Hydrocarbon reforming for production of hydrogen with integrated carbon capture

Abstract

The present disclosure provides systems and methods for hydrogen production as well as apparatuses useful in such systems and methods. Hydrogen is produced by reforming of a hydrocarbon in a first convective reformer, a second convective reformer, and an oxygen secondary reformer. The first convective reformer may be heated with a combustion exhaust stream, and the second convective reformer may be heated using a synthesis gas stream from the oxygen secondary reformer. Hydrogen thus may be produced with high recovery and cycle efficiency with low or no carbon dioxide emissions.

Description

[0001] AttyDktNo. P62622 2350WO (01244)

[0002] HYDROCARBON REFORMING FOR PRODUCTION OF HYDROGEN WITH INTEGRATED

[0003] CARBON CAPTURE

[0004] FIELD OF THE DISCLOSURE

[0005] The present disclosure relates to systems and methods for production of hydrogen by reforming of hydrocarbons in a plurality of reforming reactors.

[0006] BACKGROUND

[0007] Various processes are known for producing hydrogen, such as electrolysis of water and reforming of hydrocarbons. Electrolysis requires significant power consumption, and the electricity that is used must be from a carbon-free source to secure an environmental advantage and be referenced as so-called “green hydrogen.” Reforming of hydrocarbons requires significant heat input to drive the endothermic reactions. The synthesis gas (“syngas”) produced by reforming of hydrocarbons must be further processed to separate hydrogen from the remaining components, such as carbon monoxide (“CO”) and carbon dioxide (“CO2”). Reforming of hydrocarbons likewise has an associated environmental impact that must be mitigated by, for example, capturing emissions, such as CO and CO2. “Black” or “brown” hydrogen is provided by processes that generate hydrogen from black (bituminous) or brown (lignite) coals and that have no capture or low efficiency capture of the generated CO and CO2 emissions Hydrogen generated from natural gas or methane through steam reforming may be referenced as “grey” hydrogen due to reduced emissions compared to black and brown hydrogen, but the capture of carbon remains low. Production of “blue” hydrogen may be claimed when capture of the CO and CO2 occurs at relatively greater levels than black, brown, or even gray hydrogen production, for example, such as capturing at least 85% of the CO and CO2, or such as capture of at least 95% capture of the CO and CO2.

[0008] SUMMARY OF THE DISCLOSURE

[0009] The present disclosure relates to hydrogen production methods, individual pieces of equipment or apparatuses that are useful for hydrogen production, and combinations of pieces of the equipment or apparatuses that together may define systems, units, or plants configured for hydrogen production. The hydrogen production of the present disclosure may be carried out so that the produced hydrogen may be isolated with increased purity of product and increased process efficiency over traditional processing and production methods through appropriate combinations of system components and system operational procedures, embodiments of which are described forthcoming. The hydrogen production may be carried out with associated separation of carbon dioxide from the remainder of the products and, in some instances, byproducts. Such separated carbon dioxide may be separated such that it is not released into the environment but rather is produced as a product, such as for subsurface or other forms of chemical or physical sequestration. The hydrogen and the carbon dioxide productions may be carried out with separation of other materials, such as inert gases, for example, nitrogen and argon. The hydrogen production may

[0010] WBD (US) 4910-8123-0946vl -1- AttyDktNo. P62622 2350WO (01244) exhibit improved process efficiency and reduced materials costs through utilization of specifically chosen component parts in a hydrogen production unit, system, or plant.

[0011] Hydrogen has been described as the fuel of the future. Widespread use of hydrogen to replace hydrocarbon fuels (and complemented by renewable energy production from wind and solar systems) has been described as the best route to achieving low to zero anthropogenic emission of carbon dioxide to help address climate change. Hydrogen specifically may be used as a replacement for hydrocarbon fuels. Hydrogen may replace natural gas in the pipeline distribution network for supplying fuel for domestic, commercial, and industrial heating. Hydrogen combustion for energy production emits only water and avoids the production of carbon dioxide at the point of combustion of the hydrogen, such as when hydrocarbon fuels are burned for energy production.

[0012] Hydrogen may be produced by steam methane reforming (“SMR”) or gasification of hydrocarbons, such as coal, natural gas, or methane. The most widely used process is steam natural gas catalytic reforming, which is defined by Equation 1 :

[0013] CnH(2m) + H2O <-> nCO + (m+l)H2Eq. 1 - Steam Methane Reforming, where n is an integer of 1 or greater and m is an integer of 2 or greater. The catalytic SMR reaction is highly endothermic. Heat is typically supplied by burning methane plus waste fuel gas in a radiant furnace, which heats an array of thick-walled tubes filled with reforming catalyst. The reaction product syngas typically comprises hydrogen, CO, and CO2.

[0014] The product in Equation 1 may be further processed using the water gas shift (WGS) reaction according to Equation 2:

[0015] CO + H2O CO2 + H2Eq. 2 - Water Gas Shift.

[0016] The reaction product syngas is cooled before being passed through one or more WGS reactors, where the carbon monoxide reacts with water in the presence of a catalyst per Equation 2 to generate more hydrogen and shift the CO to CO2, forming a stream of predominantly carbon dioxide and hydrogen.

[0017] An auto-thermal reformer (“ ATR”) may also be utilized for production of syngas. An ATR may comprise a burner operating with excess methane plus added steam. The hot exhaust gas from the burner passes through a bed of methane reforming catalyst with steam to generate syngas according to the reactions of Equations 1 and 2. The high temperature syngas product from these processes is cooled in a steam generator or generator system, which produces the steam required for the reactions. In some instances, excess heat is generated that may be exported from the facility in the form(s) of steam or electric power. Regardless of the ^-generation process, the CO2 present in the product syngas or crude hydrogen streams formed through reforming and gasification methods must be removed and captured.

[0018] The presently described systems and methods provide hydrogen production with associated retention and controlled production such that CO2 is produced as a product. The produced CO2 may inherently meet or exceed current as well as future carbon capture standards. As hydrogen industries develop and new regulations are adopted, the definition of what is considered “blue” hydrogen is expected to further develop, including particularly the use of carbon intensity as a measure of carbon emissions. Using “carbon intensity” as a measure, life cycle emissions of a process may be expressed as a ratio of kilograms WBD (US) 4910-8123-0946vl -2- AttyDktNo. P62622 2350WO (01244) of CO2 equivalents per kilogram of hydrogen produced (“kg CO2e / kg H2”). In one or more embodiments, which may be combined with other embodiments, the systems and methods provided may be effective for operating with a carbon intensity ratio such as from about 4 kg CO2e / kg H2or less, such as from about 3.5 kg CO2e / kg H2or less, such as from about 3 kg CO2e / kg H2or less, such as from about 2.5 kg CO2e / kg H2or less, or such as in a range of from about 1.5 kg CO2e / kg H2to about 4 kg CO2e / kg H2, or such as in a range of from about 2 kg CO2e / kg H2less to about 4 kg CO2e / kg H2.

[0019] The present disclosure may provide hydrogen production methods as well as systems suitable for carrying out the methods. Embodiment systems and methods may be configured from a variety of combinations of components and process steps. In one or more embodiments, which may be combined with other embodiments, hydrogen production may be carried out using a plurality of convective reformers that may be operated in series or in parallel to convert a hydrocarbon and steam into syngas. The convective reformers may be configured to receive a heating fluid on a shell side of the reformer to provide heat for reactions taking place on a tube side of the reformer. Different heating fluids may be separately used as the heating fluid for different convective reformers. Syngas from the convective reformers may be combined with bypassed feed and then processed in an oxygen secondary reformer (“OSR”) to provide a final syngas stream. The final syngas stream is then processed for separation of hydrogen from the syngas. Carbon monoxide in the syngas effluent from the OSR may be further processed through one or more WGS reactors to form additional hydrogen. The raw hydrogen product may be dewatered and purified in one or more syngas separation system that may include a variety of separation components. In one or more embodiments, which may be combined with other embodiments, the syngas separation system may produce, in addition to hydrogen, a liquid CO2product that may be exported. In one or more embodiments, which may be combined with other embodiments, the syngas separation system may produce one or more tail gas streams that may be received in one or more components of the system.

[0020] At least one tail gas stream may be recycled back to any point upstream of the OSR for further conversion of any methane content of the tail gas stream to additional syngas, or to any of the shift reactors for further conversion of any CO content of the tail gas stream to additional H2and CO2. In one or more embodiments, which may be combined with other embodiments, the at least one tail gas stream may have a composition suitable for use as fuel in a combustor and may be combusted to provide a heating fluid for one of the convective reformers.

[0021] Hot combustion gases from the combustor, which may comprise primarily carbon dioxide and water, may be passed through a convective reformer as the heating fluid and then cooled and dewatered to generate a CO2containing recycle stream. The CO2containing recycle stream, in whole or in part, may be recompressed and recycled towards the combustor. The CO2containing recycle stream, in whole or in part, may be mixed with substantially pure oxygen from an oxygen supply source and function as a diluent. Embodiment oxidant streams may comprise about 35% or less oxygen on a molar basis, such as about 25% or less, such as about 23.5% or less, such as about 20% or less oxygen on a molar basis. Such diluted oxygen permits safe handling of the resulting oxidant stream for use in the combustor. The CO2containing recycle stream, in whole or in part, may be used as a diluent to provide temperature control in the flame zone WBD (US) 4910-8123-0946vl -3- AttyDktNo. P62622 2350WO (01244) of the combustor and moderate the NOx generation. The CO2 containing recycle stream, in whole or in part, may be used as a quenchant post-combustion to control the inlet temperature to the CO2 convective reformer (“CCR”). The CO2 containing recycle stream may be recompressed and then separated into one or more portions as previously described, or separate portions may be independently compressed to the same or different pressure ranges. Likewise, the CO2 containing recycle stream may be preheated and then separated into one or more portions, or separate portions may be independently preheated to the same or different temperature ranges. Preheating may be carried out against the combustion gas after its primary heating use in the CCR, further cooling the combustion gas. The CO2 containing recycle stream, or at least a portion thereof, need not necessarily be recycled back to a component of the system. All or part of the CO2 containing recycle stream may be vented to the environment, secondary containment, or secondary treatment to control buildup of inert materials in the system, such as through recycled CO2 streams. All or part of the CO2 containing recycle stream may be further purified to generate a carbon dioxide sequestration product.

[0022] In one or more embodiments, which may be combined with other embodiments, the present disclosure may provide a hydrogen production plant comprising: a first convective reformer arranged to receive a first heating fluid and configured to convert hydrocarbon and steam into a first synthesis gas; a second convective reformer arranged to receive a second heating fluid and configured to convert hydrocarbon and steam into a second synthesis gas, the second convective reformer being optional and thus being expressly present or expressly absent; an oxygen secondary reformer (OSR) arranged to receive one or both of the first synthesis gas and the second synthesis gas and configured to convert hydrocarbon and steam into a third synthesis gas; and one or more components effective for separating a stream of predominately hydrogen from one or more of the first synthesis gas, the optional, second synthesis gas, and the third synthesis gas. In one or more embodiments, which may be combined with other embodiments, the hydrogen production plant may be further defined in relation to any one or more of the following statements, which statements may be combined in any number and any order.

[0023] One or both of the first convective reformer and the second convective reformer may have a tube-in- shell arrangement.

[0024] The tube-in-shell arrangement may comprise at least one set of concentrically arranged tubes positioned within a containment vessel, each of the at least one set of concentrically arranged tubes comprising: an outer catalyst tube; an inner reaction product gas tube; and catalyst material positioned within a space defined between an inside surface of the outer catalyst tube and an outside surface of the inner reaction product gas tube.

[0025] The first convective reformer may be arranged so that the first heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the first synthesis gas, and wherein the second convective reformer is arranged so that the second heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the second synthesis gas.

[0026] The hydrogen production plant further may comprise a combustor configured to produce a combustion exhaust stream.

[0027] WBD (US) 4910-8123-0946vl -4- AttyDktNo. P62622 2350WO (01244)

[0028] The combustion exhaust stream may comprise at least a portion of the first heating fluid received by the first convective reformer.

[0029] The hydrogen production plant further may comprise a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer.

[0030] The plurality of combustion exhaust processing units may comprise one or more of: a heat exchanger; a separator configured to remove water from the combustion exhaust; a separator configured to remove inert gases from the combustion exhaust; and a separator configured to remove oxygen from the combustion exhaust.

[0031] The third synthesis gas may comprise at least a portion of the second heating fluid received by the second convective reformer.

[0032] The hydrogen production plant further may comprise one or more water gas shift units.

[0033] The one or more components effective for separating a stream of predominately hydrogen may comprise one or more hydrogen pressure swing adsorption units.

[0034] The one or more components effective for separating a stream of predominately hydrogen further may comprise one or more carbon dioxide removal units.

[0035] The one or more carbon dioxide removal units may comprise one or both of a low temperature carbon dioxide separator and a carbon dioxide pressure swing adsorption unit.

[0036] The first convective reformer, the second convective reformer, and the OSR may be arranged in series with the OSR downstream from both of the first convective reformer and the second convective reformer with respect to a flow of the first synthesis gas and the second synthesis gas.

[0037] The second convective reformer may be arranged downstream from the first convective reformer. The first convective reformer may be arranged downstream from the second convective reformer. In one or more embodiments, which may be combined with other embodiments, the present disclosure may provide a process for hydrogen production comprising: reacting hydrocarbon and steam in a first convective reformer that is heated by a first heating fluid so as to convert the hydrocarbon and steam into synthesis gas and provide a first synthesis gas stream; reacting hydrocarbon and steam in a second convective reformer that is heated by a second heating fluid so as to convert the hydrocarbon and steam into synthesis gas and provide a second synthesis gas stream; reacting at least a portion of the first synthesis gas stream and at least a portion of the second synthesis gas stream with oxygen and steam in an oxygen secondary reformer (OSR) to form additional synthesis gas and to provide a third synthesis gas stream; and processing at least a portion of the third synthesis gas stream in one or more components effective for separating a stream of predominately hydrogen from the third synthesis gas stream. In one or more embodiments, which may be combined with other embodiments, the process for hydrogen production may be further defined in relation to any one or more of the following statements, which statements may be combined in any number and any order

[0038] The process further may comprise combusting a fuel with an oxidant in a combustor to produce a combustion exhaust stream.

[0039] WBD (US) 4910-8123-0946vl -5- AttyDktNo. P62622 2350WO (01244)

[0040] The combustion exhaust stream may comprise at least a portion of the first heating fluid in the first convective reformer.

[0041] The process further may comprise processing the combustion exhaust in a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer.

[0042] Processing the combustion exhaust in the plurality of combustion exhaust processing units may comprise separating out one or more of a stream of inert gas, a stream of oxygen, a stream of carbon dioxide, and a stream of water.

[0043] The third synthesis gas may comprise at least a portion of the second heating fluid received by the second convective reformer.

[0044] Processing at least a portion of the third synthesis gas stream may comprise processing in one or more water gas shift units effective to provide a shifted synthesis gas stream.

[0045] Processing at least a portion of the third synthesis gas stream may comprise processing in one or more hydrogen pressure swing adsorption units.

[0046] Processing at least a portion of the third synthesis gas stream may comprise processing in one or more carbon dioxide removal units.

[0047] The one or more carbon dioxide removal units may comprise one or both of a cooled carbon dioxide separator and a carbon dioxide pressure swing adsorption unit.

[0048] In one or more embodiments, which may be combined with other embodiments, the present disclosure may provide a hydrogen production plant comprising: a combustor configured to produce a combustion exhaust stream; a convective reformer arranged to receive at least a portion of the combustion exhaust stream as a heating fluid and configured to convert hydrocarbon and steam into a first synthesis gas; an oxygen secondary reformer (OSR) arranged to receive the first synthesis gas and configured to convert hydrocarbon and steam into a total synthesis gas; and a separation unit for separating at least a portion of the total synthesis gas into at least one product stream and at least one tail gas stream. In one or more embodiments, which may be combined with other embodiments, the hydrogen production plant may be further defined in relation to any one or more of the following statements, which statements may be combined in any number and any order.

[0049] The separation unit may comprise a first hydrogen pressure swing adsorber, at least one carbon dioxide separator, and a second hydrogen pressure swing adsorber.

[0050] One or both of the first hydrogen pressure swing adsorber and the second hydrogen pressure swing adsorber may be a fractionating pressure swing adsorber.

[0051] The second hydrogen pressure swing adsorber may be a fractionating pressure swing adsorber and may be configured to provide a stream of predominately hydrogen, a first tail gas stream with a first composition, and a second tail gas stream with a second composition that is different from the first composition.

[0052] One of the first tail gas stream and the second tail gas stream may be concentrated in inerts and is arranged for introduction to the combustor.

[0053] WBD (US) 4910-8123-0946vl -6- AttyDktNo. P62622 2350WO (01244)

[0054] The at least one product stream may comprise a stream of predominately hydrogen from one or both of the first hydrogen pressure swing adsorber and the second hydrogen pressure swing adsorber.

[0055] The at least one carbon dioxide separator may comprise a low temperature CO2 separator and a CO2 pressure swing adsorber arranged downstream from the low temperature CO2 separator.

[0056] The at least one product stream may comprise a stream of predominately carbon dioxide from the low temperature CO2 separator.

[0057] These and other features, aspects, and advantages of the disclosure will be apparent from a reading of the following detailed description together with the accompanying drawings, which are briefly described. The disclosure includes any combination of elements, components, and features that are described, regardless of whether such elements, components, and features are expressly combined in a specific embodiment description. This disclosure is intended to be read holistically such that any separable features, components, or elements of the disclosure, in any of its various aspects and embodiments, should be viewed as intended to be combinable unless the context clearly dictates otherwise.

[0058] BRIEF DESCRIPTION OF THE FIGURES

[0059] Having thus described the disclosure in the foregoing general terms, reference will now be made to the accompanying drawings, which is not necessarily drawn to scale, and which should be viewed as illustrating example embodiments of the presently disclosed subject matter.

[0060] FIG. 1 illustrates a convective reforming reactor according to one or more embodiments of the present disclosure.

[0061] FIG. 2 is a flowchart illustrating a hydrogen production plant and associate method of operation thereof according to one or more embodiments of the present disclosure.

[0062] FIG. 3 is a flowchart illustrating components of a hydrogen recovery unit in a hydrogen production plant according to one or more embodiments of the present disclosure.

[0063] FIG. 4 is a flowchart illustrating components of a heat recovery unit for processing of a CO2 containing heating fluid stream in a hydrogen production plant according to one or more embodiments of the present disclosure.

[0064] FIG. 5 is a flowchart illustrating components of a CO2 separation unit of a hydrogen production plant according to one or more embodiments of the present disclosure.

[0065] DETAILED DESCRIPTION OF THE DISCLOSURE

[0066] The present subject matter is described more fully with reference to the one or more embodiments. These embodiments are described so that this disclosure will be thorough, complete, and will fully convey the scope of the subject matter to those skilled in the art. Indeed, the subject matter may be embodied in many different forms and should not be constmed as limited to the embodiments set forth; rather, these embodiments are provided so that this disclosure will satisfy applicable legal requirements. As used in the specification and in the appended claims, the singular forms “a”, “an”, and “the”, include plural referents unless the context clearly dictates otherwise.

[0067] WBD (US) 4910-8123-0946vl -7- AttyDktNo. P62622 2350WO (01244)

[0068] The present disclosure provides processes, systems, and equipment that may individually or in combination exhibit improvements in the production of hydrogen, particularly “blue” hydrogen, that is, hydrogen production with coproduction of CO2, where CO2 is controllably produced so that greater than 90% molar, such as greater than 95% molar, such as greater than 98% molar, or such as greater than 99% molar, of the carbon introduced into the processes, systems, and equipment is retained without atmospheric emission. The produced CO2 may be of a purity that is sufficient to meet local carbon dioxide pipeline specifications, which may vary by industry, geography, or associated applicable regulations. One or more embodiments of the systems and processes are provided, and the one or more embodiments are described individually only for ease of disclosure and understanding. The one or more embodiments, however, are expressly intended to be useful either individually or in any combination of the one or more embodiments. It is understood that each embodiment provides improvements in hydrogen production arising from the specific features of the individual embodiment. Individual embodiments arise from recognition of shortcomings in the existing methods and equipment used for hydrogen production. Each individual embodiment provides a useful improvement and advantage in hydrogen production. The improvements and advantages may be multiplied through combinations of the individual embodiments. The unique features of each embodiment are evidence that the improvements achieved with the combinations of the embodiments are not an expected, cumulative effect but rather may demonstrate synergistic effects arising from the various combinations of the individual embodiments.

[0069] In one or more embodiments, which may be combined with other embodiments, the present disclosure relates to systems configured for hydrogen production, such as a hydrogen production plant, as well as processes for hydrogen production. A hydrogen production plant according to the present disclosure may include all of the components necessary for utilizing inputs of hydrocarbon, oxygen, and water, and providing outputs of substantially pure hydrogen, carbon dioxide for use or sequestration, and, optionally, excess water. The combined parts thus define a system for producing hydrogen, and the system, plant, or unit may be combined with further industrial equipment and plants so that the produced hydrogen may be used as a feed stream into a further plant. The hydrogen production system, however, may also be operated without combination with other equipment or plants. The hydrogen production system may thus be operated as a stand-alone hydrogen production plant to export hydrogen as a product. In one or more embodiments, which may be combined with other embodiments, a hydrogen production plant may comprise any combination of components described, which may include without limitation any of a synthetic oxidant combustor, an air-fired combustor, a pressurized combustor, a CO2 convective reformer (“CCR”), a syngas convective reformer (“SGCR”), an oxygen secondary reformer (“OSR”), a heat exchanger, one or more water gas shift (“WGS”) reactors, including, but not limited to, low-temperature (LT) WGS reactors and high-temperature (HT) WGS reactors, one or more hydrogen pressure swing adsorbers (“H2 PSA1”; “H2 PSA2”, and so on), a water separator, a low temperature CO2 separation system (“LT CO2 separation system”), a CO2 pressure swing adsorber (“CO2 PSA”), and a compressor. Any of these components may be present or may be absent. Likewise, any of the components may be present singularly or in a plurality. Further, one or more pumps or compressors may be included for maintaining necessary operating pressures WBD (US) 4910-8123-0946vl -8- AttyDktNo. P62622 2350WO (01244) and flow rates in the system for fluids, which may be a liquid, gaseous, or supercritical state and may support transition between one fluid state and another. It is likewise understood that the hydrogen production plant may include necessary piping, valves, and control components useful for operation thereof.

[0070] In one or more embodiments, which may be combined with other embodiments, a hydrogen production plant according to the present disclosure may comprise a plurality of convective reformers. A first convective reformer may be arranged to receive a first heating fluid and may be configured to convert hydrocarbon and steam into a first synthesis gas. A second convective reformer may be arranged to receive a second heating fluid and may be configured to convert hydrocarbon and steam into a second synthesis gas. The hydrogen production plant also may comprise an OSR arranged to receive one or both of the first synthesis gas and the second synthesis gas and configured to convert hydrocarbon, oxygen, and steam into a third synthesis gas. The hydrogen production plant also may comprise one or more components effective for separating a stream of predominately hydrogen from one or more of the first synthesis gas, the second synthesis gas, and the third synthesis gas.

[0071] One or both of the first convective reformer and the second convective reformer may have a tube-in- shell arrangement. In one or more embodiments, which may be combined with other embodiments, the tube-in-shell arrangement may comprise at least one set of concentrically arranged tubes positioned within a containment vessel. Further, each of the at least one set of concentrically arranged tubes may comprise: an outer catalyst tube (or “scabbard”); an inner reaction product gas tube (or “bayonet”); and catalyst material positioned within a space defined between an inside surface of the outer catalyst tube and an outside surface of the inner reaction product gas tube. As illustrated in FIG. 1, a convective reformer 100 includes a containment vessel 110 and two sets of concentrically arranged tubes therein. Each set of concentrically arranged tubes is formed of the outer catalyst tube 121 and the inner reaction product tube 125. Catalyst material 123, such as reforming catalyst, is positioned in the annular space defined between an outer surface of the inner reaction product tube 125 and an inner surface of the outer catalyst tube 121.

[0072] The first convective reformer may be arranged so that the first heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the first synthesis gas that is formed. Likewise, the second convective reformer may be arranged so that the second heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the second synthesis gas.

[0073] With reference to FIG. 1, the convective reformer 100 may be configured with several fluid ingress and egress ports, such as a heating fluid inlet 130, a heating fluid outlet 133, a reactant inlet 135, and a reaction product outlet 137. The heating fluid enters the containment vessel 110 through the heating fluid inlet 130 and passes around the reaction tube sets to provide heating by heat transfer through the walls of the outer catalyst tube 121.

[0074] In one or more embodiments, which may be combined with other embodiments, heating within the convective reformer is predominately convective, such as from about 50% convective or greater, such as in a range of from about 60% to about 99.9% convective heating, or such as from about 75% to about 99% convective heating. Alternatively, in one or more embodiments, which may be combined with other embodiments, a portion of the heating within the convective reformer, such as in a range of from about 1% WBD (US) 4910-8123-0946vl -9- AttyDktNo. P62622 2350WO (01244) to about 25%, such as about 10% to about 20%, may be via other non-convective heating modes, such as radiative heating.

[0075] Hydrocarbon and steam may enter the containment vessel 110 through the reactant inlet 135. A plurality of reactant inlets may be present in embodiment vessels. The reactant inlet 135 provides fluid access to a reactant space 136 that is separated from a heating fluid space 131. A reactant tube sheet 138, along with product tube sheet 139 and containment vessel 110 in part defines reactant space 136, prevents mixing of the reactants with the heating fluid. As reactants pass through the catalyst material 123, syngas product is formed and passes through the inner passage of the inner reaction product tube 125 into a reaction product space 132. Reaction product space 132 is defined by parts of reactant tube sheet 138, containment vessel 110, and product tube sheet 139, where the product tube sheet 139 separates the reaction product from the reactants. The formed syngas exits the containment vessel 110 through the reaction product outlet 137.

[0076] As described previously and illustrated in FIG. 1, the reactants flow upward through the catalyst while the heating fluid flows down around the tubes (the so-called “scabbard tubes”) and the formed syngas flows down through the so-called “bayonet tubes,” that is, the void formed by the interior surface of the inner reaction product tube 125. The directional arrangement of parts as illustrated in FIG. 1 is not intended to be limiting, however, and the parts may be arranged as desired and lead to modifications of directional fluid flows through the convective reformer 100. For example, the parts in FIG. 1 may be arranged so that in embodiment systems and processes the reactants flow downward through the catalyst while the heating fluid flows upward around the tubes, and the formed syngas flows upward through the inner reaction product tube.

[0077] A convective reformer may be configured to use a specific heating fluid and thus may be referenced in relation to the type of heating fluid that is utilized. In one or more embodiments, which may be combined with other embodiments, a convective reformer may be configured to use a heating fluid stream comprising CO2 heating fluid. In one or more embodiments, which are combinable with other embodiments, the heating fluid may comprise, consist essentially of, or consist of predominately CO2. In this context, “predominately” means that the heating fluid comprises greater than 50% molar CO2. In one or more embodiments, which may be combined with other embodiments, a heating fluid may comprise in a range of from about 60% or greater molar CO2, such as about 70% or greater molar CO2, such as about 80% or greater molar CO2, or such as about 90% or greater molar CO2. In one or more embodiments, which may be combined with other embodiments, a heating fluid may comprise in a range of from about 30% or greater molar CO2, such as about 35% or greater molar CO2, such as about 40% or greater molar CO2, or such as about 45% or greater molar CO2. A convective reformer receiving a heating fluid stream comprising CO2 as the heating fluid may be referenced as a CO2 convective reformer (“CCR”).

[0078] In one or more embodiments, which may be combined with other embodiments, a convective reformer may be configured to utilize a heating fluid comprising, consisting essentially of, or consisting of heated syngas. A syngas stream in the context of this application may be a stream of heating fluid including at least molecular hydrogen and carbon monoxide and optionally one or more of carbon dioxide, unreacted

[0079] WBD (US) 4910-8123-0946vl -10- AttyDktNo. P62622 2350WO (01244) hydrocarbon(s), inerts, and steam. A convective reformer using a stream of syngas as the heating fluid may be referenced as a syngas convective reformer (“SGCR”).

[0080] The CO2 containing stream utilized as the heating fluid in the CCR may be formed via combustion. In one or more embodiments, which may be combined with other embodiments, a hydrogen production plant according to the present disclosure may comprise a combustor configured to produce a combustion exhaust stream. The combustor may have any configuration recognized as useful in a combustion process. The combustor may be arranged to receive fuel and oxidant for combustion to form a combustion product stream comprising CO2 and optionally one or more of water, inerts, and oxygen.

[0081] A diluent stream may also be introduced to the combustor for controlling combustion temperature. The diluent may comprise predominately or substantially completely CO2. A useful example of a combustor configuration and operation thereof that may be used according to the present disclosure is described in U.S. Patent No. 10,859,264 (to Fetvedt, et al.), the disclosure of which is incorporated by reference. Another useful example of a combustor configuration and operation thereof that may be used according to the present disclosure is described in U.S. Patent No. 9,068,743 (to Palmer, et al.), the disclosure of which is also incorporated by reference. In one or more embodiments, which may be combined with other embodiments, the combustor exhaust may be at a temperature in a range of from about 750°C to about 1300°C, such as from about 800°C to about 1100°C, or such as from about 900°C to about 1000°C, when introduced to the CCR as the heating fluid.

[0082] In one or more embodiments, which may be combined with other embodiments, the heating fluid introduced into the CCR may comprise in a range of from about 50% to about 99% molar CO2, such as in a range of from about 85% to about 98% molar CO2, such as in a range of from about 90% to about 98% molar CO2, such as in a range of from about 92% to about 96% molar CO2. The remaining fraction of the heating fluid may be comprised of any one or more of water, nitrogen, oxygen and other impurities, which may be present in de minimis amounts.

[0083] In one or more embodiments, which may be combined with other embodiments, the heating fluid introduced into in the CCR may comprise in a range of from about 0.1% to about 5% molar oxygen, such as in a range of from about 0.2% to about 3% molar oxygen, such as in a range of about 0.3% to about 2% molar oxygen.

[0084] In one or more embodiments, which may be combined with other embodiments, the heating fluid introduced into in the CCR may comprise up to about 45% molar nitrogen, such as in a range of from about 0.1% to about 40% molar nitrogen, such as in a range of from about 1% to about 35% molar nitrogen, such as in a range of from about 5% to about 25% molar nitrogen. Nitrogen in the heating fluid may arise from the use of fuel in the combustor that has a significant content of nitrogen. For example, natural gas used as a fuel in the combustor may have a nitrogen composition in a range of from about 0.2% to about 3% molar nitrogen. As a further example, a tail gas stream that is used in the combustor may comprise a significant nitrogen composition, such as in a range of from about 10% to about 50% molar nitrogen.

[0085] In one or more embodiments, which may be combined with other embodiments, the heating fluid introduced into the CCR may comprise carbon dioxide in a range of from about 50% to about 70% molar WBD (US) 4910-8123-0946vl -11- AttyDktNo. P62622 2350WO (01244)

[0086] CO2, such as in a range of from about 52% to about 60% molar CO2, and nitrogen in a range of from about 25% to about 45% molar nitrogen, such as in a range of from about 30% to about 40% molar nitrogen.

[0087] After passing from the CCR, the heating fluid stream from the combustor may undergo additional processing steps. In one or more embodiments, which may be combined with other embodiments, the hydrogen plant may comprise one or a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer, particularly the CCR. For example, the combustion exhaust processing units may be selected from a heat exchanger, a separator configured to remove water from the combustion exhaust, a flow splitter configured to split the exhaust into one or more branch streams, a compressor configured to recycle all or part of one or more of the branch streams towards the combustor, a separator configured to remove inert gases from one or more of the branch streams, and a separator or extinguisher configured to remove oxygen from one or more of the branch streams. Any one or more of these components may be present, any one or more of these components may be expressly excluded, any one or more of the components may be present as a plurality of said components, and any one or more of these components may be in combination with one another.

[0088] A stream of syngas for use as the heating fluid in the SGCR may be a syngas stream that was formed in another component of the hydrogen production plant, such as the OSR. As discussed in greater detail following, a syngas stream may be formed in a plurality of different components of the hydrogen production plant. Individual syngas streams of one or more syngas streams may be provided at different temperatures and ranges thereof. As such, one or more of the syngas streams may be used as a heating fluid to provide reaction heat in the SGCR. In one or more embodiments, which may be combined with other embodiments, the syngas stream used as a heating fluid in the SGCR may be a syngas stream formed in a component that is downstream from the tube-side flow path of the SGCR. The same component may be upstream from the SGCR in relation to the shell-side flow path of the SGCR. As such, at least a portion of the heating fluid introduced to the SGCR to provide heat to drive the conversion of reactants into syngas may comprise syngas formed in the catalyst filled tubes and passed by the same SGCR as a reaction product.

[0089] In one or more embodiments, which may be combined with other embodiments, the combination of an SGCR with a CCR may provide for operation for syngas production in parallel reaction flow paths, including with varying split fraction flow ratios. This may be effective to increase overall process efficiency while still providing the relatively high carbon capture for the overall process, as previously described. In one or more embodiments, which may be combined with other embodiments, the hydrogen production system may be configured and operated such that about 95% or greater, such as about 98% or greater, or such as about 99% or greater, of the carbon on a molar basis introduced into the hydrogen production system is produced as product carbon dioxide which, for example, may be suitable for export.

[0090] In one or more embodiments, which may be combined with other embodiments, one or more of the convective reformer used in the hydrogen production plant may comprise a tube-side flow path and a shellside fluid flow path. A convective reformer, such as the convective reformer 100 as previously described and shown in FIG. 1, may be utilized in embodiment systems and processes. As such, the pressure vessel 110 may be configured so that heating fluid remains separated from reactants and from reaction product. WBD (US) 4910-8123-0946vl -12- AttyDktNo. P62622 2350WO (01244)

[0091] The tube-side flow path through the pressure vessel 110 may comprise the reactant inlet 135, the one or more sets of concentrically arranged reaction tubes, including the catalyst filled space between the outer catalyst tube 121 and the inner reaction product tube 125, as well as the inner passage of the inner reaction product tube 125, the reaction product space 132, and the reaction product outlet 137. The shell-side flow path through the pressure vessel 110 may comprise the heating fluid inlet 130, the heating fluid space 131 around the outside of the one or more sets of concentrically arranged reaction tubes, and the heating fluid outlet 133. The tube-side of the convective reformer may independently receive flow from upstream components of the hydrogen production plant and may deliver flow to downstream components of the hydrogen production plant, and the shell-side of the convective reformer may also independently receive flow from components of the hydrogen production plant that are downstream of the tube-side flow path and may deliver flow to components of the hydrogen production plant that are upstream of the tube-side flow path. In one or more embodiments, which may be combined with other embodiments, a component of the hydrogen production system that is upstream or downstream of the tube-side flow path of the convective reformer need not necessarily also have the same arrangement relative to the shell-side flow path of the convective reformer.

[0092] In one or more embodiments, which may be combined with other embodiments, the hydrogen production plant further may include an OSR arranged to receive one or both of a first synthesis gas, such as from the tube-side outlet from the CCR, and a second synthesis gas, such as from the tube-side outlet of the SGCR. The OSR may be further configured to convert hydrocarbons and steam into syngas. In one or more embodiments, which may be combined with other embodiments, the OSR may operate adiabatically in that an introduced fuel-rich stream comprising, for example, syngas, reacts with an oxidant. The amount of oxidant introduced to the OSR may be sub-stoichiometric (that is, have an oxidant to fuel molar ratio of less than 1) so that all the introduced oxygen is consumed to near-extinction and that less than all the introduced fuel is consumed. By operating under these conditions, only a minor portion of the fuel introduced in the fuel-rich stream may be consumed. The temperature of the composition undergoing this consumption in the OSR may be raised so that the major portion of the hydrocarbons introduced and remaining in the OSR are then converted to syngas. Previously, OSR units have been used as a follow-on to a conventional SMR to reduce the hydrogen to carbon monoxide ratio in the syngas towards what is favorable to produce chemicals downstream of the hydrogen production facility from natural gas feedstocks.

[0093] Any of a variety of OSRs / ATRs that have been contemplated in the art may be used. An OSR / ATR utilized in embodiment systems and processes may be configured to utilize catalyst for sub-stoichiometric combustion of fuel in oxidant. Alternatively, an OSR may be configured to utilize a specially designed burner positioned at the top of, and within, a refractory -lined vessel. In any case, oxidant and fuel mix within the OSR / ATR, and the oxidant is fully consumed as heated combustion gas is formed. The heated combustion gas passes from a top combustion zone into a bottom catalytic zone of the OSR / ATR, where the heated combustion gas and the remaining contents of the introduced fuel-rich stream are mixed and intimately interact with a reforming catalyst specially formulated to withstand the reforming process temperatures in the OSR / ATR, forming the product syngas.

[0094] WBD (US) 4910-8123-0946vl -13- AttyDktNo. P62622 2350WO (01244)

[0095] In one or more embodiments, which may be combined with other embodiments, the system comprises one or more water gas shift reactors that are configured to form additional hydrogen from the introduced crude syngas stream. A suitable WGS reactor may be a catalytic carbon monoxide shift reactor effective to react carbon monoxide with water to form hydrogen and carbon dioxide. In one or more embodiments, which may be combined with other embodiments, the WGS reactor may produce a product stream comprising shifted syngas having a carbon monoxide composition in a range of from about 5% molar CO or less, such as from about 2% molar CO or less, such as from about 1% molar CO or less, or such as from about 0.5% molar CO or less. In one or more embodiments, which may be combined with other embodiments, the system may be configured so that a temperature of the syngas stream passing from the WGS unit or reactor can be greater than the temperature of the syngas stream introduced into the WGS unit or reactor in a range of from about 10°C to about 80°C, such as about 25°C to about 70°C. The one or more water gas shift reactors may be part of a syngas conditioning unit, as described following, which may be arranged with further components of the system, such as one or more heat exchangers to remove or recuperate heat formed using the WGS reaction of Equation 2.

[0096] In one or more embodiments, which may be combined with other embodiments, a system or process may include an H2recovery unit for separating H2from a stream, such as a product syngas stream or a shifted syngas stream. In one or more embodiments, which may be combined with other embodiments, one or more components effective for separating a stream of predominately hydrogen may include one or more hydrogen pressure swing adsorption (H2PSA) units. This may include a multi-bed PSA unit. An individual H2PSA may be effective to separate molecular hydrogen from the introduced syngas stream such that from about 70% molar or greater of the H2in the introduced syngas stream is separated. In one or more embodiments, which may be combined with other embodiments, a plurality of individual H2PSA units configured in series or in parallel or multi-bed H2PSA units may be used to increase separation efficiency of molecular hydrogen from the introduced syngas stream to a range of from about 80% molar or greater, such as about 85% molar or greater, such as about 90% molar or greater, such as about 95% molar or greater. When a plurality of H2PSA units are used in series, such units may be separated by one or more intervening units, including, but not limited to, heat exchangers, compressors, pumps, gas drying / dehydration / dewatering units, flash drums, or other types of units configured to remove other components from the introduced syngas, such as other types of PSA units, such as a PSA unit that preferentially separates CO2preferentially from an introduced gas stream (CO2PSA), or a low temperature CO2separation unit (also known as a cooled carbon dioxide separator).

[0097] In one or more embodiments, which may be combined with other embodiments, a system or process may utilize one or more different CO2separation units. In one or more embodiments, which may be combined with other embodiments, a CO2separation unit, which may also be referenced as a carbon dioxide removal unit, may include one or both of a cooled carbon dioxide separator, such as a cryogenic CO2distillation unit configured to provide a CO2product, and a carbon dioxide pressure swing adsorption (CO2PSA) unit.

[0098] WBD (US) 4910-8123-0946vl -14- AttyDktNo. P62622 2350WO (01244)

[0099] In one or more embodiments, which may be combined with other embodiments, at least one H2PSA unit may be a fractionating type of PSA. The fractionating PSA may be configured to produce two tail gas streams, each tail gas stream having a different composition from the other, and one hydrogen product stream.

[0100] Utilization of a plurality of different separation components for processing the syngas may be effective to improve separation or capture of a variety of process products and by-products. The separation components may be configured to independently provide preferential separation of inert gases, such as nitrogen and argon, from one or more of hydrogen, methane, carbon dioxide, and carbon monoxide. This may enable concentration of inert gases into a dedicated system purge stream or as part of a tail gas fuel stream directed towards the combustor. In the case of combustion, the inert gases may be concentrated in a combustion product stream and then may be removed from the combustion product stream via low temperature fractionation. In removing inert gases in this manner, embodiment systems and processes may achieve both significant carbon capture and enhancing overall process thermal efficiency. These inert gases may be provided as a useful feedstock to other systems and processes outside the boundary of embodiment systems and processes. Alternatively, the concentrated inert gases may be vented with a portion of the combustion product stream instead of being captured. Also, the inert gases may be further separated from the CO2 in the combustion product stream to further purify the product CO2stream and produce a de minimis vent stream.

[0101] An embodiment of a hydrogen production plant or system 200 is illustrated in FIG. 2. As provided, a hydrocarbon feedstock gas, such as natural gas, is introduced through line 201 to a desulfurization unit 203, which is effective for hydrogenating and desulfurizing the hydrocarbon feedstock with either or both inherently present H2or added H2,. The desulfurization unit 203 optionally may be effective for preheating of the hydrocarbon feedstock gas. Desulfurized and optionally preheated gas in line 205 passes from the desulfurization unit 203 and is split. Line 207 couples to the combustor 211 for optional passage of a first portion of the desulfurized feedstock gas as a trim fuel, which is a supplemental fuel. The flow of the trim fuel may be controlled as needed to maintain desired combustor operation properties in the event of changes to the heat content of other fuel sources used in the combustor, as discussed following. Line 209 passes a second portion of the desulfurized feedstock gas as reactant feed to one or more reformers (230, 240, 250). Steam is introduced to the reactant feed via line 208, resulting in a mixed feed in line 209. The mixed feed in line 209 is partitioned into a first portion in line 209a, which is introduced into the OSR 250, and a second portion in line 209b, which is introduced into the reformer guard bed 219. The reformer guard bed 219 may be configured for pre-reforming of at least a portion of the reactant, such as pre-reforming heavier hydrocarbons, to minimize the risk of coke deposition in the reformer catalyst bed(s). In the reformer guard bed 219, the reaction of Equation 1 may be carried out such that “heavier hydrocarbons” (that is, hydrocarbons with a carbon number greater than 1, such as C2hydrocarbons (ethane, ethylene, acetylene)) may react with steam and be reformed into a pre-reformate stream. The composition of the pre-reformate stream is substantially devoid of the heavier hydrocarbons. A reformer guard bed also may be configured to absorb materials capable of fouling the catalyst bed(s), such as sulfur, that were not removed in the WBD (US) 4910-8123-0946vl -15- AttyDktNo. P62622 2350WO (01244) desulfurization unit 203 or other materials unexpectedly present in the hydrocarbon feedstock gas or the steam. Pre-reformate passing in line 221 is further apportioned, with a first portion introduced into the CCR 230 via line 223 and a second portion introduced into the SGCR 240 via line 225.

[0102] Fuel from one or more sources is combusted in the combustor 211 with an oxidant from an oxidant source 212. The oxidant source 212 may be, for example, and air separation unit (“ASU”) or other source configured to provide a stream of high purity oxygen, such as at or near 98% molar, such as at or near 99% molar, or at or near 99.9% molar oxygen. The oxidant source may comprise oxygen mixed with one or more further materials, such as inerts or carbon dioxide. In one or more embodiment, which may be combined with other embodiments, the oxidant may be a mixture of O2 and a carbon dioxide-containing stream delivered from one or more further portions of the present system. As shown in FIG. 2, for example, oxidant in line 213 may include oxygen from the oxidant source 212 and also may include a portion of the CO2 containing recycle stream delivered to line 213 through lines 214 and 215. As noted previously, trim fuel may be introduced to the combustor 211 through line 207. A tail gas stream from the H2recovery unit 290 may be introduced to the combustor 211 through line 294.

[0103] A heating fluid stream comprising a heating fluid comprising freshly generated combustion product passes from the combustor 211 via line 216 and is introduced into the shell-side of the CCR 230. The heating fluid may comprise carbon dioxide such that the heating fluid stream is a CO2 containing stream. A convective reformer, such as the convective reformer 100 as previously described and shown in FIG. 1, may be utilized in embodiment systems and processes, for CCR 230. The heating fluid passes through the CCR 230 via the shell-side flow path, such as illustrated in the convective reformer of FIG. 1. InFIG. l, a heating fluid enters heating fluid inlet 130, circulates through the heating fluid space 131 around the outside of the one or more sets of concentrically arranged reaction tubes, and exits the heating fluid outlet 133, all of which elements may be present in the CCR 230 present in the hydrogen production system 200 of FIG. 2.

[0104] The heating fluid stream passes from the CCR 230 through line 232 and is introduced into a heat recovery unit 260. After heat extraction in the heat recovery unit, an exhausted heating fluid stream may be partitioned into one or more streams. In one or more embodiments, which may be combined with other embodiments, a first portion of the exhausted heating fluid stream may pass through line 262 for recycle to the combustor 211. The exhausted heating fluid stream in line 262 may comprise a portion of the heating fluid, whereas the heating fluid may comprise CO2 that formed previously from fuel combustion in the combustor 211 and not through syngas conversion; therefore, the stream in line 262 may be referenced as a CO2 containing recycle stream. The CO2 containing recycle stream may optionally be compressed in compressor 263 to increase its pressure, such as for mixing with the oxidant in line 213.

[0105] As shown in Fig. 2, a portion of the CO2 containing recycle stream, whether compressed or not, may be introduced back into the combustor 211 through line 214 as a diluent stream. The CO2 containing recycle stream may be split so that a first portion is introduced into the combustor 211 through line 214 and a second portion of the CO2 containing recycle stream traverses line 215 to combine with the oxidant from the oxidant source 212 in line 213, as previously described. In one or more embodiments, which may be combined with other embodiments, the diluted oxygen stream may comprise an oxidant having an O2 content in a range of WBD (US) 4910-8123-0946vl -16- AttyDktNo. P62622 2350WO (01244) from about 10% to about 75% molar, such as about 12% to about 65% molar, such as about 15% to about 50% molar, such as about 18% to 35% molar, or such as about 18% to 25% molar, such as about 18% to 23.5% molar, O2.

[0106] A second portion of the exhausted heating fluid stream passes from the heat recovery unit 260 through line 265 and is introduced into CO2 treatment unit 270. CO2 treatment unit may comprise one or a plurality of separation components. When the CO2 treatment unit 270 is present, a CO2 product stream may be provided through line 272. The CO2 product stream may have a CO2 concentration in a range of from about 90% molar or greater, such as from about 95% molar or greater, such as from about 98% molar or greater, such as from about 99% molar or greater, CO2. At least part of inert gases present in the second portion of the exhausted heating fluid, such as N2or Ar, may be vented. As illustrated by stream 266 in FIG. 2 and FIG. 5, the inert gases may be vented directly from stream 265 or may be separated using one or more components of the CO2 treatment unit 270. Alternately, all of stream 265 can be vented to the atmosphere.

[0107] The CCR 230 is heated with the combustor exhaust in the shell-side of the CCR while the reactants introduced through line 223 into the tube-side of the CCR 230 are reacted to form a first syngas product that passes from the CCR 230 in line 234. In addition to steam added in line 208, as described previously, augmenting steam through optional line 222 as well as further, optionally included lines, may be added to any, all, or none of lines 221, 223, and 225. A first portion of the pre-reformate in line 221 may pass through line 223 for introduction into the tube-side flow path of the CCR 230. A convective reformer, such as the convective reformer 100 as previously described and shown in FIG. 1, may be utilized in embodiment systems and processes, for CCR 230, to process the , which can be arranged similarly to what is illustrated in FIG. 1. For example, pre-reformate, optionally admixed with recycled tail gas or augmenting steam, can enter a reactant inlet 135, pass through one or more sets of concentrically arranged reaction tubes, including the catalyst filled space between the outer catalyst tube 121 and the inner reaction product tube 125, as well as the inner passage of the inner reaction product tube 125, pass through the reaction product space 132, and exit the reaction product outlet 137, all of which may be present in the CCR 230 of FIG. 2. A first syngas product is formed in the CCR 230, passes therefrom, and traverses through line 234 for introduction into OSR 250.

[0108] The reactants are introduced through line 225 into the tube-side of the SGCR 240. The SGCR 240 is similarly arranged to the CCR 230 as previously described to receive a second portion of pre-reformate from line 221 through line 225, optionally admixed with recycled tail gas or augmenting steam, for passage through the tube-side flow path of the SGCR 240. Again, with reference to FIG. 1, pre-reformate or augmented pre-reformate, can enter a reactant inlet 135, pass through one or more sets of concentrically arranged reaction tubes, including the catalyst filled space between the outer catalyst tube 121 and the inner reaction product tube 125, as well as the inner passage of the inner reaction product tube 125, pass through the reaction product space 132, and exit the reaction product outlet 137, all of which may be present in the SGCR 240 of FIG. 2. A second syngas product forms in the SGCR 240, passes therefrom, and traverses through line 244 for introduction into OSR 250.

[0109] WBD (US) 4910-8123-0946vl -17- AttyDktNo. P62622 2350WO (01244)

[0110] An OSR / ATR, such as OSR 250, positioned downstream of one or more convective reformers, may be effective to increase overall system hydrocarbon conversion that is partially accomplished first in the convective reformers, such as either or both the CCR 230 and the SGCR 240. In one or more embodiments, which may be combined with other embodiments, one or more of the second syngas product, such as second syngas product stream in line 244, the first syngas product, such as the first syngas product stream in line 234, and a first portion of the mixed feed, such as the stream traversing line 209a, may mix to form a combined feed stream that is introduced into the OSR 250 through line 248. Since some of these lines may be refractory lined, it may be advantageous to employ a mixing vessel prior to the OSR. It is appreciated by a person of skill in the art that the configuration of the system may provide that any or all the feedstock, steam, first syngas product from the CCR 230, and second syngas product from the SGCR 240 may be passed individually or collectively to the OSR 250 through one or more separate feed lines or through separate feed nozzles into the OSR 250.

[0111] In one or more embodiments, which may be combined with other embodiments, an oxidant, such as an oxidant-containing stream comprising substantially pure O2, such as from about 95% molar or greater, such as from about 99% molar or greater, such as from about 99.5% molar or greater, is introduced into the OSR 250, such as through line 252. The oxidant in ling 252 may be provided from the oxidant source 212 or from a separate oxidant source.

[0112] In the OSR 250, hydrocarbons in the first portion of the mixed feed from feed line 209a, hydrocarbons remaining in the first syngas product in ling 234, and hydrocarbons remaining in the second syngas product in line 244 may be converted into syngas. Any one or any combination of these sources of hydrocarbons may be introduced to the OSR 250 through line 248.

[0113] The product passing from the OSR 250 through line 253 may comprise a third syngas product. The third syngas product may comprise portions of one or both of the first syngas product and the second syngas product that are introduced into the OSR. The first syngas product and the second syngas product introduced into the OSR already comprise syngas components but also may comprise unreacted hydrocarbons. The unreacted hydrocarbons introduced into the OSR are converted into syngas components or are combusted, whereas the H2, CO, CO2, and H2O introduced into the OSR through the first and second syngas product streams are relatively inert, dilatory, and may pass through in whole or in part without reaction. The OSR 250 thus can be effective to increase the hydrocarbon conversion that is partially accomplished in the CCR 230 and the SGCR 240.

[0114] The syngas product from the OSR 250 passes through line 253 and is introduced into the SGCR 240 along the shell-side flow path. Again, with reference to FIG. 1, the syngas heating fluid introduced to the SGCR 240 enters a heating fluid inlet 130, circulates through a heating fluid space 131 around the outside of one or more sets of concentrically arranged reaction tubes, and exits a heating fluid outlet 133, all which may be present in the SGCR 240. In this manner, the SGCR 240 is arranged both upstream and downstream of the OSR 250 and vice versa. The tube-side flow path in the 240 SGCR is arranged upstream of the OSR 250 so that syngas formed in the SGCR 240 is passed to the OSR 250 for further reaction. The shell-side flow path of the SGCR 240 is arranged downstream of the OSR 250 so that the total syngas product, which WBD (US) 4910-8123-0946vl -18- AttyDktNo. P62622 2350WO (01244) in some embodiments may be the third syngas product, passes through the SGCR 240 as a heating fluid stream without intermixing with the fluid passes through the tube-side flow path of the SGCR 240. In such embodiment system configurations, the SGCR 240 utilizes synthesis gas both as a heating medium post- OSR and as a process medium pre-OSR.

[0115] The combination of the CCR, SGCR, and OSR may provide improvements in reforming by splitting reforming duty between a plurality of separate reforming reactors and by utilization of available, high grade heat in one or more of the reforming reactors. In one or more embodiments, which may be combined with other embodiments, the present systems and methods may include all of the CCR, SGCR, and OSR. In one or more embodiments, which may be combined with other embodiments, the present systems and methods may include only the CCR and the OSR. As such, the SGCR may be expressly excluded from embodiments of the disclosure. As noted previously, the CCR and the SGCR (when present) may be utilized as primary reformers that perform partial reforming only such that the syngas from the CCR 230 in line 234 and the syngas from the SGCR 240 in line 244 may comprise predominantly unconverted hydrocarbon feed (such as unconverted methane), wherein predominantly means greater than 50% molar, relative to the amount of syngas present in the respective streams.

[0116] The operation of the respective reforming reactors may be defined in one or more embodiments in relation to the reforming duty of each reforming reactor. Reforming duty may be defined as the overall number of moles of active carbon that are consumed via the steam methane reforming reaction of Equation 1 as carried out in each reforming reactor that is operational. The systems and methods may be configured so that the reforming duty of one or both of the CCR and the SGCR is based on the amount of high grade heat that is available for reuse in the respective reactor. The amount of high grade heat available for reuse in the CCR 230, and thus the reforming duty range that is assigned to the CCR, may be adjusted so that the reforming duty is substantially equal to or less than the available heat from combustion of the tail gas fuel in line 296 that may be introduced for combustion into combustor 211. The amount of high grade heat available for reuse in the SGCR 240, and thus the reforming duty range that is assigned to the SGCR, may be adjusted so that the reforming duty is substantially equal to or less than the available heat from the hot syngas stream leaving the OSR 250 in line 253.

[0117] In embodiments comprising the CCR 230 and the OSR 250 as the only reforming reactors (meaning that the SGCR 240 is absent), reforming duty may be split between the two reforming reactors so that about 50% or greater, such as about 60% or greater, such as about 70% or greater, or such as about 80% or greater of the reforming duty is provided by the OSR. In such embodiments, about 45% or less, such as about 40% or less, such as about 30% or less, or such as about 20% or less of the reforming duty may be provided by the CCR. In one or more embodiments, which may be combined with other embodiments, the OSR may provide from about 55% to about 90%, such as from about 60% to about 90%, such as from about 70% to about 90%, or such as from about 80% to about 90% of the reforming duty, and the CCR may provide from about 10% to about 45%, such as from about 10% to about 40%, such as from about 10% to about 30%, or such as from about 10% to about 30% of the reforming duty.

[0118] WBD (US) 4910-8123-0946vl -19- AttyDktNo. P62622 2350WO (01244)

[0119] In embodiments comprising the CCR 230, the SGCR 240, and the OSR 250, reforming duty may be split between the three reforming reactors so that about 50% or greater, such as about 60% or greater, such as about 65% or greater, or such as about 70% or greater of the reforming duty is provided by the OSR. In such embodiments, about 30% or less, such as about 25% or less, such as about 20% or less, or such as about 15% or less of the reforming duty may be provided by the CCR. In such embodiments, about 30% or less, such as about 25% or less, such as about 20% or less, or such as about 15% or less of the reforming duty may be provided by the SGCR. In one or more embodiments, which may be combined with other embodiments, the OSR may provide from about 50% to about 85%, such as from about 55% to about 85%, such as from about 60% to about 85%, or such as from about 70% to about 85% of the reforming duty, the CCR may provide from about 5% to about 25%, such as from about 5% to about 20%, or such as from about 5% to about 15% of the reforming duty, and the SGCR may provide from about 10% to about 30%, such as from about 10% to about 25%, or such as from about 10% to about 20% of the reforming duty.

[0120] Returning to FIG. 2, the partially cooled third syngas product passing from the SGCR 240 via line 242 is introduced into a conditioning unit 280. A conditioning unit, such as conditioning unit 280, may comprise one or more components configured to condition the syngas prior to purification. The conditioning unit 280 may include one or more WGS reactors configured to convert CO with steam into molecular hydrogen (H2) according to Equation 2. In one or more embodiments, which may be combined with other embodiments, the conditioning unit 280 may include a high temperature water gas shift (“HT WGS”) reactor 280a that produces a first WGS product syngas stream. The first WGS product syngas stream in some embodiments may be introduced into a low temperature water gas shift (“LT WGS”) reactor 280c, where a second WGS product syngas stream is formed. In one or more embodiments, which may be combined with other embodiments, a conditioned shifted syngas, which in some instances is the second WGS product syngas, may pass from the conditioning unit 280 to the H2recovery unit 290, such as through line 282, for hydrogen and optionally CO2recovery.

[0121] The conditioning unit, such as conditioning unit 280, in several embodiment configurations may have one or more opportunities to extract heat from one or more process streams and provide such heat to other portions of the process, improving thermal efficiency in the embodiment systems and processes and producing in some instances a conditioned shifted syngas. Stream 242 as introduced is a partially exhausted yet heated stream, and the WGS reactions are exothermic, providing one or more product streams that are heated. In configurations of embodiments systems, process steam may be passed from the condition unit through a process steam line, such as line 208, to introduce “reaction steam”, which acts not only for heat recovery but also water reuse, back upstream in embodiment processes. Embodiments of the system may include a conditioning unit comprising a heat exchanger (“Hx”) 281 that precedes the HT WGS 280a and acts to cool the introduced third syngas stream for the WGS rection(s) by exchanging heat. In such configurations and processes, the Hx 281 may be useful, for example, to form steam or superheat an existing steam stream. An embodiment system may also include one or both of a first WGS heat exchanger 280b and a second WGS heat exchanger 280d. The first WGS Hx 280b is positioned downstream of the first WGS reactor 280a and upstream of the second WGS reactor 280c and is configured to receive the first WGS WBD (US) 4910-8123-0946vl -20- AttyDktNo. P62622 2350WO (01244) product syngas stream and recover heat therefrom. The second WGS Hx 280d is positioned downstream of the second WGS reactor 280c and is configured to receive the second WGS product syngas stream and recover heat therefrom. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers may be configured to heat one or more tail gas streams, such as tail gas streams 294, 295, and 296, to be described following. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers may be configured to preheat boiler feed water. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers configured to heat a CO2 recycle stream, such as the CO2 recycle stream in line 262 in FIG. 2. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers may be configured to heat one or more hydrocarbon fuel-containing stream, such as in any one or more of hydrocarbon-fuel containing stream passing through lines 210, 205, 209, 209a, 209b, 221, 223, and 225. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers may be configured to generate low-pressure (LP) steam. In one or more embodiments, which may be combined with other embodiments, the one or more WGS heat exchangers may configured as an air cooler or a water cooler for condensing any process water in the stream. Such “process water” may be recovered and utilized through recycling to one or more steam generators as process feed stream, reducing or mitigating any potential fresh process steam feed. For example, a produced steam stream may pass from the conditioning unit 280 using line 208 into the main syngas production process as a reactant. Such process steam may also be useful for introduction into one or more of the reformer guard bed 291, CCR 230, and SGCR 240. In some instances, the recovered steam in line 208 may be introduced into feed line 209. In an embodiment, which may be combined with other embodiments, a steam generator may be utilized, and in some instances may be further configured with a steam separator and a thermo-syphon boiler. Additional heat exchange may be provided with a heat exchanger (“Hx”) 281 that can precede the HT WGS 280a, such as in the conditioning unit 280. The Hx 281 may be useful, for example, to form steam or superheat an existing steam stream.

[0122] In embodiments wherein the SGCR 240 is absent, line 254 may feed directly into line 242, as illustrated in FIG. 2 with optional line 253a. It is understood that combined lines 253, 253a, and 242 in FIG. 2 may be replaced with a single line in such embodiments. The syngas in line 253 therefore may pass directly into the conditioning unit 280, and heat from the syngas stream may be withdrawn in heat exchanger 281. In one or more embodiments, which may be combined with other embodiments, the heat exchanger 281 may represent a plurality of heat exchangers configured to withdraw heat from the syngas at one or more different temperature ranges for one or more different uses. In one or more embodiments, which may be combined with other embodiments, the syngas in line 253 may be processed through the heat exchangers and boilers 410 as described following in relation to FIG. 4 before or after passage through heat exchanger 281 so that heat from the syngas may be recuperated for further use, such as to form steam for passage through line 222, as otherwise described herein.

[0123] In one or more embodiments, which may be combined with other embodiments, a cooled syngas stream can be provided through line 282 passing from the conditioning unit 280 to the H2recovery unit 290. WBD (US) 4910-8123-0946vl -21- AttyDktNo. P62622 2350WO (01244)

[0124] In one or more embodiment, which may be combined with other embodiments, the conditioned shifted syngas, such as the conditioned shifted syngas passing in line 282, may be at a pressure in a range of from about 15 bar (1.5 MPa) to about 120 bar (12 MPa), such as about 20 bar (2 MPa) to about 115 bar 911.5 MPa), such as about 30 bar (3 MPa) to about 110 bar (11 MPa), such as about 50 bar (5 MPa) to about 100 bar (10 MPa). In one or more embodiment, which may be combined with other embodiments, the conditioned shifted syngas, such as the conditioned shifted syngas passing in line 282, may be at a temperature in a range of from about 10°C to about 50°C, such as from about 12°C to about 45°C, such as from about 15°C to about 40°C, such as from about 20°C to about 30°C.

[0125] The conditioned shifted syngas, such as the conditioned shifted syngas in line 282, may be introduced to an H2recovery unit, such as H2recovery unit 290. The H2recovery unit may comprise one or more components configured to produce a purified H2through a H2product line, such as H2product line 292. In one or more embodiments, which may be combined with other embodiments, the purified H2may have a hydrogen concentration in a range of from about 60% or greater H2molar, such as about 90% or greater H2molar, such as about 95% or greater H2molar, such as about 99% or greater H2molar, such as about 99.9% or greater H2molar.

[0126] One or more tail gas streams may pass from the H2recovery unit. A single or a plurality of tail gas streams having one or more compositions may be provided through separate lines to one or more downstream users. In one or more embodiments, which may be combined with other embodiments, a tail gas passing from the H2recovery unit may be split into one or more tail gas streams comprising different compositions based upon the content of inert components in each composition. An inerts-rich tail gas composition, which may be rich in non-combustible inerts, such as N2, Ar, and in some cases CO2, and poor in combustible components, such as CH4, CO, and H2, may pass from the H2recovery unit, such as H2recovery unit 290 through line 294. An inerts-poor tail gas composition, which may be rich in similar combustible components and poor in non-combustible inerts, may pass from the H2recovery unit, such as through line 295. The inerts-rich tail gas may be introduced into the combustor as not only a diluent but also to consume any remaining combustible components in the stream, reducing the hydrocarbon fuel demand to the combustor for heat generation. The inerts-poor tail gas may be recycled and introduced into the processside of any or more of the reactors (CCR, SGCR, or OSR) or upstream thereof for reformation. The inerts- poor tail gas may be recycled and introduced upstream of the hydrogen production plant to recover additional hydrogen and optionally carbon dioxide, the effect in doing so would further concentrate the process inerts.

[0127] In one or more embodiments, which may be combined with other embodiments, only a single tail gas stream may be produced from the H2recovery unit 290. A single tail gas stream may pass through line 296 and may comprise a composition comprising a homogenous mixture of inert gases, unconverted CHj and CO, and unrecovered H2and CO2. FIG. 2 illustrates line 296, which may comprise the single tail gas stream. In some instances, line 296 may be a combination of materials from both line 294 and line 295. The single tail gas stream may be split such that a first portion may be recycled and introduced into the combustor, such as combustor 211 and a second portion may be recycled and introduced into a process gas WBD (US) 4910-8123-0946vl -22- AttyDktNo. P62622 2350WO (01244) stream, such as those previously described for lines 201, 209b, 223, 225, 248, one or more lines within the conditioning unit 280, and one or more lines within the H2 recovery unit 290. Use of tail gas from one or all of line 294, line 295, and line 296, may improve overall or subsystem process efficiency, such as increased recovery of H2or CO2, which is further discussed following, particularly with reference to FIG. 3.

[0128] As previously described, the a CCR and a SGCR may be operated in parallel with each other such that each receives a portion of the pre-reformate feed into the process side of the reformers. Each reformer may be configured to provide different syngas compositions based upon a variety of factors, including, but not limited to, catalysts, operating conditions, heat duty, residence time, and relative volume or mass ratios of inlet feed, thereby producing a first and a second syngas composition with different relative compositions. The first and second syngas product, as previously described, may be combined and introduced into as a feed into the OSR 250 for additional reforming.

[0129] In one or more embodiments, which may be combined with other embodiments, the system may be configured such that the CCR and the SGCR are in a serial configuration, such that the syngas product of a first reformer is introduced at least in part if not entirely to the second reformer. In some embodiments, the first syngas product formed in an upstream CCR may be introduced into a downstream SGCR with or without fresh hydrocarbon feed gas or inerts-poor tail gas and steam to form a second syngas product. The second syngas product passing from the SGCR optionally may then be supplemented with additional hydrocarbon feed or inerts-poor tail gas and steam and then introduced into the OSR. The syngas stream passing from the OSR in this instance may be the third syngas stream. In some other embodiments, the SGCR may be upstream of the CCR and the CCR downstream of the SGCR and upstream of the OSR, where the optional supplemental hydrocarbon feed, inerts-poor tail gas, and steam may occur as previously described. Regardless of parallel or serial configuration of the CCR and SGCR as previously described, the configuration of the embodiment systems provides for the third syngas stream to pass from the OSR and be introduced into and flow through the shell-side flow path of the SGCR, such as SGCR 240 of FIG. 2, to provide the energy for the reformation reactions occurring within the process side of the SGCR.

[0130] As previously noted, the product synthesis gas in line 253 leaving the OSR 250 may be used as the heating fluid flowing through the shell-side flow path of the SGCR 240. While in many embodiments, such as those previously described, the CCR 230 and the SGCR 240 may perform partial reforming of the hydrocarbon, such as natural gas or methane, the tube-side streams passing from the CCR 230 and the SGCR 240 may mix and be introduced into the OSR 250 to maximize the conversion of the hydrocarbon. During the process of reforming by utilizing gas-based heating fluid reformers, more heat recovery for reforming takes place in the production cycle, causing the spent heating fluid leaving the convective reactors to be cooler since a significant portion of the heat in the introduced gas heating fluid is utilized to drive the reforming reactions and generate more syngas product, particularly in the SGCR. Additionally, a loss of steam production from the downstream waste heat boilers may reduce steam export or reduce the ability for power generation. Thus, the heat normally used for steam generation is instead better utilized to generate syngas, which is a higher value product in the setting of a hydrogen production plant or system. The net effect is a boost in overall hydrogen production plant operating efficiency and thermal efficiency. Since the WBD (US) 4910-8123-0946vl -23- AttyDktNo. P62622 2350WO (01244)

[0131] CCR 230 and the SGCR 240 may each be operated to process only a portion of the hydrocarbon and steam reactants to produce a first syngas product and a second syngas product, respectively, by operating the CCR 230 and the SGCR 240 in parallel, each convective reactor may be reduced in physical size, thereby reducing overall system costs. Such arrangement may also be effective to maintain the tube sheets in the CCR 230 and the SGCR 240 at relatively reduced operating temperatures versus prior art configurations. This is particularly achieved by operating the CCR 230 and the SGCR 240 in parallel, as previously described.

[0132] In one or more embodiments, the H2recovery unit may be configured to include a plurality of components that are effective to provide improved syngas separation and for recovery of H2and CO2as system products. The H2recovery unit may be effective to provide increased H2production by reducing the amount of H2that is directed through tail gas towards the combustor. Additionally, since the H2recovery unit is also configured to provide for additional recovery of CO2, a reduced amount of amount of CO2may be passed from the H2recovery unit and recycled through the combustor, which as a combustion diluent, and to units downstream, such as the heat recovery unit and the CO2treatment unit.

[0133] An example embodiment of a H2recovery unit 290 is illustrated in FIG. 3, and it is understood that any single component illustrated in FIG. 3 as well as any combination of two, three, four, five, six, seven, or eight of the components illustrated in FIG. 3 may be present in the H2recovery unit 290 illustrated in the context of the hydrogen production plant in the example embodiment shown in FIG. 2 and described previously.

[0134] With reference to FIG. 3, which is in part an embodiment system configured to perform one or more embodiment processes, the conditioned syngas stream introduced through line 282 into a first hydrogen pressure swing adsorber (“H2PS Al”) 320, which may be, for example, a multi-bed PSA unit, of H2recovery unit 290. H2PSA1 may be configured to separate the components of the introduced conditioned syngas stream into at least two different compositions, such as a stream of purified H2passing via line 322 as a first H2product and a stream comprising residual gas in which a portion of the introduced H2has been extracted from the introduced conditioned syngas steam passes via line 325. In one or more embodiments, which may be combined with other embodiments, the H2PSA1 may be configured such that the purified hydrogen product may comprise in a range of from about 60% to about 95% molar of the H2introduced through the conditioned syngas stream, such as from about 70% to about 92%, such as from about 80% to about 90% molar, whereas the residual gas may comprise the remaining introduced hydrogen. In addition, the residual gas may further comprise substantially all the remaining components introduced into H2PS Al. In one or more embodiments, which may be combined with other embodiments, the residual gas stream may comprise water, CO, CO2, methane, and inert gases, such as N2and Ar.

[0135] In one or more embodiments, which may be combined with other embodiments, the residual gas may be compressed in a compressor, such as a first compressor 326 to form a compressed stream, such as compressed residual gas stream in line 327, having a pressure in a range of from about 15 bar (1.5 MPa) to about 80 bar (8 MPa), such as from about 20 bar (2 MPa) to about 75 bar (7.5 MPa), such as from about 25 bar (2.5 MPa) to about 60 bar (6 MPa). The compressed residual stream may be introduced into a dryer, WBD (US) 4910-8123-0946vl -24- AttyDktNo. P62622 2350WO (01244) such as dryer 330, to produce a dry residual stream that then passes from the dryer, such as through line 333. The dryer may be any conventional drying apparatus, such as a water separator or a desiccant dryer.

[0136] In one or more embodiments, which may be combined with other embodiments, the H2 recovery unit may comprise only one hydrogen PSA, such as H2PSA1 320, and optionally the compressor 326. Depending upon the composition of the conditioned syngas steam or residual stream in lines 325, 327, respectively, the stream may be introduced to one or both of the combustor, such as combustor 211, and the SGCR, such as SGCR 240, without additional, intervening processing.

[0137] An advantage of the presently disclosed configuration of the hydrogen production plant and method of operation is the ability to increase recovery of a purified H2product and also to recover further, individual components of the syngas stream for carbon capture. The present systems and methods thus can be effective to increase hydrogen production plant operation efficiency, maintain high carbon capture as defined previously, and create an outlet for removing inert molecules that may be introduced into the system with one or more of the hydrocarbon feed for the CCR 230, SGCR 240, OSR 250, and combustor 211, and the oxygen supply for the combustor. Embodiment configurations of the system and processes for operation thereof concentrate the inerts through removal of hydrogen and carbon dioxide such that only a minor content of the overall produced CO2, such as less than 5% molar of formed CO2, is passed with the inerts, such as through venting or export to an external processing unit for inert gases.

[0138] In one or more embodiments, which may be combined with other embodiments, a dry residual gas stream, such as dry residual gas stream in line 333, may be introduced to a low temperature CO2separator (“LT CO2separator”), such as LT CO2separator 340. A LT CO2separator may utilize refrigeration to cool an introduced stream comprising CO2to at least to a temperature less than its dew point, and even to temperatures proximate to but greater than the CO2freezing point of pure CO2. In one or more embodiments, which may be combined with other embodiments, an LT CO2separator may be configured to extract in a range of from about 70% molar to about 95% molar of the carbon dioxide introduced into the LT CO2separator via the dry residual gas stream on a single pass basis. In one or more embodiments, which may be combined with other embodiments, an LT CO2separator may be configured to extract all or substantially all of the CO2produced in the hydrogen production process, where “all or substantially all” in this instance is in a range of from about 70% or greater of the CO2produced on a molar basis, such as from about 75% or greater of the CO2produced on a molar basis, such as from about 80% or greater of the CO2produced on a molar basis, such as from about 85% or greater of the CO2produced on a molar basis, such as from about 90% or greater of the produced CO2on a molar basis, or such as in a range of from about 70% to about 95% of the CO2produced on a molar basis, such as from about 75% to about 90% of the CO2produced O2on a molar basis, and where “CO2produced in the hydrogen production process” specifically excludes carbon dioxide produced from the combustion of fuel in the combustor. The separated CO2may be passed from the hydrogen production plant through line 345 as a CO2product. Separating and passing the CO2product from the hydrogen production process prevents directing all of the CO2formed as part of the syngas production process through the combustor, where it would act as a combustion diluent, such as may be done in the absence of the CO2separation components within the H2separation unit 290.

[0139] WBD (US) 4910-8123-0946vl -25- AttyDktNo. P62622 2350WO (01244)

[0140] The LT CO2 separator may be, for example, a low temperature or cryogenic distillation separation unit. Operation of the LT CO2 separator may vary and may depend on the desired delivery pressure of the H2product to be captured downstream from the LT CO2 separator. In one or more embodiments, which may be combined with other embodiments, the LT CO2 separator may be configured to operate at a pressure in a range of from about ambient conditions to about 74 bar (7.4 MPa). The operating temperature may be set based upon the desired purity of the recovered CO2, such as near the CO2 liquefaction temperature at a given operating pressure. In one or more embodiments, which may be combined with other embodiments, where the LT CO2 separator is configured with a distillation column operable to separate components within the column, the LT CO2 separator may maintain a temperature profile such that the bottom temperature is in a range of from about 5°C to about 50°C warmer than the top temperature within the column. In one or more embodiments, which may be combined with other embodiments, where the LT CO2 separator is configured with a distillation column operable to separate components within the column, the LT CO2 separator may maintain a pressure profile such that the bottom pressure is in a range of from about 30 bar (3 MPa) to about 40 bar (4 MPa) and the bottom temperature is in a range of from about -7°C to about 5°C.

[0141] Refrigeration for the LT CO2 separator 340 may be provided by external refrigerants or may be provided by one or more gas streams that are native to the operation of the hydrogen production plant. This may be achieved in a stepwise manner using one or more heat exchangers and one or more separation units that may utilize differences in liquefaction temperatures and pressure of various stream in a series of flash separation drums or a main low temperature distillation column. Carbon dioxide, for example, may be used as a flash refrigerant in this manner. Likewise, one or more process gases circulating in the system may be used as a refrigerant by expanding them through a turbine, which may provide power production, or through a valve. An example of a low-temperature distillation system for CO2 recovery that may be used according to the present disclosure is described in US Patent Publication No. 2019 / 0135626 (to Rafati, et al.), which is incorporated by reference in its entirety.

[0142] As a product of LT CO2 separator, a purified stream of CO2 may be passed from the LT CO2 separator, such as through line 345. An overhead gas stream, which is CCh-lean, may also be passed from the LT CO2 separator via line 343. The CO2-lean overhead gas stream may be introduced into a downstream CO2 PSA unit, such as CO2 PSA 350. In one or more embodiments, which may be combined with other embodiments, the CO2 PSA unit may be configured to preferentially recover CO2 from the introduced CO2-lean material feed stream.

[0143] In some configurations of the hydrogen production system, a recycle line, such as line 347, may be utilized to direct the recovered CO2 from the introduced CO2-lean material back to the inlet of the residual gas compressor, such as residual gas compressor 326. In one or more embodiment, which may be combined with other embodiments, when the hydrogen production system is configured to recycle CO2 passing from the CO2 PSA unit to upstream of the LT CO2 separator, the LT CO2 separator may be configured to extract all or substantially all of the CO2 produced in the hydrogen production process, where “all or substantially all” in this instance is in a range of from at least 97% molar, such as at least 99% molar, such as at least 99.5% molar, such as at least 99.9% molar of the CO2 produced, and where “CO2 produced WBD (US) 4910-8123-0946vl -26- AttyDktNo. P62622 2350WO (01244) in the hydrogen production process” specifically excludes carbon dioxide produced from the combustion of fuel in the combustor. .

[0144] The CO2 PSA unit may be configured as an adsorber effective to selectively adsorb and retain CO2 onto one or more layers of an absorbent configured to preferentially absorb carbon dioxide, such as carbon, alumina, and zeolites, such as molecular sieves. This enables production of a product gas with reduced CO2 composition to pass from the CO2 PSA, such as through line 353. This pass-through gas, which has a comparatively reduced CO2 composition compared to the introduced Ch-lean overhead gas, may pass at essentially the same pressure as the introduced CO2-lean overhead gas stream . The pass-through gas passing the CO2 PSA may comprise any one or more% of methane, hydrogen, carbon monoxide, and one or more inert gases.

[0145] The CO2 retained by the sorbent may be regenerated in subsequent steps, such as through isolation, depressurization, blowdown, and purge. The recovery steps may be carried out at a reduced pressure than the inlet pressure of the CO2 PSA unit, including at sub-atmospheric or vacuum conditions. A portion of the purified H2recovered from any of the H2PSA units, such as H2PSA 1 or H2PSA 2, may be used to sweep the CO2 PSA adsorber beds, which in some instances is passed from the CO2 PSA unit as a portion of the pass-through gas.

[0146] The pass-through gas in line 353 may be introduced to a second hydrogen PSA 360 (H2PSA2). The H2 PSA2 may be configured to recover H2 from the introduced stream, increasing overall system hydrogen production efficiency. The recovered H2 may be produced though line 355 as a second hydrogen product stream. In one or more embodiments, which may be combined with other embodiments, the purified H2of the second hydrogen product stream may have a hydrogen concentration in a range of from about 60% or greater H2molar, such as about 90% or greater H2molar, such as about 95% or greater H2molar, such as about 99% or greater H2molar, such as about 99.9% or greater H2molar. In embodiment systems and configurations, the use of multiple H2PSAs may be effective to provide a greater overall hydrogen production plant production efficiency and greater overall total production of H2than systems and processes that do not. This likewise may reduce the amount of H2that is present in tail gases passing from the H2PSA2 360 and thus minimizes losses from the hydrogen product streams through lines 322 and 355.

[0147] H2PSA1 320 and H2PSA2 360 may be any conventional PSA unit configured to remove hydrogen from a stream. Because the inlet streams 282 and 353, respectively, will have different feed compositions, such as having little or no CO2 or H2O in line 353, and different flow rates through the units, H2PSA2 360 may have a reduced size and operational capacity relative to H2PSA1 320.

[0148] In one or more embodiments, which may be combined with other embodiments, a fractionating PSA may be used for any of the PSAs present in the H2recovery unit. A fractionating PSA unit particularly may be effective to produce different and separate tail gas compositions passing from the second H2 PSA. Tail gas is formed during the isolation, depressurization, blowdown, and purging portions of the pressure swing cycle of the adsorbent beds present in the H2PSA2. In such embodiment configurations, a fractionating PSA may be effective to produce different compositions of tail gas based upon the differences in absorption and desorption rates of different molecular and atomic species. Stream components with different WBD (US) 4910-8123-0946vl -27- AttyDktNo. P62622 2350WO (01244) adsorbance tendencies will be retained in different layers of the PSA while the PSA is functioning in the so- called production mode of its cycle when the desired product for purification and capture is being produced. For example, a multicomponent gaseous stream such as the stream in line 282 to H2PSA1 320 may comprise strongly adsorbing components, such as H2O and CO2, moderately adsorbing components, such as CH4, CO, and N2, weakly sorbing components, such as Ar, and the product component, such as H2, which may be considered to be substantially non-adsorbing. During the production mode of the PSA cycle, the strongly sorbed components are retained in the portion of the sorbent(s) layers close to the feed end of the PSA. The moderately sorbed components are retained in succeeding layers. The weakly sorbed components are retained in the last layer near the product end. The product species that are substantially non-sorbed are not retained to any significant amount except for the voids in the bed, and they emanate as a purified product from the product end. It is thus possible to split up the bed into two sequential beds in two separate vessels, such that the H2O and CO2are retained in the first sequential bed in the first vessel, and the other sorbing components are retained in succeeding sequential bed(s) inside sequential vessel(s). In one or more embodiments, which may be combined with other embodiments, each of the two vessels may be blown down and operated in series by blowing down and purging each of the set of vessels separately while still maintaining a steady flowrate of non-absorbent material, that is hydrogen. The isolation, blowdown, and purge from the sequential beds may be utilized to isolate and capture various species, such as methane, carbon dioxide, carbon monoxide, water, argon, and nitrogen, for purging or separate processing.

[0149] Alternatively, in one or more embodiments, which may be combined with other embodiments, the beds may not be in separate vessels. Rather, the vessel can be depressurized from either end, either in temporal sequence or simultaneously. The depressurized exudates from the product end can recover much or most of the moderately or weakly sorbed components, and the depressurized exudates from the feed end can recover the strongly adsorbed species. The depressurization can occur in a finite number of pressure steps, with each step to a different pressure level. Each step can thus furnish a “cut” with the earlier cuts enriched in the weakly sorbing species. The PSA cycle can conclude with a final blowdown and countercurrent purge of the beds to keep the product ends “clean”. The composition of the exudates from the feed end during these steps is not constant and thus provides an opportunity to harvest separate temporal “cuts” of gaseous streams with different compositions, thereby manifesting the desired fractionation in a yet another alternative approach. In still a further alternative approach, a fractionating PSA can comprise an adsorption vessel that includes a plurality of adsorption layers that are independently selective for different, specific components of the stream to be fractionated. The different components will be sorbed selectively and can be withdrawn from the adsorption vessel at different pressure ranges based on relative adsorption strengths of the different stream components for their respective adsorption layers. Any of these approaches can be combined. Although a composition handled through H2PSA1 320 is discussed previously as an example embodiment, the same approach can be used in relation to H2PSA2 360, although the stream in line 353 typically will have no moisture and little to no CO2content with the feed stream already having passed through the dryer 330, the LT CO2separator 340, and the CO2PSA 350. Nevertheless, fractionation may still be used to separate the stream(s) exiting H2PSA2 360 into the stream that is rich in inerts and the WBD (US) 4910-8123-0946vl -28- AttyDktNo. P62622 2350WO (01244) stream that is lean in inerts. In one or more embodiments, which may be combined with other embodiments, the tail gas passing from the H2PSA2 360 may be provided in a single line that may be split into different portions downstream of the H2PSA2. In one or more other embodiments, which may be combined with other embodiments, the tail gas may be provided in a plurality of separate lines. In FIG. 3, as an example embodiment, the tail gas leaving the H2PSA2 360 is apportioned into a first stream in line 356 and a second stream in line 358. The stream in line 356 may be compressed in compressor 357, and the stream in line 358 may be compressed in compressor 359 prior to passing through recycle lines to one or more different components of the hydrogen production plant. This provides for compression to different pressures for different uses; however, a single line providing the tail gas may be compressed with a single compressor, and the compressed stream then separated into a plurality of services lines.

[0150] The tail gas may be split between the portions in lines 356 and 358 so that specific components of the tail gas may be recycled to the appropriate components of the hydrogen production plant, and this may be varied as desired depending on the specific application and the content of the mixed components present in the tail gas. The portion of the tail gas in line 356 may be introduced to the combustor 211 to be combusted to directly heat the recycled exhaust stream (see line 262 in FIG. 2) utilized on the heating side of the CCR 230. The tail gas portion in line 356 may include a significant portion of the inert gases present in the feed to the H2PSA2 360, significant meaning at least 40% molar, at least 50% molar, at least 60% molar, at least 80% molar, or at least 90% molar, and including up to all, such as 100% molar, or substantially all, such as 99%+ molar, of the inert gases. The tail gas portion in line 358 may be introduced to any one or more of the units arranged upstream from the H2PSA1 320, which encompasses streams upstream from the H2recovery unit 290 in FIG. 2, including the reformer guard bed 219, the CCR 230, the SGCR 240, the OSR 250, and the conditioning unit 280 or any component thereof, such as a WGS reactor. The introduction may be directly into said component(s) or into a feed line that is introduced to said component(s). The stream in line 358 may include the remaining fraction of inert gases that is not partitioned into the stream in line 356 and also may include one or more of CH4, CO, and CO2. Recycling of said stream to one or more of the convective reformers or other components of the hydrogen plant may be effective to provide a further opportunity for the materials in the stream to be converted to syngas in one or more of the reforming reactors or be shifted in one or more of the WGS reactors. Recycling of tail gas components from the H2recovery unit 290, and particularly the H2PSA2 360, is thus useful to increase total production of H2is also useful to increase overall system efficiency.

[0151] The split tail gas portions in lines 356 and 358 may determine how much feedstock fuel is introduced to the combustor 211 and the amount of heat generated and transferred in the CCR 230, which may affect the reforming duty of the CCR 230. The recycle streams that flow back towards the convective reformers, such as the CCR 230 and the SGCR 240, may be useful to any one or more of: increase operational efficiency of the hydrogen production plant; improve ability to handle greater inert-containing feedstocks; provide greater (or at least not reduced) overall carbon capture; and reduce combustor device and associated heat recovery equipment size leading to capital equipment cost savings. Configurations that provide the ability to concentrate inert gases in a tail gas that is passed to the combustor 211 may be WBD (US) 4910-8123-0946vl -29- AttyDktNo. P62622 2350WO (01244) effective to purge the inert gases from the system more thoroughly, which allows for increasing flow partition of carbon- and hydrogen-containing molecules into the tail gas portion stream that is sent back to the reformers. The net effect may be an increase in overall recovery of H2and conversion of methane and CO to H2compared to system configuration without such modifications. This practice also may reduce the heat duty of the combustor and CCR pair and place a greater heat demand on the SGCR and OSR. This combination of process and configuration changes may have the net effect of reducing oxygen consumption and overall power demand, and, therefore, improving overall plant efficiency, of the hydrogen production plant while reducing capital costs for the CO2exhaust side and the air separation unit (“ASU”) that may be used to provide the substantially pure oxygen to one or more components of the system.

[0152] Operational efficiency may be limited by the content of inert gases, which may accumulate due to continued recycling. Since these molecules do not take part in any reactions carried out in the hydrogen production process, accumulation in a high concentration may reduce process performance, such as combustion, reformation, and PSA and LT CO2recovery. The inert gases that are present in the portion of the tail gas that is sent to the combustor 211 through line 294 in FIG. 2 or line 356 in FIG. 3 may remain in the hot exhaust gas exiting the combustor 211 while passing through the shell-side flow path of the CCR 230. After exiting through line 232, the inert gases may be introduced downstream to the exhaust gas handling units, such as one or more components of the heat recovery unit 260 to recover the heat therefrom. Therefore, although inert, the gases may function to retain and distribute heat through the heating side of the reformer units.

[0153] In one or more embodiments, which may be combined with other embodiments, the heat recovery unit 260 may comprise a single or a plurality of heat recovery components. As illustrated in FIG. 4, the combustor exhaust stream that passes from the CCR 230 in line 232 may be introduced to one or more heat exchangers or boilers, as represented by unit 410. Heat exchanger members in unit 410 may include, for example, a waste heat boiler for forming steam from water, a recuperator heat exchanger, or one or more water coolers, and the type of heat exchangers and number of heat exchanges may vary. As a non-limiting example, the combustor exhaust stream in line 232 may pass through one or more heat exchangers and thereby provide heating to any one or more of: the feed stream in line 209b for the reformer guard bed; the feed stream in any of line 221, line 223, and line 225 for the CCR 230 and the SGCR 240; the recycle stream in line 262 or line 214 passing to the combustor 211; the oxidant in line 213 passing to the combustor 211; the feed hydrocarbon in any of line 201, 205 and 209; the oxygen feed in line 252 for the OSR 250; and a low pressure steam generator (“LP steam generator”). Any one or more components of the heat recovery unit 260 may be used as an LP steam generator. Likewise, LP steam may be generated with low grade heat in the hydrogen production process train, such as downstream of the LT WGS 280c. Although heat exchanger 280d is shown in FIG. 2 as a single element, it is understood that heat exchanger 280d may comprise a plurality of independent heat exchangers, any one or more of which may be used as an LP steam generator.

[0154] The initially cooled combustor exhaust stream passing from the unit 410 in line 415 is introduced to one or more heat discarding components, which may be useful for discarding unrecoverable heat, thereby WBD (US) 4910-8123-0946vl -30- AttyDktNo. P62622 2350WO (01244) condensing water from combustion, and one or more water removal components, and this is represented by unit 420. Waste heat may be discarded into the ambient through one or more coolers or Direct Contact Condensers (DCC), thereby enabling dewatering (removal of water of combustion) and cooler entry into the recycle compressor 263.

[0155] A portion of the cooled and dewatered combustor exhaust stream, which may be CCh-rich but which may comprise a significant fraction, such as up to 50% molar, of other components, particularly inerts, may be recycled via line 262 to the combustor 211 via lines 214 or 216. The remaining portion of the combustor exhaust stream passes through line 265 for introduction to the CO2 treatment unit 270, which may comprise a single component or may comprise a plurality of components effective for purification of a CCh-rich stream. In one or more embodiments, which may be combined with other embodiments, up to 100% of the stream in line 265 may be vented to the atmosphere through line 266, as shown in FIG. 5. As such, substantially 100% of the stream in line 265 may be vented through line 266, which may branch from line 265 or which may come from a component of the CO2 treatment unit 270. Alternatively, substantially 100% of the stream in line 265 may be processed in the CO2 treatment unit 270. As a further alternative, part of the stream in line 265 may be vented through line 266, and part of the stream in line 265 may be processed in the CO2 treatment unit 270.

[0156] All or a portion of the cooled and dewatered combustor exhaust stream in line 265 that is introduced to the CO2 treatment unit 270 may first be introduced to a dryer 505, which may include a desiccant dryer, to further remove any remaining water prior to introduction through line 507 to LT CO2 separator 510. Because the hydrogen production plant may optionally include at least two LT CO2 separators for processing two different streams, in one or more embodiments, which may be combined with other embodiments, the LT CO2 separator 340 may be a first LT CO2 separator, and the LT CO2 separator 510 may be referenced as a second LT CO2 separator. The first and second LT CO2 separators may each be the same type of apparatus operating in substantially the same manner. Alternatively, the two LT CO2 separators may be different types of apparatuses operating in substantially different manners. In one or more embodiments, which may be combined with other embodiments, the second LT CO2 separator 510 may operate substantially as discussed previously with reference to the first LT CO2 separator 340, but operating pressure of the second LT CO2 separator 510 may be set based on the operating pressure of the combustor 211 with consideration of minor pressure drops as the combustor exhaust stream passes through the previously described processing equipment, such as the heat recovery components. Operating pressure of the LT CO2 separator 510 may be, for example, in the range of from about 15 bar (1.5 MPa) to about 60 (6 MPa), such as from about 20 bar (2 MPa) to about 55 bar (5.5 MPa), such as from about 25 bar (2.5 MPa) to about 50 bar (5.5 MPa). The LT CO2 separator 510 may operate with a distillation column having a bottom portion operating at a temperature that is from about 5°C to about 50°C warmer than the top portion of the column. In an example embodiment, a distillation column may be operated so the bottom portion is at a pressure of about 25 bar (2.5 MPa) to about 50 bar (5.5 MPa) and a temperature of from about -13°C to about 14°C. Refrigeration for the LT CO2 separator 510 may be provided by external refrigerants or may be provided by one or more gas streams that are native to the operation of the hydrogen production plant. This may be achieved in a WBD (US) 4910-8123-0946vl -31- AttyDktNo. P62622 2350WO (01244) stepwise manner using one or more heat exchangers and one or more separation units that may utilize differences in liquefaction temperatures and pressure of various stream in a series of flash separation drums or a main low temperature distillation column. Carbon dioxide, for example, may be used as a flash refrigerant in this manner. Likewise, one or more process gases circulating in the system may be used as a refrigerant by expanding them through a turbine, which may provide power production, or through a valve. An example of a low-temperature distillation system for CO2 recovery that may be used according to the present disclosure is described in US Patent Publication No. 2019 / 0135626 (to Rafati, et al.), which is incorporated by reference in its entirety.

[0157] The LT CO2 separator 510 may be operated under conditions so that inert gases and residual oxygen from the oxidant used in the combustor 211 will not liquefy and will not be concentrated in a stream of liquid carbon dioxide. The stream from the second LT CO2 separator containing the inert gases and residual oxygen may be safely vented to the atmosphere with minimal carbon contribution through vent line 512. This practice provides for the removal of inert gases from a feedstock in an efficient manner that only vents a fractional portion of the overall carbon dioxide produced by the hydrogen production process. In doing so, the disclosure still provides for overall carbon capture at a high percentage, such as greater than 90% molar, such as greater than 95% molar, such as greater than 98% molar, or such as greater than 99% molar.

[0158] Inclusion and operation of a components for pre-removal of inert gases before introduction to the hydrogen production process may depend on the amount and type of inert gases that are present within the hydrocarbon feedstock and oxygen used and the purity specification of the CO2 and H2products. A typical method for hydrogen production may exhaust inert gases from the process via combustion of the fuel in a fired heater with air as the oxidant while venting combustion exhaust gas and delivering heat to use in preheating feedstocks, generating steam, or superheating steam. According to the present disclosure, the hydrogen production plant and method of operation are configured so that combustion that does not result in an exhaust gas contaminated with nitrogen or argon from air. The inert gases are thus concentrated in the absence of collateral N2in the combusted off gases, the volume of gases to be processed is reduced up to a factor of 5, and it is simpler to separate out the inerts and purify the CO2, the concentration of which is proportionately increased. Thus, compared to previously known technologies, the present systems and methods may be configured to purge out a greater amount of inert gases without any substantial reduction in carbon capture or may be configured to purge out substantially the same amount of inert gases while providing a significantly greater level of overall carbon capture.

[0159] With reference again to FIG. 5, the CO2 stream in line 515 passing from the LT CO2 separator 510 may be introduced to the oxygen and water removal unit 520, which may comprise a single component or a plurality of any number of components. Although water removal unit 420 may be expected to remove the bulk of any water present in the combustion exhaust that is processed therethrough, it may be useful to utilize further drying components to ensure removal of substantially all water present in the streams. This is achieved in part with dryer 505 discussed previously. Although the LT CO2 separator 510 may be configured to remove substantially all of the excess oxygen present in line 265, a polishing unit 520 may be included for further oxygen removal due to stringent product quality requirements and the possibility of WBD (US) 4910-8123-0946vl -32- AttyDktNo. P62622 2350WO (01244) traces of oxygen escaping the LT CO2 separator 510. For example, oxygen may be removed in a catalytic unit where the oxygen reacts with hydrogen to form water, which then may be dried in a desiccant bed, all of which may be present in unit 520.

[0160] In one or more embodiments, which may be combined with other embodiments, the hydrogen production plant may be configured with alternative arrangements of the combustor circuit, which includes the combustor 211, the shell-side flow path through the CCR 230, and any of the heat recovery components in unit 260. As an example embodiment, the combustor 211 may be configured to output a stream of substantially pure CO2, such as at least 90% molar CO2, such as at least 95% molar CO2, such as at least 98% molar CO2, or such as at least 99% molar CO2, which stream is used as a heating fluid stream in the CCR 230 but which may be fully vented after heat recovery in unit 260 (see line 266 n FIG. 5). In such embodiments, a portion of the CO2 capture is sacrificed. Nevertheless, operating with this configuration may still enable removal of inert gases from the hydrogen production plant and achieve an overall carbon capture in a range of about 94% or greater molar CO2 capture, such as about 97% or greater molar CO2 capture, and still exhibit a carbon intensity in a range of from about 4 kg CChe / kg H2or less. Furthermore, operating the hydrogen production plant in this manner may reduce capital expenses by eliminating the need for plant components that would otherwise be necessary for treatment of the exhausted stream.

[0161] In another embodiment, which may be combined with other embodiments, the combustor 211 may be operated in a moderate pressure range, such as about 20 bar (2 MPa) to about 60 bar (6 MPa), such as about 25 bar (2.5 MPa) to about 50 bar (5 MPa), or such as about 35 bar (3.5 MPa) to about 45 bar (4.5 MPa), using air as the oxidant instead of substantially pure oxygen diluted with CO2. Compressed air may be supplied for combustion of tail gas fuel (see line 294 in FIG. 2) and trim natural gas fuel (see line 207 in FIG. 2) introduced to the combustor 211. The exhaust gas from the combustor in such embodiments will be high in nitrogen, such as about 75% to about 85% molar nitrogen, and carbon dioxide from this stream will not be captured. The combustor exhaust gas will be utilized for heat in the CCR 230 and may again be processed in the downstream heat recovery components previously described with reference to heat recovery unit 260. A portion of the combustor exhaust gas may be recycled to the combustor 211 for temperature control. Depending on project specific requirements, equipment for removal of nitrogen oxides “NOX”) may be utilized before venting the combustor exhaust gas to the atmosphere. This configuration may provide for reduced capital expenses, reduced oxygen demand, and reduced power consumption by downsizing or eliminating the air separation unit.

[0162] The present hydrogen production plant may exhibit several advantages in addition to the advantages described previously. For example, the use of the back-end syngas separation components in H2recovery unit 290 provides for removal of CO2 to define the tail gas stream 356 (see FIG. 3) that may be sent to the combustor 211. It also provides for recycle of reactants to the one or more reformers for improved conversion and greater hydrogen recovery. In one or more embodiments, which may be combined with other embodiments, the hydrogen production plant is configured to recover a refined hydrogen product that is about 80% molar or greater, such as about 85% molar or greater, such as about 90% molar or greater, such as about 95% molar or greater, or such as about 97% molar or greater of the H2produced in the plant. The WBD (US) 4910-8123-0946vl -33- AttyDktNo. P62622 2350WO (01244) combustor may utilize as fuel a tail gas stream that is predominantly formed of fuel materials, simplifying the combustor design and reducing the heat duty of the combustor. This reduced heat duty and improved recycle of unconverted reactants in the tail gas may produce the same hydrogen production volume with a reduction in oxygen demand of about 30-40%, which may reduce power consumption, as compared to previously disclosed systems and methods of operation. The reduced heat duty of the combustor may provide for a reduction in equipment size of the combustor itself and all downstream processing equipment. The inert gases that are present in the hydrocarbon feed or oxygen supply may be concentrated in the combustor exhaust CO2 stream, providing for separation in an optional low temperature fractionation unit to purge inert gases with minimal or no reduction in carbon capture.

[0163] In one or more embodiments, which may be combined with other embodiments, various configurations of components of the hydrogen production plant as described may provide for improved performance of the hydrogen production plant. The following are several comparative prophetic examples, including a comparative example and several embodiment examples. The determination of the examples was made using simulations carried out with ASPEN PLUS software. As seen in the Table, advantages of several embodiment configurations of a hydrogen production plant and methods of operation of the same may produce hydrogen more efficiently while maintaining high carbon capture and a low carbon intensity value. The “Comp” column is a comparative example of a plant configuration utilizing a CCR and an OSR without utilization of an SGCR or a LT CO2 separator. Case 1 is an embodiment plant configuration that uses a CCR, an OSR, and a backend separation systems, such as the LT CO2 separator, as previously described in relation to FIG. 3. Case 2 is identical to Case 1 but also include an SGCR as described in relation to FIG. 2. Case 3 illustrates an alternative embodiment plant configuration where the combustor is air-fired versus using substantially pure oxygen diluted with recycled CO2. This alternative embodiment of Case 3 may reduce capital expenses and power consumption in exchange for decreasing the amount of CO2 capture, such as resulting in a produced amount of carbon dioxide being vented in a range of from about 6% molar or less, such as from about 4% molar or less. The “Cases” addressed in the Table do not account for the use of a fractionating PSA as the H2PSA1, H2PSA2, or CO2 PSA. Nevertheless, it is believed that the operational results are substantially similar to the values shown in the Table for Case 2 but with a further incremental improvement in gas efficiency and reduced oxygen demand.

[0164] TABLE

[0165] WBD (US) 4910-8123-0946vl -34- AttyDktNo. P62622 2350WO (01244)

[0166] In the Table, “kg O2 / kg H2” means kilograms of substantially pure (that is, excluding combustion air) oxygen consumed per kilogram of molecular hydrogen produced, “kWh / kg H2” means net kilowatts- hour per kilogram of hydrogen produced, “HHV” means higher heating value, “kg NG / kg H2” means kilograms of natural gas consumed per kilogram of hydrogen produced, and “kg CO2e / kg H2” means kilograms of carbon dioxide equivalent emitted per kilogram of hydrogen produced. Carbon intensity is calculated using the GREET® (greenhouse gases, regulated emissions, and energy use in technologies) lifecycle analysis model (U Chicago Argonne, LLC, Chicago, IL) that is employed in the United States with average emission factors for pipeline natural gas and grid power as of year 2024. The performance cases shown in the Table were calculated using US Gulf Coast conditions with a 120°F (49.9°C) process outlet temperature achievable via cooling water heat exchange. It may be expected that power consumption would decrease significantly with ISO conditions for the cooling water system.

[0167] In one or more embodiments, which may be combined with other embodiments, the present disclosure provides processes for hydrogen production. The hydrogen production processes may be carried out using any arrangement of a hydrogen production plant described foregoing. As such, the hydrogen production process may be understood with reference to the hydrogen production plant illustrated in FIG. 2.

[0168] A process for hydrogen production, for example, may comprise reacting hydrocarbon and steam in a first convective reformer that is heated by a first heating fluid so as to convert the hydrocarbon and steam into synthesis gas and provide a first synthesis gas stream. The first convective reformer may be a CCR. The first heating fluid may be an exhaust stream from a combustor. The process also may comprise reacting hydrocarbon and steam in a second convective reformer that is heated by a second heating fluid to convert the hydrocarbon and steam into synthesis gas and provide a second synthesis gas stream. The second convective reformer may be an SGCR. The second heating fluid may be an outlet stream from an OSR. The process further may comprise passing at least a portion of the first synthesis gas stream and at least a portion of the second synthesis gas stream through the OSR to form additional synthesis gas and to provide a third synthesis gas stream. The process also may comprise processing at least a portion of the third synthesis gas stream in one or more components effective for separating a stream of predominately hydrogen from the third synthesis gas stream.

[0169] In one or more embodiments, which may be combined with other embodiments, a hydrogen production process may comprise combusting a fuel with an oxidant in a combustor to produce a combustion exhaust stream. Again, the combustion exhaust stream may comprise at least a portion of the first heating fluid in the first convective reformer. The combustion exhaust may be processed in a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer. This may comprise, for example separating out one or more of a stream of inert gas, a stream of oxygen, a stream of carbon dioxide, and a stream of water.

[0170] In one or more embodiments, processing at least a portion of the third synthesis gas stream may comprise processing in one or more water gas shift units effective to provide a shifted synthesis gas stream. Processing at least a portion of the third synthesis gas stream may comprise processing in one or more hydrogen pressure swing adsorption units. Processing at least a portion of the third synthesis gas stream WBD (US) 4910-8123-0946vl -35- AttyDktNo. P62622 2350WO (01244) may comprise processing in one or more carbon dioxide removal units. For example, the one or more carbon dioxide removal units comprise one or both of a cooled carbon dioxide separator and a carbon dioxide pressure swing adsorption unit.

[0171] While the hydrogen production process has been thus described generally, it is understood that the description of the hydrogen production plant has been provided so that the process of operating the hydrogen production plant likewise discloses the hydrogen production method that may be carried out using the hydrogen production plant. As such, the disclosure around operating methods and conditions for any of the components of the hydrogen production plant is understood to likewise disclose the hydrogen production method.

[0172] The terms “about” or “substantially” as used herein may indicate that certain recited values or conditions are intended to be read as encompassing the expressly recited value or condition and values that are relatively close thereto or conditions that are recognized as being relatively close thereto. For example, unless otherwise indicated herein, a value of “about” a certain number or “substantially” a certain value may indicate the specific number or value as well as numbers or values that vary therefrom (±) by 10% or less, such as 5% or less, such as 4% or less, such as 3% or less, such as 2% or less, or such as 1% or less, and any one of such values may be used interchangeably with the words “about” or “substantially” as needed for clarity. Similarly, unless otherwise indicated, a condition that substantially exists may indicate the condition is met exactly as described or claimed or is within typical manufacturing tolerances or would appear to meet the required condition upon casual observation even if not perfectly meeting the required condition. In some embodiments, the values or conditions may be defined as being express and, as such, the term “about” or “substantially” (and thus the noted variances) may be excluded from the express value.

[0173] Many modifications and other embodiments of the presently disclosed subject matter will come to mind to one skilled in the art to which this subject matter pertains having the benefit of the teachings presented in the foregoing descriptions and the associated drawings. Therefore, it is to be understood that the present disclosure is not to be limited to the specific embodiments described and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are employed, they are used in a generic and descriptive sense only and not for purposes of limitation.

[0174] WBD (US) 4910-8123-0946vl -36-

Claims

AttyDktNo. P62622 2350WO (01244)CLAIMS:

1. A hydrogen production plant comprising: a first convective reformer arranged to receive a first heating fluid and configured to convert hydrocarbon and steam into a first synthesis gas; an optional, second convective reformer arranged to receive a second heating fluid and configured to convert hydrocarbon and steam into a second synthesis gas; an oxygen secondary reformer (OSR) arranged to receive one or both of the first synthesis gas and the second synthesis gas and configured to convert hydrocarbon and steam into a third synthesis gas; and one or more components effective for separating a stream of predominately hydrogen from one or more of the first synthesis gas, the optional, second synthesis gas, and the third synthesis gas.

2. The hydrogen production plant of claim 1, wherein one or both of the first convective reformer and the second convective reformer have a tube-in-shell arrangement.

3. The hydrogen production plant of claim 2, wherein the tube-in-shell arrangement comprises at least one set of concentrically arranged tubes positioned within a containment vessel, each of the at least one set of concentrically arranged tubes comprising: an outer catalyst tube; an inner reaction product gas tube; and catalyst material positioned within a space defined between an inside surface of the outer catalyst tube and an outside surface of the inner reaction product gas tube.

4. The hydrogen production plant of claim 1, wherein the first convective reformer is arranged so that the first heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the first synthesis gas, and wherein the second convective reformer is arranged so that the second heating fluid provides reaction heat while remaining separated from the hydrocarbon, the steam, and the second synthesis gas.

5. The hydrogen production plant of claim 1, further comprising a combustor configured to produce a combustion exhaust stream.

6. The hydrogen production plant of claim 5, wherein the combustion exhaust stream comprises at least a portion of the first heating fluid received by the first convective reformer.

7. The hydrogen production plant of claim 6, further comprising a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer.

8. The hydrogen production plant of claim 7, wherein the plurality of combustion exhaust processing units comprise one or more of:WBD (US) 4910-8123-0946vl -37-AttyDktNo. P62622 2350WO (01244) a heat exchanger; a separator configured to remove water from the combustion exhaust; a separator configured to remove inert gases from the combustion exhaust; and a separator configured to remove oxygen from the combustion exhaust.

9. The hydrogen production plant of claim 1, wherein the third synthesis gas comprises at least a portion of the second heating fluid received by the second convective reformer.

10. The hydrogen production plant of claim 1, further comprising one or more water gas shift units.

11. The hydrogen production plant of claim 1, wherein the one or more components effective for separating a stream of predominately hydrogen comprises one or more hydrogen pressure swing adsorption units.

12. The hydrogen production plant of claim 11, wherein the one or more components effective for separating a stream of predominately hydrogen further comprises one or more carbon dioxide removal units.

13. The hydrogen production plant of claim 12, wherein the one or more carbon dioxide removal units comprise one or both of a low temperature carbon dioxide separator and a carbon dioxide pressure swing adsorption unit.

14. The hydrogen production plant of claim 1, wherein the first convective reformer, the second convective reformer, and the OSR are arranged in series with the OSR downstream from both of the first convective reformer and the second convective reformer with respect to a flow of the first synthesis gas and the second synthesis gas.

15. The hydrogen production plant of claim 14, wherein the second convective reformer is arranged downstream from the first convective reformer.

16. The hydrogen production plant of claim 14, wherein the first convective reformer is arranged downstream from the second convective reformer.

17. A process for hydrogen production comprising: reacting hydrocarbon and steam in a first convective reformer that is heated by a first heating fluid so as to convert the hydrocarbon and steam into synthesis gas and provide a first synthesis gas stream;WBD (US) 4910-8123-0946vl -38-AttyDktNo. P62622 2350WO (01244) reacting hydrocarbon and steam in a second convective reformer that is heated by a second heating fluid so as to convert the hydrocarbon and steam into synthesis gas and provide a second synthesis gas stream; reacting at least a portion of the first synthesis gas stream and at least a portion of the second synthesis gas stream with oxygen and steam in an oxygen secondary reformer (OSR) to form additional synthesis gas and to provide a third synthesis gas stream; processing at least a portion of the third synthesis gas stream in one or more components effective for separating a stream of predominately hydrogen from the third synthesis gas stream.

18. The process of claim 17, further comprising combusting a fuel with an oxidant in a combustor to produce a combustion exhaust stream.

19. The process of claim 18, wherein the combustion exhaust stream comprises at least a portion of the first heating fluid in the first convective reformer.

20. The process of claim 19, further comprising processing the combustion exhaust in a plurality of combustion exhaust processing units arranged to receive the combustion exhaust from the first convective reformer.

21. The process of claim 20, wherein processing the combustion exhaust in the plurality of combustion exhaust processing units comprises separating out one or more of a stream of inert gas, a stream of oxygen, a stream of carbon dioxide, and a stream of water.

22. The process of claim 17, wherein the third synthesis gas comprises at least a portion of the second heating fluid received by the second convective reformer.

23. The process of claim 17, wherein processing at least a portion of the third synthesis gas stream comprises processing in one or more water gas shift units effective to provide a shifted synthesis gas stream.

24. The process of claim 17, wherein processing at least a portion of the third synthesis gas stream comprises processing in one or more hydrogen pressure swing adsorption units.

25. The process of claim 17, wherein processing at least a portion of the third synthesis gas stream comprises processing in one or more carbon dioxide removal units.

26. The process of claim 25, wherein the one or more carbon dioxide removal units comprise one or both of a cooled carbon dioxide separator and a carbon dioxide pressure swing adsorption unit.WBD (US) 4910-8123-0946vl -39-AttyDktNo. P62622 2350WO (01244)27. A hydrogen production plant comprising: a combustor configured to produce a combustion exhaust stream; a convective reformer arranged to receive at least a portion of the combustion exhaust stream as a heating fluid and configured to convert hydrocarbon and steam into a first synthesis gas; an oxygen secondary reformer (OSR) arranged to receive the first synthesis gas and configured to convert hydrocarbon and steam into a total synthesis gas; and a separation unit for separating at least a portion of the total synthesis gas into at least one product stream and at least one tail gas stream.

28. The hydrogen production plant of claim 27, wherein the separation unit comprises a first hydrogen pressure swing adsorber, at least one carbon dioxide separator, and a second hydrogen pressure swing adsorber.

29. The hydrogen production plant of claim 28, wherein one or both of the first hydrogen pressure swing adsorber and the second hydrogen pressure swing adsorber is a fractionating pressure swing adsorber.

30. The hydrogen production plant of claim 29, wherein the second hydrogen pressure swing adsorber is a fractionating pressure swing adsorber and is configured to provide a stream of predominately hydrogen, a first tail gas stream with a first composition, and a second tail gas stream with a second composition that is different from the first composition.

31. The hydrogen production plant of claim 30, wherein one of the first tail gas stream and the second tail gas stream is concentrated in inerts and is arranged for introduction to the combustor.

32. The hydrogen production plant of claim 28, wherein the at least one product stream comprises a stream of predominately hydrogen from one or both of the first hydrogen pressure swing adsorber and the second hydrogen pressure swing adsorber.

33. The hydrogen production plant of claim 28, wherein the at least one carbon dioxide separator comprises a low temperature CO2 separator and a CO2 pressure swing adsorber arranged downstream from the low temperature CO2 separator.

34. The hydrogen production plant of claim 33, wherein the at least one product stream comprises a stream of predominately carbon dioxide from the low temperature CO2 separator.WBD (US) 4910-8123-0946vl -40-

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