Systems & methods for improving the overall efficiency and reducing carbon intensity for hydrogen production processes

Abstract

Systems and methods for producing hydrogen with reduced carbon intensity by generating work from expansion of high-pressure produced hydrogen. An expander with a rotating output shaft can be used to convert the expansion of hydrogen into useful work in the form of rotation (torque) of the output shaft, and also utilizes the low temperature of expanded hydrogen as a cooling media to cool a process fluid such physical solvent(s) used for CO2 removal.

Description

SYSTEMS & METHODS FOR IMPROVING THE OVERALL EFFICIENCY AND REDUCING CARBON INTENSITY FOR HYDROGEN PRODUCTION PROCESSESFIELD OF DISCLOSURE

[0001] The present disclosure relates generally to production of hydrogen and, more particularly but not by way of limitation, to systems and methods for reducing the carbon footprint of hydrogen production by generating work from expansion of high-pressure produced hydrogen.BACKGROUND

[0002] Hydrogen may be used in certain industrial applications as a relatively “clean” (low- carbon) fuel. However, the pressures at which certain processes produce hydrogen may exceed the pressures at which hydrogen may be used as a fuel. In such applications, elevated pressure of hydrogen (greater than 6 bar) is not needed for use. Hence, hydrogen must be expanded to reduce pressure for use. Hydrogen is one of relatively few gases that generate heat due to Joule-Thomson effects when expanded without producing work.SUMMARY

[0003] The present systems and methods utilize an expander with a rotating output shaft to convert the expansion of hydrogen into useful work in the form of rotation (torque) of the output shaft, and also utilizes the low temperature of expanded hydrogen as a cooling media to cool a process fluid such physical solvent(s) used for CO2 removal. Certain processes for generating hydrogen, such as autothermal reforming (ATR) and partial oxidation (POX) produce hydrogencontaining gases (e.g., syngas) at elevated pressures (e.g., at least 30 bar, 40 bar, 50 bar, 60 bar, 70 bar, or more). Such gases are typically subjected to additional processes to remove non-hydrogen components (e.g., carbon dioxide (CO2), hydrogen sulfide (H2S), carbonyl sulfide (COS)) and / or to convert non-hydrogen components to hydrogen, to produce a hydrogen gas stream that is substantially all hydrogen (H2), often with a pressure of 50 bar or greater. However, this elevated pressure presents an opportunity to extract meaningful work when the pressure is reduced for low pressure applications, such as fuel usage, to a lower pressure (e.g., at or below 6 bar) that is closer to atmospheric pressure.

[0004] The extraction of work from expanding hydrogen is beneficial because it both: (a) reduces the amount of energy that must come from other sources to perform beneficial taskslike compression of CO2 for sequestration and / or generation of electrical power, and (b) reduces or eliminates the need to counterbalance the production of thermal energy that would occur due to Joule-Thomson effects during expansion. For example, the output shaft of the expander can be coupled to a compressor to compress CO2 — e.g., CO2 removed from the hydrogen-containing gas (e.g., syngas) — for sequestration. By way of further example, the output shaft of the expander can be coupled to a generator to generate electrical power.

[0005] Additionally, the use of the expanded hydrogen to cool (e.g., via heat exchanger) other process fluids can also reduce the need for cooling processes from other sources. In some implementations, expansion with work can reduce temperature and may result in an expanded hydrogen gas stream with a temperature of below 0°C, for example below -50°C. Some CO2 removal systems and processes used in hydrogen production utilize a physical solvent (e.g., methanol) to clean up the syngas and separate hydrogen from other contents. Examples of such CO2 removal systems using a physical solvent include acid gas removal systems and processes, such as Rectisol® and Recticap® (Air Liquide Group). In such systems, the expanded hydrogen can be used to cool a circulating physical solvent stream (and any makeup solvent added to the stream) before the physical solvent stream is returned to the CO2 removal column.

[0006] The extraction of useful work and / or the use of the expanded hydrogen gas stream for cooling can improve the overall efficiency and reduce the carbon footprint of hydrogen production processes, improving various processes for the production of low-carbon hydrogen conditioned for low-pressure applications. These effects may be particularly beneficial for industrial applications in locations where hydrogen is produced and used on-site, and CO2 is captured and compressed for sequestration.

[0007] In some configurations of the present systems for production of hydrogen, the system comprises: a CO2 removal system, an expander, and a heat exchanger. The CO2 removal system has a gas inlet, a gas outlet, a solvent inlet, and a solvent outlet, and the CO2 removal system is configured to receive a hydrogen-containing gas stream through the gas inlet such that as the gas stream flows through the CO2 removal system and a physical solvent flows through the CO2 removal system, CO2 is removed from the gas stream to produce an initial hydrogen gas stream. The expander has an output shaft, an outlet, and an inlet in fluid communication with the CO2 removal system gas outlet, and the expander is configured such that as an initial hydrogen gas stream passes from the inlet to the outlet, the output shaft rotates and the hydrogen gas expands toform an expanded hydrogen gas stream with a lower temperature and pressure than those of the initial hydrogen gas stream. The heat exchanger has a hydrogen outlet, a hydrogen inlet in fluid communication with the expander outlet, a solvent inlet in fluid communication with the CO2 removal system solvent outlet, and a solvent outlet in fluid communication with the CO2 removal system solvent inlet, and the heat exchanger is configured such that when an expanded hydrogen gas stream flows from the hydrogen inlet to the hydrogen outlet and a solvent stream flows from the solvent inlet to the solvent outlet, the expanded hydrogen gas stream is in thermal communication with the solvent. In such configurations, the system is configured to: circulate a physical solvent through the heat exchanger solvent inlet, the heat exchanger solvent outlet, the CO2 removal system solvent inlet, the CO2 removal system solvent outlet, and the heat exchanger solvent inlet; receive a hydrogen-containing gas stream through the CO2 removal system gas inlet, convey an initial hydrogen gas stream from the CO2 removal system to the expander, convey an expanded hydrogen gas stream from the expander to the heat exchanger hydrogen inlet; and convey the expanded hydrogen gas stream through the heat exchanger such that thermal energy is transferred from the physical solvent to the expanded hydrogen gas stream to cool the physical solvent.

[0008] In some of the foregoing configurations of the present systems, the system further comprises: a syngas production unit and a water shift reactor. The syngas production unit comprises one or more components selected from the list of components consisting of: an auto thermal reformer (ATR), a partial oxidation (POX) system, and a steam methane reformer (SMR) (including combinations of any two or more thereof); and the syngas production unit is configured to receive a natural gas stream and generate a hydrogen-containing gas stream. The water shift reactor has a reactor inlet in fluid communication with an outlet of the syngas production unit, and a reactor outlet in fluid communication with the CO2 removal system gas inlet, the water shift reactor configured to increase proportions of H2 and CO2 in the hydrogen-containing gas stream. In some such configurations, the syngas production unit comprises one or more POX system(s) but not any ATRs or SMRs, and the syngas production unit is configured to receive an untreated natural gas stream. In some such configurations, the syngas production unit comprises a partial oxidation (POX) system, and the water shift reactor is a sour water shift reactor.

[0009] In some of the foregoing configurations of the present systems, the system further comprises: a generator coupled to the output shaft of the expander, the generator configured to generate electric power responsive to rotation of the output shaft.

[0010] In some of the foregoing configurations of the present systems, the system further comprises: a compressor coupled to the output shaft of the expander, the compressor having a gas outlet, and a gas inlet in fluid communication with a CO2 outlet of the CO2 removal system, the compressor configured to compress CO2 from the CO2 removal system responsive to rotation of the output shaft.

[0011] In some of the foregoing configurations of the present systems, the CO2 removal system is configured to remove from the hydrogen-containing gas stream hydrogen sulfide (H2S) and carbonyl sulfide (COS) and divert the H2S and COS to a gas desulfurization system.

[0012] In some implementations of the present methods for producing hydrogen, the method comprises: producing an initial hydrogen gas stream by removing CO2 from a hydrogencontaining gas stream in a CO2 removal system utilizing a physical solvent; expanding the initial hydrogen gas stream in an expander, such that an output shaft of the expander rotates, to produce an expanded hydrogen gas stream with a temperature and pressure that are lower than those of the initial hydrogen gas stream; transferring in a heat exchanger thermal energy from a physical solvent stream exiting the CO2 removal system to the expanded hydrogen gas stream to cool the physical solvent stream; and returning the cooled physical solvent stream to the CO2 removal system. Some such implementations further comprise: adding physical solvent to the physical solvent stream between the CO2 removal system solvent outlet and the heat exchanger solvent inlet.

[0013] In some of the foregoing implementations of the present methods, the method further comprises: increasing proportions of H2 and CO2 in the hydrogen-containing gas stream using a water shift reactor between a syngas production unit and the CO2 removal system; where the syngas production unit comprises an auto thermal reformer (ATR) or a partial oxidation (POX) system. In some such configurations, the syngas production unit comprises a partial oxidation (POX) system, and the water shift reactor is a sour water shift reactor.

[0014] In some of the foregoing implementations of the present methods, the method further comprises: generating electrical power with a generator driven by the rotation of the expander output shaft.

[0015] In some of the foregoing implementations of the present methods, the method further comprises: compressing CO2 from the CO2 removal system with a compressor driven by the rotation of the expander output shaft. In some such implementations, the rotation of the expander output shaft is supplemented by an electric motor to drive the compressor.

[0016] In some of the foregoing implementations of the present methods, producing the initial hydrogen gas stream further includes removing hydrogen sulfide (H2S) and carbonyl sulfide (COS) from the hydrogen-containing gas stream, and the method further comprises: directing the removed H2S and COS to a gas desulfurization system.

[0017] In some of the foregoing implementations of the present methods and configurations of the present systems, the method or system has at least one characteristic selected from the group of characteristics consisting of: the CO2 removal system is an acid gas cleaning system; the physical solvent is methanol; the hydrogen-containing gas stream comprises syngas; the heat exchanger is a direct contact heat exchanger; the expanded hydrogen gas stream exits the expander at a temperature of below 0°C, optionally below -50°C.

[0018] The term “coupled” is defined as connected, although not necessarily directly, and not necessarily mechanically; two items that are “coupled” may be unitary with each other. The terms “a” and “an” are defined as one or more unless this disclosure explicitly requires otherwise. The term “substantially” is defined as largely but not necessarily wholly what is specified (and includes what is specified; e.g., substantially 90 degrees includes 90 degrees and substantially parallel includes parallel), as understood by a person of ordinary skill in the art. In any embodiment of the present apparatuses, kits, and methods, the term “substantially” may be substituted with “within [a percentage] of’ what is specified, where the percentage includes 0.1, 1, 5, and / or 10 percent.

[0019] The terms “comprise” (and any form of comprise, such as “comprises” and “comprising”), “have” (and any form of have, such as “has” and “having”), “include” (and any form of include, such as “includes” and “including”) and “contain” (and any form of contain, such as “contains” and “containing”) are open-ended linking verbs. As a result, an apparatus or kit that “comprises,” “has,” “includes” or “contains” one or more elements possesses those one or more elements, but is not limited to possessing only those elements. Likewise, a method that “comprises,” “has,” “includes” or “contains” one or more steps possesses those one or more steps, but is not limited to possessing only those one or more steps.

[0020] Further, an apparatus, device or system that is configured in a certain way is configured in at least that way, but it can also be configured in other ways than those specifically described.

[0021] Any embodiment of any of the present apparatuses and methods can consist of or consist essentially of - rather than comprise / include / contain / have - any of the described steps, elements, and / or features. Thus, in any of the claims, the term “consisting of’ or “consisting essentially of’ can be substituted for any of the open-ended linking verbs recited above, in order to change the scope of a given claim from what it would otherwise be using the open-ended linking verb.

[0022] Some details associated with the various configurations and implementations of the present systems and methods are described above, and others details are described below. Other implementations, advantages, and features of the present disclosure will become apparent after review of the entire application, including the Brief Description of the Drawings, Detailed Description, and the Claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The following drawings illustrate by way of example and not limitation. For the sake of brevity and clarity, every feature of a given structure is not always labeled in every figure in which that structure appears. Identical labels or reference numbers do not necessarily indicate an identical structure. Rather, the same reference number may be used to indicate a similar feature or a feature with similar functionality, as may non-identical reference numbers.

[0024] FIG. 1 depicts a schematic diagram of a first example of the present hydrogenproduction systems, which utilizes a hydrogen expander to generate power, a heat exchanger to cool a physical solvent, and a treated natural gas as a feedstock.

[0025] FIG. 2 depicts a schematic diagram of a second example of the present hydrogenproduction systems, which utilizes a hydrogen expander to generate power, a heat exchanger to cool a physical solvent, gas desulfurization system and an untreated natural gas as a feedstock.

[0026] FIG. 3 depicts a schematic diagram of a second example of the present hydrogenproduction systems, which utilizes a hydrogen expander to compress CO2, a heat exchanger to cool a physical solvent, and a treated natural gas as a feedstock.

[0027] FIG. 4 depicts a schematic diagram of a fourth example of the present hydrogenproduction systems, which utilizes a hydrogen expander to compress CO2 , a heat exchanger to cool a physical solvent, gas desulfurization system and an untreated natural gas as a feedstock.DETAILED DESCRIPTION

[0028] Referring now to the drawings, and more particularly to FIG. 1, shown there is a schematic diagram of a first example 100a of the present hydrogen-production systems. In the depicted example, system 100 comprises a CO2 removal system 104a, an expander 108 (e.g., turboexpander), and a heat exchanger 112 (e.g., a direct contact heat exchanger).

[0029] As shown, CO2 removal system 104a has a gas inlet 116, a gas outlet 120, a solvent inlet 124, and a solvent outlet 128. CO2 removal system 104a is configured to remove at least CO2 from a hydrogen-containing gas stream (e.g., a syngas). In the depicted configuration, CO2 removal system 104a comprises an acid gas cleaning or acid gas removal system that utilizes a physical solvent (e.g., methanol) to remove at least CO2 and, in some configurations, other gases such as, for example, H2S, COS, and / or the like. Examples of such acid gas removal systems use physical solvents such as Rectisol® and Recticap® (Air Liquide Group). As shown, CO2 removal system 104a is configured to receive a hydrogen-containing gas (e.g., syngas) stream through gas inlet 116 such that as the gas stream flows through CO2 removal system 104a (from gas inlet 116 to gas outlet 120) and a physical solvent flows through the CO2 removal system (from solvent inlet 124 to solvent outlet 128), CO2 is removed from the gas stream and diverted via a CO2 outlet 132 to produce an initial hydrogen gas stream that exits gas outlet 120.

[0030] As also shown, expander 108 has an output shaft 136, an inlet 140, and an outlet 144. In this configuration, inlet 140 is in fluid communication with gas outlet 120 of CO2 removal system 104a to receive the initial hydrogen gas stream. Expander 108 is configured to extract useful work from the expansion of the hydrogen gas. More particularly, as the initial hydrogen gas stream passes from inlet 140 to outlet 144, output shaft 136 rotates and the hydrogen gas expands to form an expanded hydrogen gas stream that exits outlet 144. After this expansion and extraction of work, the expanded hydrogen gas stream has a lower pressure than the initial hydrogen gas stream, and a lower temperature than the initial hydrogen gas stream. For example, when the initial hydrogen gas stream has an initial pressure of 50 bar or greater, and the expandedhydrogen gas stream has an expanded pressure of 10 bar or less, the expanded hydrogen gas stream may decrease in temperature to an expanded temperature of 0°C or less (e.g., -50 °C or less).

[0031] As also shown, heat exchanger 112 has a hydrogen inlet 148, a hydrogen outlet 152, a solvent inlet 156, and a solvent outlet 160. In this example, hydrogen inlet 148 is in fluid communication with expander outlet 144, solvent inlet 156 is in fluid communication with CO2 removal system solvent outlet 128, and solvent outlet 160 is in fluid communication with CO2 removal system solvent inlet 124. Heat exchanger 112 is configured to allow thermal energy to transfer from the relatively warmer physical solvent to the relatively cooler expanded hydrogen gas stream. More particularly, heat exchanger 112 is configured such that when the expanded hydrogen gas stream flows through the heat exchanger (from hydrogen inlet 148 to hydrogen outlet 152) and the physical solvent stream flows through the heat exchanger (from solvent inlet 156 to solvent outletl60), the expanded hydrogen gas stream is in thermal communication with the physical solvent stream, to allow heat transfer therebetween. For example, in some implementations, heat exchanger 112 comprises a direct contact heat exchanger. In other implementations, heat exchanger 112 is configured such that the expanded hydrogen gas stream and the physical solvent are not in fluid communication (e.g., in a counter-flow heat exchanger, shell-and-tube heat exchanger, and / or the like).

[0032] In operation, CO2 removal system 104a receives a hydrogen-containing gas stream through gas inlet 116 and extracts CO2 to form an initial hydrogen gas stream that then flows from CO2 removal system 104a to expander 108. Expander 108 rotates output shaft 136 as the hydrogen gas stream expands to form an expanded hydrogen gas stream, which then flows from expander 108 to heat exchanger 112. Meanwhile, a physical solvent circulates between CO2 removal system 104a (heating) and heat exchanger 112 (cooling). More particularly, the physical solvent circulates sequentially through heat exchanger solvent inlet 156, heat exchanger solvent outlet 160, CO2 removal system solvent inlet 124, CO2 removal system solvent outlet 128, and heat exchanger solvent inlet 156. Finally, as the expanded hydrogen gas stream flows through heat exchanger 112, thermal energy is transferred from the physical solvent to the expanded hydrogen gas stream, which results in cooling of the physical solvent, and the cooled physical solvent returns to the CO2 removal system. Additionally, in the depicted configuration, additional (make-up) physical solvent is added to the system at point 164, between CO2 removal system solvent outlet 128 andheat exchanger solvent inlet 156, as needed to replace physical solvent that may be used up in the CO2 removal process and / or otherwise lost to leakage or the like.

[0033] In the depicted example, output shaft 136 of expander 108 is coupled to a generator 168 that is configured to generate electric power responsive to rotation of the output shaft. Thus, in this configuration, the work output of the expansion of the hydrogen can be utilized in the form of electrical energy, for example, to reduce the amount of electrical energy sourced from a power grid and / or other potentially non-renewable sources.

[0034] In the depicted configuration, the hydrogen containing gas entering CO2 removal system 104a begins as a treated natural gas stream that is converted to syngas (hydrogencontaining gas) in a syngas production unit 172, and the syngas is then subjected to a water shift reaction in one or more water shift reactor(s) 176 prior to flowing to CO2 removal system 104a. In this example, a syngas production unit comprises an auto thermal reformer (ATR), a partial oxidation (POX) system, a steam methane reformer (SMR), or any combination of the foregoing units and / or any other syngas production unit that uses natural gas or biogas as a feedstock. Steam reforming typically utilizes reactions given by Equations 1 and 2.CH4 + H2O CO + 3H2(1)CO + H2O CO2 + H2 (2)Syngas may also be formed by the ATR process with a typical temperature of about 1000°C and a pressure on the order of at least 30 bar to 50 bar (e.g., greater than any one of, or between any two of: 30 bar, 40 bar, 50 bar, or more). ATR processes can also be performed with a water shift reaction at different steam carbon feed ratios. The ATR process may also be referred to as oxidative steam reforming, but its target chemical reaction using H2O is generally given by the following Equation 3, and its target chemical reaction using CO2 is given by Equation (4):4CH4+ O2 + 2H2O 1 OH2 + 4CO (3)2CH4+ O2 + CO2 3H2+ 3 CO + H2O (4)The target reaction of the POX process is given by the following Equation 5:2CH4+ 02^ 2C0 + 4H2(5)Syngas may be formed by the POX process with a temperature of about 1200°C and a pressure on the order of at least 40 bar to 80 bar (e.g., greater than any one of, or between any two of: 40 bar, 50 bar, 60 bar, 70 bar, 80 bar, or more). While steam methane reforming (SMR) is another known option for generating syngas (performing reactions given by Equations 1, 2), it generally does so at relatively lower pressures, typically no more than 40 bar and often as low as 15 bar, to ensure mechanical integrity for reformer tubes, that makes SMR units less suitable for use in the present systems and methods which require sufficient energy density — typically in the form of elevated pressure — in the hydrogen gas stream prior to expansion.

[0035] Water shift reactor(s) 176 is / are configured to increase the proportions of Eb and consequently CO2 in the hydrogen-containing gas stream. As shown, each water shift reactor 176 has a reactor inlet 180 in fluid communication with an outlet 184 of syngas production unit 172, and a reactor outlet 188 in fluid communication with gas inlet 116 of the CO2 removal system 104a. The water gas shift process generally converts H2O, in the form of steam, and CO into H2 and CO2 according the reaction given by the following Equation 6:CO + H2O H2 + CO2 (6)

[0036] FIG. 2 shows a schematic diagram of a second example 100b of the present hydrogenproduction systems. System 100b is similar in many respects to system 100a of FIG. 1, with the primary exceptions being that in system 100b syngas production unit 172 comprises a partial oxidation (POX) system, the feedstock to syngas production unit 172 is an untreated natural gas or biogas, CO2 removal system 104b is configured to divert sulfur compounds to a gas desulfurization system 192, and each of water shift reactor(s) 176 is a sour water shift reactor in which the catalyst tolerates sulfur components. As shown, CO2 removal system is configured to divert — via fraction outlet 196 — sulfur-containing compounds, such as for example hydrogen sulfide (H2S) and carbonyl sulfide (COS) — to gas desulfurization system 192. Gas desulfurization system 192 can utilize any of various desulfurization processes, for example, a Claus process, a wet sulfuric acid (WSA) process, and / or the like.

[0037] FIG. 3 shows a schematic diagram of a third example 100c of the present hydrogenproduction systems. System 100c is similar in many respects to system 100a of FIG. 1, with the primary exceptions being that instead of a generator, system 100c utilizes the rotation of output shaft 136 of expander 108 to drive a compressor 200. More particularly, compressor 200 iscoupled to output shaft 136 of expander 108, and is configured to compress CO2 from CO2 removal system for sequestration, thereby reducing the energy that must come from other sources to prepare that CO2 for sequestration. As shown, compressor 200 has a gas inlet 204 in fluid communication with CO2 outlet 132 of CO2 removal system 104b, the compressor configured to compress CO2 from the CO2 removal system responsive to rotation of output shaft 136 to generate a compressed CO2 stream that exits a gas outlet 208 of the compressor. During at least some periods of operation, the power output of expander 108 may not be sufficient to operate compressor 200 at desired levels and, as such, system 100b also comprises a motor 212 to also drive compressor 200.

[0038] FIG. 4 shows a schematic diagram of a fourth example lOOd of the present hydrogenproduction systems. System lOOd is similar in many respects to system 100b of FIG. 2, with the primary exceptions being that instead of a generator, system 100c utilizes the rotation of output shaft 136 of expander 108 to drive a compressor 200. More particularly, compressor 200 is coupled to output shaft 136 of expander 108, and is configured to compress CO2 from CO2 removal system for sequestration, thereby reducing the energy that must come from other sources to prepare that CO2 for sequestration. As shown, compressor 200 has a gas inlet 204 in fluid communication with CO2 outlet 132 of CO2 removal system 104b, the compressor configured to compress CO2 from the CO2 removal system responsive to rotation of output shaft 136 to generate a compressed CO2 stream that exits a gas outlet 208 of the compressor. During at least some periods of operation, the power output of expander 108 may not be sufficient to operate compressor 200 at desired levels and, as such, system 100b also comprises a motor 212 to also drive compressor 200.

[0039] Certain implementations of the present methods may be implemented utilizing the present systems and are therefore described with reference to the present systems. However, the present methods may also be implemented utilizing variations on the depicted examples of the present systems, or with other systems.

[0040] In some implementations of the present methods for producing hydrogen, the method comprises producing an initial hydrogen gas stream by removing CO2 from a hydrogen-containing gas stream in a CO2 removal system (e.g., 104a, 104b) utilizing a physical solvent (e.g., methanol). Some such implementations further comprise: expanding the initial hydrogen gas stream in an expander (e.g., 108), such that an output shaft (e.g., 136) of the expander rotates, to produce an expanded hydrogen gas stream with a temperature and pressure that are lower than those of the initial hydrogen gas stream. Some such implementations further comprise transferring in a heatexchanger (e.g., 112) thermal energy from a physical solvent stream exiting the CO2 removal system (e.g., 104a, 104b) to the expanded hydrogen gas stream (from the expander, e.g., 108) to cool the physical solvent stream; and returning the cooled physical solvent stream to the CO2 removal system (e.g., 104a, 104b).

[0041] Some implementations of the present methods further comprise: adding physical solvent to the physical solvent stream between the CO2 removal system (e.g., 104a, 104b) and the heat exchanger (e.g., 108), for example, at a point (e.g., 164) between a solvent outlet (e.g., 128) of the CO2 removal system (e.g., 104a, 104b) and a solvent inlet (e.g., 156) of the heat exchanger (e.g., 112).

[0042] Some implementations of the present methods further comprise: increasing proportions of H2 and CO2 in the hydrogen-containing gas stream using a water shift reactor (e.g., 176) between a syngas production unit (e.g., 172) and the CO2 removal system (e.g., 104a, 104b); where the syngas production unit comprises an auto thermal reformer (ATR) or a partial oxidation (POX) system or SMR operated at elevated pressure or a combination between these units. In some such implementations, the syngas production unit comprises a partial oxidation (POX) system, and the water shift reactor is a sour water shift reactor.

[0043] Some implementations of the present methods further comprise: generating electrical power with a generator (e.g., 168) driven by the rotation of the expander output shaft (e.g., 136).

[0044] Other implementations of the present methods further comprise: compressing CO2 from the CO2 removal system (e.g., 104a, 104b) with a compressor (e.g., 200) driven by the rotation of the expander output shaft (e.g., 136).

[0045] In some of the foregoing implementations of the present methods, producing the initial hydrogen gas stream further includes removing hydrogen sulfide (H2S) and carbonyl sulfide (COS) from the hydrogen-containing gas stream, and the method further comprises: directing (e.g., via fraction outlet 196) the removed H2S and COS to a gas desulfurization system (e.g., 192), for example, utilizing a Claus process, WSA process, or the like.* * *

[0046] Additional details about various components of steam cracking plants and processes can be found in International Patent Application Publication No. W02020 / 150244, which is incorporated by reference in its entirety.

[0047] The above specification and examples provide a complete description of the structure and use of exemplary embodiments. Although certain embodiments have been described above with a certain degree of particularity, or with reference to one or more individual embodiments, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the scope of this invention. As such, the various illustrative embodiments of the present devices are not intended to be limited to the particular forms disclosed. Rather, they include all modifications and alternatives falling within the scope of the claims, and embodiments other than the one shown may include some or all of the features of the depicted embodiment. For example, components may be combined as a unitary structure, and / or connections may be substituted. Further, where appropriate, aspects of any of the examples described above may be combined with aspects of any of the other examples described to form further examples having comparable or different properties and addressing the same or different problems. Similarly, it will be understood that the benefits and advantages described above may relate to one embodiment or may relate to several embodiments.

[0048] The claims are not intended to include, and should not be interpreted to include, means- plus- or step-plus-function limitations, unless such a limitation is explicitly recited in a given claim using the phrase(s) “means for” or “step for,” respectively.

Claims

CLAIMS1. A system for production of hydrogen, the system comprising: a CO2 removal system having a gas inlet, a gas outlet, a solvent inlet, and a solvent outlet, the CO2 removal system configured to receive a hydrogen-containing gas stream through the gas inlet such that as the gas stream flows through the CO2 removal system and a physical solvent flows through the CO2 removal system, CO2 is removed from the gas stream to produce an initial hydrogen gas stream; an expander having an output shaft, an outlet, and an inlet in fluid communication with the CO2 removal system gas outlet, the expander configured such that as an initial hydrogen gas stream passes from the inlet to the outlet, the output shaft rotates and the hydrogen gas expands to form an expanded hydrogen gas stream with a lower temperature and pressure than those of the initial hydrogen gas stream; a heat exchanger having a hydrogen outlet, a hydrogen inlet in fluid communication with the expander outlet, a solvent inlet in fluid communication with the CO2 removal system solvent outlet, and a solvent outlet in fluid communication with the CO2 removal system solvent inlet, the heat exchanger configured such that when an expanded hydrogen gas stream flows from the hydrogen inlet to the hydrogen outlet and a solvent stream flows from the solvent inlet to the solvent outlet, the expanded hydrogen gas stream is in thermal communication with the solvent; and where the system is configured to: circulate a physical solvent through the heat exchanger solvent inlet, the heat exchanger solvent outlet, the CO2 removal system solvent inlet, the CO2 removal system solvent outlet, and the heat exchanger solvent inlet; and receive a hydrogen-containing gas stream through the CO2 removal system gas inlet, convey an initial hydrogen gas stream from the CO2 removal system to the expander, convey an expanded hydrogen gas stream from the expander to the heat exchanger hydrogen inlet; and convey the expanded hydrogen gas stream through the heat exchanger such that thermal energy is transferred from the physical solvent to the expanded hydrogen gas stream to cool the physical solvent.

2. The system of claim 1, further comprising: a syngas production unit comprising one or more components selected from the list of components consisting of: an auto thermal reformer (ATR), a partial oxidation (POX) system, and a steam methane reformer (SMR); the syngas production unit configured to receive a natural gas stream and generate a hydrogen-containing gas stream; and a water shift reactor having a reactor inlet in fluid communication with an outlet of the syngas production unit, and a reactor outlet in fluid communication with the CO2 removal system gas inlet, the water shift reactor configured to increase proportions of H2 and CO2 in the hydrogen-containing gas stream.

3. The system of claim 2, where the syngas production unit comprises one or more POX system(s) but not any ATRs or SMRs, and the syngas production unit is configured to receive an untreated natural gas stream.

4. The system of any of claims 2-3, where the syngas production unit comprises a partial oxidation (POX) system, and the water shift reactor is a sour water shift reactor.

5. The system of any of claims 1-3, further comprising: a generator coupled to the output shaft of the expander, the generator configured to generate electric power responsive to rotation of the output shaft.

6. The system of any of claims 1-3, further comprising: a compressor coupled to the output shaft of the expander, the compressor having a gas outlet, and a gas inlet in fluid communication with a CO2 outlet of the CO2 removal system, the compressor configured to compress CO2 from the CO2 removal system responsive to rotation of the output shaft.

7. The system of any of claims 5-6, where the CO2 removal system is configured to remove from the hydrogen-containing gas stream hydrogen sulfide (H2S) and carbonyl sulfide (COS) and divert the H2S and COS to a gas desulfurization system.

8. A method for producing hydrogen, the method comprising: producing an initial hydrogen gas stream by removing CO2 from a hydrogen-containing gas stream in a CO2 removal system utilizing a physical solvent; expanding the initial hydrogen gas stream in an expander, such that an output shaft of the expander rotates, to produce an expanded hydrogen gas stream with a temperature and pressure that are lower than those of the initial hydrogen gas stream; transferring in a heat exchanger thermal energy from a physical solvent stream exiting the CO2 removal system to the expanded hydrogen gas stream to cool the physical solvent stream; and returning the cooled physical solvent stream to the CO2 removal system.

9. The method of claim 8, further comprising: adding physical solvent to the physical solvent stream between the CO2 removal system solvent outlet and the heat exchanger solvent inlet.

10. The method of any of claims 8-9, further comprising: increasing proportions of H2 and CO2 in the hydrogen-containing gas stream using a water shift reactor between a syngas production unit and the CO2 removal system; where the syngas production unit comprises an auto thermal reformer (ATR) or a partial oxidation (POX) system.

11. The method of claim 10, where the syngas production unit comprises a partial oxidation (POX) system, and the water shift reactor is a sour water shift reactor.

12. The method of any of claims 8-10, further comprising: generating electrical power with a generator driven by the rotation of the expander output shaft.

13. The method of any of claims 8-10, further comprising: compressing CO2 from the CO2 removal system with a compressor driven by the rotation of the expander output shaft; optionally where the rotation of the expander output shaft is supplemented by an electric motor to drive the compressor.

14. The method of any of claims 12-13, where producing the initial hydrogen gas stream further includes removing hydrogen sulfide (H2S) and carbonyl sulfide (COS) from the hydrogencontaining gas stream, and the method further comprises: directing the removed H2S and COS to a gas desulfurization system.

15. The system of any of claims 1-7 or the method of any of claims 8-14, where the system or method has at least one characteristic selected from the group of characteristics consisting of: the CO2 removal system is an acid gas cleaning system; the physical solvent is methanol; the hydrogen-containing gas stream comprises syngas; the heat exchanger is a direct contact heat exchanger; the expanded hydrogen gas stream exits the expander at a temperature of below 0°C, optionally below -50°C.

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