METHOD AND SYSTEM FOR CONVERTING NON-METHANE HYDROCARBONS TO RECOVER HYDROGEN GAS AND/OR METHANE GAS THEREFROM

Abstract

The disclosure relates to methods, systems, and apparatus arranged and designed for converting non-methane hydrocarbon gases into multiple product gas streams including a predominately hydrogen gas stream and a predominately methane gas steam. Hydrocarbon gas streams are reformed, cracked, or converted into a synthesis gas stream and methane gas stream by receiving a volume of flare gas or other hydrocarbon liquid or gas feed, where the volume of hydrocarbon feed includes a volume of methane and a volume of non-methane hydrocarbons. The hydrogen contained in the syngas may be separated into a pure hydrogen gas stream. A corresponding gas conversion system can include a super heater to provide a hydrocarbon feed/steam mixture, a heavy hydrocarbon reactor for synthesis gas formation, and a hydrogen separator to recover the hydrogen portion of the synthesis gas. The gas conversion system can have a modal design such that it can operate to form hydrogen gas or alternatively operate to form synthetic natural gas with the same unit operation components.

Claims

1. A hydrocarbon conversion system for converting a hydrocarbon gas feed stream comprising non-methane hydrocarbons and optionally methane to form at least one of (i) a hydrogen gas stream and (ii) a product gas stream comprising methane, the hydrocarbon conversion system comprising: a heavy hydrocarbon reforming (HHR) module comprising: a first inlet for receiving the hydrocarbon gas feed stream; a second inlet for receiving system water; a first outlet for delivering a platform gas comprising methane and hydrogen; a steam generator adapted to (i) receive system water and (ii) output steam; a super heater adapted to (i) receive a feed gas comprising in admixture the hydrocarbon gas feed stream from the first inlet and the steam from the steam generator and (ii) superheat the feed gas to a predetermined temperature range to form a superheated feed gas; a first reactor containing a first catalyst and being adapted to receive the superheated feed gas from the super heater in fluid communication with the first reactor, wherein the first reactor and the first catalyst are adapted to react at least a portion of the non-methane hydrocarbons in the superheated feed gas into carbon oxides, hydrogen, methane, and water, thereby forming a first reformate comprising the carbon oxides, the hydrogen, the methane, and water; and a cooler adapted to (i) receive the first reformate from the first reactor in fluid communication with the cooler, and (ii) separate at least a portion of the water from the first reformate, thereby providing (i) a dried first reformate in fluid communication with the first outlet as the platform gas and (ii) a recycled system water stream in fluid communication with the steam generator and the second inlet.

2. The hydrocarbon conversion system of claim 1, further comprising: a mixer in fluid communication with the first inlet for receiving the hydrocarbon gas feed stream and in fluid communication with the steam generator for receiving the output steam, the mixer being adapted to (i) flow control at least a portion of the hydrocarbon gas feed stream and the steam, and (ii) output the feed gas to the super heater in fluid communication with the mixer.

3. The hydrocarbon conversion system of claim 1, further comprising: a first heat exchanger positioned between the steam generator and the super heater, the first heat exchanger being adapted to receive the feed gas from the steam generator as a first cold heat exchange fluid and the first reformate as a first hot heat exchange fluid, thereby heating the feed gas delivered to the super heater; a second heat exchanger positioned between the first inlet and the steam generator, the second heat exchanger being adapted to receive the hydrocarbon gas feed stream from the first inlet as a second cold heat exchange fluid and the first reformate as a second hot heat exchange fluid, thereby heating the hydrocarbon gas feed stream to be mixed with the steam to provide the feed gas; and a third heat exchanger positioned between the cooler and the steam generator, the third heat exchanger being adapted to receive the recycled system water stream from the cooler and the second inlet as a third cold heat exchange fluid and the first reformate as a third hot heat exchange fluid, thereby heating the recycled system water stream delivered to the steam generator and cooling the first reformate delivered to the cooler.

4. The hydrocarbon conversion system of claim 3, further comprising: a vaporizer heat exchanger positioned between the first reactor and the first heat exchanger, the vaporizer heat exchanger being adapted to receive at least a portion of the system water as the vaporizer cold heat exchange fluid and the first reformate as the vaporizer hot heat exchange fluid, thereby heating and vaporizing the portion of the system water delivered as steam to the steam generator or downstream thereof.

5. The hydrocarbon conversion system of claim 4, further comprising: a flow splitter adapted to (i) receive the system water, (ii) deliver at least a portion of the system water to the steam generator, and (iii) deliver at least a portion of the system water to the vaporizer heat exchanger.

6. The hydrocarbon conversion system of claim 1, further comprising: a vaporizer heat exchanger positioned between the first reactor and the cooler, the vaporizer heat exchanger being adapted to receive at least a portion of the system water as the vaporizer cold heat exchange fluid and the first reformate at the vaporizer hot heat exchange fluid, thereby heating and vaporizing the portion of the system water delivered as steam to the steam generator or downstream thereof.

7. The hydrocarbon conversion system of claim 1, further comprising: a flow splitter adapted to (i) receive the system water, (ii) deliver at least a portion of the system water to a boiler portion of the steam generator, and (iii) deliver at least a portion of the system water to a steam reservoir portion of the steam generator.

8. The hydrocarbon conversion system of claim 1, wherein the cooler comprises: (i) a chiller in fluid communication with and adapted to reduce the temperature of the first reformate from the first reactor, thereby condensing water from the first reformate; (ii) a water separator in fluid communication with the chiller and adapted to remove the condensed water from the first reformate, thereby forming the platform gas and the reformate water stream as outlets to the water separator; and (iii) a de-aerator in fluid communication with the reformate water stream from the water separator and adapted to remove entrained reformate gas therefrom, thereby forming the recycled water stream.

9. The hydrocarbon conversion system of claim 1, wherein the HHR module is free from at least one of methane separators, hydrogen separators, carbon dioxide separators, and synthetic natural gas (SNG) reactors.

10. The hydrocarbon conversion system of claim 1, wherein the first reactor is adapted to operate as an adiabatic reactor, an isothermal reactor, a temperature increase-controlled reactor, or a temperature decrease-controlled reactor.

11. The hydrocarbon conversion system of claim 1, wherein the first reactor is adapted to receive a countercurrent or cocurrent heat exchange fluid, thereby providing heat to a reaction volume in the first reactor containing the first catalyst and the superheated feed gas.

12. The hydrocarbon conversion system of claim 1, wherein the non-methane hydrocarbons in the hydrocarbon gas feed stream are selected from C2 hydrocarbons, C3 hydrocarbons, C4 hydrocarbons, C5 hydrocarbons, C6 hydrocarbons, C1 alcohol oxygenated hydrocarbons, C2 alcohol oxygenated hydrocarbons, C3 alcohol oxygenated hydrocarbons, C4 alcohol oxygenated hydrocarbons, C5 alcohol oxygenated hydrocarbons, C6 alcohol oxygenated hydrocarbons, C7-C15 hydrocarbons, and combinations thereof.

13. The hydrocarbon conversion system of claim 1, wherein the hydrocarbon gas feed stream comprises methane.

14. The hydrocarbon conversion system of claim 1, wherein the hydrocarbon gas feed stream is substantially free from methane.

15. The hydrocarbon conversion system of claim 1, further comprising: a methane separator adapted to (i) receive a hydrocarbon gas pre-feed stream comprising non-methane hydrocarbons and methane and (ii) separate at least a portion of the methane from the pre-feed stream, thereby providing the hydrocarbon gas feed stream comprising the non-methane hydrocarbons as a feed to the first inlet.

16. The hydrocarbon conversion system of claim 1, wherein: the hydrocarbon conversion system is free from further separation or reaction apparatus downstream of the HHR module first outlet; and the platform gas is the product gas stream.

17. The hydrocarbon conversion system of claim 1, further comprising: a carbon dioxide separator in fluid communication with the first outlet of the HHR module and adapted to (i) receive the platform gas from the HHR module and (ii) separate at least a portion of carbon dioxide present in the platform gas, thereby providing (i) a carbon dioxide stream and (ii) the product gas stream comprising the methane and the hydrogen from the platform gas.

18. The hydrocarbon conversion system of claim 1, further comprising: a synthetic natural gas (SNG) module comprising: a first inlet for receiving an SNG feed stream comprising hydrogen, carbon oxides, and optionally methane, the first inlet of the SNG module being in fluid communication with the first outlet of the HHR module; a first outlet for delivering the product gas stream comprising the methane; a second outlet for delivering the recycled system water, the second outlet of the SNG module being in fluid communication with the second inlet of the HHR module; a heater adapted to (i) receive the SNG feed stream and (ii) heat the SNG feed stream to a predetermined temperature range to form a heated SNG feed gas; a second reactor (SNG) containing a second catalyst and being adapted to receive the heated SNG feed gas from the heater in fluid communication with the second reactor, wherein the second reactor and the second catalyst are adapted to react at least a portion of the carbon oxides and the hydrogen in the heated SNG feed gas into converted methane and water, thereby forming a wet synthetic natural gas comprising the converted methane and the water, wherein the wet synthetic natural gas has an overall higher methane mole fraction than the SNG feed stream; and a cooler adapted to (i) receive the wet synthetic natural gas from the second reactor in fluid communication with the cooler, and (ii) separate at least a portion of the water from the wet synthetic natural gas, thereby providing (i) a dried synthetic natural gas in fluid communication with the first outlet as the product gas and (ii) a recycled system water stream in fluid communication with the second outlet.

19. The hydrocarbon conversion system of claim 1, further comprising: a carbon dioxide separator in fluid communication with the first outlet of the HHR module and adapted to (i) receive the platform gas from the HHR module and (ii) separate at least a portion of carbon dioxide present in the platform gas, thereby providing (i) a carbon dioxide stream and (ii) an intermediate product gas stream comprising the methane, the hydrogen, and unseparated carbon oxides from the platform gas; and a hydrogen separator module comprising: a first inlet for receiving the intermediate product gas stream from and in fluid communication with the carbon dioxide separator; a first outlet for delivering the hydrogen gas stream; and a second outlet for delivering a compressed tail gas comprising hydrogen, carbon oxides, and methane; a hydrogen separator adapted to (i) receive the intermediate product gas and (ii) separate at least a portion of the hydrogen from the intermediate product gas, thereby providing (i) the hydrogen gas stream and (ii) a tail gas comprising hydrogen, carbon oxides, and methane; and a compressor adapted to receive and compress the tail gas, thereby providing the compressed tail gas as the product gas.

20. The hydrocarbon conversion system of claim 1, further comprising: a carbon dioxide separator in fluid communication with the first outlet of the HHR module and adapted to (i) receive the platform gas from the HHR module and (ii) separate at least a portion of carbon dioxide present in the platform gas, thereby providing (i) a carbon dioxide stream and (ii) an intermediate product gas stream comprising the methane, the hydrogen, and unseparated carbon oxides from the platform gas; and a hydrogen separator module comprising: a first inlet for receiving the intermediate product gas stream from and in fluid communication with the carbon dioxide separator; a first outlet for delivering the hydrogen gas stream; and a second outlet for delivering a compressed tail gas comprising hydrogen, carbon oxides, and methane; a hydrogen separator adapted to (i) receive the intermediate product gas and (ii) separate at least a portion of the hydrogen from the intermediate product gas, thereby providing (i) the hydrogen gas stream and (ii) a tail gas comprising hydrogen, carbon oxides, and methane; and a compressor adapted to receive and compress the tail gas; and a synthetic natural gas (SNG) module comprising: a first inlet for receiving an SNG feed stream comprising hydrogen, carbon oxides, and optionally methane, the first inlet of the SNG module being in fluid communication with the second outlet of the hydrogen separator module; a first outlet for delivering the product gas stream comprising the methane; a second outlet for delivering the recycled system water, the second outlet of the SNG module being in fluid communication with the second inlet of the HHR module; a heater adapted to (i) receive the SNG feed stream and (ii) heat the SNG feed stream to a predetermined temperature range to form a heated SNG feed gas; a second reactor (SNG) containing a second catalyst and being adapted to receive the heated SNG feed gas from the heater in fluid communication with the second reactor, wherein the second reactor and the second catalyst are adapted to react at least a portion of the carbon oxides and the hydrogen in the heated SNG feed gas into converted methane and water, thereby forming a wet synthetic natural gas comprising the converted methane and the water, wherein the wet synthetic natural gas has an overall higher methane mole fraction than the SNG feed stream; and a cooler adapted to (i) receive the synthetic natural wet processed gas from the second reactor in fluid communication with the cooler, and (ii) separate at least a portion of the water from the wet synthetic natural gas, thereby providing (i) a dried synthetic natural gas in fluid communication with the first outlet as the product gas and (ii) a recycled system water stream in fluid communication with the second outlet.

21. A hydrocarbon conversion system for forming (i) a hydrogen gas stream and (ii) a product gas stream from a hydrocarbon gas feed stream comprising non-methane hydrocarbons and optionally methane, the gas conversion system comprising: a super heater adapted to (i) receive a feed gas comprising the hydrocarbon gas feed stream and water in admixture and (ii) superheat the feed gas to a predetermined temperature range to form a superheated feed gas; a first reactor containing a first catalyst and being adapted to receive the superheated feed gas from the super heater in fluid communication with the first reactor, wherein the first reactor and the first catalyst are adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas into carbon oxides and hydrogen, thereby forming a first reformate comprising the carbon oxides, the hydrogen, and optionally methane; and a hydrogen separator adapted to (i) receive the first reformate from the first reactor in fluid communication with the hydrogen separator, and (ii) separate at least a portion of the hydrogen from the reformate, thereby providing (i) the hydrogen gas stream comprising the separated hydrogen, and, separately, (ii) the product gas stream comprising the carbon oxides.

22.-33. (canceled)

34. A hydrocarbon conversion system for forming (i) optionally a hydrogen gas stream and (ii) a product gas stream from a hydrocarbon gas feed stream comprising non-methane hydrocarbons and optionally methane, the gas conversion system comprising: a super heater adapted to (i) receive a feed gas comprising the hydrocarbon gas feed stream and water in admixture and (ii) superheat the feed gas to a predetermined temperature range to form a superheated feed gas; a first reactor containing a first catalyst and being adapted to receive the superheated feed gas from the super heater in fluid communication with the first reactor, wherein the first reactor and the first catalyst are adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas into carbon oxides and hydrogen, thereby forming a first reformate comprising the carbon oxides, the hydrogen, and optionally methane; a second reactor containing a second catalyst and being adapted to operate in a first mode as a heavy hydrocarbon reactor or in a second mode as a syngas reactor, wherein (i) in the first mode (HHR), the second reactor is adapted to receive the superheated feed gas from the super heater in fluid communication with the second reactor, wherein the second reactor and the second catalyst are adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas into carbon oxides and hydrogen, thereby forming a second reformate comprising the carbon oxides, the hydrogen, and optionally methane, and (ii) in the second mode (SNG), the second reactor is adapted to receive the first reformate from the first reactor in fluid communication with the second reactor, wherein the second reactor and the second catalyst are adapted to convert at least a portion of the carbon oxides and the hydrogen in the first reformate into converted methane, thereby forming a synthetic natural wet processed gas comprising the converted methane, wherein the synthetic natural wet processed gas has an overall higher methane mole fraction than the hydrocarbon gas feed stream; a first flow splitter adapted to receive the superheated feed gas from the super heater in fluid communication with the first flow splitter, wherein (i) in the first mode (HHR) of the second reactor, the first flow splitter is adapted to feed at least a portion of the superheated feed gas to both of the first reactor and the second reactor in parallel such that each is in fluid communication with and adapted to receive a portion of the superheated feed gas, and (ii) in the second mode (SNG) of the second reactor, the first flow splitter is adapted to (A) feed at least a portion of the superheated feed gas to the first reactor and (B) prevent flow of the superheated feed gas to the second reactor; and a first flow mixer in fluid communication with the first reactor and the second reactor, wherein (i) in the first mode (HHR) of the second reactor, the first flow mixer is adapted to receive and combine the first reformate and the second reformate into a single reformate, and (ii) in the second mode (SNG) of the second reactor, the first flow mixer is adapted to receive only the first reformate; and a second flow splitter in fluid communication with the first flow mixer, wherein (i) in the first mode (HHR) of the second reactor, the second flow splitter is adapted to (A) receive the combined first reformate and second reformate and (B) prevent flow of the combined first reformate and second reformate to the second reactor, and (ii) in the second mode (SNG) of the second reactor, the second flow splitter is adapted to (A) receive only the first reformate and (B) feed at least a portion of the first reformate to the second reactor.

35. (canceled)

36. A method for forming at least one of (i) a hydrogen gas stream and (ii) a product gas stream from a hydrocarbon gas feed stream comprising non-methane hydrocarbons and optionally methane, the method comprising: feeding the hydrocarbon gas feed stream to a hydrocarbon conversion system according to claim 1, thereby forming at least one of (i) a hydrogen gas stream and (ii) a product gas stream; and optionally adding an additional product stream to at least one of the hydrogen gas stream and the product gas stream, thereby forming a designer fuel stream having a selected composition.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0059] For a more complete understanding of the disclosure, reference should be made to the following detailed description and accompanying drawings wherein:

[0060] FIG. 1 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system used for hydrogen gas production.

[0061] FIG. 2 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system used for hydrogen gas production, further including a hydrogen separator for production of essentially pure hydrogen gas.

[0062] FIG. 3 is a process flow diagram illustrating representative unit operations and streams in the disclosed modal gas conversion system used for either hydrogen gas production or methane production using the same unit operations.

[0063] FIG. 4 is a process flow diagram illustrating the modal gas conversion system of FIG. 3 in the first mode with hydrogen separation.

[0064] FIG. 5 is a process flow diagram illustrating the modal gas conversion system of FIG. 3 in the first mode without hydrogen separation.

[0065] FIG. 6 is a process flow diagram illustrating the modal gas conversion system of FIG. 3 in the second mode.

[0066] FIG. 7 is a process flow diagram illustrating representative flow rates and energy contents for streams in the disclosed gas conversion system used for hydrogen gas production in an embodiment without bypass/enrichment of the product stream.

[0067] FIG. 8 is a process flow diagram illustrating representative flow rates and energy contents for streams in the disclosed gas conversion system used for hydrogen gas production in an embodiment including a raw flare/associated gas bypass stream for enrichment of the product stream.

[0068] FIG. 9 is a process flow diagram illustrating representative flow rates and energy contents for streams in the disclosed gas conversion system used for hydrogen gas production in an embodiment including both (i) a raw flare/associated gas bypass stream and (ii) a methane/light gas bypass stream for enrichment of the product stream.

[0069] FIG. 10 is a process flow diagram illustrating representative flow rates and energy contents for streams in the disclosed gas conversion system used for hydrogen gas production in an embodiment including (i) a raw flare/associated gas bypass stream for enrichment of the product stream, (ii) a methane/light gas bypass stream for enrichment of the product stream, (iii) hydrogen gas stream separation, and (iv) carbon dioxide gas stream separation.

[0070] FIG. 11 is a process flow diagram illustrating representative unit operations and streams in an HHR module of the disclosed gas conversion system.

[0071] FIG. 12 is a process flow diagram illustrating representative unit operations and streams in an HHR module further including a vaporizer.

[0072] FIG. 13 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module and a carbon dioxide separator or module.

[0073] FIG. 14 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module and an SNG module.

[0074] FIG. 15 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, a carbon dioxide separator or module, a hydrogen separator module, and an SNG module.

[0075] FIG. 16 is a process flow diagram illustrating specific streams in the gas conversion system of FIG. 15.

DETAILED DESCRIPTION

[0076] The disclosure generally relates to methods, systems, and apparatus to produce a hydrogen gas stream (e.g., a substantially pure hydrogen gas stream), a carbon dioxide gas stream (e.g., a substantially pure carbon dioxide gas stream), and a high quality, methane rich gas stream from flare gas or other hydrocarbon feed gas streams. Hydrocarbon feed gas streams are reformed, cracked, or converted into a syngas stream and methane gas stream by receiving a volume of hydrocarbon feed gas, where the volume of hydrocarbon feed gas includes a volume of methane (C1) and a volume of non-methane (C2+) hydrocarbons. The method can control both an inlet flow of the volume of hydrocarbon feed gas and a volume of steam to at least one reformer system that will reform, crack, or convert at least a portion of the volume of C2+ hydrocarbons (e.g., with or without methane present). In this way, the steam reformer system(s) generates a volume of syngas and a volume of methane gas from the volume of hydrocarbon feed gas and the volume of steam. The hydrogen contained in the syngas may be separated into a high purity hydrogen gas stream by various technologies including membrane separation and pressure swing adsorption (“PSA”) systems leaving a residual, predominately methane and carbon oxide gas stream. The separated hydrogen or the residual predominately methane and carbon oxide stream may be combined with the hydrocarbon feed gas to form an enriched product gas with targeted quality values including heating value, methane number or Wobbe index. In this way, the hydrogen gas and the residual predominately methane and carbon oxide gas is made available for use on-site as a fuel or for compression or liquefaction and storage or transportation off-site.

[0077] The disclosure further relates to methods, systems, and apparatus to produce a hydrogen gas stream (e.g., a substantially pure hydrogen gas stream) and a high quality, methane rich gas stream from flare gas or other hydrocarbon feed gases by receiving a volume of the hydrocarbon feed gas, where the volume of hydrocarbon feed gas includes a volume of methane (C1) and a volume of C2+ hydrocarbons. The method separates the hydrocarbon feed gas into a predominately methane gas stream and a predominately C2+ hydrocarbon gas stream using various gas separation technologies including Joule-Thompson, mechanical refrigeration and membrane systems. The method can control both an inlet flow of the volume of C2+ hydrocarbons and a volume of steam to at least one reformer system that will reform, crack, or convert at least a portion of the volume of the predominately C2+ hydrocarbons. In this way, the steam reformer system(s) generates a volume of syngas and a volume of methane gas from the volume of predominately C2+ hydrocarbons and the volume of steam. The method may then further separate the hydrogen gas contained in the syngas into a separate high purity hydrogen gas stream by any of various technologies including membrane and pressure swing adsorption (“PSA”) systems leaving a residual, predominately methane and carbon oxide gas stream. The separated hydrogen or the predominately methane and carbon oxide stream may be combined with the predominately methane gas separated from the hydrocarbon feed gas and/or with the hydrocarbon feed gas to produce an enriched product gas with targeted gas quality values including specific heating value, methane number or Wobbe index. In this way, the hydrogen gas and the predominately methane and carbon oxide gas is made available for use on-site as a fuel or for compression or liquefaction and transportation off-site.

[0078] In a particular aspect, the disclosure relates to modular systems, methods, and apparatus to produce one or both of (i) a hydrogen gas stream (e.g., a substantially pure hydrogen gas stream), and (ii) a methane-containing product stream (such as methane rich gas stream or a methane/hydrogen blend) from non-methane hydrocarbon feed gas streams. The modular systems allow flexible fuel production ranging from fuel cell grade hydrogen to pipeline quality methane to site-specific “designer fuel” blend containing methane, hydrogen, and (optionally) carbon dioxide according to a given user's specifications. The modular design allows quick configuration and onsite installation and assembly of a system tailored to a specific user's needs. Using a modular design, an HHR module as the core component is flexible in that it can provide a platform gas output with a targeted, selectable distribution between primary hydrogen and methane components using a single, consistent installed/assembled set of unit operations. By varying operating conditions such as steam:carbon ratio and HHR reactor temperature, relative conversion and selectivity of steam reformation and methanation reactions in the HHR reactor can be controlled within wide ranges such the composition of the platform gas can include a relatively higher fraction of hydrogen product (e.g., compared to methane) when hydrogen is the ultimate desired product, the platform gas can include a relatively higher fraction of methane product (e.g., compared to hydrogen) when methane is the ultimate desired product, the platform gas can include a balanced blend of hydrogen and methane when both are desired ultimate products, etc. This flexibility of the HHR module platform gas output, which is obtainable using a single installed arrangement of unit operations in the HHR module, allows selection of further downstream unit operation modules to provide fuel product outputs corresponding specifically to a given user's needs. Such downstream modules can include those directed to carbon dioxide separation, hydrogen separation, and/or SNG production.

[0079] Another embodiment of the disclosure relates to methods, systems, and apparatus to produce a high purity hydrogen gas stream and a methane rich gas stream from flare gas or other hydrocarbon feed gases, as described above, wherein the syngas is further processed in a water gas shift reactor to increase the hydrogen content prior to its separation by membrane, PSA or other technologies.

[0080] Another embodiment of the disclosure relates to methods, systems, and apparatus to produce a high purity hydrogen gas stream and a methane rich gas stream from C2+ hydrocarbons wherein the system feed gas does not include methane gas. Possible feed gases include ethane, propane, butane and other C2+ hydrocarbons.

[0081] FIGS. 1-2 include process flow diagrams illustrating representative unit operations and streams in the disclosed hydrocarbon or gas conversion system 50 used for hydrogen gas production.

[0082] A hydrocarbon gas feed 62 including non-methane hydrocarbons and optionally methane is fed as a conditioned gas to a mixer 130 which receives steam 126 from a steam generator 120. The mixer 130 outputs a corresponding feed gas 132 including the hydrocarbon gas feed stream and water (e.g., steam) in admixture. Heat exchangers (HEX) 170, for example illustrated as a first heat exchanger 172 and a second heat exchanger 174, can be included upstream and downstream of the mixer 130 to adjust the temperature of the hydrocarbon gas feed 62 and corresponding feed stream using heat from the reformate streams 152. The feed gas 132 is then fed to a super heater 140, which superheats the feed gas 132 to a selected temperature and outputs a superheated feed gas 142. The superheated feed gas 142 is then fed to a first HHR reactor 150, which contains a catalyst adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas 142 into carbon oxides and hydrogen, thereby forming a reformate 152 including carbon oxides, hydrogen, and optionally methane. As illustrated, a second HHR reactor 150 can be included to operate in parallel with the first reactor 150. More generally, any number of HHR reactors 150 can be used. As further illustrated, the HHR reactors 150 can include countercurrent heat exchange streams 154 to maintain approximately isothermal operating conditions in the reactors 150. The reformate streams 152 exiting the HHR reactors 150 can be passed through a cooler 160 to remove water 169, which can be recycled, for example to the steam generator 120. In the embodiment shown in FIG. 1, the dried reformate 114 can be recovered as the product gas 74 as a mixture of syngas (i.e., carbon oxides and hydrogen) as well as any methane originally present in the feed or produced by methanation in the HHR reactors 150. In the embodiment shown in FIG. 2, the dried reformate 114 is further passed through a hydrogen separator 310 to form a product gas stream 74 including the carbon oxides and a hydrogen gas stream 72 including the separated hydrogen. Other upstream unit operations such as a dehydrator 166 and/or a compressor 320 can be used depending on the state of the dried reformate.

[0083] FIGS. 3-6 include process flow diagrams illustrating representative unit operations and streams in the disclosed modal gas conversion system 50 used for either hydrogen gas production or methane production using the same unit operations.

[0084] The modal gas conversion system 50 is similar to that described above with respect to FIGS. 1-2, but it further includes flow splitters 136A, B, C, D and flow mixers 134A that can be set to direct flow through the system 50 such that the system operates either in a first (HHR) mode for hydrogen generation or a second (SNG) mode for methane production. In the first mode, the superheated feed gas 142 is split into two (or more) parallel streams for reaction in HHR reactors 150, thus forming a hydrogen gas product. In the second mode, superheated feed gas 142 is fed in series to a first HHR reactor 150 (labeled as left HHR in the figures) for syngas production, and then to a second SNG reactor 420 (labeled as right HHR/SNG in the figures), thus forming a methane gas product. FIG. 4 illustrates operation in the first mode for hydrogen generation, where hydrogen gas is recovered as a product. Carbon dioxide as well as process gas (e.g., carbon dioxide, residual hydrocarbons) are also separated as product streams. FIG. 5 illustrates operation in the first mode for hydrogen generation, where hydrogen gas is left as a component of the product gas (i.e., further including carbon oxides as a syngas). FIG. 6 illustrates operation in the second mode for methane generation, where the product gas includes methane as well as any unreacted carbon oxides, hydrogen, or heavier hydrocarbons.

[0085] FIGS. 7-10 include process flow diagrams illustrating representative flow rates and energy contents for streams in the disclosed gas conversion system 50 incorporating an HHR module 100 and hydrogen separator 310 used for hydrogen gas production to provide a hydrogen gas stream 72, a product gas stream 74, and optionally one or more additional product stream(s) 76, 76A, 76B, 76C, 76D. FIG. 7 illustrates an embodiment without any feed bypass or product enrichment streams. FIG. 8 illustrates an embodiment including a raw flare/hydrocarbon feed gas bypass stream 66 for enrichment of the product stream 74. FIG. 9 illustrates an embodiment including both (i) a raw flare/hydrocarbon feed bypass stream 66C and (ii) methane/light gas bypass streams 66B, 66A from a methane separator 80 (e.g., including an NGL separator 81 and an NGL run tank 82 as illustrated) for enrichment of the product stream 74. FIG. 10 illustrates an embodiment including (i) a raw flare/hydrocarbon feed bypass stream 66C for enrichment of the product stream 74, (ii) methane/light gas bypass streams 66B, 66A for enrichment of the product stream 74, (iii) hydrogen gas stream 72 separation via a hydrogen separator 310, and (iv) carbon dioxide gas stream 76D separation via a carbon dioxide separator 210. Tables 1-4 below provide a summary of the flow rates and energy contents for streams in FIGS. 7-10.

TABLE-US-00001 TABLE 1 Stream Properties for FIG. 7 Flow Rate Energy Name Stream (mscfd) (btu/scf) Other Raw Flare 62 360 1351 Feed Product Gas 74 689 565 1.7 MW 1816 DGE/month Hydrogen Gas 72 1030 kg/day

TABLE-US-00002 TABLE 2 Stream Properties for FIG. 8 Flow Rate Energy Name Stream (mscfd) (btu/scf) Other Raw Flare 62 360 1351 Feed Raw Flare 64 1521 1351 Feed Raw Flare 66 1109 1351 Enrichment Process Gas 76 689 565 Product Gas 74 1798 1050 8.4 MW 443,480 DGE/month Hydrogen Gas 72 1030 kg/day

TABLE-US-00003 TABLE 3 Stream Properties for FIG. 9 Flow Rate Energy Name Stream (mscfd) (btu/scf) Other NGL Tank 62 149 3050 Liquids NGL Tank 64A Raw Flare 64B 1285 1349 Feed Raw Flare 64C 2317 1351 Feed NGL Tank Light 66A 134 1512 Gas JT Light Gas 66B 1002 1074 Raw Flare 66C 923 1351 Enrichment Process Gas 1 76A 683 517 Process Gas 2 76B 817 680 Product Gas 1 76C 1819 897 Product Gas 2 74 2741 1050 .sup. 13 MW Hydrogen Gas 72 1042 kg/day

TABLE-US-00004 TABLE 4 Stream Properties for FIG. 10 Flow Rate Energy Name Stream (mscfd) (btu/scf) Other NGL Tank 62 147 3050 Liquids NGL Tank 64A Raw Flare 64B 1264 1349 Feed Raw Flare 64C 1603 1351 Feed NGL Tank Vent 66A 132 1512 Gas NGL 66B 986 1074 Separation Light Gas Raw Flare 66C 223 1351 Enrichment Process Gas 76A 467 725 Product Gas 1 76B 599 898 Product Gas 2 76C 1585 1008 Product Gas 3 74 1808 1050 8 MW 445915 DGE/month Hydrogen Gas 72  1151 kg/day Carbon Dioxide 76D 13159 kg/day Gas

[0086] FIGS. 11-16 include process flow diagrams illustrating representative unit operations and streams in the disclosed hydrocarbon or gas conversion system 50 used to produce one or both of hydrogen gas and a product gas comprising methane using the same unit operations in various modular arrangements. As illustrated, the hydrocarbon or gas conversion system 50 includes an HHR module 100 alone or in combination with one or more other separators or modules, for example including a carbon dioxide module 200, a hydrogen separator module 300, and/or an SNG module 400.

[0087] As illustrated in FIG. 11, the HHR module 100 can include a first (HHR) inlet 102 for a hydrocarbon feed, a second (HHR) inlet 104 for recycled system water, a third (HHR) inlet 105 for makeup water, a first (HHR) outlet 106 for platform gas, and a second (HHR) outlet 107 for deaerated reformate gas. A hydrocarbon gas feed 62 including non-methane hydrocarbons is fed to a mixer 130 which receives steam 126 from a steam generator 120. The mixer 130 outputs a corresponding feed gas 132 including the hydrocarbon gas feed stream and water (e.g., steam) in admixture. Recuperative heat exchangers (HEX) 170, for example illustrated as a first heat exchanger 172, a second heat exchanger 174, and a third heat exchanger 176, can be included upstream and downstream of the mixer 130 to adjust the temperature of the hydrocarbon gas feed 62 and corresponding feed stream using heat from the reformate streams 152 as the hot side heat exchange fluids. The feed gas 132 is then fed to a super heater 140, which superheats the feed gas 132 to a selected temperature and outputs a superheated feed gas 142. The superheated feed gas 142 is then fed to a first (HHR) reactor 150, which contains a catalyst adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas 142 into carbon oxides, hydrogen, and methane via equilibrium steam reformation and methanation reactions. Suitable catalysts for the first (HHR) and second (SNG) reactors in the various embodiments are not particularly limited, and can include a variety of commercially available catalysts such as commercial steam reforming catalysts. Examples include an AR-401 catalyst (nickel catalyst on activated magnesium alumina spinel support; available in pellet form or a disc with holes from Haldor Topsoe), a CRG-LHR catalyst (precipitated catalyst with nickel active component; available in pellet form from Johnson Matthey), an MC-750R catalyst (nickel-based catalyst; available in pellet form from Unicat), and a REFORMAX 100RS catalyst (nickel-based catalyst; available in pellet form from Clariant).

[0088] The product output of the first reactor 150 is a (wet) reformate 152 including carbon oxides, hydrogen, methane, and water. More generally, any number of first reactors 150 can be used for example in parallel to increase capacity of the HHR module 100. The reformate stream 152 exiting the first reactor 150 can be passed through the recuperative heat exchangers 170 and then to a cooler or water separation unit 160 to remove water, which can be recycled, for example to the steam generator 120. In the embodiment shown in FIG. 11, the cooler 160 can include a first water separator 166 to remove some water condensed after passing through the recuperative heat exchangers 170, followed by a chiller 164 to further cool and condense water that can be removed from the reformate in a second water separator 166 to form a dried reformate 167 with a substantially reduced water content. The system water recovered from the water separators 166 can be passed to a deaerator 168 to separate and remove some reformate compounds (e.g., minor amounts of methane, carbon dioxide, hydrogen) via the second outlet 107, thereby forming a recycled system water stream 169. The recycled system water 169 can be mixed with further recycled system water 112 from downstream modules as well as fresh or makeup water via the third inlet 105, for example in a collection point or water reservoir 162 to provide system water 163 back to the steam generator 120.

[0089] The dried reformate 167 exits the HHR module 100 via the first outlet 106 as a platform gas 114. In some embodiments, the platform gas 114 can be recovered and used as a product gas 74 as a mixture of methane, hydrogen, and carbon dioxide without the need for further downstream separation and/or reaction unit operations. In other embodiments, the platform gas 114 can represent an intermediate product that is passed as a feed to one or more further downstream separation and/or reaction unit operations.

[0090] FIG. 12 illustrates an alternate embodiment of the HHR module 100 further including a vaporizer 180. The vaporizer 180 can be positioned downstream of the first reactor 150 and upstream of the recuperative heat exchangers 170 so that it can receive the hot wet reformate 152 as a hot heat exchange fluid to vaporize at least a portion of the system water 163 that would otherwise be returned to the steam generator 120 as illustrated in FIG. 11. As shown in FIG. 12, a portion 184 of the system water 163 is passed to the steam generator 120 as liquid water, for example to a boiler 122 component thereof. Similarly, a portion 186 of the system water 163 is passed to the vaporizer 180 as a cold heat exchange fluid, whereupon it is vaporized by the hot reformate 152 and then passed to the steam generator 120 as steam, for example to a steam drum 124 component thereof.

[0091] FIG. 13 illustrates a modular hydrocarbon or gas conversion system 50 including a carbon dioxide separator module 200 in series with an HHR module 100. The carbon dioxide separator module 200 can include a first (CO2) inlet 202 for a feed containing carbon dioxide, a first (CO2) outlet 206 for separated carbon dioxide, and a second (CO2) outlet 208 for an intermediate or final product gas with reduced carbon dioxide. As illustrated, the platform gas 114 from the HHR module 100 is fed to a carbon dioxide separator 210 in the module 200 via the first inlet 202. Example carbon dioxide separators 210 can include scrubbers (e.g., amine scrubbers), membrane separators, etc. A carbon dioxide-rich stream leaves the separator 210 and module 200 via the first outlet 206, for example as an additional carbon dioxide product stream 76, which can be subsequently used as a fuel diluent, added to an SNG feed as a source of carbon oxide reactant. A second stream containing reduces or substantially no carbon dioxide leaves the separator 210 and module 200 via the first outlet 208, for example as a product stream 74 containing both methane and hydrogen. In some embodiments, the product stream 74 can be used as a blue hydrogen-rich turbine fuel, which, similar to raw platform gas, can be blended with other fuel components such as C1 hydrocarbons or a mixture of hydrocarbons containing primarily C1 and C2, for example pipeline methane or otherwise a predominantly methane stream. In some embodiments, the methane/hydrogen mixture can be withdrawn as an intermediate product stream 212 and fed to other downstream modules (e.g., for hydrogen separation and/or SNG production).

[0092] FIG. 14 illustrates a modular hydrocarbon or gas conversion system 50 including an SNG module 400 in series with an HHR module 100. The SNG module 400 can include a first (SNG) inlet 402 for a feed containing hydrogen and carbon oxide, a first (SNG) outlet 406 for synthetic natural gas, and a second (SNG) outlet 408 for recycled system water. As illustrated, the platform gas 114 from the HHR module 100 is fed to a heater 410, for example a recuperative heat exchanger, in the module 400 via the first inlet 402. The platform gas 114 includes a mixture of hydrogen, carbon oxides, and methane and is heated to a selected temperature by the heater 410 before being fed to a second (SNG) reactor 420, which contains a catalyst adapted to react at least a portion of the carbon oxides and hydrogen to methane and water via methanation reactions. The product output of the second reactor 420 is a wet synthetic natural gas 422 including methane and water. More generally, any number of second reactors 420 can be used for example in parallel to increase capacity of the SNG module 400. The wet synthetic natural gas 422 exiting the second reactor 420 can be passed through a recuperative heat exchanger (for example the heater 410) then to a cooler or water separation unit 430 to remove water, which can be recycled, for example to the HHR module 100. In the embodiment shown in FIG. 14, the cooler 430 can include a chiller 434 to cool and condense water that can be removed from the wet gas in a water separator 436 to form a dried synthetic natural gas 437 with a substantially reduced water content. The dried synthetic natural gas 437 exits the SNG module 400 via the first outlet 406 as a product gas containing high levels of or substantially pure methane. The system water recovered from the water separator 436 can be fed back to the HHR module 100 via the second outlet 408 as further a recycled system water stream 112.

[0093] FIG. 15 illustrates a modular hydrocarbon or gas conversion system 50 including carbon dioxide separator module 200, a hydrogen separator module 300, and an SNG module 400 in series with an HHR module 100. The carbon dioxide separator module 200 and the SNG module 400 operate substantially as described above for the modular embodiments of FIG. 13 and FIG. 14, with the primary difference being that the hydrogen separator module 300 can withdraw high purity hydrogen as a product prior to passing a mixture of carbon oxides and hydrogen to the SNG module 400 to form a methane-rich product stream. The hydrogen separator module 300 can include a first (H2) inlet 302 for a feed containing hydrogen and carbon oxide, a first (H2) outlet 304 for high purity hydrogen gas, a second (H2) outlet 306 for compressed tail gas as an SNG feed, and a third (H2) outlet 308 for compressed tail gas as an alternative methane-containing product gas. As illustrated, the intermediate product gas 212 from the carbon dioxide separator module 200 is fed to a hydrogen separator 310 in the module 300 via the first inlet 302. Example hydrogen separators 310 can include PSA separators, membrane separators, etc. A hydrogen-rich stream leaves the separator 310 and module 300 via the first outlet 304, for example as a high purity hydrogen gas 72. Tail gas 312 exiting the hydrogen separator 310 is then compressed in a compressor 320 to provide a compressed tail gas 322 output. In some embodiments, a portion (or all) of the compressed tail gas 322 can be withdrawn via the third outlet 308 as an additional product stream 76B (e.g., as well as an additional product stream 76A containing primarily carbon dioxide). In some embodiments, a portion (or all) of the compressed tail gas 322 is fed via the second outlet 306 to the SNG module 400 as the SNG feed stream containing carbon oxides and hydrogen. In some embodiments, a portion of the carbon dioxide stream (or trim stream) from the upstream carbon dioxide separator 210 (e.g., via the first outlet 206 thereof) could be added to the tail gas 312 prior to compression such that the compressed tail gas 322 fed to the SNG module 400 contains additional carbon oxide reactants to promote higher conversion to methane in the SNG module 400.

[0094] In an alternative embodiment to that illustrated in FIG. 15, the SNG module 400 can be omitted. In such cases, two main products of the modular system 50 include the hydrogen gas stream 72 and the compressed tail gas stream 76B.

[0095] In another alternative embodiment to that illustrated in FIG. 15, the modular system can include a bypass line such that a portion (or all) of the platform gas 114 can be fed directly to the SNG module 400, thus bypassing the carbon dioxide separator module 200 and the hydrogen separator module 300. For example, a suitable flow splitter on the platform gas 114 line upstream of the carbon dioxide separator module 200 permits partitioning of the platform gas 114 such that the system 50 can operate as illustrated in FIG. 14 (i.e., methane as primary product), FIG. 15 (i.e., hydrogen and methane as primary products), or a user-desired combination of the two embodiments.

EXAMPLES

[0096] The following examples include process simulations providing illustrative compositions and stream conditions for hydrocarbon conversion systems according to the disclosure.

Example 1

[0097] Table 5 below provides illustrative composition values for a process as generally illustrated in FIG. 8 incorporating a raw flare/associated gas bypass stream for enrichment of the product stream. The inlet feed gas is representative of a typical flare gas, containing about 60-65 mol. % methane, about 30-35 mol. % ethane and propane combined, and about 1-5 mol. % of heavier hydrocarbons (C4+). The “process gas” and “product gas” columns include the fraction of hydrogen gas formed in the system, which is about 10-50 mol. % or 20-25 mol. % based on the throughput of the gas conversion system or about 6-10 mol. % based on the overall feed gas (i.e., bypass amount plus gas conversion system throughput amount combined). In an embodiment in which the hydrogen component is separated from the output of the gas conversion system, the hydrogen amounts in the “process gas” column is recovered in a substantially pure hydrogen stream, and the concentrations of the other components are correspondingly increased proportionally (e.g., based on hydrogen separation as well as possible carbon dioxide separation as well).

TABLE-US-00005 TABLE 5 Illustrative Process Stream Components for Hydrogen Generation with Enrichment Flare Feed Gas Process Gas Product Gas Component (mol. %) (mol. %) (mol. %) CH4 62.77 63.08 62.87 C2 20.45 14.04 C3 11.53 7.92 iC4 1.13 0.78 nC4 1.75 1.20 iC5 0.20 0.14 nC5 0.13 0.09 C6+ 0.12 0.08 H2 — 23.39 7.32 CO2 1.54 13.33 5.23 N2 0.39 0.19 0.33

Example 2

[0098] Similar to Example 1, Table 6 below provides illustrative composition values for a process as generally illustrated in FIG. 10 incorporating both a raw flare/associated gas bypass stream for enrichment of the product stream as well as both hydrogen separation and carbon dioxide separation for two additional product streams.

TABLE-US-00006 TABLE 6 Illustrative Process Stream Components for Hydrogen and Carbon Dioxide Generation with Enrichment Feed Gas H2 Gas CO2 Gas Product Gas 3 Component (mol. %) (kg/day) (kg/day) (mol. %) CH4 60.00 67.54 C2 14.76 11.43 C3 10.19 6.42 iC4 1.02 0.45 nC4 3.54 1.28 iC5 0.81 0.16 nC5 0.94 0.19 C6+ 2.93 0..41 H2 — 1151 6.59 CO2 0.32 13159 0.99 N2 5.48 4.50 MeOH 0.05

Examples 3-6

[0099] Examples 3-6 illustrate the ability of an HHR module according to the disclosure to provide a controllable, variable-composition platform gas using the same installed configuration of process equipment, but with a varied inlet steam:carbon ratio and temperature for the first (HHR) reactor. The HHR module is as illustrated in FIG. 11, and the hydrocarbon gas feed is pure ethane. Tables 7-10 below provide stream conditions for superheated inlet to the first (HHR) reactor, wet reformate outlet from the first (HHR) reactor, and dry reformate platform gas of the HHR module (i.e., streams 142, 152, and 167, respectively, in FIG. 11).

TABLE-US-00007 TABLE 7 Example 3 Stream Properties - Hydrogen Target Product, Lower Temperature Property Superheated Feed Wet Reformate Platform Gas T (° C.) 455 566 49 P (MPa) 3.50 3.36 3.15 Steam:Carbon 4.08 — — Total Molar Flow 965.3 1083.3 363.4 (kmol/hr) Methane (mol. %) — 13.41 39.92 Ethane (mol. %) 10.91 — — Carbon Dioxide — 5.66 16.65 (mol. %) Carbon Monoxide — 0.38 1.13 (mol. %) Water (mol. %) 89.09 66.49 0.42 Hydrogen (mol. %) — 14.07 41.88

TABLE-US-00008 TABLE 8 Example 4 Stream Properties - Hydrogen Target Product, Higher Temperature Property Superheated Feed Wet Reformate Platform Gas T (° C.) 475 700 49 P (MPa) 3.4 3.2 2.98 Steam:Carbon 4.02 — — Total Molar Flow 902.4 1118.5 506.0 (kmol/hr) Methane (mol. %) — 8.18 18.2 Ethane (mol. %) 11.06 — — Carbon Dioxide — 7.33 16.0 (mol. %) Carbon Monoxide — 2.33 5.1 (mol. %) Water (mol. %) 88.94 54.76 0.42 Hydrogen (mol. %) — 27.40 60.3

TABLE-US-00009 TABLE 9 Example 5 Stream Properties - Methane Target Product, Lower Flow Rate Property Superheated Feed Wet Reformate Platform Gas T (° C.) 500 473 49 P (MPa) 3.4 3.2 2.98 Steam:Carbon 2.3 — — Total Molar Flow 396.0 988.8 396.4 (kmol/hr) Methane (mol. %) — 25.2 62.7 Ethane (mol. %) 17.78 — — Carbon Dioxide — 6.0 14.7 (mol. %) Carbon Monoxide — 0.2 0.4 (mol. %) Water (mol. %) 82.22 60 0.4 Hydrogen (mol. %) — 8.7 21.7

TABLE-US-00010 TABLE 10 Example 6 Stream Properties - Methane Target Product, Higher Flow Rate Property Superheated Feed Wet Reformate Platform Gas T (° C.) 500 473 49 P (MPa) 3.4 3.2 2.98 Steam: Carbon 2.3 — — Total Molar Flow 980.2 1106.5 427.8 (kmol/hr) Methane (mol. %) — 25.8 66.8 Ethane (mol. %) 17.78 — — Carbon Dioxide — 5.6 14.4 (mol. %) Carbon Monoxide — 0.11 0.3 (mol. %) Water (mol. %) 82.22 61.5 0.4 Hydrogen (mol. %) — 6.98 18.1

Example 7

[0100] Example 7 illustrates the ability of a hydrocarbon conversion system according to the disclosure to provide multiple, high purity product streams of hydrogen, methane, and carbon dioxide using a modular system design. The hydrocarbon conversion system includes an HHR module, carbon dioxide separator, hydrogen separator module, and SNG module as illustrated in FIGS. 11 and 15. The HHR module is operated as described above for a hydrogen main product at a high reactor temperature as described above for Example 4, and the hydrocarbon gas feed is pure ethane. Table 11 below provides stream conditions for the various process streams illustrated in FIG. 16.

TABLE-US-00011 TABLE 11 Example 7 Stream Properties Property 1 2 Steam 3 4 5 6 7 8 Total   99.8   99.8 802.5 902.3  902.3  902.3  1118.5 1118.5 1118.5 Molar Flow (kmol/hr) Methane — — — — — — 8.18 8.18 8.18 (mol. %) Ethane 100 100 — 11.1 11.1 11.1 — — — (mol. %) Carbon — — — — — — 7.33 7.33 7.33 Dioxide (mol. %) Carbon — — — — — — 2.33 2.33 2.33 Monoxide (mol. %) Water — — 100   88.9 88.9 88.9 54.8 54.8 54.8 (mol. %) Hydrogen — — — — — — 27.4 27.4 27.4 (mol. %) Property 9 10 11 12 13 14 15 16 17 Total 1118.5 1080.4 1080.4 507.2 424.6 186.1 185.2 185.2 138.8  Molar Flow (kmol/hr) Methane 8.18 8.47 8.47 18.0 21.5 49.0 49.2 49.2 82.4 (mol. %) Ethane — — — — — — — — — (mol. %) Carbon 7.33 7.59 7.59 14.0 — 0.01 0.01 0.01  2.04 Dioxide (mol. %) Carbon 2.33 2.41 2.41 5.14 6.13 14.0 14.1 14.1 — Monoxide (mol. %) Water 54.8 53.2 53.2 0.43 0.38 0.86 0.41 0.41 15.2 (mol. %) Hydrogen 27.4 28.4 28.4 60.2 72.0 36.2 36.3 36.3  0.34 (mol. %) Property 18 19 20 21 22 23 Total 138.8  138.8  118.2   238.5 88.31  1.12 Molar Flow (kmol/hr) Methane 82.4 82.4 96.7  — 0.09 6.24 (mol. %) Ethane — — — — — — (mol. %) Carbon  2.04  2.04 2.40 — 91.7  73.64 Dioxide (mol. %) Carbon — — — — — 1.14 Monoxide (mol. %) Water 15.2 15.2 0.47 — 8.18 4.57 (mol. %) Hydrogen  0.34  0.34 0.40 100 0.06 13.4 (mol. %)

[0101] U.S. Publication No. 2019/0024003 is incorporated herein by reference in its entirety.

[0102] Because other modifications and changes varied to fit particular operating requirements and environments will be apparent to those skilled in the art, the disclosure is not considered limited to the example chosen for purposes of illustration, and covers all changes and modifications which do not constitute departures from the true spirit and scope of this disclosure.

[0103] Accordingly, the foregoing description is given for clearness of understanding only, and no unnecessary limitations should be understood therefrom, as modifications within the scope of the disclosure may be apparent to those having ordinary skill in the art.

[0104] All patents, patent applications, government publications, government regulations, and literature references cited in this specification are hereby incorporated herein by reference in their entirety. In case of conflict, the present description, including definitions, will control.

[0105] Throughout the specification, where the compositions, processes, kits, or apparatus are described as including components, steps, or materials, it is contemplated that the compositions, processes, or apparatus can also comprise, consist essentially of, or consist of, any combination of the recited components or materials, unless described otherwise. Component concentrations can be expressed in terms of weight concentrations, unless specifically indicated otherwise. Combinations of components are contemplated to include homogeneous and/or heterogeneous mixtures, as would be understood by a person of ordinary skill in the art in view of the foregoing disclosure.

FIGURE COMPONENTS LIST

[0106] 50 hydrocarbon (or gas) conversion system [0107] 60 system feed stream(s) [0108] 62 hydrocarbon gas feed stream [0109] 64, 66 additional hydrocarbon feed or bypass/enrichment stream(s) [0110] 70 system product stream(s) [0111] 72 hydrogen gas stream [0112] 74 product gas stream [0113] 76 additional product stream(s) [0114] 80 methane separator [0115] 81 NGL separator [0116] 82 NGL run tank [0117] 90 auxiliary system(s) [0118] 100 heavy hydrocarbon reactor (HHR) module [0119] 102 first inlet (hydrocarbon feed) [0120] 104 second inlet (recycled water) [0121] 105 third inlet (makeup water) [0122] 106 first outlet (platform gas) [0123] 107 second outlet (deaerated reformate gas) [0124] 112 recycled system water [0125] 114 platform gas [0126] 120 steam generator [0127] 122 boiler [0128] 124 steam drum/reservoir [0129] 126 output steam [0130] 130 mixer [0131] 132 feed gas [0132] 134 additional flow mixer(s) [0133] 136 additional flow splitter(s) [0134] 140 super heater [0135] 142 superheated feed gas [0136] 150 first reactor or heavy hydrocarbon reactor (HHR) [0137] 152 first reformate [0138] 154 heating or heat exchange streams [0139] 160 cooler [0140] 162 collection or mixing point/water reservoir [0141] 163 system water [0142] 164 chiller [0143] 166 water separator [0144] 167 dried first reformate [0145] 168 de-aerator [0146] 169 recycled water stream [0147] 170 recuperative heat exchangers [0148] 172 first heat exchanger [0149] 174 second heat exchanger [0150] 176 third heat exchanger [0151] 180 vaporizer [0152] 182 flow splitter [0153] 184 recycled water to steam generator/boiler [0154] 186 recycled water to vaporizer or steam generator/reservoir [0155] 188 steam to steam generator (or steam drum) [0156] 200 carbon dioxide separator (002) module [0157] 202 first inlet [0158] 206 first outlet [0159] 208 second outlet [0160] 210 carbon dioxide separator [0161] 212 intermediate product stream [0162] 300 hydrogen separator (H2) module [0163] 302 first inlet [0164] 304 first outlet [0165] 306 second outlet [0166] 308 third outlet [0167] 310 hydrogen separator [0168] 312 tail gas [0169] 320 compressor [0170] 322 compressed tail gas [0171] 400 synthetic natural gas (SNG) module [0172] 402 first inlet [0173] 406 first outlet [0174] 408 second outlet [0175] 410 heater (or heat exchanger) [0176] 420 second reactor or synthetic natural gas (SNG) reactor [0177] 422 wet synthetic natural gas [0178] 430 cooler [0179] 434 chiller [0180] 436 water separator [0181] 437 dried synthetic natural gas [0182] 439 recycled water