedstock per day), and thus may not be feasible based on regional supplies. Smaller facilities may be more feasible from a feedstock availability perspective but may drive up the capital expenditures. The cost of the biomass feedstocks can be dependent on costs for storage and transportation of the biomass, the latter of which may be dependent on the collection radius. Feedstock costs may be modest where agricultural residues can be collected and transported over short distances, but can be high when significant transport distances are involved, at least in part due to the low energy density of biomass.

[0050] Alternatively, compare the process discussed with reference to FIGS. 2 and 3 to the SMR of biogas, wherein biomass is transported to a centralized processing facility that conducts the anaerobic digestion, biogas upgrading, and hydrogen production (i.e., upgraded biogas is not transported). As with the gasification of biomass, the feedstock costs for such a process can be largely dependent on the storage and transportation of the biomass. When the feedstock has a large moisture content (e.g., manure or food waste) the transportation cost may be even higher.

[0051] In contrast, in the process illustrated in FIGS. 2 and 3, the upgraded biogas is transported to a facility having the hydrogen production 200. Transporting upgraded biogas over extended distances can be more cost efficient than transporting feedstock for anaerobic digestion and/or gasification. In particular, upgraded biogas such as RNG may be transported using any method suitable for transporting natural gas (e.g., a truck designed for transporting liquified natural gas (LNG) or compressed natural gas (CNG), the latter of which is often transported at pressures above about 3600 psig (24.8 MPa)). Transporting the upgraded biogas as bio-LNG or bio-CNG allows more MJ to be delivered per truck (e.g., relative to biomass for gasification or anaerobic digestion) and/or can increase the collection radius for the renewable feedstock. Alternatively, or additionally, the upgraded biogas can be transported by pipeline (e.g., in a natural gas distribution system such as the US natural gas grid), where it is transported as a fungible batch.

[0052] Transporting the upgraded biogas via a natural gas distribution system is particularly advantageous. In particular, it is a cost effective method that uses existing infrastructure, and depending upon the applicable regulatory agency, may have only a small penalty (cost and/or GHG emissions) for transporting the upgraded biogas over extended distances. Accordingly, the collection zone for the renewable feedstock is not necessarily limited to the area around a centralized facility conducting anaerobic digestion, biogas upgrading, and hydrogen production, but rather can include any area that provides feedstock for biogas production, where the biogas production is near the natural gas distribution system or can be economically transported to an injection point of the natural gas distribution system. This can increase the area from which the feedstock is collected, thereby making more feedstock available for the process and increasing the feasible scale of the renewable hydrogen production and/or CCS. Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).

[0053] Coprocessing renewable and non-renewable feedstock can increase the possible scale of hydrogen production, can facilitate using existing hydrogen plant(s) configured to process natural gas, and/or can reduce operational complications associated with intermittent renewable feedstock supply (e.g., cold start-up times may be between about 15 and 24 hours). Accordingly, the costs of hydrogen production can be reduced.

[0054] Advantageously, providing multiple CO.sub.2 capture steps (e.g., the disaggregation of CO.sub.2 capture process) for CO.sub.2 storage allows each capture process to be optimized for the CO.sub.2 capture. For example, since biogas upgrading typically includes separating CO.sub.2 from CH.sub.4, many biogas upgrading technologies can include CO.sub.2 capture, can be readily modified to include CO.sub.2 capture, or may facilitate CO.sub.2 capture, thereby reducing costs of the CO.sub.2 capture.

[0055] Further details about the biogas production 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv, the biogas processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv, hydrogen production 200, capture and/or storage 300, and fuel/product production 500, are discussed below.

Biogas Production

[0056] In general, the multiple biogas productions 50.sub.i, 50.sub.ii, 50.sub.iii, 50.sub.iv produce multiple biogases (i.e., each biogas production produces a respective biogas). Each biogas can be produced from any suitable biomass. For example, each biogas can be produced from the anaerobic digestion of any suitable feedstock. Anaerobic digestion, which refers to the biological breakdown of organic matter by anaerobic microorganisms, is typically conducted in anaerobic or low oxygen conditions, and may involve a series of microorganism types and processes (e.g., hydrolysis, acidogenesis, acetogenesis, and methanogenesis).

[0057] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of a feedstock, where the feedstock is and/or comprises: (i) an energy crop (e.g., switchgrass, sorghum, etc.); (ii) residues, byproducts, or waste from the processing of plant material in a facility, or feedstock derived therefrom (e.g., sugarcane bagasse, sugarcane tops/leaves, corn stover, etc.); (iii) agricultural residues (e.g., wheat straw, corn cobs, barley straw, corn stover, etc.); (iv) forestry material; (v) pulp and paper residues; and/or (vi) municipal waste or components removed or derived from municipal waste. In one embodiment, the feedstock for the anaerobic digestion is or includes cellulosic and/or lignocellulosic material(s).

[0058] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of “organic waste.” Using organic waste as the feedstock for anaerobic digestion is particularly advantageous. Organic waste, may for example, include the organic fraction of municipal solid waste (MSW), sludge from a wastewater treatment plant (WWTP), manure from a livestock farm (e.g., a dairy or swine farm), or food or yard waste collected from households, restaurants, supermarkets, food-processing companies, schools, businesses, etc. In one embodiment, the feedstock for the anaerobic digestion is manure (e.g., swine or dairy) or other farm waste, the organic fraction of MSW, or agricultural residues (e.g., straw, stover, etc.).

[0059] The composition of biogas produced from each anaerobic digestion can be dependent upon the feedstock. For example, although biogas produced from anaerobic digestion generally has a CH.sub.4 content between about 35% and 75% (e.g., about 60%) and a CO.sub.2 content between about 15% and 65% (e.g., about 35%), the CH.sub.4 content can tend towards the high end of this range when the feedstock is agricultural waste (e.g., between about 50% and 75%) and towards the low end of this range when the feedstock is the organic fraction of municipal solid waste (e.g., between about 25% and 65%). In addition to CH.sub.4 and CO.sub.2 biogas produced from anaerobic digestion may also include N.sub.2, H.sub.2O, H.sub.2S, O.sub.2, NH.sub.3, VOCs, siloxanes, and/or particulates, in dependence upon its source. For example, biogas produced from a landfill often has a higher N.sub.2 content than biogas produced in anaerobic digester. In one embodiment, each biogas has a CH.sub.4 content between about 25% and 75% and a CO.sub.2 content between about 15% and 65%, and the CO.sub.2 and CH.sub.4 make up at least 75% of the biogas by volume.

[0060] The anaerobic digestion of the feedstocks (e.g., solid or liquid) can be conducted in any suitable environment, including a natural environment (e.g., a landfill) or a controlled environment (e.g., an anaerobic digester). An anaerobic digester can be a holding tank, or another contained volume, such as a covered lagoon or sealed structure, configured to facilitate the breakdown of organic material by microorganisms under anaerobic or low oxygen conditions. Anaerobic digestion may be carried out in one or multiple anaerobic digesters connected in series and/or parallel, where each digester may be a single-stage or multi-stage digestion system, and/or may be designed and/or operated in a number of configurations including batch or continuous, mesophilic or thermophilic temperature ranges, and low, medium, or high rates. The term “anaerobic digester”, as used herein, can refer to plurality of fluidly connected anaerobic digesters. The operation of an anaerobic digester may be dependent on nature of the organic matter fed to the anaerobic digester and/or the level of digestion required. The appropriate selection of operating parameters, including but not limited to residence time, temperature, pH, and/or the nutrients supplied, will be known to those skilled in the art. When conducted in one or more anaerobic digesters, the anaerobic digestion of biomass also produces a potentially usable digestate. Digestate refers to the material remaining after one or more stages of the anaerobic digestion (e.g., may refer to acidogenic digestate, methanogenic digestate, or a combination thereof). Digestate can include organic material not digested by the anaerobic microorganisms, by-products of the anaerobic digestion released by the microorganisms, and/or the microorganisms themselves. For example, the digestate can include carbohydrates, nutrients (such as nitrogen compounds and phosphates), other organics, and/or wild yeasts. The composition of digestate, can vary depending on the biomass from which it is derived. Digestate often has both a solid and liquid component. A common use of digestate is as a soil conditioner, where it can provide nutrients for plant growth and/or displace the use of fossil-based fertilizers. In one embodiment, the digestate is processed to provide carbon-containing material that is stored as part of CCS. Processing of the digestate can include any type of processing, including but not limited to, solid liquid separations (e.g., feeding it into a screw press), heating, combustion, pyrolysis, hydrothermal treatment, etc.

[0061] In one embodiment, each of the biogases is produced from a single source (e.g., a landfill or anaerobic digester). In one embodiment, one or more of the biogases is produced from multiple sources (e.g., one or more landfills and/or one or more anaerobic digesters).

Biogas Upgrading

[0062] In general, at least part of each processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv includes biogas upgrading. Biogas upgrading, which can be conducted in a biogas plant situated at or close the biogas production, refers to a process where biogas is purified in one or more stages to provide upgraded biogas. Biogas upgrading, which increases the calorific value of the biogas, typically provides a CH.sub.4-rich gas having a CH.sub.4 content of at least 90%. In one embodiment, the upgraded biogases have a CH.sub.4 content of at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, or at least at least 98%. It can be particularly advantageous to produce upgraded biogas having a CH.sub.4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system. In one embodiment, the biogas upgrading produces RNG. In one embodiment, the biogas upgrading produces biogas having a CH.sub.4 content of at least 95%. In one embodiment, the biogas upgrading produces biogas having a heating value of at least 950 BTU/ft.sup.3.

[0063] Biogas upgrading can be conducted using any suitable technology or combination of technologies that can separate CH.sub.4 from one or more non-methane components in the biogas (e.g., CO.sub.2, N.sub.2, H.sub.2S, H.sub.2O, NH.sub.3, O.sub.2, VOCs, siloxanes, and/or particulates). For example, biogas upgrading technologies are often based on absorption, adsorption, membrane separation, and/or cryogenic separation. As will be understood by those skilled in the art, the technology used for the biogas upgrading can be dependent up the composition of the biogas and the desired purity of the upgraded biogas.

[0064] As biogas typically has a significant CO.sub.2 content, biogas plants often include at least one system for separating CH.sub.4 from CO.sub.2. Some examples of technologies that can remove CO.sub.2 from biogas include, but are not limited to, absorption (e.g., water scrubbing, organic physical scrubbing, chemical scrubbing), adsorption (e.g., pressure swing adsorption (PSA)), membrane separation (e.g., CO.sub.2 selective membranes based on polyimide, polysulfone, cellulose acetate, polydimethylsiloxane), and cryogenic separation.

[0065] While some CO.sub.2 removal systems may remove one or more other non-methane components in addition to CO.sub.2 (e.g., N.sub.2, H.sub.2S, H.sub.2O, NH.sub.3, O.sub.2, VOCs, siloxanes, and/or particulates), biogas plants often include one or more other systems (e.g., dehydration units, H.sub.2S removal units, N.sub.2 rejection units, etc.). For example, some CO.sub.2 removal systems require that the biogas be cleaned upstream of CO.sub.2 removal (e.g., remove impurities that can negatively affect the CO.sub.2 removal unit. Alternatively, or additionally, the biogas can be cleaned and/or upgraded downstream of CO.sub.2 removal. In general, the non-methane components can be removed by any combination of chemical and/or physical technologies, in one or more stages. For example, H.sub.2O may be removed using a standard biogas dehumidifier, whereas H.sub.2S may be removed using a commercial H.sub.2S removal unit (e.g., based on activated carbon, molecular sieve, iron sponge, water scrubbing, NaOH washing, and/or biofilter or biotrickling filter technologies). In some cases, one stage may remove more than one non-methane component. For example, in some cases, some H.sub.2S may also be removed during the water removal step.

[0066] In general, the biogas upgrading can be conducted close to the biogas source (e.g., at a biogas plant at the landfill site or near the anaerobic digester) and/or at a centralized biogas plant (e.g., which receives raw, cleaned, or partially purified biogas from multiple sources). For example, a centralized biogas plant may be connected to one or more anaerobic digesters (e.g., each at a separate farm) via a biogas pipeline and/or grid. Alternatively, or additionally, the centralized biogas plant may receive biogas from one or more biogas sources by vehicle (e.g., see U.S. Pat. No. 10,760,024). In one embodiment, each biogas processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv is conducted on biogas from a single biogas source. In one embodiment, at least one biogas processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv is conducted at a centralized processing plant that receives biogas from multiple biogas sources (e.g., multiple farms).

[0067] Each of the upgraded biogases 150.sub.i, 150.sub.ii, 150.sub.iii, 150.sub.iv is transported to a facility having hydrogen production (e.g., to a stand-alone hydrogen plant or to a production facility having at least one hydrogen production process). As each upgraded biogas may be relatively pure (e.g., have a CH.sub.4 content greater than about 92%), it may be transported using methods used to transport natural gas. For example, if the biogas is upgraded to RNG it can be transported in a CNG tanker (e.g., at a pressure of about 3600 psig) and/or transported by pipeline (e.g., a natural gas distribution system such as the US natural gas grid). In some cases, upgraded biogas that does not meet pipeline standards can be mixed with another gas (e.g., propane or fossil based natural gas) in order to facilitate injection into the natural gas distribution system.

[0068] In general, when upgraded biogas is transported by pipeline, it is transferred as a fluid (e.g., in gaseous or liquid form), and may be provided as a segregated batch or a fungible batch. The term “batch”, as used herein, refers to a certain amount of the gas (e.g., energy delivered) and does not imply or exclude an interruption in the production and/or delivery.

[0069] When upgraded biogas is transported as a fungible batch in a natural gas distribution system, a quantity of the upgraded biogas (e.g., in MJ) is injected into the natural gas distribution system, where it can comingle with non-renewable natural gas, and an equivalent quantity of gas (e.g., in MJ) is withdrawn at another location (i.e., as long as there is a physical link between the injection point and the withdrawal point). The transfer or allocation of the environmental attributes of the upgraded biogas injected into the natural gas distribution system to gas withdrawn at a different location is typically recognized. Accordingly, the withdrawn gas can be recognized as the transported upgraded biogas and/or can qualify as RNG under applicable regulations (e.g., even though the withdrawn gas may not contain actual molecules from the original biomass and/or contains methane from fossil sources). Such transport may be carried out on a displacement basis, where transactions within the natural gas distribution system involve a matching and balancing of inputs and outputs. Typically, the direction of the physical flow of gas is not considered. Establishing that a gas is recognized as and/or qualifies as RNG (e.g., originates from renewable sources) under applicable regulations can depend on whether the gas is transported by truck or by pipeline and the practices and requirements of the applicable regulatory agency, where such practices may include, for example, the use of chain of custody accounting methods such as identity preservation, book-and-claim, and/or mass balance.

[0070] Transporting the upgraded biogas via a natural gas grid is particularly advantageous as it facilitates transporting the renewable feedstock anywhere where the grid delivers without significant additional cost (e.g., financially and/or GHG emissions). In one embodiment, the upgraded biogas is transported to a facility having hydrogen production, at least in part, via a natural gas distribution system. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, by vehicle. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, using a transportation system.

[0071] The term “transportation system”, as used herein with reference to an element (e.g., natural gas or CO.sub.2 or H.sub.2), refers to a system configured to transport the element, and/or a fungible element, by a distribution system and/or vehicle. For example, a transportation system can include a mobile pressure vessel configured to be transported by vehicle (e.g., truck, rail car, ship). The term “distribution system”, as used herein with reference to an element (e.g., natural gas or CO.sub.2 or H.sub.2), refers to a system configured to transport the element, and/or a fungible element, in one or more interconnected pipes (e.g., by pipeline). For example, a natural gas distribution system such as the US natural gas grid can be used to transport natural gas and/or upgraded biogas.

Hydrogen Production

[0072] In general, the hydrogen production may be conducted at one or more hydrogen plants. The term “hydrogen plant”, as used herein, refers to a system or combination of systems primarily used for hydrogen production. The term “renewable hydrogen”, as used herein, refers to hydrogen produced using biogas (e.g., upgraded biogas and/or RNG). For example, the term “renewable hydrogen” can refer to hydrogen produced by methane reforming a feed withdrawn from a natural gas distribution system, when at least a portion of the withdrawn feed is recognized as and/or qualifies as RNG under applicable regulations.

[0073] In general, the hydrogen production may use any suitable technology known in the art that can convert one or more of the upgraded biogases and/or natural gas to hydrogen. Examples of technologies that may be suitable include, but are not limited to, steam methane reforming (SMR), autothermal reforming (ATR), partial oxidation (POX), and dry methane reforming (DMR). SMR, ATR, and DMR, which are types of catalytic reforming, may operate by exposing natural gas to a catalyst at high temperature and pressure to produce syngas. POX reactions, which include thermal partial oxidation reactions (TPOX) and catalytic partial oxidation reactions (CPOX), may occur when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a reformer. POX also may be referred to as oxidative reforming. For purposes herein, the term “methane reforming” may refer to SMR, ATR, DMR, or POX.

[0074] Of the various types of methane reforming, SMR is the most common. In SMR, which is an endothermic process, methane is reacted with steam under pressure in the presence of a catalyst to produce carbon monoxide (CO) and H.sub.2 according to the following reaction:

CH.sub.4+H.sub.2O+heat.fwdarw.CO+3H.sub.2  (1)

[0075] Referring to the hydrogen plant in FIG. 1, this reaction may occur in the SMR reactor tubes, which contain the reforming catalyst. Without being limiting, the catalyst may be nickel-based, the operating pressure may be between 200 psig (1.38 MPa) and 600 psig (4.14 MPa), and the operating temperature may be between about 450 to 1000° C. The heat required for the catalytic reforming of Eq. 1 can be provided by the combustion in the SMR burners (e.g., the combustion chamber may surround the reformer tubes in which the reaction is conducted).

[0076] The syngas produced from Eq. (1) may be further reacted in the WGS 20. The WGS is based on the water gas shift reaction, wherein carbon monoxide is converted to carbon dioxide and hydrogen:

CO+H.sub.2O.fwdarw.CO.sub.2+H.sub.2+small amount of heat  (2)

[0077] Providing WGS downstream of SMR increases the yield of H.sub.2, and thus is commonly included in hydrogen production. For example, in addition to H.sub.2, the syngas produced from the SMR may have a CO.sub.2 content between about 7-10%, a CO content between about 12-19%, and a CH.sub.4 content between about 2-6%, whereas the syngas produced from the WGS may have a CO.sub.2 content between about 15-16%, a CO content between about 4-5%, and a CH.sub.4 content between about 3-4%.

[0078] The gas produced from methane reforming (e.g., the syngas 25) is subjected to a hydrogen purification, wherein H.sub.2 is separated from CO, CO.sub.2, and/or CH.sub.4 in one or more stages to produce a hydrogen product (e.g., containing at least 80% hydrogen). For example, in one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 90, 92, 94, 96, 98, 99, or 99.5%. In one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 99.9%. Without being limiting, some examples of suitable hydrogen purification technologies include, but are not limited to: a) absorption, b) adsorption, c) membrane separation, d) cryogenic separation, and e) methanation. Some examples of absorption systems that may be suitable include, but are not limited to, a monoethanolamine (MEA) unit or a methyl-diethanolamine (MDEA) unit. A MEA unit may include one or more absorption columns containing an aqueous solution of MEA at about 30 wt %. The outlet liquid stream of solvent may be treated to regenerate the MEA and separate CO.sub.2. Some examples of adsorption systems that may be suitable include, but are not limited to, systems that use adsorbent bed (e.g., molecular sieves, activated carbon, active alumina, or silica gel) to remove impurities such as CH.sub.4, CO.sub.2, CO, N.sub.2, and/or water from the syngas gas. For example, hydrogen purification systems that are based on PSA are commonly used for hydrogen plants, as such systems produces a purge gas that can be recycled to fuel the SMR burners, thereby improving energy efficiency (e.g., see FIG. 1). In one embodiment, hydrogen purification uses vacuum PSA system (VPSA). Some examples of membranes systems that may be suitable include, but are not limited to, H.sub.2 selective membranes. A hydrogen purification unit that is based on cryogenic separation may cool the syngas gas down to temperatures where the impurities condense or sublimate and can be separated as a liquid or a solid fraction, while the hydrogen accumulates in the gas phase. For example, cryogenic separations may use temperatures below −10° C. or below −50° C. Methanation is a catalytic process that can be conducted to convert the residual carbon monoxide and/or carbon dioxide in the syngas to methane. For example, see equation 3.

CO+3H.sub.2.fwdarw.CH.sub.4+H.sub.2O  (3)

Since the methanation reaction consumes hydrogen, a hydrogen purification unit that includes a methanation may include CO.sub.2 removal prior to methanation.

[0079] In general, hydrogen production is well known and those skilled in the art will understand that the hydrogen plant(s) may use any suitable technology and/or have any suitable configuration. For example, the hydrogen production may be based on any suitable methane reforming technology combined with any suitable hydrogen purification. With specific regard to FIG. 1, those skilled in the art will understand that each of the SMR unit 10 and WGS unit 20 may include a single reactor or multiple reactors (e.g., the WGS unit 20 may include a high temperature WGS reactor (e.g., 350° C.) followed by a low temperature WGS reactor (e.g., 200° C.)), that the SMR reactor(s) may be top-fired reformers, side-fired reformers, bottom-fired reformers, etc., that the SMR reformer may be downstream of a purification unit to remove sulfur, chloride, olefin, and/or other compounds that may be detrimental to the SMR reforming catalysts, or that the SMR reformer may be downstream a pre-reforming unit, which allows a higher inlet feed temperature with minimal risk of carbon deposition. Those skilled in the art will also understand that although a steam methane reformer may be referred to as a “methane reformer,” typically they can convert any of the hydrocarbons present in the natural gas to syngas (i.e., not just the methane).

[0080] In the above-described embodiments, the feedstock for the hydrogen production process contains at least a portion of one or more of the upgraded biogases (e.g., RNG), which can be transported to the facility containing the hydrogen production (e.g., at least one hydrogen plant) by vehicle and/or as a fungible batch via a natural gas distribution system. In each embodiment, the feedstock may contain only the upgraded biogas or may contain both upgraded biogas and fossil based gas such as natural gas (e.g., the hydrogen can be produced by coprocessing renewable and non-renewable methane). When the feed contains both upgraded biogas and fossil based gas (e.g., natural gas or refinery gas), the quantity of renewable hydrogen produced can be determined using the renewable fraction of the feedstock (based on energy).

[0081] In the above-described embodiments, the feedstock for the renewable hydrogen process contains at least a portion of one or more of the upgraded biogases. However, in some embodiments, a portion of one or more of the upgraded biogases is fed to the combustion zone of the methane reformer (e.g., to the SMR burners). Since combusting upgraded biogas simply returns to the atmosphere carbon that was recently fixed by photosynthesis, and thus is considered relatively benign, this can reduce GHG emissions from the SMR furnace (e.g., compared to using fossil-based methane). Accordingly, the CI of renewable hydrogen could be reduced. While it may be advantageous to sacrifice some of the upgraded biogas for fuel in order to improve the GHG balance of the hydrogen production and/or fuel/product production process, this reduces the yield of renewable hydrogen and/or the yield of renewable content of the fuel(s)/product(s) produced. Accordingly, there may be a compromise between increasing the yield of renewable hydrogen/renewable content and decreasing the lifecycle GHG emissions, for a given quantity of upgraded biogas. In certain embodiments, low-carbon electricity such as renewable electricity is used to provide heat for the methane reforming (e.g., for SMR). Low-carbon electricity refers to electricity generated in a process that does not emit significant amounts of fossil-based carbon dioxide and/or is produced from renewable energy sources. Without being limiting, low-carbon electricity can include electricity produced using nuclear power, hydropower, solar power, wind power, geothermal power, wave power, tidal power, or electricity produced from the combustion of a low-carbon energy source (e.g., biomass, biogenic syngas, or hydrogen) or of a fossil-based energy source with CCS. In certain embodiments, heat required for the SMR is generated using renewable electricity (i.e., electricity produced using renewable energy sources such as hydropower, solar power, wind power, geothermal power, wave power, tidal power, etc.). In certain embodiments, the low-carbon electricity is generated from gasification of agricultural and/or solid waste. In general, any suitable technology known in the art that can use electricity to produce a sufficient amount of heat for at least part of the methane reforming can be used. The low-carbon electricity can produce the heat for methane reforming directly (e.g., to power resistive or inductive heaters that provide the heat directly for the methane reforming) and/or indirectly (e.g., using a heat storage medium and/or heat transfer fluid). In certain embodiments, the methane reformer (e.g., SMR) is an electrically heated methane reformer (e.g., electrically heated SMR), wherein the heat that would have been generated with conventional fired burners is replaced with electrically generated heat. Such methane reformers are generally configured such that there is no flue gas, and thus there are no carbon emissions associated with the flue gas (e.g., carbon emissions of hydrogen production may be reduced by 20-50% relative to the conventional fired SMR).

Carbon Capture and Storage

[0082] In general, at least part of each processing 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv includes carbon capture, wherein at least a portion of the CO.sub.2 from the biogas produced (e.g., generated during anaerobic digestion) is captured. The capture of CO.sub.2 from each biogas produced can be conducted using any suitable technology or combination of technologies that can capture CO.sub.2 for storage. As the CO.sub.2 may be part of a gas mixture (e.g., biogas, syngas, flue gas, etc.), the CO.sub.2 capture can include and/or depend upon the separation of CO.sub.2 from one or more other gas components in a gas mixture. Technology that may be suitable for separating CO.sub.2 from one or more other gas components in a gas mixture includes, but is not limited to, absorption, adsorption, membrane separation, and cryogenic separation.

[0083] The CO.sub.2 from each of the biogases (e.g., generated during anaerobic digestion) can be captured upstream of biogas upgrading, as part of biogas upgrading, and/or from a tail gas produced from biogas upgrading. For example, since biogas upgrading can include steps where CO.sub.2 is separated from CH.sub.4, such steps can be part of the CO.sub.2 capture process, or can facilitate the CO.sub.2 capture process, thereby reducing capital and operating costs. Biogas upgrading, which typically focuses on providing a relatively pure product stream (e.g., greater than 95% CH.sub.4), can produce a tail gas that contains CO.sub.2 separated from the CH.sub.4 in addition to other non-methane components separated from the CH.sub.4. For example, biogas upgrading units based on absorption, adsorption, or membrane separation, can produce a CO.sub.2 rich tail gas that is too impure for CO.sub.2 storage and/or transport without further purification and/or upstream removal of one or more components. However, in some cases, biogas upgrading (e.g., based on cryogenic separation), can yield both relatively pure CH.sub.4 (e.g., greater than about 95% CH.sub.4) and relatively pure CO.sub.2 (e.g., greater than about 95% CO.sub.2). While cryogenic biogas upgrading may require upstream biogas cleaning, it advantageously can provide the CO.sub.2 is a form that facilitates transport by vehicle and/or a CO.sub.2 distribution system (e.g., can provide the CO.sub.2 in liquid or solid form).

[0084] In one embodiment, at least one of the processing steps 100.sub.i, 100.sub.ii, 100.sub.iii, 100.sub.iv includes a separate CO.sub.2 removal step for the CO.sub.2 capture (i.e., separate from the biogas upgrading). For example, in one embodiment, a separate CO.sub.2 separation is conducted on the tail gas from biogas upgrading to provide a CO.sub.2 product that is sufficiently pure for CO.sub.2 storage and/or transport. In another embodiment, a separate CO.sub.2 separation is conducted upstream of biogas upgrading to provide a CO.sub.2 product that is sufficiently pure for CO.sub.2 storage and/or transport.

[0085] In one embodiment, the biogas upgrading is conducted in stages and at least one stage of the biogas upgrading is a CO.sub.2 capture step.

[0086] In one embodiment, the CO.sub.2 capture step is integrated with the biogas upgrading. For example, in one embodiment, the biogas upgrading is selected to and/or modified to provide a CO.sub.2 product suitable for geological storage and/or transport by a CO.sub.2 distribution system (e.g., after dehydration and compression). In general, this may be achieved by selecting suitable separation technology and/or modifying the configuration of the system (e.g., removing one or more components upstream of the CO.sub.2 separation). For example, in one embodiment, cryogenic CO.sub.2 capture is part of biogas upgrading. When cryogenic separation is used as part of biogas upgrading, the biogas may be cleaned (e.g., to remove H.sub.2S and H.sub.2O) and then subjected to a cryogenic separation that provides relatively pure CO.sub.2 (e.g., >95% CO.sub.2) while also providing a relatively pure CH.sub.4 (e.g., >95% CH.sub.4) and N.sub.2 (if present).

[0087] Storage of CO.sub.2 captured from the biogases can be conducted using any suitable technology or combination of technologies. For example, carbon storage technologies, which are well known in the art, can sequester CO.sub.2 in geological formations (i.e., subsurface formations). Suitable geological formations, which can occur in onshore or offshore settings, are often configured such that CO.sub.2 injected therein, is trapped. Appropriate storage of the CO.sub.2 can reduce GHG emissions and/or mitigate climate change. The level of GHG reduction achieved may be dependent on whether it is all biogenic, the applicable regulatory authority, the permanence of the storage, and/or whether its use displaces the use of fossil fuel products. In one embodiment, the captured CO.sub.2 from one or more of the biogases is sequestered in at least one geological formation. For example, in one embodiment the captured CO.sub.2 from one or more of the biogases is sequestered in a saline aquifer or is sequestered in an oil/natural gas reservoir as part of enhanced oil recovery (EOR)). In one embodiment, the captured CO.sub.2 from one or more of the biogases is stored in concrete. In one embodiment, storage of the captured CO.sub.2 from one or more of the biogases permanently displaces fossil based CO.sub.2 emissions.

[0088] The purity of the CO.sub.2 required for storage can be dependent upon the selected storage and/or selected mode of transportation, if applicable. For example, for geological sequestration and/or EOR, where the CO.sub.2 is often transported, at least in part, via a CO.sub.2 distribution system (e.g., pipeline), the CO.sub.2 content should be as high as possible (e.g., at least about 95%). However, for some applications (e.g., bauxite residue carbonation, etc.) lower CO.sub.2 contents may be suitable. In addition to a minimum CO.sub.2 content, the CO.sub.2 provided for storage and/or transport may have limits on the maximum amount of H.sub.2O, H.sub.2S, CO, CH.sub.4, N.sub.2, Ar, H.sub.2, etc.

[0089] In general, when the CO.sub.2 is captured far from storage, the process includes transporting the captured CO.sub.2 to storage (e.g., by vehicle and/or a CO.sub.2 distribution system). In order to transport CO.sub.2 for storage, the CO.sub.2 typically requires significant compression and/or cooling. When CO.sub.2 is transported by vehicle (e.g., truck, ship, rail car) it is often transported as a liquid (e.g., a pressure of about 290 psig and a temperature of about −20° C., or a pressure of about 100 psig and a temperature of about −50° C.). When CO.sub.2 is transported by a CO.sub.2 distribution system (e.g., a CO.sub.2 pipeline) it is often transported as a supercritical fluid (critical point is −31° C., −1070 psig). For example, many CO.sub.2 pipelines are operated between about 1250 psig and about 2200 psig, or higher. In some embodiments, the collected CO.sub.2 is also stored locally at a relatively high pressure (e.g., −1600 psig) prior to transport by pipeline. In general, the CO.sub.2 can be compressed to the desired pressure using a gas compressor, or alternatively, the collected CO.sub.2 can be liquified at a lower pressure using a refrigeration system (e.g., 235 psig) and then pumped to the desired pressure. In one embodiment, the process produces a compressed stream of relatively pure CO.sub.2 (e.g., at least 95% CO.sub.2). In one embodiment, the CO.sub.2 is transported to storage, at least in part, as a fungible batch using a CO.sub.2 distribution system.

[0090] The CO.sub.2 captured from the multiple biogas upgrading processes can be stored together or separately (e.g., in the same geological formation or in different geological formations). In general, how and where the captured CO.sub.2 is stored may be dependent upon the closest storage site. In one embodiment, the CO.sub.2 captured from one or more of the biogases is, at least in part, transported using a CO.sub.2 distribution system.

[0091] In one embodiment, at least 50% of the CO.sub.2 from each of one or more of the biogases is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO.sub.2 from each of one or more of the biogases is captured and stored.

[0092] In certain embodiments, the carbon intensity and/or lifecycle GHG emissions of the fuel/product(s) is further reduced by storing carbon containing material obtained or derived from the biogas production/biogas upgrading. For example, in certain embodiments, digestate from anaerobic digestion of the biomass is provided for storage as part of CCS. In certain embodiments, the digestate is treated prior to CCS. For example, digestate can be subjected to a hydrothermal liquefaction to provide a bio-oil that can be sequestered. In some cases, the sequestration method is selected to prevent biodegradation of the material and/or trap GHGs in the event of biodegradation. In some cases, the material is treated in a process to reduce the potential for biodegradation. The amount of carbon obtained or derived from the digestate and provided as part of CCS can be expressed as kg C per m.sup.3 (dry weight). Advantageously, storing a liquid or solid by-product produced from the process as part of CCS can further reduce the carbon intensity of the hydrogen produced and/or a fuel or product produced from the hydrogen.

Fuel or Product Production

[0093] In general, the process produces fuel and/or product (e.g., having renewable content) using renewable hydrogen. In one embodiment, the process produces fuel. In one embodiment, the fuel is methanol. In one embodiment, the fuel is gasoline, diesel, and/or jet fuel. In one embodiment, the fuel is an aviation fuel. In one embodiment, the fuel is a transportation fuel. In one embodiment, the fuel is a liquid transportation fuel. In one embodiment, the process produces one or more products (e.g., the renewable hydrogen is used as an industrial feedstock to produce one or more fuels and/or chemical products). In one embodiment, the renewable hydrogen is used to produce ammonia (e.g., in a Haber-Bosch process). In the Haber-Bosch process, which is well-known to those skilled in the art, nitrogen is converted to ammonia in a process conducted under high temperatures and pressures with a metal catalyst. Ammonia has an important role in the agricultural industry for production of fertilizers. Ammonia may also be used as a fuel and/or an energy carrier for energy storage and transportation. In one embodiment, the renewable hydrogen is used to produce fertilizer. Using the upgraded biogas and/or renewable hydrogen to produce fuel and/or product can provide the fuel and/or product with renewable content and/or can reduce the lifecycle GHG emissions of the fuel and/or product, particularly when the upgraded biogas and/or renewable hydrogen has a low CI attributed to CCS.

[0094] In general, the fuel and/or product may be produced by processing the upgraded biogas and/or renewable hydrogen with one or more other renewable feedstocks and/or one or more non-renewable feedstocks. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the fuel can have renewable content (e.g., be a partially renewable fuel). The term “renewable content”, as used herein, refers the portion of the fuel(s)/product(s) that is recognized and/or qualifies as renewable (e.g., a biofuel) under applicable regulations. The quantification of the renewable content can be determined using any suitable method and is typically dependent upon the applicable regulations.

[0095] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon such that the renewable hydrogen is incorporated into a crude-oil derived liquid hydrocarbon to produce gasoline, diesel, and/or jet fuel having renewable content (e.g., see U.S. Pat. Nos. 8,658,026, 8,753,854, 8,945,373, 9,040,271, 10,093,540, 10,421,663, and 10,723,621, 10,981,784). In this embodiment, use of the renewable hydrogen can produce gasoline, diesel, and/or jet fuel having renewal content. Advantageously, such fuels can replace and/or be used with non-renewable gasoline, diesel, and/or jet fuel without affecting performance and/or operation (e.g., are drop-in fuels). Further advantageously, such fuels can be produced at existing oil refineries using existing equipment. The term “crude oil derived liquid hydrocarbon”, as used herein, refers to any carbon-containing material obtained and/or derived from crude oil that is liquid at standard ambient temperature and pressure. The term “crude oil”, as used herein, refers to petroleum extracted from geological formations (e.g., in its unrefined form). Crude oil includes liquid, gaseous, and/or solid carbon-containing material from geological formations, including oil reservoirs, such as hydrocarbons found within rock formations, oil sands, or oil shale. In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon to produce aviation fuel having renewable content. This embodiment is particularly advantageous as it could help decarbonize commercial air travel and/or extend the life of older aircraft types by lowering their carbon footprint.

[0096] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of renewable fats and/or oils (e.g., algae, jatropha, tallows, camelina, pyrolysis oil produced from biomass, etc.) to produce renewable gasoline, diesel, and/or jet fuel. This embodiment is particularly advantageous as the resulting fuel can be fully renewable and have a reduced CI (i.e., relative to an analogy process where the hydrogen is produced from fossil based natural gas).

[0097] In general, the renewable hydrogen can be used in any suitable fuel and/or product production process. For example, in one embodiment, the renewable hydrogen is used in a Fischer-Tropsch type process to produce a liquid transportation fuel. In one embodiment, the renewable hydrogen and biogenic carbon dioxide are subjected to a gas fermentation to produce an alcohol such as ethanol.

[0098] In general, the renewable hydrogen may be produced at a commercial hydrogen plant or at a hydrogen plant at the production facility. In both cases, the renewable hydrogen may be provided for fuel/product production via a H.sub.2 distribution system (e.g., a H.sub.2 pipeline or local H.sub.2 pipe system) as a fungible batch. More specifically, the renewable hydrogen may be allocated for the desired use (e.g., a specific fuel production process or a specific hydroprocessing unit). The term “allocating”, as used herein in respect of a particular element, refers to designating the element for a specific purpose.

Carbon Intensity and/or Fuel Credits

[0099] In general, the carbon intensity and/or lifecycle GHG emissions of the fuel and/or product having renewable content is relatively low as a result of the use of renewable hydrogen and/or storage of captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv (i.e., low relative to fuel produced by an analogous process using hydrogen produced using fossil based natural gas or an analogous process where the biogenic CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv is not stored). Advantageously, when the process produces fuel, the renewable content attributed to the use of renewable hydrogen and/or the low CI attributed to storing the captured CO.sub.2 170.sub.i, 170.sub.ii, 170.sub.iii, 170.sub.iv can facilitate the generation of fuel credits.

[0100] Fuel credits are used to incentivize renewable fuels, often in the transportation sector. For example, fuel credits can be used to demonstrate compliance with some government initiative, standard, and/or program, where the goal is to reduce GHG emissions (e.g., reduce CI in transportation fuels as compared to some baseline level related to conventional petroleum fuels) and/or produce a certain amount of biofuel (e.g., produce a mandated volume or a certain percentage of biofuels). The target GHG reductions and/or target biofuel amounts may be set per year or for a given target date. Some non-limiting examples of such initiatives, standards, and/or programs include the Renewable Fuel Standard Program (RFS2) in the United States, the Renewable Energy Directive (RED II) in Europe, the Fuel Quality Directive in Europe, the Renewable Transport Fuel Obligation (RTFO) in the United Kingdom, and/or the Low Carbon Fuel Standards (LCFS) in California, Oregon, or British Columbia).

[0101] The term “fuel credit”, as used herein, refers to any rights, credits, revenues, offsets, GHG gas rights, or similar rights related to carbon credits, rights to any GHG gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract, or otherwise. A fuel credit can be a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline (e.g., a gasoline baseline) set by a government authority. Non-limiting examples of fuel credits include RINs and LCFS credits. A Renewable Identification Number (or RIN), which is a certificate that acts as a tradable currency for managing compliance under the RFS2, may be generated for each gallon of biofuel (e.g., ethanol, biodiesel, etc.) produced. A Low Carbon Fuel Standard (LCFS) credit, which is a certificate which acts as a tradable currency for managing compliance under California's LCFS, may be generated for each metric ton (MT) of CO.sub.2 reduced.

[0102] In general, the requirements for generating or causing the generation of fuel credits can vary by country, the agency, and or the prevailing regulations in/under which the fuel credit is generated. In many cases, fuel credit generation may be dependent upon a compliance pathway (e.g., predetermined or applied for) and/or the biofuel meeting a predetermined GHG emission threshold. For example, with regard to the former, the RFS2 categorizes biofuel as cellulosic biofuel, advanced biofuel, renewable biofuel, and biomass-based diesel. With regard to the latter, to be a renewable biofuel under the RFS2, corn ethanol should have lifecycle GHG emissions at least 20% lower than an energy-equivalent quantity of gasoline (e.g., 20% lower than the 2005 EPA average gasoline baseline of 93.08 gCO.sub.2e/MJ). In low carbon-related fuel standards, biofuels may be credited according to the carbon reductions of their pathway. For example, under California's LCFS, each biofuel is given a CI score indicating their GHG emissions as grams of CO.sub.2 equivalent per megajoule (MJ) of fuel, and fuel credits are generated based on a comparison of their emissions reductions to a target or standard that may decrease each year (e.g., in 2019, ethanol was compared to the gasoline average CI of 93.23 gCO.sub.2e/MJ), where lower CIs generate proportionally more credits. In one embodiment, the fuel produced is a transportation fuel, and a fuel credit is generated or is caused to be generated. In one embodiment, the transportation fuel and/or renewable content has lifecycle GHG emissions that are at least 20% less than the lifecycle GHG emissions of a gasoline baseline using EPA methodology, preferably at least 50% or 60% less.

[0103] With respect to renewable hydrogen produced according to the instant disclosure, it can be advantageous for the CI of the hydrogen to be as low as possible, particularly when the hydrogen is used as a fuel or to produce a fuel, so that more valuable fuel credits can be generated. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the CI is measured for the resulting product from each of the co-processed feedstocks (i.e., there is a different CI for each the renewable and non-renewable feedstocks). In one embodiment, the process includes producing hydrogen associated with one or more producer credits.

Example

[0104] Referring to Table 1, there is shown a list of estimated GHG emission values for hydrogen produced by various processes. As summarized in Table 2, these processes produce: 1) grey hydrogen from the SMR of natural gas with no CCS; 2) blue hydrogen from the SMR of natural gas with CCS (i.e., where the CO.sub.2 is captured from the feedstock); 3) renewable hydrogen labelled “RH” from the SMR of RNG with no CCS; 4) renewable hydrogen labelled “RH+CCS.sub.H2” from the SMR of RNG with CCS (i.e., where the CO.sub.2 is captured from the feedstock only); 5) renewable hydrogen labelled “RH+CCS.sub.H2+CCS.sub.BG” from the SMR of RNG with CCS (i.e., where the CO.sub.2 is captured from the feedstock and from the biogas); and 6) renewable hydrogen labelled “RH+CCS.sub.BG” from the SMR of RNG with CCS (i.e., where the CO.sub.2 is captured from the biogas only).

[0105] For each process, it was assumed that the fuel for the SMR burners is fossil based natural gas and that the feedstock for the methane reforming is RNG produced from landfill gas (i.e., is upgraded landfill gas). In order to compare the different processes, which can use different feedstocks, the emissions for the hydrogen production were split into the contributions from the feedstock (i.e., upstream emissions) and from the hydrogen production. Each emission (positive number) and emission credit (negative number) is an estimation based on one or more published values and/or determined using stoichiometry. For example, the feedstock emissions of 10 gCO.sub.2e/MJ of H.sub.2 for natural gas and 35 gCO.sub.2e/MJ of H.sub.2 for landfill gas are estimated from the CA-GREET 3.0 model. The feedstock emission credit of −42 gCO.sub.2e/MJ of H.sub.2, which is a net credit at least partially based on theoretical calculations, assumes that the emissions for CCS of the biogas is 5 gCO.sub.2e/MJ of H.sub.2. For the hydrogen production, emissions from the combustion of fuel for the SMR burners is assumed to be 28 gCO.sub.2e/MJ of H.sub.2, electricity is assumed to be 2 gCO.sub.2e/MJ of H.sub.2, and emissions from the conversion of the feedstock to syngas is assumed to be 60 gCO.sub.2e per MJ of H.sub.2. Assuming all of the CO.sub.2 from the feedstock is captured and stored, and if the CCS process from hydrogen production results in 5 gCO.sub.2e/MJ of H.sub.2 of emissions, the CCS.sub.H2 process provides a net credit of −55 gCO.sub.2e/MJ of H.sub.2.

TABLE-US-00001 TABLE 1 GHG Emission Values, in gCO.sub.2e/MJ of H.sub.2, for various SMR based H.sub.2 production processes Feedstock Hydrogen Plant Feedstock Hydrogen CO.sub.2 Fuel Feedstock Plant CO.sub.2 Process Feedstock capture Combustion conversion Electricity capture CI Grey H.sub.2 10 28 60 2 100 Blue H.sub.2 10 28 60 2 −55 45 RH 35 28 2 65 RH + CCS.sub.H2 35 28 2 −55 11 RH + CCS.sub.H2 + 35 −42 28 2 −55 −31 CCS.sub.BG RH + CCS.sub.BG 35 −42 28 2 24

TABLE-US-00002 TABLE 2 Summary of the various SMR based H.sub.2 production processes Process Description Feedstock CO.sub.2 capture 1 Grey H.sub.2 Natural Gas None 2 Blue H.sub.2 Natural Gas Yes—Syngas 3 Renewable H.sub.2 (RH) RNG (landfill) None 4 Renewable H.sub.2 RNG (landfill) Yes—Syngas only and CCS.sub.H2 5 Renewable H.sub.2 and RNG (landfill) Yes—Syngas and CCS.sub.H2 and CCS.sub.BG upstream 6 Renewable H.sub.2 RNG (landfill) Yes—Upstream only and CCS.sub.BG

[0106] While the GHG emission values in Table 1 are estimations provided for comparative purposes, they do appear reasonable. For example, Table 1 lists the CI of grey hydrogen as 100 gCO.sub.2e/MJ, which is within a published range of 94.8 to 101.4 g CO2e/MJ. With regard to the CI of blue hydrogen, which Table 1 lists as 45 gCO.sub.2e/MJ (with CCS of about 60% of the total CO.sub.2 produced), some published values are 19.6 gCO.sub.2e/MJ (with CCS of about 90% of the total CO.sub.2 produced) and 34.5 gCO.sub.2e/MJ (with CCS of about 80% of the total CO.sub.2 produced).

[0107] As evident from Table 1, simply using RNG as a feedstock for hydrogen production, using RNG as a feedstock for hydrogen production and capturing CO.sub.2 from the hydrogen production, or using RNG as a feedstock for hydrogen production and capturing CO.sub.2 from the biogas, does not necessarily produce hydrogen having a negative CI, and can produce hydrogen having a higher CI than green hydrogen (e.g., which can be less than 10 gCO.sub.2e/MJ).

[0108] However, as evident from Table 1, using RNG as a feedstock for hydrogen production and capturing CO.sub.2 from the biogas does produce hydrogen having a lower CI than blue hydrogen, without the challenges of capturing and storing CO.sub.2 from hydrogen production. Moreover, it produces renewable hydrogen. When renewable hydrogen having a relatively low CI is used in a fuel and/or product production process, the fuel and/or product produced can have renewable content, and the renewable content can have a relatively low CI (i.e., relative to the analogous process without storing the CO.sub.2 from the biogas). Accordingly, the process(es) disclosed herein can be used to produce fuel having renewable content and a relatively low CI without CCS of CO.sub.2 from hydrogen production.

[0109] Of course, the above embodiments have been provided as examples only. It will be appreciated by those of ordinary skill in the art that various modifications, alternate configurations, and/or equivalents will be employed without departing from the scope of the invention. For example, although the instant disclosure provides a process that provides renewable hydrogen and/or fuel and/or product having renewable content, with a relatively low CI without CCS of CO.sub.2 from the hydrogen production, and although this is generally advantageous, in some embodiments, the CO.sub.2 from hydrogen production is also captured and stored (e.g., from the syngas and/or the flue gas). Accordingly, the scope of the invention is therefore intended to be limited solely by the scope of the appended claims.