WO2023167922A1

WO2023167922A1 - Electric power co-generation for chemical and physical processes with steam utilization

Info

Publication number: WO2023167922A1
Application number: PCT/US2023/014272
Authority: WO
Inventors: Liang-Shih Fan; Qiaochu Zhang
Original assignee: Ohio State Innovation Foundation
Priority date: 2022-03-01
Filing date: 2023-03-01
Publication date: 2023-09-07

Abstract

An exemplary system may be configured to provide steam. Exemplary systems may comprise a water source in fluid communication with a pump. The pump may be in fluid communication with a first heat exchanger, which may be in fluid communication with a power generator, which may be a turbine. The power generator may be in fluid communication with a second heat exchanger. An outlet of the second heat exchanger may be in fluid communication with a reactor system.

Description

ELECTRIC POWER CO-GENERATION FOR CHEMICAL AND PHYSICAL PROCESSES WITH STEAM UTILIZATION CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This application claims priority to U.S. Provisional Patent Application No. 63/315,173, filed on March 1, 2022, the entire contents of which are hereby incorporated by reference. FIELD OF THE INVENTION [0002] The present disclosure relates to systems and methods for electric power co- generation using steam. Exemplary electric power co-generation modules may be integrated into chemical and physical processes. INTRODUCTION [0003] The combustion of fossil fuels has been the primary resource for the generation of thermal energy for many industries, such as power generation and chemical production. However, there is concern regarding fossil fuels being nonrenewable. Currently, efforts have been made to enhance energy conversion efficiency in various technology sectors. If energy conversion efficiency is desired, an enhanced heat-to-electricity conversion needs to be developed. [0004] Electricity can be generated from various sources such as, but not limited to, hydropower, wind power, solar power, combustion of fossil energy, nuclear, and biomass energy. Among these energy sources, the majority of electric power (i.e., over 60%) is currently generated from fossil energy. Regarding methods of electricity generation, steam turbines are used to generate the majority of the world’s electricity and accounted for about 44% of electricity generation in the United States in 2020. As will be described in detail below, various energy sources can be used to provide heat for steam generation, including fossil energy, nuclear, geothermal, solar thermal electric power plants, waste incineration plants, etc. [0005] During the operation of the steam-electric power process, the Rankine cycle indicates the basic principle of electricity production and has been applied to most heat-to-electric power systems. The Rankine cycle is a thermodynamic cycle allowing mechanical work to be extracted from a fluid as it moves between a heat source and a heat sink. A typical working fluid in the Rankine cycle is steam. The pumped water is converted to high-pressure steam to power a power generator (i.e., turn the blades of a turbine), the high-pressure steam is created by providing heat to the water via a heat exchanger (i.e., a boiler). After the high-pressure steam passes through the turbine to produce electricity, the steam is condensed back into water and cooled before entering the pump to complete the cycle. [0006] Steam is a substantial working fluid in the Rankine cycle to generate electricity and essential raw material for industrial chemical or physical processes. Chemical or physical prosses include, but are not limited to, steam methane reforming (SMR) systems, auto-thermal reforming (ATR) systems, water gas shift (WGS) systems, integrated gasification combined cycle (IGCC) systems, steam cracking systems, petroleum refining systems, enhanced oil recovery systems, chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and chemical looping combustion combined with steam methane reforming (CLC-SMR) systems. [0007] Reforming reactions for steam methane reforming (SMR) and auto-thermal recovery systems are provided below: SMR reaction: CH₄ + H₂O = CO + 3H₂ (1) ATR reaction: 4CH₄ +O₂ + 2H₂O = 10H₂ + 4CO (2) [0008] In the operation of the water gas shift (WGS) system, carbon monoxide (CO) reacts with steam (H₂O) to generate carbon dioxide (CO₂) and hydrogen gas (H₂). Water gas shift (WGS) system reactions can produce both hydrogen gas (H₂) with carbon monoxide (CO) and can be applied to improve the H₂/CO ratio as required in various downstream processes and/or products. During the operation of water gas shift (WGS) systems, a considerable amount of steam is required to push the reaction forward based on Le Chatelier’s principle to convert CO and H₂O into H₂ and CO₂. A water gas shift (WGS) reactor reaction is shown below. WGS reaction: CO + H₂O = CO₂ + H₂ (3) [0009] Coal gasification is a relatively clean pathway for converting coal into fuel gas by partially oxidizing coal with air, oxygen, steam, or carbon dioxide. The fuel gas produced can be further prepared for combustion to provide heat for the gas turbine and steam turbine to generate electricity in an integrated gasification combined cycle (IGCC) system. A coal gasification reaction is shown below: Coal gasification:

[0010] Steam cracking is a petrochemical process for saturated hydrocarbons to break down into smaller hydrocarbons. During the operation of the steam cracking process, a hydrocarbon with a high molecular weight is diluted with steam and heated in a furnace without oxygen. [0011] Petroleum refining processes are a chemical engineering process for transforming crude oil into various products, including liquefied petroleum gas (LPG), gasoline or petrol, kerosene, jet fuel, diesel oil, and fuel oils. In this process, steam distillation can process the reduced crude to provide lubricating oil fractions or asphalt base stocks. [0012] In the oil industry, steam injection has become an increasingly common method of extracting heavy crude oil to enhance oil recovery as the primary type of thermal stimulation of oil reservoirs. [0013] Chemical looping hydrogen generation (CLHG) systems and chemical looping combustion combined with steam methane reforming (CLC-SMR) systems are hydrogen production processes that employ chemical looping technology and require steam as the primary reactant. The chemical looping system uses a solid oxygen carrier as a medium to transfer the molecular oxygen from steam or air to the fuel to generate heat or chemical products. Both systems do not require direct contact between fuel and steam or air in the chemical looping systems. Carbon dioxide (CO₂) is generated by the oxidization of an oxygen carrier and can be easily separated and captured from the system. In a chemical looping hydrogen generation combined with a 3-reactor system (CLHG-3R), the natural gas feedstock is capable of reducing the oxygen carrier to low-price forms in the reducer reactor. Steam is injected into an oxidizer reactor to react with reduced iron oxide particles (Fe/FeO) to generate hydrogen. Finally, the oxygen carrier is regenerated with the air in the combustor. Reducer, oxidizer, and combustor reactor reactions are shown below: Reducer reactions:CH₄ + Fe₂O₃ → CO₂ + H₂O + Fe/FeO (5) Oxidizer reactions: Fe/FeO +H₂O → Fe₃O4 +H₂ (6) Combustor reactions: Fe₃O₄ + O₂ → Fe₂O₃ (7) [0014] In the operation of the chemical looping combustion combined with steam methane reforming (CLC-SMR) system, the chemical looping combustion (CLC) system replaces a traditional furnace to supply heat for the steam reformer. Similar to the steam methane reforming (SMR) system, the chemical looping combustion combined with steam methane reforming (CLC-SMR) system also requires plenty of steam to promote the reforming reaction. [0015] Reducer and combustor reactor reactions in the CLC section are shown below: Reducer reactions: CH₄ + Fe₂O₃ → CO₂ + H₂O + Fe/FeO (8) Combustor reactions: Fe/FeO + O₂ → Fe₂O₃ (9) SUMMARY OF THE INVENTION [0016] Generally, the instant disclosure relates to systems and methods configured to provide steam to a reactor system. [0017] In one aspect, a system for operating a system to provide steam is disclosed. The example system may include a water source in fluid communication with a pump; a first heat exchanger in fluid communication with the pump; a power generator in fluid communication with the first heat exchanger, the power generator configured to generate electric power using fluid from the first heat exchanger; a second heat exchanger in fluid communication with the power generator; and a reactor system in fluid communication with an outlet of the second heat exchanger. [0018] In another aspect, a method for operating a system is disclosed. The example method may include increasing a pressure of water from a water source with a pump; providing the pressurized water from the pump to a first heat exchanger; in the first heat exchanger, heating the pressurized water to generate pressurized steam; providing the pressurized steam to a power generator; with the power generator, producing electricity using the pressurized steam; providing an outlet stream of the power generator to a second heat exchanger, in the second heat exchanger, adjusting a temperature of the outlet stream of the power generator; and providing an outlet stream of the second heat exchanger to a reactor system. [0019] There is no specific requirement that a material, technique, or method relating to power co-generation include all of the details characterized herein, in order to obtain some benefit according to the present disclosure. Thus, the specific examples characterized herein are meant to be exemplary applications of the techniques described, and alternatives are possible. BRIEF DESCRIPTION OF THE DRAWINGS [0020] FIG.1 shows a temperature-entropy diagram of a conventional Rankine Cycle. [0021] FIG.2 shows a block diagram of a conventional Rankine Cycle process with steam utilization. [0022] FIG.3 shows a temperature-entropy diagram for exemplary systems. [0023] FIG.4 shows a block diagram of an exemplary electric power co-generation module in fluid communication with a chemical or physical process. [0024] FIG.5 shows a block diagram of an exemplary electric power co-generation module in fluid communication with chemical or physical processes with combustion streams in fluid communication with one or more heat exchangers. [0025] FIG.6A shows a block diagram of a conventional steam methane reforming (SMR) system. FIG.6B shows a block diagram of an exemplary electric power co-generation module integrated into a steam methane reforming (SMR) system. [0026] FIG.7A shows a block diagram of a conventional chemical looping combustion combined with a steam methane reforming (CLC-SMR) system. FIG.7B shows a block diagram of an exemplary electric power co-generation module integrated into a chemical looping combustion combined with a steam methane reforming (CLC-SMR) system. [0027] FIG.8A shows a block diagram of a conventional chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) system. FIG.8B shows a block diagram of an exemplary electric power co-generation module integrated into chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) system. DETAILED DESCRIPTION [0028] Systems, methods and techniques disclosed herein may provide enhanced heat-to- electricity energy conversion for physical processes and/or chemical processes. [0029] FIG.1 shows the temperature-entropy diagram of a Rankine Cycle, FIG.2 shows the process diagram for the Rankine cycle shown in FIG.1, and both figures are discussed below. FIG.1 shows water source 202 is first pressurized through pump 204; this is shown in FIG.1 as the connection of points A → B. The pressurized water from pump 204 is heated to generate high-pressure steam in boiler 206, shown in FIG.1 as the connection of points B → C. The high- pressure steam enters turbine 208 to produce electricity, shown in FIG.1 as the connection of points C → D. Condenser 210 condenses the exhaust steam from turbine 208 into liquid water for, at least, another iteration of the described cycle, shown in the connections of points D → A. [0030] During the operation of industrial processes, different types of turbines are applied depending on the pressure of steam, which include the high-pressure (HP) turbine, the intermediate-pressure (IP) turbine, and the low-pressure (LP) turbine. As will be described below, HP and IP turbines are applied and integrated into exemplary electric power co- generation modules, where exemplary electric power co-generation modules enhance the thermal efficiency for electricity generation. [0031] The efficiency of the existing Rankine cycle is limited due, in part, to a large amount of heat loss in the condensation of the low-temperature steam of the condenser, thereby causing the actual thermal efficiency to be less than 60% for typical power systems. [0032] Exemplary systems and methods disclosed herein may utilize exhaust steam after a turbine as feedstock for industrial processes. Heat loss from the steam condensation is avoided, thereby enhancing the thermal energy conversion efficiency. By combining steam turbines with chemical and/or physical processes that originally require steam as a feedstock, exemplary systems can become more energy efficient for electric power generation. [0033] In existing systems, the Rankine cycle in its operation of electricity generation in a chemical or physical process system is not directly linked to the functions of other system components except a heat exchanger. However, exemplary systems and methods for power generation disclosed herein provide for the mass transfer of, at least, steam to other system components, forming an integrated operating system. I. Definitions [0034] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art. In case of conflict, the present document, including definitions, will control. Example methods and materials are described below, although methods and materials similar or equivalent to those described herein can be used in practice or testing of the present disclosure. All publications, patent applications, patents and other references mentioned herein are incorporated by reference in their entirety. The materials, methods, and examples disclosed herein are illustrative only and not intended to be limiting. [0035] The terms “comprise(s),” “include(s),” “having,” “has,” “can,” “contain(s),” and variants thereof, as used herein, are intended to be open-ended transitional phrases, terms, or words that do not preclude the possibility of additional acts or structures. The singular forms “a,” “an” and “the” include plural references unless the context clearly dictates otherwise. The present disclosure also contemplates other embodiments “comprising,” “consisting of” and “consisting essentially of,” the embodiments or elements presented herein, whether explicitly set forth or not. [0036] The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (for example, it includes at least the degree of error associated with the measurement of the particular quantity). The modifier “about” should also be considered as disclosing the range defined by the absolute values of the two endpoints. For example, the expression “from about 2 to about 4” also discloses the range “from 2 to 4.” The term “about” may refer to plus or minus 10% of the indicated number. For example, “about 10%” may indicate a range of 9% to 11%, and “about 1” may mean from 0.9-1.1. Other meanings of “about” may be apparent from the context, such as rounding off, so, for example “about 1” may also mean from 0.5 to 1.4. [0037] Definitions of specific functional groups and chemical terms are described in more detail below. For purposes of this disclosure, the chemical elements are identified in accordance with the Periodic Table of the Elements, CAS version, Handbook of Chemistry and Physics, 75^th Ed., inside cover, and specific functional groups are generally defined as described therein. [0038] For the recitation of numeric ranges herein, each intervening number there between with the same degree of precision is explicitly contemplated. For example, for the range of 6-9, the numbers 7 and 8 are contemplated in addition to 6 and 9, and for the range 6.0-7.0, the numbers 6.0, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 6.8, 6.9, and 7.0 are explicitly contemplated. II. Exemplary Electric Power Co-Generation Modules [0039] Various chemical or physical processes may include exemplary electric power co- generation modules to utilize exhaust steam as a feedstock, thereby allowing the various chemical or physical processes to be more energy efficient for electric power generation. A. Exemplary Temperature-Entropy Diagram [0040] FIG.3 shows an exemplary temperature-entropy diagram of the exemplary electric power co-generation module. As shown in FIG.3, the connection of points A → B → C → D illustrates the temperature/entropy change in conventional steam utilization processes, as described above. [0041] As shown in FIG.3, the connection of points A → B’ → C’ → C → D illustrates the temperature/entropy change for exemplary electric power co-generation modules. The integration of an exemplary power generator provides for an enhanced temperature/entropy change. As shown in FIG.3, the connection of A → B’ shows a water source being pumped at a high pressure. The connection of points B’ → C’ shows the pressurized stream being heated by an exemplary first heat exchanger. The connection of points C’ → C shows the temperature and pressure decrease of steam as the steam powers an exemplary power generator to generate electric power. The connection of points C → D shows a fluid outlet of the power generator is in fluid communication with a second heat exchanger. The connection of points C → D indicates that the temperature of the steam is adjusted, as needed, to provide the steam at a temperature as required for the inlet to a chemical or physical process. B. Exemplary Electric power co-generation module [0042] FIG.4 shows an exemplary electric power co-generation module 400. As shown, exemplary electric power co-generation module 400 includes water source 402, pump 404, first heat exchanger 406, power generator 408, and second heat exchanger 410. Other embodiments may include more or fewer components. An outlet of the second heat exchanger 410 is in fluid communication with chemical or physical process 412. [0043] Exemplary water source 402 is in fluid communication with exemplary pump 404. Exemplary pump 404 is in fluid communication with exemplary first heat exchanger 406. Exemplary first heat exchanger 406 is in fluid communication with exemplary power generator 408. Exemplary power generator 408 is in fluid communication with exemplary second heat exchanger 410. [0044] Exemplary electric power co-generation modules may be configured to operate in continuous operation, batch operation, or a semi-batch operation. [0045] Exemplary pump 404 pressurizes the water from exemplary water source 402 and provides the pressurized water to exemplary first heat exchanger 406. Exemplary pump 404 may comprise one or more inlets, where the one or more inlets of exemplary pump 404 may be configured to receive water from one or more water source 402. Exemplary pump 404 may comprise one or more outlets, where the one or more outlets may be in fluid communication with exemplary heat exchanger 406. [0046] Exemplary electric power co-generation module 400 may include one or more exemplary heat exchangers or a plurality of exemplary heat exchangers. In some instances, an exemplary heat exchanger may be a heater or boiler. In some instances, exemplary heat exchangers may be a condenser. Exemplary heat exchangers 406 and 410 transfer heat from a hot inlet stream to a cold inlet stream, thereby producing a cooled hot output stream and a heated cold output stream. [0047] Exemplary first heat exchanger 406 generates steam from water received from pump 402. Exemplary first heat exchanger 406 is configured to provide generated steam to an inlet of exemplary power generator 408. First heat exchanger 406 may have various internal configurations. [0048] In various embodiments, first heat exchanger 406 comprises a first hot stream inlet, a first hot stream outlet, a first cold stream inlet, and a first cold stream outlet. In various embodiments, first heat exchanger 406 receives a first hot stream input from a downstream operation. In various embodiments, first heat exchanger 406 receives a first cold stream input that comprises water from pump 404. [0049] Exemplary power generator 408 produces electricity using steam received from exemplary first heat exchanger 406. Exemplary power generator 408 may include impulse turbines or reaction turbines. Exemplary power generator 408 may comprise one or more inlets to receive an inlet stream from exemplary first heat exchanger 406. Exemplary power generator 408 may comprise one or more outlets, where the one or more outlets may be in fluid communication with exemplary heat exchanger 410. [0050] Exemplary second heat exchanger 410 operates to heat or cool a temperature of the outlet stream from exemplary power generator 408. Exemplary second heat exchanger 410 may be configured such that the temperature of the outlet stream of exemplary second heat exchanger 410 matches the temperature requirements of the feedstock of chemical or physical process 412. [0051] In various embodiments, second heat exchanger 410 comprises a second hot stream inlet, a second hot stream outlet, a second cold stream inlet, and a second cold stream outlet. In various embodiments, second heat exchanger 410 receives a second hot stream input from a downstream operation. In various embodiments, second heat exchanger 410 receives a second cold stream input that comprises steam from power generator 408. [0052] As shown, exemplary second heat exchanger 410 is in fluid communication with exemplary power generator 408 and chemical or physical process 412. Exemplary chemical or physical processes 412 may comprise a reactor system. Exemplary reactor systems may include a steam methane reforming (SMR) system, an auto-thermal reforming (ATR) system, a water-gas shift (WGS) system, an integrated gasification combined cycle (IGCC) system, a steam cracking system, a petroleum refining reactor system, an enhanced oil recovery system, a chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and a chemical looping combustion combined with steam methane reforming (CLC-SMR) system. C. Exemplary Electric power co-generation module with Combustion Streams [0053] FIG.5 shows an exemplary electric power co-generation module 500 with combustion streams 502 and 504. The exemplary electric power co-generation module 500 includes water source 402, pump 404, first heat exchanger 406, power generator 408, and second heat exchanger 410, various aspects of which are discussed above with reference to FIG.4. As shown, an outlet of the second heat exchanger is in fluid communication with chemical or physical process 412. Other embodiments may include more or fewer components. [0054] Stream 502 comprises a combustion stream from chemical or physical process 412. Stream 504 comprises a combustion stream from chemical or physical process 412. Stream 506 is an output stream from first heat exchanger 406. Stream 508 is an output stream from second heat exchanger 410. Stream 510 is a product stream from chemical or physical process 412. [0055] In various embodiments, chemical or physical process 412 generates combustion stream 502 by combusting natural gas or recycled tail gas. In various embodiments, combustion stream 502 is provided as a hot stream input to first heat exchanger 406. [0056] In various embodiments, chemical or physical process 412 generates combustion stream 504 by combusting natural gas or recycled tail gas from. In various embodiments, combustion stream 504 is provided as a hot stream input to second heat exchanger 410. III. Exemplary Methods of Operating Electric Power Co-Generation Modules [0057] Exemplary methods of operating electric power co-generation modules may comprise various operations. For instance, an exemplary method of operating an electric power co- generation module may comprise increasing a pressure of water from a water source with a pump, providing the pressurized water from the pump to a first heat exchanger, in the first heat exchanger, heating the pressurized water to generate pressurized steam, providing the pressurized steam to a power generator, with the power generator, producing electricity using the pressurized steam, providing an outlet stream of the power generator to a second heat exchanger, adjusting a temperature of the outlet stream of the power generator, and providing an outlet stream of the second heat exchanger to a reactor system. Other embodiments may comprise more or fewer operations. [0058] An exemplary method may begin by increasing a pressure of water from a water source with a pump. An exemplary pump may operate to increase the water pressure to any suitable pressure. In various embodiments, an exemplary pump increases a pressure of the water to a pressure between 1 MPa to 20 MPa. In various embodiments, the pressurized water from an exemplary pump has a pressure between 1 MPa to 20 MPa; 1 MPa to 10 MPa; 3 MPa to 19 MPa; 3 MPa to 18 MPa; 4 MPa to 18 MPa; 4 MPa to 16 MPa; 5 MPa to 16 MPa; 5 MPa to 15 MPa; 6 MPa to 15 MPa; 7 MPa to 14 MPa; 8 MPa to 13 MPa; 9 MPa to 12 MPa; 9 MPa to 11 MPa. In various embodiments, the pressurized water generated by an exemplary pump has a pressure of no less than 1 MPa; no less than 3MPa; no less than 4 MPa; no less than 6 MPa; no less than 8 MPa; no less than 10 MPa; no less than 12 MPa; no less than 14 MPa; no less than 16 MPa; or no less than 18 MPa. In various embodiments, the pressurized water generated by an exemplary pump has a pressure of no greater than 20 MPa; no greater than 19 MPa; no greater than 17 MPa; no greater than 15 MPa; no greater than 13 MPa; no greater than 11 MPa; no greater than 9 MPa; no greater than 7 MPa; no greater than 5 MPa; no greater than 3 MPa, or no greater than 1 MPa. [0059] Exemplary methods may comprise providing the pressurized water from a pump to a first heat exchanger. Exemplary first heat exchangers are configured to heat the pressurized water to generate pressurized steam. In various embodiments, an exemplary first heat exchanger may be configured to heat the pressurized water to a temperature between 100 °C to 1000 °C. In various embodiments, the pressurized stream generated by the first heat exchanger has a temperature between 100 °C to 1000 °C; 250 °C to 1000 °C; 350 °C to 1000 °C; 100 °C to 500 °C; 500 °C to 1000°C; 500 °C to 950 °C; 500 °C to 900 °C; 550 °C to 900 °C; 550 °C to 850 °C; 600 °C to 850 °C; 600 °C to 800 °C; 650 °C to 800 °C; 650 °C to 750 °C. In various embodiments, the pressurized steam from an exemplary first heat exchanger has a temperature of no less than 100 °C; no less than 200 °C; no less than 300 °C; no less than 400 °C; no less than 500 °C; no less than 550 °C; no less than 600 °C; no less than 650 °C; no less than 700 °C; no less than 750 °C; no less than 800 °C; no less than 850 °C; no less than 900 °C; no less than 950 °C; no less than 1000°C. In various embodiments, the pressurized steam generated by an exemplary first heat exchanger has a temperature of no greater than 1000 °C; no greater than 975 °C; no greater than 925 °C; no greater than 875 °C; no greater than 825 °C; no greater than 775 °C; no greater than 725 °C; no greater than 675 °C; no greater than 625 °C; no greater than 575 °C; no greater than 525 °C; no greater than 500 °C; no greater than 400 °C; no greater than 300 °C; or no greater than 250 °C or no greater than 150 °C. [0060] Exemplary methods may comprise an exemplary first heat exchanger, in fluid communication with an exemplary power generator, providing pressurized steam to exemplary power generator. [0061] Exemplary methods may comprise a power generator producing electricity using the pressurized steam. Various examples and aspects of exemplary power generators are discussed in greater detail above and below. [0062] In various embodiments, an exemplary power generator may produce between 0.5 MW to 5 MW of electricity. In various embodiments, an exemplary power generator may produce between 0.5 MW to 5 MW of electricity; 0.5 MW to 4.5 MW; 1 MW to 4.5 MW; 1 MW to 4 MW; 1 MW to 3.5 MW; 1 MW to 3 MW; 1.5 MW to 3 MW; or about 2 MW. In various embodiments, an exemplary power generator may produce no less than 0.5 MW of electricity; no less than 1 MW; no less than 1.5 MW; no less than 2 MW; no less than 2.5 MW; no less than 3 MW; no less than 3.5 MW; no less than 4 MW; or no less than 4.5 MW. IN various embodiments, an exemplary power generator may produce no greater than 5 MW of electricity; no greater than 4.5 MW; no greater than 4 MW; no greater than 3.5 MW; no greater than 3 MW; no greater than 2.5 MW; no greater than 2 MW; no greater than 1.5 MW; or no greater than 1 MW. [0063] Exemplary methods may comprise an exemplary power generator, in fluid communication with an exemplary second heat exchanger, providing an outlet stream to exemplary second heat exchanger. In various embodiments, an outlet stream of an exemplary power generator may have a pressure between 0.005 MPa to 6 MPa. In various embodiments, the outlet stream of an exemplary power generator may have a pressure between 0.005 MPa to 6 MPa; 0.005 to 3 MPa; 0.2 MPa to 5 MPa; 0.2 MPa to 4.5 MPa; 0.5 MPa to 4.5 MPa; 0.5 MPa to 4 MPa; 1 MPa to 4 MPa; 1 MPa to 3.5 MPa; 1.5 MPa to 3.5 MPa; 1.5 MPa to 3 MPa; or 2 M MPa to 3 MPa. In various embodiments, the outlet stream from an exemplary power generator may have a pressure of no less than 0.005 MPa; no less than 0.01 MPa; no less than 0.1 MPa; no less than 0.2 MPa; no less than 0.5 MPa; no less than 1 MPa; no less than 1.5 MPa; no less than 2 MPa; no less than 2.5 MPa; no less than 3 MPa; no less than 3.5 MPa; no less than 4 MPa; or no less than 4.5 MPa. In various embodiments, an outlet stream from an exemplary power generator may have a pressure of no greater than 6 MPa; no greater than 5.5 MPa; no greater than 5 MPa; no greater than 4.75 MPa; no greater than 4.25 MPa; no greater than 3.75 MPa; no greater than 3.25 MPa; no greater than 2.75 MPa; no greater than 2.25 MPa; no greater than 1.75 MPa; no greater than 1.25 MPa; no greater than 0.75 MPa; no greater than 0.25 MPa; no greater than 0.2 MPa; no greater than 0.15 MPa; or no greater than 0.01 MPa. [0064] In various embodiments, an outlet stream of an exemplary power generator may have a temperature between 100 °C to 700°C. In various embodiments, an outlet stream from an exemplary power generator may have a temperature between 100 °C to 700 °C; 100 °C to 400 °C; 400 °C to 700 °C; 100 °C to 575 °C; 375 °C to 575°C; 375 °C to 550 °C; 400 °C to 550 °C; 400 °C to 525 °C; 450 °C to 525 °C or 450 °C to 500 °C. In various embodiments, an outlet stream from an exemplary power generator may have a temperature of no less than 100 °C; no less than 150 °C; no less than 200 °C; no less than 250 °C; no less than 350 °C; no less than 400 °C; no less than 450 °C; no less than 500 °C; no less than 550 °C; no less than 600 °C; or no less than 650 °C. In various embodiments, an outlet stream from an exemplary power generator may have a temperature of no greater than 700 °C; no greater than 650 °C; no greater than 600 °C; no greater than 575 °C; no greater than 525 °C; no greater than 475 °C; no greater than 425 °C; no greater than 375 °C, no greater than 325 °C; no greater than 275 °C; no greater than 225 °C; no greater than 175 °C; or no greater than 125 °C. [0065] Exemplary methods may comprise adjusting the temperature of the outlet stream of exemplary power generator with a second heat exchanger. [0066] An outlet stream of an exemplary second heat exchanger may have a temperature between 100 °C to 1000 °C. In various embodiments, an outlet stream from an exemplary second heat exchanger may have a temperature between 100 °C to 1000 °C; 100 °C to 900 ; 100 °C to 800 °C; 200 °C to 800 °C; 200 °C to 600 °C; 250 °C to 600 °C; 300 °C to 600 °C; 350 to 575 °C; 375 °C to 575°C; 375 °C to 550 °C; 400 °C to 550 °C; 400 °C to 525 °C; 450 °C to 525 °C or 450 °C to 500 °C. In various embodiments, an outlet stream from an exemplary second heat exchanger may have a temperature of no less than 100 °C; no less than 200 °C; no less than 250 °C; no less than 350 °C; no less than 400 °C; no less than 450 °C; no less than 500 °C; no less than 550 °C; no less than 650 °C; no less than 750 °C; no less than 800 °C; no less than 850 °C; no less than 900 °C; or no less than 950 °C. In various embodiments, an outlet stream from an exemplary second heat exchanger may have a temperature of no greater than 1000 °C; no greater than 975 °C; no greater than 925 °C; no greater than 875 °C; no greater than 825 °C; no greater than 775 °C; no greater than 725; no greater than 675 °C; no greater than 625 °C; no greater than 600 °C; no greater than 575 °C; no greater than 525 °C; no greater than 475 °C; no greater than 425 °C; no greater than 375 °C; no greater than 325 °C; no greater than 275 °C; no greater than 225 °C; no greater than 175 °C; or no greater than 125 °C. [0067] Exemplary methods may comprise providing an outlet stream of an exemplary second heat exchanger to a chemical or physical process. III. Exemplary Chemical or Physical Systems Incorporating Exemplary Electric power co-generation module [0068] Various chemical or physical processes may incorporate exemplary electric co- generation modules that provide a steam feedstock to exemplary chemical or physical systems. As will be discussed in greater detail below, exemplary electric co-generation modules may be incorporated into, for instance, steam methane reforming (SMR) systems, chemical looping combustion combined with steam methane reforming (CLC-SMR) systems, and chemical looping hydrogen generation in a 3-reactor system (CLHG-3R). A. Steam Methane Reforming Systems [0069] As shown in FIG.6A, the methane reforming process includes three main steps: syngas (with carbon monoxide (CO) and H₂ as main components) generation, water-gas shift (WGS) reaction, and hydrogen purification. Other steps such as desulfurization and heat recovery may be necessary to maintain the quality of hydrogen produced and the efficiency of the process operation. In this regard, the natural gas containing H₂S can be desulfurized through a ZnO bed and then enters a reformer for syngas generation. In the second step, the syngas then goes through the water-gas shift reaction that includes the high-temperature and low-temperature shifts. In the water-gas shift step, the CO is converted to CO₂ through its reaction with steam to produce hydrogen. The last step of the process is pressure swing adsorption (PSA) to separate and purify the hydrogen product from the water-gas shift step. The modern methane reforming process is to be operated with CO₂ capture in which CO₂ is removed from the syngas after the WGS reaction and the stack gas generation from the boiler/furnace combustion of methane with amine scrubbing (MDEA/MEA amine scrubber) for acid gas removal (AGR). The recycled fuel gas is also combusted to provide the endothermic heat required for the natural gas reforming reaction and steam generation. [0070] FIG.6B shows an exemplary steam methane reforming (SMR) system integrated with an exemplary electric power co-generation module with combustion streams. [0071] During the operation of the exemplary steam methane reforming (SMR) system, steam is injected into the steam reformer and the downstream WGS reactor. In various embodiments, steam produced by an exemplary first heat exchanger (i.e., HRSG) can be utilized to power an exemplary power generator (i.e., high-pressure (HP) turbine) to produce electricity. [0072] Exemplary pumps increase the pressure of the water. Exemplary pressure increases are discussed in greater detail above. [0073] In various embodiments, exemplary first heat exchanger increases the temperature of the water, where the exemplary first heat exchanger converts the input pressurized water to pressurized steam. [0074] During operation of exemplary steam methane reforming (SMR) system, heat is provided by one or more combustion streams from combustion of natural gas or recycled tail gas in the exemplary steam methane reforming (SMR) system. [0075] The pressurized steam may be fed to the inlet of the exemplary power generator, where the pressurized steam powers the exemplary power generator, and the exemplary power generator produces electricity. [0076] In various embodiments, the pressure of the outlet of the exemplary power generator decreases. Exemplary temperatures of the outlet of the exemplary power generator are discussed in greater detail above. [0077] In various embodiments, the exemplary power generator is in fluid communication with an exemplary second heat exchanger. [0078] In various embodiments, the temperature of the outlet of the exemplary second heat exchanger has a temperature as required for the feedstock into the inlet of the exemplary steam methane reforming (SMR) system. B. Chemical Looping Combustion Combined with Steam Methane Reforming System (CLC-SMR) [0079] The conventional CLC-SMR process, as shown in FIG.7A, utilizes natural gas as the feedstock and produces hydrogen. The process is composed of two sections – CLC and SMR. The SMR reactor tubes are embedded in the CLC combustor (or reducer) so that the exothermic oxygen carrier regeneration reaction can efficiently provide the heat required by the endothermic reforming reaction. [0080] In the first section, Chemical looping combustion (CLC) is employed for power generation from carbonaceous fuels with in-situ carbon capture. The CLC section is divided into two reactors: the reducer reactor and the combustor reactor. In the reducer reactor, the oxygen carrier transfers lattice oxygen to the fuel while getting reduced to lower oxidation states. In the combustor reactor, the reduced oxygen carrier is then oxidized by air, releasing a large amount of heat. The overall reaction is the same as direct combustion. By splitting the reaction into two separate steps, the CLC process enables in-situ CO₂ capture and eliminates the need for downstream CO₂ capture processes, which increases process efficiency and energy output. [0081] The SMR section is the same as the conventional system. The recycled flue gas from PSA is injected as the feedstock of the CLC reducer, while additional natural gas is supplied to provide extra heat. The heat requirement for the system decreases significantly compared with traditional SMR because of the removal of the MDEA unit, which requires extra steam for CO₂ capture. During the reaction between the flue gas and oxygen carrier, the reducing gas is fully oxidized into CO₂ and H₂O, which can be readily captured after condensing water. [0082] FIG.7B shows an exemplary chemical looping combustion combined with steam methane reforming (CLC-SMR) system integrated with an exemplary electric power co- generation module. [0083] During the operation of the exemplary chemical looping combustion combined with steam methane reforming (CLC-SMR) systems, steam is injected into an oxidizer reactor during oxidization reactions. In various embodiments, steam produced by an exemplary first heat exchanger (i.e., heater) can be utilized to power an exemplary power generator (i.e., high- pressure (HP) turbine) to produce electricity. [0084] In various embodiments, exemplary pumps increase the pressure of the water. In various embodiments, exemplary first heat exchanger (i.e., heater) increases the temperature of the water, where the exemplary first heat exchanger (i.e., heater) converts the inlet pressurized water to pressurized steam in the output stream. [0085] In various embodiments, the pressurized steam is fed to the inlet of the exemplary power generator, where the pressurized steam powers the exemplary power generator, and the exemplary power generator produces electricity. [0086] In various embodiments, the exemplary power generator is in fluid communication with an exemplary second heat exchanger. In various embodiments, the temperature of the outlet of the exemplary second heat exchanger has a temperature as required for the feedstock into the inlet of the exemplary chemical looping combustion combined with steam methane reforming (CLC-SMR) system. C. Chemical Looping Hydrogen Generation in a 3-Reactor System [0087] Figure 8A describes a chemical looping hydrogen generation in a 3-reactor (CLHG- 3R) system, which includes three key operating reactors, namely a reducer reactor, an oxidizer reactor, and a combustor reactor along with riser, standpipe, and ancillary equipment such as the pumps, the air compressor, and the heat exchangers. In the reducer reactor, the natural gas is oxidized to CO₂ and H₂O by the oxygen carrier particles, made up of hematite (Fe₂O₃) and inert material. Meanwhile, hematite in the oxygen carrier particles is reduced to a mixture of iron (Fe) and iron (II) oxide (FeO). In the oxidizer reactor, the steam is converted to hydrogen by reacting with reduced oxygen carrier particles while the reduced oxygen carrier particles are oxidized to a mixture of magnetite (Fe₃O₄) and FeO. Finally, preheated air is used to regenerate the mixture back to hematite in a fluidized bed combustor. The regenerated particles then circulate through a riser to the reducer. The CLHG-3R process can be operated under ambient or elevated pressure conditions. [0088] FIG.8B shows an exemplary chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) integrated with an exemplary electric power co-generation module. [0089] During the operation of the exemplary chemical looping hydrogen generation in a 3- reactor system (CLHG-3R), a considerable amount of steam is injected into the oxidizer reactor during oxidization reactions. In various embodiments, steam produced by an exemplary first heat exchanger (i.e., heater #2) can be utilized to power an exemplary power generator (i.e., IP turbine) to produce electricity. [0090] In various embodiments, exemplary pumps may increase the pressure of the water to no greater than 4.5 MPa (i.e., 50 bar). [0091] In various embodiments, exemplary first heat exchanger (i.e., heater #2) may increase the temperature of the water to no greater than 650 °C, where the exemplary first heat exchanger (i.e., heater #2) converts the inlet pressurized water to pressurized steam in the output stream. [0092] In various embodiments, the pressurized steam is fed to the inlet of the exemplary power generator, where the pressurized steam powers the exemplary power generator, and the exemplary power generator produces electricity. [0093] In various embodiments, the pressure of the outlet of the exemplary power generator decreases to no greater than 0.75 MPa. [0094] In various embodiments, the temperature of the outlet of the exemplary power generator is no greater than 350 °C. [0095] In various embodiments, the exemplary power generator is in fluid communication with an exemplary second heat exchanger. [0096] In various embodiments, the outlet of the exemplary second heat exchanger has a temperature of no greater than 500 °C. In various embodiments, the temperature of the outlet of the exemplary second heat exchanger has a temperature as required for the feedstock into the inlet of the exemplary chemical looping hydrogen generation in a 3-reactor system (CLHG-3R). [0097] The present disclosure is not limited to the addition of a single power generator and a single heat exchanger to exemplary systems. In various embodiments, one or more power generators and/or one or more heat exchangers can be integrated and combined into an existing exemplary system with the same methods to produce electricity and enhance the thermal energy efficiency. In various embodiments, the combination of HP and IP turbines are added to the chemical looping hydrogen generation (CLHG) system. Although only an HP and an IP turbine are shown in FIG.8, an LP turbine can also be combined with the existing chemical process system for electricity co-generation. [0098] The exemplary chemical or physical process systems are not limited to what is described above. In various embodiments, the thermal efficiency of other processes with steam utilization can be improved by integrating exemplary electric power co-generation modules to existing systems such as, but not limited to, auto-thermal reforming (ATR) systems, water gas shift (WGS) systems, integrated gasification combined cycle (IGCC) systems, steam cracking systems, and petroleum refining enhanced oil recovery systems. IV. Computational Evaluations [0099] Various aspects of the exemplary steam methane reforming (SMR) system shown in FIG.6, chemical looping combustion combined with steam methane reforming (CLC-SMR) system shown in FIG.7, and chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) shown in FIG.8, were computationally evaluated using ASPEN Plus V11 software, and the results are discussed below. A. Natural Gas Consumption and Electric Power Output [00100] Natural gas consumption and electric power output were calculated for the exemplary systems shown in FIG.6, FIG.7, and FIG.8. [00101] The exemplary steam methane reforming (SMR) system consumed 3945.5 kg/hr natural gas, thereby providing extra heat input into the exemplary SMR system. The exemplary power generator in the SMR system produced 1.69 MW of electric power output. [00102] The exemplary chemical looping combustion combined with steam methane reforming (CLC-SMR) system consumed 3311.6 kg/hr natural gas, thereby providing extra heat input into the exemplary SMR system. The exemplary power generator in the CLC-SMR system produced 1.69 MW of electric power output. [00103] The exemplary chemical looping hydrogen generation in a 3-reactor system (CLHG- 3R) consumed 3457 kg/hr natural gas, thereby providing an extra heat input of 2.48 MW into the exemplary SMR system. The exemplary power generator in the CLHG-3R system produced 2.40 MW of electric power output. B. Operational and Economic Impact Data for Steam Methane Reforming (SMR) System with Exemplary Electric power co-generation module [00104] Experimental steam methane reforming (SMR) systems integrated with exemplary electric power co-generation modules were computationally and experimentally evaluated, and the results are discussed below. [00105] Table 1, as shown below, shows the simulation model setup. Table 1.

[00106] Table 2, as shown below, shows the natural gas composition. Table 2.

[00107] Table 3, as shown below, shows the additional operating parameters for an exemplary steam methane reforming (SMR) system combined with an exemplary electric power co- generation module. Table 3.

C. Thermal Efficiency of Exemplary Electric power co-generation modules [00108] Extra electricity consumption is defined as the increase in electricity consumption compared to the original process without the steam turbine. [00109] Table 4 compares the thermal efficiency performance of SMR, CLC-SMR, and CLHG-3R. Table 4. Thermal efficiency of integrated turbines combined process

^{[00110] The thermal efficiency is calculated using equation 10, as shown below:}

[00111] For the steam methane reforming (SMR) systems and the chemical looping combustion combined with steam methane reforming (CLC-SMR) systems, the thermal efficiency is calculated based on the extra natural gas heating value (LHV), and the chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) efficiency is calculated based on extra heat input. The extra heat input to the chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) is provided from various sources, such as the combustion of fossil fuels. If the energy conversion efficiency from other forms of energy to heat is considered, the overall thermal efficiency can be lower than 97%. [00112] Tables 1-3 indicates the ASPEN simulation configuration. Based on the computational calculations (ASPEN simulation) disclosed in Table 4, steam methane reforming (SMR) systems, chemical looping combustion combined with steam methane reforming (CLC- SMR) systems, and chemical looping hydrogen generation in a 3-reactor system (CLHG-3R) produce electricity at extremely high thermal efficiency, much higher than the conventional thermal efficiency of a commercial plant (~40%) and even the efficiency of the Carnot cycle (theoretical limit). Embodiments [00113] For reasons of completeness, various embodiments of the present disclosure are provided below. Embodiment 1. A system configured to provide steam, the system comprising: a water source in fluid communication with a pump; a first heat exchanger in fluid communication with the pump; a power generator in fluid communication with the first heat exchanger, the power generator configured to generate electric power using fluid from the first heat exchanger; a second heat exchanger in fluid communication with the power generator; and a reactor system in fluid communication with an outlet of the second heat exchanger. Embodiment 2. The system according to Embodiment 1, the reactor system being selected from: a steam methane reforming (SMR) system, an auto-thermal reforming (ATR) system, a water-gas shift (WGS) system, an integrated gasification combined cycle (IGCC) system, a steam cracking system, a petroleum refining system, an enhanced oil recovery system, a chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and a chemical looping combustion combined with steam methane reforming (CLC-SMR) system. Embodiment 3. The system according to Embodiment 2, the reactor system being the steam methane reforming (SMR) system, and further comprising an inlet to a steam reforming reactor configured to receive natural gas and steam from the second heat exchanger. Embodiment 4. The system according to Embodiment 2, the reactor system being the chemical looping hydrogen generation in the 3-reactor system (CLHG-3R), and further comprising a first inlet to an oxidizer reactor configured to receive steam from the second heat exchanger and a second inlet to the oxidizer reactor configured to receive material from a reducer reactor. Embodiment 5. The system according to any one of Embodiments 1-4, wherein the second heat exchanger is a condenser or a heater. Embodiment 6. The system according to any one of Embodiments 1-5, further comprising a combustion stream from the reactor system in fluid communication with the first heat exchanger. Embodiment 7. The system according to any one of Embodiments 1-6, further comprising a combustion stream from the reactor system in fluid communication with the second heat exchanger. Embodiment 8. The system according to any one of Embodiments 1-7, wherein the power generator is a turbine. Embodiment 9. A method of operating a system, the method comprising: increasing a pressure of water from a water source with a pump; providing the pressurized water from the pump to a first heat exchanger; in the first heat exchanger, heating the pressurized water to generate pressurized steam; providing the pressurized steam to a power generator; with the power generator, producing electricity using the pressurized steam; providing an outlet stream of the power generator to a second heat exchanger, in the second heat exchanger, adjusting a temperature of the outlet stream of the power generator; and providing an outlet stream of the second heat exchanger to a reactor system. Embodiment 10. The method according to Embodiment 9, wherein the power generator is a turbine and the pressurized steam turns one or more blades of the turbine. Embodiment 11. The method according to Embodiment 9 or Embodiment 10, wherein the reactor system is selected from: a steam methane reforming (SMR) system, an auto-thermal reforming (ATR) system, a water-gas shift (WGS) system, an integrated gasification combined cycle (IGCC) system, a steam cracking system, a petroleum refining reactor system, an enhanced oil recovery system, a chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and a chemical looping combustion combined with steam methane reforming (CLC-SMR) system. Embodiment 12. The method according to any one of Embodiments 9-11, wherein the pressurized water from the pump has a pressure between 1 MPa to 20 MPa. Embodiment 13. The method according to any one of Embodiments 9-12, wherein the pressurized steam from an outlet of the first heat exchanger has a temperature between 100 °C to 1000 °C. Embodiment 14. The method according to any one of Embodiments 9-13, wherein the outlet stream of the power generator has a pressure between 0.005 MPa to 6 MPa. Embodiment 15. The method according to any one of Embodiments 9-14, wherein the outlet stream of the power generator has a temperature between 100 °C to 700 °C. Embodiment 16. The method according to any one of Embodiments 9-15, the second heat exchanger comprising a second hot stream inlet, second hot stream outlet, a second cold stream inlet, and a second cold stream outlet, and the method further comprising: receiving a combustion stream from the reactor system at the second hot stream inlet; and receiving the outlet stream from the power generator at second cold stream inlet. Embodiment 17. The method according to any one of Embodiments 9-16, the first heat exchanger comprising a first hot stream inlet, a first hot stream outlet, a first cold stream inlet, and a first cold stream outlet, and the method further comprising: receiving a combustion stream from the reactor system in the first hot stream inlet; and receiving the water from the pump at the first cold stream inlet. Embodiment 18. The method according to Embodiment 17, the method further comprising: combusting natural gas or recycled tail gas in the reactor system, thereby producing the combustion stream. Embodiment 19. The method according to any one of Embodiments 9-17, the method further comprising: combining the outlet of the second heat exchanger with a natural gas stream to generate a feedstock; and providing the feedstock to a reforming reactor. Embodiment 20. The method according to any one of Embodiments 9-19, the method further comprising: providing the outlet of the second heat exchanger to an oxidizer reactor.

Claims

CLAIMS What is claimed is: 1. A system configured to provide steam, the system comprising: a water source in fluid communication with a pump; a first heat exchanger in fluid communication with the pump; a power generator in fluid communication with the first heat exchanger, the power generator configured to generate electric power using fluid from the first heat exchanger; a second heat exchanger in fluid communication with the power generator; and a reactor system in fluid communication with an outlet of the second heat exchanger.

2. The system according to claim 1, the reactor system being selected from: a steam methane reforming (SMR) system, an auto-thermal reforming (ATR) system, a water-gas shift (WGS) system, an integrated gasification combined cycle (IGCC) system, a steam cracking system, a petroleum refining system, an enhanced oil recovery system, a chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and a chemical looping combustion combined with steam methane reforming (CLC-SMR) system.

3. The system according to claim 2, the reactor system being the steam methane reforming (SMR) system, and further comprising an inlet to a steam reforming reactor configured to receive natural gas and steam from the second heat exchanger.

4. The system according to claim 2, the reactor system being the chemical looping hydrogen generation in the 3-reactor system (CLHG-3R), and further comprising a first inlet to an oxidizer reactor configured to receive steam from the second heat exchanger and a second inlet to the oxidizer reactor configured to receive material from a reducer reactor.

5. The system according to claim 1, wherein the second heat exchanger is a condenser or a heater.

6. The system according to claim 1, further comprising a combustion stream from the reactor system in fluid communication with the first heat exchanger.

7. The system according to claim 6, further comprising a combustion stream from the reactor system in fluid communication with the second heat exchanger.

8. The system according to claim 1, wherein the power generator is a turbine.

9. A method of operating a system, the method comprising: increasing a pressure of water from a water source with a pump; providing the pressurized water from the pump to a first heat exchanger; in the first heat exchanger, heating the pressurized water to generate pressurized steam; providing the pressurized steam to a power generator; with the power generator, producing electricity using the pressurized steam; providing an outlet stream of the power generator to a second heat exchanger, in the second heat exchanger, adjusting a temperature of the outlet stream of the power generator; and providing an outlet stream of the second heat exchanger to a reactor system.

10. The method according to claim 9, wherein the power generator is a turbine and the pressurized steam turns one or more blades of the turbine.

11. The method according to claim 10, wherein the reactor system is selected from: a steam methane reforming (SMR) system, an auto-thermal reforming (ATR) system, a water-gas shift (WGS) system, an integrated gasification combined cycle (IGCC) system, a steam cracking system, a petroleum refining reactor system, an enhanced oil recovery system, a chemical looping hydrogen generation in a 3-reactor system (CLHG-3R), and a chemical looping combustion combined with steam methane reforming (CLC-SMR) system.

12. The method according to claim 9, wherein the pressurized water from the pump has a pressure between 1 MPa to 20 MPa.

13. The method according to claim 9, wherein the pressurized steam from an outlet of the first heat exchanger has a temperature between 100 °C to 1000 °C.

14. The method according to claim 9, wherein the outlet stream of the power generator has a pressure between 0.005 MPa to 6 MPa.

15. The method according to claim 9, wherein the outlet stream of the power generator has a temperature between 100 °C to 700 °C.

16. The method according to claim 9, the second heat exchanger comprising a second hot stream inlet, second hot stream outlet, a second cold stream inlet, and a second cold stream outlet, and the method further comprising: receiving a combustion stream from the reactor system at the second hot stream inlet; and receiving the outlet stream from the power generator at second cold stream inlet.

17. The method according to claim 9, the first heat exchanger comprising a first hot stream inlet, a first hot stream outlet, a first cold stream inlet, and a first cold stream outlet, and the method further comprising: receiving a combustion stream from the reactor system in the first hot stream inlet; and receiving the water from the pump at the first cold stream inlet.

18. The method according to claim 17, further comprising: combusting natural gas or recycled tail gas in the reactor system, thereby producing the combustion stream.

19. The method according to claim 9, further comprising: combining the outlet of the second heat exchanger with a natural gas stream to generate a feedstock; and providing the feedstock to a reforming reactor.

20. The method according to claim 9, further comprising: providing the outlet of the second heat exchanger to an oxidizer reactor.