WO2025059409A1

WO2025059409A1 - Method and system for converting non-methane hydrocarbons to recover hydrogen gas and/or methane gas therefrom

Info

Publication number: WO2025059409A1
Application number: PCT/US2024/046538
Authority: WO
Inventors: Robert Terry KENNON; Dean C. HOAGLAN; Karen Lizeth DELFIN
Original assignee: Proteum Energy LLC
Current assignee: Proteum Energy LLC
Priority date: 2023-09-14
Filing date: 2024-09-13
Publication date: 2025-03-20
Anticipated expiration: 2026-03-14

Abstract

The disclosure relates to methods, systems, and apparatus arranged and designed for converting liquid and/or gaseous non-methane hydrocarbons 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 hydrocarbon liquid or gas feed. The platform gas may be separated and/or further reacted to form a pure hydrogen gas stream and/or a syngas stream. 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.

Description

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

CROSS REFERENCE TO RELATED APPLICATION

[0001] Priority is claimed to U.S. Provisional Application No. 63/538,491 (filed September 14, 2023), which is incorporated herein by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

Field of the Disclosure

[0002] The disclosure relates to methods, systems, and apparatus arranged and designed for converting non-methane hydrocarbon gases and liquids, including oxygenated hydrocarbons like ethanol, into multiple product gas streams including a predominately hydrogen gas stream and a predominately methane gas steam.

Brief Description of Related Technology

[0003] Oil wells often have an amount of natural gas associated with them (also referred to herein as "associated gas" and "flare gas"). Crude oil and natural gas are extracted from the oil wells together, and the natural gas and crude oil must be separated. In remote areas with insufficient infrastructure or where the economics present a challenge, this associated gas may be flared. The flaring process causes carbon dioxide and volatile organic compound emissions and is being targeted for removal for environmental protection reasons. In addition, the flaring process wastes substantial amounts of valuable energy by unproductively burning the associated gas and is attracting increasing scrutiny for such waste.

[0004] Natural gas associated with oil wells can be high in alkanes other than methane (C 1 ), such as ethane (C2), propane (C3) and butane (C4). These higher carbon number alkanes are of high caloric value compared to methane and can result in the associated gas having a heating value exceeding the limits for use as a conventional fuel in natural gas engines and other applications. In order to reduce the heating value of the associated gas to a range that is consistent with application specifications, the majority of the C2+ hydrocarbons are often removed producing a methane-rich gas which can be used as a conventional fuel. This gas conditioning process wherein a methane-rich gas is produced results in a by-product stream consisting predominately of the high heating value C2+ hydrocarbons which are generally referred to as natural gas liquids (“NGLs”) and which are typically unusable as fuel. The by-product NGLs are generally transported off-site for further processing which adds to the cost and complexity of using associated gas as a conventional fuel.

[0005] The most common remote processing technologies for NGL separation include mechanical refrigeration units (“MRU”), Joule-Thompson Skids (“JT Skid”) and membrane systems. Each of these methods separates a portion of the NGLs to provide a useable methane-rich gas, but also yields a typically unusable, high heating value NGL stream which must be collected, stored and ultimately transported off-site for processing, adding to overall costs and complexity. The alternative of converting the entire associated gas stream into a liquid fuel, referred to as gas-to-liquid (“GTL”), has so far proven to be uneconomic at the scale needed to process associated gas in the field. Both processes are energy intensive and typically require onsite electrical power generation.

[0006] Although these methods address excessive NGL content in associated gas, which often renders the gas unusable as a conventional fuel, they increase the cost and complexity of using associated gas as a fuel due to the added burden of NGL separation, storage and transportation. In cases where the associated gas is used as a conventional fuel, the engine is generally de-rated, yielding a significant loss in performance and efficiency. In addition, using associated gas as fuel can increase emissions and reduce engine life.

[0007] Oxygenated hydrocarbons, including methanol and ethanol, are attractive feed stocks for steam reforming. Corn and cellulosic ethanol offer advantages over methane and other alkane feedstocks due to their biogenic nature. For instance, ethanol produced from corn is a renewable fuel because the carbon dioxide released when it is combusted is consumed by corn as it grows, resulting in no increase in atmospheric carbon dioxide from use of the fuel. When ethanol is steam reformed the resulting product gases, including hydrogen and methane, are also renewable owing to ethanol-derived, biogenic carbon which is released during reformation to produce the hydrogen, and contained in the methane coproduct. As such, corn ethanol is an attractive feedstock for renewable hydrogen and renewable natural gas as neither product gas yields an increase in atmospheric carbon dioxide when used as fuel. Cellulosic ethanol also represents an attractive biogenic feedstock for non-methane steam reformation due to the plant and organic feedstock used in its production.

[0008] Although corn and cellulosic ethanol represent attractive renewable fuels, their production is energy intensive, generally requiring fossil-based energy inputs resulting in greenhouse gas emissions (GHG), including carbon dioxide. In addition, reformation of ethanol is also energy intensive and contributes to the total emissions associated with the production of ethanol-derived product gases including hydrogen and methane. There are various methodologies for totaling and allocating these GHG emissions to the ethanolderived product gases providing a carbon intensity measure for each product gas. These GHG emissions, and related carbon intensity, can be minimized through various strategies including the use of non-fossil energy inputs including biogas and solar power, and the use of carbon capture and sequestration (CCS) to mitigate the release of carbon dioxide to the atmosphere. Incorporating these and other GHG mitigation strategies can yield renewable hydrogen, renewable natural gas, and other ethanol-derived renewable product gases with low or negative carbon intensity measures.

[0009] Methods exist for generating hydrogen from hydrocarbon streams, but scale and energy requirements have so far prevented economically viable application of such methods, especially in remote, distributed generation applications. For example, hydrogen gas can be produced using several different processes including thermochemical dissociation of hydrocarbons, electrolysis of water and anaerobic digestion of organic biomass. Hydrogen can be produced in centralized, large scale plants or in distributed, small scale facilities. There are cost tradeoffs between the two approaches with centralized production yielding a reduction in production cost but an increase in distribution cost compared to the opposite for distributed production due largely to lack of scale economies.

[0010] The least expensive and most common method for producing hydrogen is steam methane reforming (“SMR”). This process is complex and energy intensive due to the high temperatures required to dissociate the carbon and hydrogen molecules comprising methane gas. This results in increased cost and carbon intensity when compared to steam reforming non-methane hydrocarbons, especially ethanol. As such, small-scale, distributed SMR is difficult economically and, regardless of scale, the produced hydrogen is nonrenewable and higher in carbon intensity compared to steam non-methane reforming. Although hydrogen production and use in large integrated facilities is economically viable, the remote use of such hydrogen is too costly to compete with alternative fuel sources owing to hydrogen’s high cost of storage and transportation. Water electrolysis is more suitable for distributed production but due to the high energy requirements of the process the hydrogen production cost has so far proved uneconomic.

[0011] Steill et al. U.S. Publication No. 2019/0024003 addresses these problems with methods and systems for converting associated gas in which a volume of methane and a volume of other alkanes may be cleaned of the other alkanes using a steam reformer system to create synthesis gas. The disclosed method may then further process the synthesis gas to convert it to a methane rich process gas which may be combined with flare gas to form an enriched product gas with a specific caloric value and methane number.

[0012] Kennon et al. U.S. Publication No. 2022/0009773 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.

SUMMARY

[0013] In various aspects, the disclosure relates to a hydrocarbon conversion system for forming one or more of a hydrogen gas stream, a carbon dioxide gas stream, a methane gas stream, and a product gas stream from a hydrocarbon feed stream comprising non-methane hydrocarbons, including oxygenated hydrocarbons, and optionally methane. As used herein, reference to a hydrocarbon gas feed stream and a gas conversion system can more generically apply to, or otherwise be used interchangeably with, a hydrocarbon feed and a hydrocarbon conversion system, respectively, for example when processing liquid hydrocarbons to be vaporized, including oxygenated hydrocarbons, as components of the system feed. The system feed can also comprise a combination of liquid hydrocarbons and gaseous hydrocarbons in the same or separate feed steams/inlets.

[0014] In an aspect, the disclosure relates to a hydrocarbon conversion system and related method for converting a hydrocarbon gas feed (or hydrocarbon feed) stream comprising one or more non-methane hydrocarbons, water, 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 can be a modular system, for example comprising a heavy hydrocarbon reforming (HHR) module alone or in combination with one or more other modules or unit operations such as one or more carbon dioxide separators or modules, a methanation reactor or synthetic natural gas (SNG) module, hydrogen separator or separator module, and/or a methane separator or separator module. Using a modular design, the HHR module is flexible in that it can provide a platform gas output with a targeted, selectable distribution between hydrogen and methane components using a single, consistent set of unit operations by adjusting the operating conditions thereof. The flexibility of the HHR module platform gas output allows selection of further downstream unit operation modules to provide fuel product outputs corresponding specifically to a given user’s needs.

[0015] The heavy hydrocarbon reforming (HHR) module comprises: a first inlet for receiving the one or more non-methane hydrocarbons (e.g., of the hydrocarbon gas feed stream); a first outlet for delivering a platform gas comprising methane and hydrogen; a second outlet for delivering a combustion flue gas; a third outlet for delivering steam; at least one of a vaporizer and a heater (e.g., one or both of the apparatus); a first (HHR) reactor, a cooler, and a steam generator. The platform gas can be the product gas when there are no further downstream modules. Alternatively, the platform gas can be an intermediate gas fed to one or more further downstream modules for separation and/or reaction.

[0016] The vaporizer and/or heater are adapted to (i) receive a feed stream comprising in admixture the one or more non-methane hydrocarbons and water and (ii) output the feed stream as the hydrocarbon gas feed stream at a predetermined temperature. For example, the feed stream can be liquid phase (e.g., liquid ethanol and liquid water), gas phase (e.g., gaseous ethane and steam), or gas/liquid multiphase (e.g., liquid ethanol, liquid water, gaseous ethane, and/or steam; optionally also including methane). The hydrocarbon gas feed stream output is essentially all gas phase such as when a vaporizer is used to vaporize an at least partially liquid feed stream, or when a heater/superheater is used to heat a feed stream already in gas phase. The predetermined temperature can be the desired inlet reactor temperature such as when a heater/superheater is used, or it can be an intermediate temperature that requires further heating (e.g., via downstream heat exchangers) to reach the desired inlet reactor temperature).

[0017] The first (HHR) reactor contains a first catalyst (e.g., a catalyst fill comprising at least one catalyst, two or more catalysts, layers of different catalysts) and is adapted to (i) receive the hydrocarbon gas feed stream in fluid communication with the first reactor and (ii) receive an inlet heating fluid (e.g., providing heat/energy for an endothermic reforming reaction), wherein the first reactor and the first catalyst are adapted to thereby (i) form a first reformate comprising the carbon oxides, the hydrogen, the methane, and water (e.g., a wet first reformate), and (ii) form an outlet heating fluid (e.g., a combustion flue gas exiting the reactor). In an embodiment, the HHR reactor can be a "box furnace" style reactor containing internal, catalyst-filled tubes. The furnace has gas-fired burners which can be located at the top, side, and/or bottom of the box furnace such that combustion takes place inside the reactor. When burners are located at top or bottom of the furnace only (or when burners generally present throughout the reactor are selectively activated), the feed gas can be concurrent or counter-current to heating.

[0018] The cooler is 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. The initial (wet) reformate streams exiting the reactors generally contain 40 to 80 mol.% (or vol.%) water, for example at least 40, 45, 50, 55, or 60 mol.% and/or up to 60, 65, 70, 75, or 80 mol.% water. The cooler typically removes at least 85% of the water in the initial reformate, for example removing at least 85, 90, 95, 98, or 99% of the water. The dried reformate streams exiting the cooler or other water separator system generally contain up to 20 mol.% (or vol.%) water, for example at least 0.1, 0.2, 0.5, 1, 2, or 5 mol.% and/or up to 1, 2, 3, 5, 7, 10, 15, or 20 mol.% water.

[0019] The steam generator is adapted to (i) receive the recycled system water stream (e.g., a portion or all of the recycled system water stream from the cooler), (ii) receive the outlet heating fluid, and (iii) output steam (e.g., using the outlet heating fluid as a heat/energy source to vaporize recycled system water). The recycled system water can generally include water removed from the platform gas and other system modules and unit operations, a downstream SNG module, make-up water, or fresh water for initial charge.

[0020] 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 one or more non-methane hydrocarbons, water, and optionally methane comprises: feeding the one or more nonmethane hydrocarbons (e.g., feed optionally also can include water and/or methane; water also can be fed from a different external source and/or be recycled system water added to the feed stream ) to a hydrocarbon conversion system comprising the HHR module; receiving the one or more non-methane hydrocarbons at the first inlet in combination with at least one of (i) water co-fed with the one or more non-methane hydrocarbons at the first inlet and (ii) water added to the one or more non-methane hydrocarbons (e.g., at least some recycled system water within the HHR module and/or other unit operations and, optionally, fresh water added/fed to the HHR module at a different inlet) to provide a feed stream comprising in admixture the one or more non-methane hydrocarbons and the water; feeding the feed stream to the at least one of the vaporizer and the heater, thereby forming a hydrocarbon gas feed stream at a predetermined temperature; feeding (i) the hydrocarbon gas feed stream and (ii) an inlet heating fluid to the first reactor to react at least a portion of the non-methane hydrocarbons (e.g., and optionally methane, which can occur at higher reactor temperatures) in the hydrocarbon gas feed stream, thereby forming (i) a first reformate comprising carbon oxides, hydrogen, methane, and water, and (ii) an outlet heating fluid; separating at least a portion of the water from the first reformate in the cooler, thereby providing (i) a dried first reformate and (ii) a recycled system water stream; feeding at least a portion of (i) the recycled system water stream and (ii) the outlet heating fluid to the steam generator, thereby forming steam; delivering the dried first reformate as a platform gas via the first outlet, the platform gas comprising at least one of (i) a hydrogen gas stream and (ii) a product gas stream; delivering the outlet heating fluid from the steam generator as a combustion flue gas via the second outlet; delivering the steam from the steam generator via the third outlet; 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.

[0021] Various refinements and embodiments of the disclosed systems and methods are possible.

[0022] In a refinement of the modular system design, the HHR module is free from at least one of methane separators, hydrogen separators, carbon dioxide separators, and synthetic natural gas (SNG) reactors. In view of the modular design of the hydrocarbon conversion system, the HHR module is generally not designed to perform some or all of typical operations associated with methane separation, hydrogen separation, carbon dioxide separation, and/or SNG production, such operations generally being performed upstream or downstream of the HHR module, depending on a particular user’s desired final product(s) of the hydrocarbon conversion system. The HHR module being free from such operations (e.g., free from corresponding unit operation apparatus) can be expressed as the HHR module (or hydrocarbon conversion system more generally) not containing one or more of methane separators, hydrogen separators, carbon dioxide separators, and/or SNG reactors downstream of the outlets and/or upstream of the first inlets. Even in such cases where the HHR module is free from various separators and/or SNG reactors, the HHR module can include multiple reactors for forming multiple reformate streams to increase production capacity, for example including multiple HHRs in parallel to form multiple reformate streams in parallel. Such multiple reformate streams could remain in parallel streams, consolidated into fewer streams or a single stream, etc. for subsequent cooling and water removal.

[0023] In a refinement of the modular system design, the hydrocarbon conversion system or method is free from further separation or reaction apparatus or steps downstream of the HHR module first outlet; and the platform gas is the product gas stream. In some embodiments, the platform gas can be used as the final fuel product of the hydrocarbon conversion system, for example for use as a hydrogen-rich turbine fuel. In such cases, the platform gas can be used as is, or it 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), but it need not be subjected to further separation and/or reaction steps or unit operations.

[0024] In some embodiments, the hydrocarbon conversion system includes at least one of a deaerator module and/or a cooling tower adapted to (i) receive water containing small amounts of hydrocarbons and carbon oxides from the HHR module and/or other unit operations and (ii) supply essentially pure recycle water to the HHR module and/or other unit operations. In another aspect, the hydrocarbon conversion system does not include a deaerator and/or a cooling tower, and recycle water from the HHR and/or other unit operations can be combined in a recycle water storage tank and supplied to the HHR and other unit operations as required.

[0025] The hydrocarbon feed stream in various aspects includes non-methane hydrocarbons, for example including oxygenated hydrocarbons like ethanol and/or nonoxygenated hydrocarbons like ethane, and optionally methane. Namely, in some embodiments, the hydrocarbon feed can include methane. In other embodiments, the hydrocarbon feed can exclude or otherwise be substantially free from methane. For example, in some embodiments, methane is present in a flare gas/associated gas stream that can be used as a feed to the disclosed system, but such methane is an optional component of the hydrocarbon feed stream in the event of an upstream Joule-Thompson (JT) or other NGL separation. In other embodiments, methane can be absent from the hydrocarbon feed stream when a feedstock other than a flare gas/associated gas stream is used (e.g., ethane, ethanol, or other feed gas or liquid). The hydrocarbon feed stream may be a gas, liquid, vaporized liquid, or a combination of the foregoing.

[0026] In a refinement, the one or more non-methane hydrocarbons in the hydrocarbon gas feed stream or corresponding inlet stream (e.g., as fed to the HHR module) are selected from C2 hydrocarbons, C3 hydrocarbons, C4 hydrocarbons, 05 hydrocarbons, 06 hydrocarbons, and combinations (e.g., mixtures) thereof. Examples of suitable non-methane hydrocarbons include ethane, propane, butane, pentane, and hexane, including linear and branched isomers thereof. More generally, the non-methane hydrocarbons can include hydrocarbons with two or more carbon atoms (e.g., “02+ hydrocarbons”), for example including some hydrocarbons with more than six carbon atoms, for example including C7+, C8+, C9+, or 010+ hydrocarbons (e.g., up to 010, 012, or 015) such as naphtha, etc. In some embodiments, the non-methane hydrocarbons can include oxygenated hydrocarbons, for example alcohols such as a methanol, ethanol, n-propanol, isopropanol, etc. (e.g., 01, 02, 03, 04, 05, or 06 alcohols). Such alcohols can be included with the alkane hydrocarbons listed above, or instead of the alkane hydrocarbons listed above, for example including a hydrocarbon gas feed composed primarily of ethanol as the reformation reactant. Other non-hydrocarbon components of the hydrocarbon gas feed stream can include carbon dioxide, nitrogen, water vapor, hydrogen sulfide, and combinations thereof.

[0027] In a refinement, the one or more non-methane hydrocarbons received at the first inlet comprise at least one liquid-phase non-methane hydrocarbon; and the feed stream comprises liquid water co-fed with the one or more non-methane hydrocarbons at the first inlet (e.g., liquid phase mixture of liquid water and liquid ethanol and/or other liquid alcohols). In a further refinement, the one or more non-methane hydrocarbons received at the first inlet further comprise at least one gas-phase non-methane hydrocarbon (e.g., gaseous ethane in a multiphase mixture with the liquid water/ethanol; such as without any steam fed to the first inlet).

[0028] In a further refinement, the HHR module further comprises: a second inlet for receiving one or more additional gaseous non-methane hydrocarbons (e.g., ethane); and the heater and the vaporizer, in which the heater is adapted (i) to receive and heat the one or more additional gaseous non-methane hydrocarbons from the second inlet, and (ii) to feed the heated one or more additional gaseous non-methane hydrocarbons to the vaporizer along with the feed stream (e.g., as a multiphase mixture of the liquid ethanol, liquid water, gaseous ethane, and optionally gaseous water); the method further comprises: receiving the one or more additional gaseous non-methane hydrocarbons at the second inlet; feeding the one or more additional gaseous non-methane hydrocarbons to the heater, thereby forming the heated one or more additional gaseous non-methane hydrocarbons at a predetermined temperature; and combining (e.g., mixing) the heated one or more additional gaseous non- methane hydrocarbons with one or both of (i) the feed stream before feeding both to the vaporizer to form the hydrocarbon gas feed stream, and (ii) the hydrocarbon gas feed stream downstream of the vaporizer. This is illustrated in Fig. 9 in which a first feed of liquid ethanol and liquid water is received at a first inlet, and gaseous ethane is received at a second inlet, and the two streams are blended before being fed to the vaporizer. As also illustrated in Fig. 9 as an alternative, the heated gaseous ethane can be blended with the vaporized ethanol water mixture downstream of the vaporizer. Although this embodiment can accommodate any relative blend or mixture of gaseous and liquid hydrocarbon feeds, it can accommodate limiting cases in which only liquid-phase non-methane hydrocarbons are fed via the first inlet (e.g., and no feed via the second inlet), or in which only gas-phase non-methane hydrocarbons are fed via the second inlet (e.g., and no feed via the first inlet). In other cases, the combined feed between the two inlets can be about 10-90% liquid non-methane hydrocarbons (on a molar or weight basis) and about 10-90% gaseous non-methane hydrocarbons (on a molar or weight basis), for example at least 10, 20, 30, 40, 50, 60, or 70% liquid non-methane hydrocarbons, up to 30, 40, 50, 60, 70, 80, or 90% liquid nonmethane hydrocarbons, at least 10, 20, 30, 40, 50, 60, or 70% gaseous non-methane hydrocarbons, and/or up to 30, 40, 50, 60, 70, 80, or 90% gaseous non-methane hydrocarbons.

[0029] In a refinement, the one or more non-methane hydrocarbons received at the first inlet comprise at least one gas-phase non-methane hydrocarbon (e.g., gaseous ethane, such as without any liquid water or steam); and the feed stream comprises water added to the one or more non-methane hydrocarbons downstream of the first inlet. For example, the feed stream can include a gas phase mixture of steam and gaseous ethane when combined with steam from a (second) steam generator within the HHR module. Alternatively, the feed stream can include a multiphase mixture of gaseous ethane with liquid water from the recycled system water (cooler condensate) and/or from a fresh liquid water feed to the HHR module (e.g., steam is not added to the hydrocarbon gas feed stream and/or the HHR module does not contain a second steam generator to provide steam to the hydrocarbon gas feed stream). In a further refinement, the one or more non-methane hydrocarbons received at the first inlet further comprise at least one liquid-phase non-methane hydrocarbon (e.g., gaseous ethane in a multiphase mixture with liquid ethanol; such as with or without any liquid water and/or steam fed to the first inlet).

[0030] In a refinement, the hydrocarbon gas feed stream or corresponding inlet stream comprises methane (i.e. , in addition to non-methane hydrocarbons such as the C2+ hydrocarbons). Depending on the particular source of the feedstock, the methane content of the feed gas ranges up to 90 mol.% (or vol. %), with the C2+ hydrocarbons being substantially the balance of the feed. For example, the hydrocarbon gas feed stream suitably contains at least 20, 30, 40, 50, 60, or 70 mol.% methane and up to 50, 60, 70, 80, or 90 mol.% methane. Similarly, the hydrocarbon gas feed stream suitably contains less than 20, 15, 10, 5, 2, 1 , 0.5, 0.2, or 0.1 mol.% of gas species (e.g., nitrogen, carbon dioxide, or other inert gases) other than methane and non-methane hydrocarbons combined.

[0031] In a refinement, the hydrocarbon gas feed stream or corresponding inlet stream is substantially free from methane. This can be the case, for example, when methane is present in a flare gas/associated gas stream, but is substantially absent in the feed to the gas conversion system in the event of upstream JT or other NGL separation, or fractionation, or when using propane or other feed gas. For example, the hydrocarbon gas feed stream can be a result of upstream methane separation providing a feed gas with less than

20 mol.% (or vol. %) methane, with the C2+ hydrocarbons being substantially the balance of the feed. Thus, the hydrocarbon gas feed stream can be free or substantially free from methane. In various embodiments, the hydrocarbon gas feed stream suitably contains at least 0.01, 0.1, 0.2, 0.5, 1, 2, or 5 mol.% methane and up to 1, 2, 5, 10, 15, 20, 25, or

30 mol.% methane. Similarly, the hydrocarbon gas feed stream suitably contains less than 15, 10, 5, 2, 1, 0.5, 0.2, or 0.1 mol.% of gas species other than methane and non-methane hydrocarbons combined. When a non-methane-containing stream is used as the initial feedstock, the hydrocarbon gas feed stream suitably contains less than 15, 10, 5, 2, 1, 0.5, 0.2, or 0.1 mol.% of gas species other than all non-methane hydrocarbons combined (e.g., up to essentially 100 mol.% C2+ hydrocarbons of varying species in any suitable distribution).

[0032] In a refinement, the combustion flue gas comprises nitrogen (e.g., elemental nitrogen, such as in nitrogen-containing NOx species, N2, etc.), carbon dioxide, oxygen (e.g., elemental oxygen, such as in oxygen-containing NOx species, etc., but not water), and water. A representative flue gas composition can include 2-20 mol.% carbon dioxide, 50- 90 mol.% nitrogen, 0.1-5 mol.% oxygen, and 10-30 mol.% water. A typical flue gas outlet exiting the HHR reactor is about 950-1050°C. Combustion is performed inside HHR reactor by supplying fuel to the HHR burners which combust inside.

[0033] The reformate stream(s) in any aspect similarly include methane as an optional component, in addition to its carbon oxide and hydrogen components. The methane can be present in the reformate based on methane present in the hydrocarbon feed stream and/or methane formed in the HHR reactor via methanation/reverse reaction of an equilibrium steam reformation reaction. In other cases, the reformate stream can have very little or be essentially free from methane, for example containing only minor or trace amounts of methane.

[0034] The dry reformate or platform gas in any aspect includes predominantly hydrogen, methane and carbon oxides, along with water. In various embodiments, the specific composition of the reformate or platform gas can be selected and controlled to be within relatively broad ranges by varying steam:carbon ratio and reaction temperature in the first reactor of the HHR module. For example, the methane content of the platform gas can be in a range of 0.10-80 mol.%, for example at least 0.1 , 10, 20, 30, 40, 50, or 60 mol.% and/or up to 30, 40, 50, 60, 70, or 80 mol.%. The hydrogen content of the platform gas can be in a range of 10-80 mol.%, for example at least 10, 20, 30, 40, or 50 mol.% and/or up to 30, 40, 50, 60, 70 or 80 mol.%. The carbon dioxide content of the platform gas can be in a range of 5-30 mol.% or 10-30 mol.%, for example at least 5, 8, 10, 12 or 14 mol.% and/or up to 12, 16, 20, 2, or 30 mol.%. The carbon monoxide content of the platform gas can be in a range of 0.01-10 mol.%, for example at least 0.01, 0.1, 0.2, or 0.5 mol.% and/or up to 1 , 2, 3, 5, 7, or 10 mol.%. The water content of the platform gas can be in a range of 0.01-5 mol.%, for example at least 0.01 , 0.1 , 0.2, or 0.5 mol.% and/or up to 0.5, 1, 2, 3, or 5 mol.%.

[0035] In a refinement, the method comprises: feeding the hydrocarbon gas feed stream to the first reactor at first operating conditions having a selected steam:carbon ratio and having a selected reaction temperature favoring methane production in the first reactor, in the resulting first reformate, and in the resulting platform gas; wherein: the steam:carbon ratio for the first operating conditions is up to 2.6; the reaction temperature for the first operating conditions is characterized by an inlet temperature to the first reactor in a range of 400°C to 550°C; the reaction temperature for the first operating conditions is characterized by an outlet temperature of the first reactor within 100°C of the inlet temperature (e.g., temperature difference between hydrocarbon gas feed stream and first (wet) reformate); and the platform gas has (e.g., after passing through cooler/condensate drum): a methane content in a range of 40 mol.% to 70 mol.%; a hydrogen content in a range of 10 mol.% to 30 mol.%; a carbon dioxide content in a range of 10 mol.% to 30 mol.%; optionally a carbon monoxide content in a range of 0.01 mol.% to 5 mol.%; and optionally a water content in a range of 0.01 mol.% to 5 mol.%.

[0036] More generally, in cases where the HHR module is operated to favor methane as a desired or targeted product, the methane content of the platform gas can be in a range of 50-80 mol.%, for example at least 50, 55, 60, 65, or 70 mol.% and/or up to 60, 65, 70, 75, or 80 mol.%. Similarly, the hydrogen content of the platform gas can be in a range of IQ- 40 mol.%, for example at least 10, 15, 20, or 25 mol.% and/or up to 20, 25, 30, 35, or 40 mol.%. Similarly, the carbon dioxide content of the platform gas can be in a range of 5- 30 mol.%, for example at least 5, 8, 10, or 12 mol.% and/or up to 12, 16, 20, 24, or 30 mol.%. Similarly, the carbon monoxide content of the platform gas can be in a range of 0.01-3 mol.%, for example at least 0.01, 0.1 , 0.2, or 0.5 mol.% and/or up to 1, 2, or 3 mol.%. Similarly, the water content of the platform gas can be in a range of 0.01-5 mol.%, for example at least 0.01 , 0.1 , 0.2, or 0.5 mol.% and/or up to 0.5, 1, 2, 3, or 5 mol.%.

[0037] In a refinement, the method comprises: feeding the hydrocarbon gas feed stream to the first reactor at second operating conditions having a selected steam:carbon ratio and having a selected reaction temperature favoring hydrogen production in the first reactor, in the resulting first reformate, and in the resulting platform gas; the steam:carbon ratio for the second operating conditions is in a range of 3 to 8; the reaction temperature for the second operating conditions is characterized by an inlet temperature to the first reactor in a range of 400°C to 850°C; the reaction temperature for the second operating conditions is characterized by an outlet temperature of the first reactor that is 50°C to 400°C higher than the inlet temperature (e.g., temperature difference between hydrocarbon gas feed stream and first (wet) reformate); and the platform gas has (e.g., after passing through cooler/condensate drum): a methane content up to 30 mol.%; a hydrogen content of at least 50 mol.%; a carbon dioxide content in a range of 10 mol.% to 30 mol.%; optionally a carbon monoxide content in a range of 0.01 mol.% to 10 mol.%; and optionally a water content in a range of 0.01 mol.% to 10 mol.%.

[0038] More generally, in cases where the HHR module is operated to favor hydrogen as a desired or targeted product, the hydrogen content of the platform gas can be in a range of 30-80 mol.%, for example at least 30, 35, 40, 45, or 50 mol.% and/or up to 50, 55, 60, 65, or 70, 75, or 80 mol.%. Similarly, the methane content of the platform gas can be in a range of 0.10-50 mol.%, for example at least 0.1 , 1.0, 2.5, 5.0, 7.5, 10, 15, 20, 25, or 30 mol.% and/or up to 15, 20, 25, 30, 35, 40, 45, or 50 mol.%. Similarly, the carbon dioxide content of the platform gas can be in a range of 5-40 mol.%, for example at least 5, 8, 10, 12, or 14 mol.% and/or up to 12, 16, 20, 24, 30, 35, or 40 mol.%. Similarly, the carbon monoxide content of the platform gas can be in a range of 0.1-10 mol.%, for example at least 0.1, 0.2, or

0.5 mol.% and/or up to 1, 2, 3, 5, 7, or 10 mol.%. Similarly, the water content of the platform gas can be in a range of 0.01-10 mol.%, for example at least 0.01 , 0.1, 0.2, or 0.5 mol.% and/or up to 1, 2, 5, 7, or 10 mol.%.

[0039] In a refinement, the method further comprises: operating the first reactor under at least one of the first operating conditions favoring methane production and the second operating conditions favoring hydrogen production; and subsequently operating under the other of the first operating conditions favoring methane production or the second operating conditions favoring hydrogen production. This can be performed, for example, using suitable process control electronics/computer system as part of the hydrocarbon conversion system to monitor and adjust reaction/reactor temperature, steam:carbon ratio, reactant feed, product output, etc. to continuously operate under a specific set of operating conditions or switch between different sets of operating conditions.

[0040] In a refinement, the method further comprises: operating the first reactor under the first operating conditions favoring methane production as an isothermal reactor; and operating the first reactor under the second operating conditions favoring hydrogen production as a temperature increase-controlled reactor.

[0041] In a refinement, the method comprises: operating the first reactor as an adiabatic reactor, an isothermal reactor, a temperature increase-controlled reactor, or a temperature decrease-controlled reactor.

[0042] In a refinement, the method comprises: feeding the inlet heating fluid to the first reactor cocurrent to the hydrocarbon gas feed stream.

[0043] In a refinement, the method comprises: feeding the inlet heating fluid to the first reactor countercurrent to the hydrocarbon gas feed stream.

[0044] In a refinement, the method comprises: adding an additional product stream and/or an external gas stream (e.g., natural gas) to at least one of the hydrogen gas stream and the product gas stream, thereby forming a designer fuel stream having a selected composition and optionally having one or more targeted fuel parameters selected from the group consisting of Wobbe Index, methane number, heating value, and combinations thereof. This is illustrated in Fig. 10, where the product gas can include any desired mixture and relative proportions of a natural gas stream (or other gas stream external to the HHR module or hydrocarbon conversion system), the platform gas (or reformate), the CO2-removed platform gas, and/or the tail gas.

[0045] The synthetic natural gas in any aspect includes predominantly methane, possibly along with minor amounts of unreacted carbon oxides and/or hydrogen, and typically at least some water. For example, wet synthetic natural gas can include methane in an amount of about 30-70 mol.%, for example at least 30, 40, or 50 mol.% and/or up to 50, 60, or 70 mol.%. Similarly, the wet synthetic natural gas can include water in an amount of about 20-60 mol.%, for example at least 20, 25, 30, or 35 mol.% and/or up to 15, 40, 50, or 60 mol.%. Similarly, the wet synthetic natural gas can include a combined amount of carbon oxides and/or hydrogen in an amount of about 1-10 mol.%, for example at least 1, 1.5, or 2, mol.% and/or up to 3, 4,5, or 6 mol.%. After water removal, dried synthetic natural gas can include methane in an amount of about 80-99 mol.%, for example at least 80, 85, or 90 mol.% and/or up to 95, 96, 97, 98, or 99 mol.%. Similarly, the dried synthetic natural gas can include water in an amount of 0.01-5 mol.%, for example at least 0.01 , 0.1, 0.2, or 0.5 mol.% and/or up to 0.5, 1 , 2, 3, or 5 mol.%. Similarly, the dried synthetic natural gas can include a combined amount of carbon oxides and/or hydrogen in an amount of about 0.1- 5 mol.%, for example at least 0.1 , 0.2, 0.5, or 1 mol.% and/or up to 0.5, 1, 2, 3, or 5 mol.%. [0046] In an alternative embodiment, the hydrocarbon or gas conversion system can incorporate a super heater into an HHR module unit operation. For example, the super heater can be incorporated into the HHR module such that the HHR reactor is adapted to receive the hydrocarbon feed stream from the super heater, wherein the super heater heats the hydrocarbon feed stream to form the superheated feed gas to the HHR reactor. Alternatively, the input to the hydrocarbon conversion system can already be in the form of a superheated feed gas including the hydrocarbon feed and water from some other source, which superheated feed gas can then be fed to the reactor(s).

[0047] As described above, the specific composition of the reformate or platform gas can be selected and controlled to be within relatively broad ranges by varying steam:carbon ratio and reaction temperature in the first reactor of the HHR module. Steam is generally admixed with the hydrocarbon feed such that the steam:carbon ratio in the resulting feed stream (and hydrocarbon gas feed stream) is in a range of 2 to 4, 5, 6, or higher. For example, the steam:carbon ratio can have a value of about 2.3 to promote methane production, such as at least 2.0, 2.1 , or 2.2 and/or up to 2.4, 2.5, or 2.6. Alternatively, the steam:carbon ratio can have a value of about 4 or higher to promote hydrogen production, such as at least 3, 3.5, 4, 4.5, 5, 6 and/or up to 4, 4.5, 5, 6, 7, or 8. The steam:carbon ratio is a molar ratio between the moles of water and moles of carbon atoms in the feed gas (e.g., 1 mol of ethanol in the feed gas provides 2 mol of carbon atoms for determination of the steam:carbon ratio). The steam in the feed can come from liquid water co-fed with a hydrocarbon feed, liquid water added to the hydrocarbon feed (e.g., from recycled system water), and/or gaseous water added to the hydrocarbon feed. In cases where liquid water is added to or a component of the hydrocarbon feed (e.g., in combination with a liquid hydrocarbon such as ethanol), the liquid components are vaporized to form steam and gaseous hydrocarbon before being fed to the first reactor. The first reactor of the HHR module can operate over a wide range of temperatures, for example in a range of about 400- 850°C. For example, the first reactor can have an inlet temperature (or superheated feed gas temperature) in a range of about 400-550°C to promote methane production, such as at least 400, 425, or 450°C and/or up to 450, 475, 500, 525, or 550°C inlet temperature, optionally with little or substantially no temperature increase or decrease at the outlet (e.g., within 25 or 50°C of inlet). Alternatively, the first reactor can have an inlet temperature (or vaporized and/or heated feed gas temperature) in a range of about 400°C to 850°C, 450°C to 800°C, or 450°C to 700°C to promote hydrogen production, such as at least 400, 425, or 450°C and/or up to 450, 475, 500, 525, or 550°C inlet temperature, further including a temperature increase at the outlet (e.g., at least 50, 75, 100, or 125°C and/or up to 100, 150, 200, 250, 300, 350, or 400°C increase relative to inlet).

[0048] In a refinement, the first reactor (e.g., and multiple reactors if present) is adapted to operate as an adiabatic reactor, an isothermal reactor, a temperature increase-controlled reactor, or a temperature decrease-controlled reactor. Isothermal operation of a reactor can include relatively small temperature gradients between inlet and outlet reactant/product streams, for example having a temperature difference or absolute temperature difference (AT or |AT|) up to about 25, 50, 75, or 100°C. Temperature increase-/decrease-controlled operation of a reactor can include a moderate temperature increase or decrease from inlet to outlet for reactant/product streams, respectively, for example having a temperature difference (AT, outlet minus inlet) of at least 50, 75, 100, 125, or 150°C and/or up to about 125, 150, 175, 200, 250, 300, 350, or 400°C for a controlled temperature increase, or at least -125, -150, -175, -200, -250, -300, -350, or -400°C, and/or up to -50, -75, -100, -125, or -150°C for a controlled temperature decrease.

[0049] In a refinement, the first reactor (e.g., and multiple reactors if present) is adapted to receive a countercurrent, (hot) heat exchange fluid, thereby providing heat to a reaction volume in the first reactor containing the first catalyst and the feed gas. More generally, the first reactor can be adapted to independently receive either a countercurrent or cocurrent heat exchange fluid, depending on whether the given reactor is configured to operate as an isothermal or adiabatic reactor for an endothermic or exothermic reaction

[0050] In a refinement, the method further comprises: feeding the platform gas to at least one of a methane separator, a carbon dioxide separator, a hydrogen separator, and a methanation reactor (e.g., synthetic natural gas (SNG) reactor) in series to provide the at least one of the hydrogen gas stream and the product gas stream. This is generally illustrated in Fig. 1, where some or all of the processes or unit operations downstream of the HHR module can be incorporated in different embodiments.

[0051] In a further refinement, the method comprises: feeding the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream. This is generally illustrated in Fig. 4, where all of the platform gas is fed to the carbon dioxide separator and the hydrogen separator in series.

[0052] In a further refinement, the method comprises: feeding a (first) portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream; and combining a (second) portion of the platform gas with a hydrogen-rich tail gas stream from the hydrogen separator to form the product gas stream. This is generally illustrated in Fig. 5, where a first flow splitter downstream of the cooler (condensate drum) can partition the platform gas as desired between the first and second portions. In limiting cases, the first flow splitter can deliver all of the platform gas to the carbon dioxide separator and the hydrogen separator in series, or all of the platform gas directly as the product gas (i.e. , without any further separation or reaction).

[0053] In a further refinement, the method comprises: feeding a (first) portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream; and combining a (second) portion of the platform gas with (i) a portion of the carbon dioxide separator outlet stream (e.g., after carbon dioxide removal but before being fed to the hydrogen separator), and (ii) a hydrogen-rich tail gas stream from the hydrogen separator and optionally an external gaseous stream (e.g., natural gas stream) to form the product gas stream. This is generally illustrated in Fig. 6, where a first flow splitter downstream of the cooler (condensate drum) can partition the platform gas as desired between the first and second portions, and a second flow splitter between the carbon dioxide separator and the hydrogen separator can partition the CO2-removed platform gas as desired between the hydrogen separator and the product gas. In limiting cases, the first flow splitter can deliver all of the platform gas to the carbon dioxide separator and the hydrogen separator in series, or all of the platform gas directly as the product gas (i.e., without any further separation or reaction). In further limiting cases, the second flow splitter can deliver all of the CO2-removed platform gas to the hydrogen separator, or all of the CO2-removed platform gas directly as the product gas (i.e., without any further separation or reaction). Fig. 10 illustrates a further refinement in which a natural gas or other external gaseous stream can be blended with the foregoing streams/stream portions to provide the product gas.

[0054] In a further refinement, the method comprises: feeding the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream; and feeding the hydrogen-rich tail gas stream to the methanation reactor to provide a methane-rich product gas (e.g., synthetic natural gas). This is generally illustrated in Fig. 7, where all of the platform gas is fed to the carbon dioxide separator and the hydrogen separator in series to provide the fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream as outputs from the hydrogen separator, followed by a methanation reaction for the tail gas to form SNG. [0055] In a further refinement, the method comprises: feeding a (first) portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream; and feeding at least one of (i) the hydrogen-rich tail gas stream, (ii) a (second) portion of the platform gas, and (iii) a portion of the carbon dioxide separator outlet stream to the methanation reactor to provide a methane-rich product gas (e.g., synthetic natural gas). This is generally illustrated in Fig. 8, where a first flow splitter downstream of the cooler (condensate drum) can partition the platform gas as desired between the first and second portions, and a second flow splitter between the carbon dioxide separator and the hydrogen separator can partition the CO2- removed platform gas as desired between the hydrogen separator and the product gas. In limiting cases, the first flow splitter can deliver all of the platform gas to the carbon dioxide separator and the hydrogen separator in series, or all of the platform gas directly to the methanation reactor. In further limiting cases, the second flow splitter can deliver all of the CO2-removed platform gas to the hydrogen separator, or all of the CO2-removed platform gas to the methanation reactor.

[0056] In a further refinement, the method comprises: feeding the platform gas to the methanation reactor to provide a methane-rich product gas (e.g., feeding all platform gas to the methanation reactor, either before or after carbon dioxide removal synthetic natural gas production only). This is also illustrated as a limiting case in Fig. 8 in which the first and second flow splitters collectively deliver all platform gas and/or CO2-removed platform gas to the methanation reaction (i.e. , the hydrogen separator is bypassed or not present, and there is no fuel cell-grade hydrogen gas stream produced).

[0057] In a further refinement, the method further comprises: feeding the combustion flue gas (e.g., from the second outlet) and the steam (e.g., from the third outlet) to a combustion carbon dioxide separator, thereby forming a carbon dioxide-rich stream. The combustion carbon dioxide separator can be an amine separator in which the steam provides the heat for the amine process fluid therein to remove carbon dioxide. The output from the combustion carbon dioxide separator can be combined with the output from additional/different carbon dioxide separators used to form the hydrogen gas stream and/or other product gas streams, thereby forming a single carbon dioxide-rich stream from the different carbon dioxide separators. As generally illustrated in the figures, there can be two types of carbon dioxide separators in the hydrocarbon conversion system - one for flue gas carbon dioxide and another for produced carbon dioxide (i.e., reformate or SNG carbon dioxide). The apparatus and specific operating conditions are different, but such carbon dioxide separators are generally known in the art. Carbon dioxide-rich streams are produced by both types of systems, with the primary purpose for separation is carbon dioxide sequestration and/or sale of carbon dioxide as product gas. In some cases, there can be a third carbon dioxide separator after the methanation reactor to remove residual carbon dioxide in the SNG product gas.

[0058] In a further refinement, the method further comprises: feeding the platform gas to at least one of a reverse water gas shift (rWGS) reactor, a Fischer-Tropsch (FT) reactor, and a hydrotreater (or hydrodesulfurization reactor) in series to provide a heavy hydrocarbon gas stream (e.g., having a distribution of hydrocarbons with between about 4 and 25 carbon atoms per molecule).

[0059] The rWGS reactor is adapted to perform a reverse water gas shift reaction favoring formation of additional carbon monoxide and water relative to that in the platform gas/dried reformate (e.g., shifting the equilibrium to convert carbon dioxide and hydrogen to carbon monoxide and water in the platform gas; rWGS reactors with suitable catalyst, reactor vessel, etc. are known in the art). The rWGS reactor is used to adjust the H2:CO ratio to a desired value/range for a subsequent FT process in which an (average) carbon number of the resulting hydrocarbons correlate to the H2:CO molar ratio in the FT reactor feed. FT reactors with suitable catalyst, reactor vessel, etc. are known in the art, and they perform a variety of chemical reactions to produce hydrocarbons, typically alkanes. A representative FT reaction is (2n+1) H2 + n CO — C_nH2n+2 + n H2O, in which case a desired hydrocarbon (alkane) product with (an average of) n carbon atoms has an inlet H2:CO molar ratio of about ((2n+1)/n).

[0060] The heavy hydrocarbon gas stream generally contains a distribution of hydrocarbons having a range of different carbon atoms per hydrocarbon molecule. The hydrocarbons are generally alkanes, primarily linear alkanes, although branched alkanes, linear or branched alkenes, and/or linear or branched alcohols are also possible, typically at low levels if present at all. The hydrocarbons in the heavy hydrocarbon gas stream can have at least 4, 5, 6, 8, 9, 10, 12, or 15 carbon atoms and/or up to 7, 10, 12, 14, 15, 16, 18, 20, or 25 carbon atoms. The foregoing values/ranges can represent upper and lower bounds of a hydrocarbon distribution (e.g., 1/99%, 5/95%, or 10/90% lower and upper carbon numbers in molar- or weight-based cumulative distribution) and/or an average (e.g., molar- or weight-based average) carbon number of the hydrocarbon distribution. Depending on the carbon number distribution, the heavy hydrocarbon gas stream can be useful as a variety of fuels, such as gasoline, diesel, aviation fuel, jet fuel. [0061] In a further refinement, the method further comprises: feeding one or more components of the platform gas to a methanol production process for the synthesis of methanol from products of the HHR module (e.g., blue and green methanol or eMethanol). Product streams or components from the HHR module and/or one or more downstream unit operations, such as syngas, carbon dioxide, and/or fuel-cell grade hydrogen could be used as feed to a methanol synthesis process.

[0062] In a further refinement, the HHR module further comprises: a water gas shift (WGS) reactor positioned between the first reactor and the cooler, the water gas shift reactor being adapted to (i) receive the first reformate from the first reactor, (ii) perform a water gas shift reaction favoring formation of additional hydrogen in the first reformate (e.g., shifting the equilibrium to convert carbon monoxide and water to carbon dioxide and hydrogen in the first reformate; WGS reactors with suitable catalyst, reactor vessel, etc. are known in the art) to form a hydrogen-enriched first reformate, and (iii) feed the hydrogen-enriched first reformate to the cooler; and the method further comprises: operating the first reactor under second operating conditions favoring hydrogen production; feeding the first reformate to the water gas shift reactor, thereby performing a water gas shift reaction favoring formation of additional hydrogen in the first reformate to form a hydrogen-enriched first reformate; and feeding the hydrogen-enriched first reformate to the cooler. The first reformate can pass through the vaporizer and/or one or more heat exchangers as a hot fluid heating the hydrocarbon gas feed stream, thereby cooling the first reformate before it enters the water gas shift reactor. The hydrogen-enriched first reformate can pass through one or more heat exchangers as a hot fluid heating the feed stream and/or a recycled system water stream before it enters the cooler. This is generally illustrated in Figs. 2 and 3 in which the WGS reactor is positioned between the vaporizer (i.e. , the wet reformate having been used as a hot fluid for vaporization of the feed stream therein) and the cooler/condensate drum.

[0063] In a further refinement, the HHR module does not contain a water gas shift reactor. Alternatively, the HHR module can contain a water gas shift reactor that is not in use during certain operations, such as under the first operating conditions favoring methane production, in which case the water gas shift reactor can be bypassed with suitable valves, bypass lines, etc. in the HHR module.

[0064] In a further refinement, the HHR module further comprises: a second steam generator adapted to (i) receive at least one of the recycled system water and fresh water fed to the HHR module, and (ii) output steam; and a super heater (e.g., as the heater apparatus above) adapted to (i) receive the one or more non-methane hydrocarbons in gaseous form and the steam from the second steam generator, which together form the feed stream, and (ii) superheat the feed stream to the predetermined temperature range as the hydrocarbon gas feed stream; the method further comprises: outputting steam from the second steam generator; admixing the steam from the second steam generator with the one or more non-methane hydrocarbons, thereby forming the feed stream; superheating the feed stream in the superheater, thereby forming the hydrocarbon gas feed stream; feeding the hydrocarbon gas feed stream from the superheater to the first reactor.

[0065] In a further refinement, the HHR module comprises the vaporizer; the method further comprises: feeding the first reformate to the vaporizer as a hot fluid vaporizing the feed stream to form the hydrocarbon gas feed stream, thereby cooling the first reformate (e.g., before it enters one or more downstream heat exchanges or a water gas shift reactor).

[0066] In a further refinement, the HHR module comprises the vaporizer; and the HHR module further comprises: one or more heat exchangers in series positioned upstream or downstream of the vaporizer, the one or more heat exchangers being adapted to heat the at least one of the feed steam and the hydrocarbon gas feed stream before entering at least one of the vaporizer and the first reactor by using the first reformate as a hot heat exchange fluid. This can include two heat exchangers as illustrated in the figures: a first heat exchanger upstream of the vaporizer between the ethanol/water feed and the vaporizer, and a second heat exchanger downstream of the vaporizer between the vaporizer and the first reactor.

[0067] In a further refinement, the HHR module further comprises: one or more heat exchangers in series positioned between (i) the at least one of the vaporizer and the heater (e.g., outlet thereof), and (ii) the first reactor (e.g., inlet thereof), the one or more heat exchangers being adapted to heat the hydrocarbon gas feed stream before entering the first reactor by using the outlet heating fluid as a hot heat exchange fluid. This can include one heat exchanger as illustrated in the figures: a heat exchanger using the using the outlet heating fluid as the hot fluid to heat the hydrocarbon gas feed stream to the desired reactor inlet temperature just before the first reactor.

[0068] In a further refinement, the HHR module further comprises: one or more heat exchangers in series positioned between (i) the first reactor (e.g., outlet thereof), and (ii) the cooler (e.g., inlet thereof), the one or more heat exchangers being adapted to heat the recycled system water by using the first reformate as hot heat exchange fluid. This can include two or three heat exchangers as illustrated in the figures: a first, second, third, etc. heat exchanger using the first reformate as the hot fluid to heat the recycled system water as it exits the cooler and variously passes through other water-handling unit operations such as a cooling tower and a deaerator.

[0069] In a refinement, the hydrocarbon or gas conversion system further comprises a direct connection with a co-located producer of the hydrocarbon feed wherein the hydrocarbon feed is supplied by the hydrocarbon producer directly from its production process to the hydrocarbon conversion system. In such case, the hydrocarbon conversion system will include one or more hydrocarbon feed storage tanks in fluid communication with the hydrocarbon feed producer. The hydrocarbon feed can be a liquid, a gas or a combination.

[0070] In a refinement, the hydrocarbon conversion system can have one or more hydrocarbon feed storage tanks in fluid communication with an ethanol production process. The hydrocarbon feed storage tank(s) can be positioned between the vaporizer and the ethanol production process in fluid communication with one or more intermediate “wet” ethanol production process streams (e.g., ethanol with a vol% concentration less than the ethanol vol% of the final anhydrous ethanol product). For example, the hydrocarbon feed storage tank can be in fluid communication with one or more production process streams before, within, or after one or more stages of ethanol separation and distillation wherein water and other by-products are separated from the ethanol. The intermediate wet ethanol production process streams can have an ethanol vol% concentration at or near the ethanol vol% concentration required for the targeted steam to carbon ratio selected for the hydrocarbon feed stream delivered to the hydrocarbon conversion system.

[0071] In a refinement, the hydrocarbon or gas conversion system further comprises one or more mixers located between the hydrocarbon feed storage tank(s) and the intermediate wet ethanol production process streams and is adapted to: (i) receive the wet ethanol from the ethanol intermediate production process stream(s) at a higher ethanol vol% concentration than required for the hydrocarbon conversion system; (ii) flow control an amount of water into the received wet ethanol; and (iii) deliver a wet ethanol to a hydrocarbon feed storage tank with a lower ethanol vol% concentration than the wet ethanol vol% concentration received from the ethanol intermediate production process stream(s). The water flow controlled to the wet ethanol can be system water, fresh water, and/or water from other sources. The amount of water flow controlled to the wet ethanol can be varied as required to maintain a target steam to carbon ratio. [0072] In a refinement, the hydrocarbon or gas conversion system can include direct feed connections to the co-located ethanol production process, thereby eliminating the need for storage tank(s)

[0073] In a refinement, the hydrocarbon or gas conversion system can include direct connections to the co-located ethanol production process wherein one or more sources of thermal energy produced within the ethanol production process (e.g., steam and/or a hot fluid like water or exhaust gas) can be supplied to the hydrocarbon conversion system.

[0074] In a refinement, heat can be supplied from the hydrocarbon conversion system to the ethanol plant.

[0075] In a refinement, system water from the hydrocarbon or gas conversion system can be supplied to a co-located ethanol production process.

[0076] In a refinement, non-ethanol liquid hydrocarbons (e.g., methanol and/or NGLs) can be flow controlled into the wet ethanol prior to and/or after the addition of water.

[0077] In alternative embodiments, the hydrocarbon conversion system can be connected to and/or integrated with a co-located ethanol production process wherein ethanol, at various vol% concentrations, thermal energy, in various forms, and/or water is sourced, supplied and/or shared.

[0078] In a refinement, the hydrogen separator is adapted to provide a hydrogen content of at 99.97 mol.% (e.g., on a mole, volume, or weight basis) in the hydrogen gas stream, which is a minimum specification for fuel cell grade hydrogen. Lower hydrogen contents are possible for other applications/uses. Suitably, the hydrogen separator separates up to 90% of the hydrogen in the reformate gas (e.g., at least 20, 30, 40, 50, 60, or 70% and up to 50, 60, 70, 80, or 90% hydrogen separation and recovery in the hydrogen gas stream). In various embodiments, the hydrogen gas stream can have a hydrogen content of at least 80, 85, 90, 95, 98, 99, 99.5. 99.9, 99.97, or 99.99 mol.% and/or up to 98, 99, 99.5, 99.8, 99.9, 99.97, 99.99, 99.999, or 100 mol.%. The tail gas remaining after hydrogen removal includes predominantly methane, hydrogen, and carbon monoxide. For example, the tail gas can include methane in an amount of about 20-70 mol.%, for example at least 20, 30, 40, or 50 mol.% and/or up to 50, 60, or 70 mol.%. Similarly, the tail gas can include hydrogen in an amount of about 20-60 mol.%, for example at least 20, 30, or 40 mol.% and/or up to 40, 50, or 60 mol.%. Similarly, the tail gas can include carbon monoxide in an amount of about 5- 30 mol.%, for example at least 5, 10, or 15 mol.% and/or up to 15, 20, or 30 mol.%. In embodiments where the tail gas (or a portion thereof) is withdrawn from the system as a designer fuel with a targeted composition, any of the foregoing component ranges can apply to the designer fuel as well. In embodiments where the tail gas (or portion thereof) is blended with other component(s) such as carbon dioxide (e.g., from a carbon dioxide separator or module), pipeline methane, synthetic natural gas (e.g., from an SNG module), etc., to provide a designer fuel with a target composition, the designer fuel can have alternative component ranges in addition to those mentioned above for the tail gas. For example, the designer fuel can include methane in an amount of about 50-99 mol.%, for example at least 50, 60, 70, 80, or 90 mol.% and/or up to 70, 80, 90, 95, 98, or 99 mol.%. Similarly, the designer fuel can include carbon oxides, hydrogen, or carbon oxides and hydrogen combined independently in an amount of about 0.1-50 mol.%, for example at least 0.1 , 1 , 2, 5, 10, 20, or 30 mol.% and/or up to 3, 5, 7, 10, 15, 20, 25, 30, 40, or 50 mol.%.

[0079] In a refinement, the hydrogen separator is selected from the group consisting of a membrane separator, a pressure-swing adsorption (PSA) separator, and a cryogenic separator. In some embodiments, the system can further include a dehydrator and/or compressor upstream of the hydrogen separator and downstream of the reactor(s) and cooler. For example, hydrogen separation can be performed at elevated pressures, for example up to 350-600 psi or 400-500 psi. Accordingly, in some embodiments and depending on the pressure of the incoming feed to the hydrogen separator, it can be desirable to include a compressor to increase the pressure of an incoming low-pressure feed (e.g., in a range of about 20-50 psi or 30-35 psi) up to the desired elevated pressure. In other embodiments, for example where the incoming hydrocarbon feed gas to the system is compressed to the elevated pressures, a compressor prior to the hydrogen separator can be omitted. Suitably, the system also includes a carbon dioxide separator as illustrated in the figures, for example an amine or other standalone apparatus separate from the hydrogen separator. Thus, the hydrogen separator can provide up to three outlets: a hydrogen gas stream, a carbon dioxide stream, and a residual product stream (e.g., including residual hydrogen, carbon dioxide, methane and non-methane hydrocarbons, etc.).

[0080] Carbon dioxide removal allows the gas conversion system the flexibility to provide product streams based on desired end uses. For example, carbon dioxide removal can be used in order to provide the produced hydrogen gas as “Blue” hydrogen, which increases the market value of the product. As background, there are three types/grades of hydrogen produced: 1) Grey hydrogen (produced from reformation without carbon capture and sequestration (CCS); Blue hydrogen (produced from hydrocarbons like reformation but with CCS); and 3) Green hydrogen (produced completely from renewable resources (typically electrolysis with energy provided via wind, solar or nuclear). Carbon dioxide removal (e.g., via CCS) can provide a green benefit and produce another source of revenue from sale and/or carbon/renewable energy credits. Carbon dioxide removal or separation can be performed by any suitable apparatus or combination of apparatus, for example a membrane separator and/or a scrubber. In an embodiment, the carbon dioxide separator is a full amine plant system (e.g., amine-based scrubber), for example including an amine contacting tower and amine recovery loop. Carbon monoxide is typically not removed from process streams; carbon monoxide can remain in a product gas and be consumed/combusted for its fuel value, or it can be converted to methane as a reactant in an SNG reactor or module. After carbon dioxide removal, the product gas or intermediate product gas can contain methane in a range of 10-90 mol.% (e.g., at least 10, 20, 30, 40, 50, 60, or 70 mol.% and/or up to 30, 40, 50, 60, 70, 80, or 90 mol.%), hydrogen in a range of 10-90 mol.% (e.g., at least 10, 20, 30, 40, 50, 60, or 70 mol.% and/or up to 30, 40, 50, 60, 70, 80, or 90 mol.%), carbon monoxide in a range of 0.01-10 mol.% (e.g., at least 0.01 , 0.1 , 0.2, or 0.5 mol.% and/or up to 1 , 2, 3, 5, 7, or 10 mol.%), water in a range of 0.01-5 mol.% (e.g., at least 0.01, 0.1 , 0.2, or 0.5 mol.% and/or up to 0.5, 1, 2, 3, or 5 mol.%), and/or less than 0.1, 0.01 , or 0.001 mol.% carbon dioxide.

[0081] Selection and control of hydrogen, methane, and/or carbon dioxide content of the product streams also allows the gas conversion system the flexibility to provide fuel streams according to a user-specific set of criteria (e.g., a “designer” fuel). System capacity and production can be autonomously and independently varied among the primary hydrogen, methane, and carbon dioxide products such that one or more gas streams with desired hydrogen, methane, and/or carbon dioxide contents can be produced based on user demand. The gas conversion system permits removal of product streams and/or addition of product streams to produce a fuel tailored to specific applications, providing optimum fuel parameters for reciprocating and turbine engine performance. For example, reciprocating and turbine engine manufacturers consider fuel diluent (carbon dioxide) and hydrogen (H2) content as highly beneficial additions to a methane-based fuel. Specifically: 1) the system can adjust the diluent content (carbon dioxide) of a methane-based fuel to target values consistent with lower engine emissions and better engine performance and longer life, 2) the system can adjust the hydrogen content in a methane-based fuel to provide performance, life, and emissions benefits to engine/turbine performance, and 3) the system can control other parameters like heating value, C2+ content, Wobbe Index, etc. to benefit performance, life, and emissions. In another mode of operation, the system is used favor hydrogen production for the production of designer fuels only such that the hydrogen gas is not separated into a final, substantially pure hydrogen gas product, but instead included as a fuel component. For example, there may be applications where removing hydrogen gas is not desired and production of a tailored methane-based fuel is desired.

[0082] In a refinement, the method comprises: establishing a direct connection between the HHR module and an ethanol production facility, wherein: (i) an ethanol and water mixture (e.g., having an ethanol content in a range of 25-35% (v/v) and a water content in a range of 65-75% (v/v)) is obtained from one or more ethanol production process streams in the ethanol production facility, and (ii) the ethanol and water mixture is received at the first inlet as the feed stream.

[0083] In another aspect, the disclosure relates to 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 ethanol and water, the method comprising: establishing a direct connection between a first (HHR) reactor and an ethanol production facility wherein an ethanol and water mixture with a target ethanol concentration is obtained from one or more (intermediate) ethanol production process streams (e.g., blending multiple intermediate ethanol production process streams); suppling the ethanol and water mixture with the target ethanol concentration directly to a hydrocarbon conversion system comprising the first reactor for use as a feed stream to the first reactor; optionally adding water and/or additional hydrocarbons to the ethanol and water mixture to achieve a target steam to carbon ratio for the hydrocarbon feed stream; and feeding the hydrocarbon feed stream in gaseous form (e.g., after vaporizing a liquid hydrocarbon feed stream) to the first reactor, thereby reacting at least a portion of the hydrocarbon feed stream to form a first reformate comprising carbon oxides, hydrogen, methane, and water. The hydrocarbon conversion system and the first reactor are not particularly limited, but they can include one or more of the features described herein for the other aspects of the disclosure.

[0084] In a refinement, the ethanol and water mixture (or the hydrocarbon feed stream, such as more generally described above in the first aspect) has a water concentration of about 70% (v/v) (e.g., and about 30% (v/v) ethanol), for example about 65-75% or 68-72% (v/v) water and about 25-35% or 28-32% (v/v) ethanol. A 70/30 water/ethanol ratio (v/v) represents a corresponding steam (or water): carbon ratio desirable for processing in the first reactor. This ratio (or other desired ratio) can be obtained, for example, by withdrawing a portion of a single intermediate ethanol production process stream having the desired ethanol/water ratio. More commonly, a desired water/ethanol ratio can be obtained by blending portions of one or more intermediate ethanol production process steams, and optionally water, to obtain the desired ratio. This approach provides a highly cost-effective source of the hydrocarbon feed stream, because it sources ethanol from various process streams in an ethanol production plant which required less overall energy for water removal as compared to the final anhydrous ethanol product, and which also contain water as a desirable co-reactant for a reforming reaction.

[0085] In a refinement, wherein the ethanol and water mixture (or the hydrocarbon feed stream, such as more generally described above in the first aspect) has a water concentration of about 1-99% or 10-90% (v/v) (e.g., and about 1-99% or 10-90% (v/v) ethanol), for example at least 1, 2, 5, 10, 20, 30, 40, 50, 60, or 70% (v/v) water, up to 30, 40, 50, 60, 70, 80, 90, 95, 98, or 99% (v/v) water, at least 1, 2, 5, 10, 20, 30, 40, 50, 60, or 70% (v/v) ethanol, and/or up to 30, 40, 50, 60, 70, 80, 90, 95, 98, or 99% (v/v) ethanol. In some refinements, the ethanol and water mixture provided by the ethanol producer can be an anhydrous ethanol stream (e.g., at least 95, 98, or 99% (v/v) ethanol) either before or after a denaturant is added (i.e. , hydrocarbon feed stream can include or be free from one or more ethanol denaturants such as denatonium or other bitterant/aversive agent, pyridine, methanol, isopropyl alcohol, t-butyl alcohol, ethyl acetate, acetone, methyl ethyl ketone, and methyl isobutyl ketone). In cases where the water/ethanol ratio is high relative to a desired S:C ratio, additional hydrocarbon such as ethane or other hydrocarbons can be added to the hydrocarbon feed stream prior to being fed to the first reactor. Similarly, when the water/ethanol ratio is low relative to a desired S:C ratio, additional water can be added to the hydrocarbon feed stream prior to being fed to the first reactor.

[0086] An illustrative ethanol production process can include one or more of the following steps: fermenting a biomass (e.g., containing one or more of starch, cellulose, and lignocellulose, such as from corn, wood, or other plant-based or renewable material) to form an initial ethanol/water mixture (or process stream) having an initial concentration of ethanol (e.g., a low concentration of about 5-15% (v/v) ethanol in water for common fermentation processes); performing one or more separation (or concentration) steps to remove water from the first ethanol/water mixture, thereby forming one or more intermediate ethanol/water mixtures (or process streams) having an intermediate concentration of ethanol greater than the initial concentration of ethanol (e.g., i = 1 to n intermediate separation/concentration steps such as distillation, etc. to incrementally remove water and increase ethanol concentration, such that Co < Ci < C2 ... < C_n, where Co is first/initial concentration of ethanol, and Ci to C_n are the increasing intermediate concentrations of ethanol in different process streams); performing a final separation (or concentration) step to remove water from one or more of the intermediate ethanol/water mixtures, thereby forming a final (anhydrous) ethanol/water mixture (or process stream) having a final concentration of ethanol greater than the intermediate concentrations of ethanol (e.g., a final concentration C_n+i > C_n, where C_n+i is typically at least about 95% (v/v) ethanol in water for various commercial grades of anhydrous ethanol); and withdrawing a (liquid) hydrocarbon feed stream containing ethanol and water, the hydrocarbon feed stream (i) comprising one or more of the initial ethanol/water mixture, the intermediate ethanol/water mixtures, and the final ethanol/water mixture (e.g., portions of multiple streams in admixture), and (ii) having an ethanol concentration greater than the initial concentration of ethanol and less than the final concentration of ethanol.

[0087] In another aspect, the disclosure relates to a hydrocarbon conversion system for converting a hydrocarbon gas feed stream comprising one or more non-methane hydrocarbons, water, 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 one or more non-methane hydrocarbons; a first outlet for delivering a platform gas comprising methane and hydrogen; a second outlet for delivering a combustion flue gas; a third outlet for delivering steam; at least one of a vaporizer and a heater adapted to (i) receive a feed stream comprising in admixture the one or more non-methane hydrocarbons and water, and (ii) output the feed stream as the hydrocarbon gas feed stream at a predetermined temperature; a first (HHR) reactor containing a first catalyst and being adapted to (i) receive the hydrocarbon gas feed stream in fluid communication with the first reactor and (ii) receive an inlet heating fluid, wherein the first reactor and the first catalyst are adapted to react at least a portion of the non-methane hydrocarbons in the hydrocarbon gas feed stream into carbon oxides, hydrogen, methane, and water, thereby (i) forming a first reformate comprising the carbon oxides, the hydrogen, the methane, and water, and (ii) forming an outlet heating fluid; 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; and a steam generator adapted to (i) receive the recycled system water stream, (ii) receive the outlet heating fluid, and (iii) output steam. The hydrocarbon conversion system can further include any of the corresponding features described above with respect to the method and systems.

[0088] While the disclosed methods, systems, apparatus, and compositions are susceptible of embodiments in various forms, specific embodiments of the disclosure are illustrated (and will hereafter be described) with the understanding that the disclosure is intended to be illustrative, and is not intended to limit the claims to the specific embodiments described and illustrated herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0089] For a more complete understanding of the disclosure, reference should be made to the following detailed description and accompanying drawings wherein:

[0090] Figure 1 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module along with one or more of downstream carbon dioxide separators, a hydrogen separator, and a methanation reactor to provide one or more product streams including a carbon dioxide product stream, a (fuel cell-grade) hydrogen product stream, and a synthetic natural gas product stream.

[0091] Figure 2 is a process flow diagram illustrating representative unit operations and streams in an embodiment of an HHR module of the disclosed gas conversion system and related method.

[0092] Figure 3 is a process flow diagram illustrating representative unit operations and streams in another embodiment of an HHR module of the disclosed gas conversion system and related method having a simplified water recycle system.

[0093] Figure 4 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, and a hydrogen separator.

[0094] Figure 5 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, and a platform gas flow splitter.

[0095] Figure 6 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, and platform gas flow splitters.

[0096] Figure 7 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, and a methanation reactor.

[0097] Figure 8 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, a methanation reactor, and platform gas flow splitters.

[0098] Figure 9 is a process flow diagram illustrating representative unit operations and streams in another embodiment of an HHR module of the disclosed gas conversion system and related method having an additional inlet and heater for gaseous hydrocarbon feeds.

[0099] Figure 10 is a process flow diagram illustrating representative unit operations and streams in another embodiment of an HHR module of the disclosed gas conversion system and related method having an additional supply of natural gas or other external gas supply for blending with one or more output streams from the gas conversion system to provide a designer fuel stream as a product gas.

[00100] Figure 11 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, a methanol production reactor, and platform gas flow splitters.

[00101] Figure 12 is a process flow diagram illustrating representative unit operations and streams in the disclosed gas conversion system incorporating an HHR module, carbon dioxide separators, a hydrogen separator, a heavy hydrocarbon production reactor, and platform gas flow splitters.

DETAILED DESCRIPTION

[00102] 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 hydrocarbon feed gas containing one or more nonmethane hydrocarbons, such as ethanol and/or ethane. 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 nonmethane 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 and/or with external natural gas or other gaseous streams 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 are made available for use on-site as a fuel or for compression or liquefaction and storage or transportation off-site.

[00103] 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 stearmcarbon 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.

[00104] 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.

[00105] Figure 1 is a process flow diagram illustrating representative unit operations and streams to process one or more feed streams 60 in the disclosed gas conversion system 50 incorporating an HHR module 100 along with one or more of downstream carbon dioxide separators 200A, 200B, a hydrogen separator 300, and a methanation reactor (or SNG reactor) 400 to provide one or more product streams 70. The feed streams 60 can include hydrocarbon feed stream 62 with one or more non-methane hydrocarbons such as an alcohol (e.g., ethanol), oxygenate, or other liquid-phase hydrocarbon feed. In embodiments, the feed streams 60 can include an additional hydrocarbon feed steam 64 such as a gasphase hydrocarbon feed (e.g., ethane). The product streams 70 can include one or more of a (fuel cell-grade) hydrogen product stream 72, a product stream 74 (e.g., synthetic natural gas, platform gas, tail gas, and blends thereof for a desired designer fuel composition), and a carbon dioxide product stream 76.

[00106] As illustrated in Figure 1, the hydrocarbon feed stream 62 and optionally the additional hydrocarbon feed steam 64 are fed to the HHR module 100 via a first inlet 102 and a second inlet 104, respectively. As described in more detail below, the HHR module 100 includes apparatus to react the hydrocarbon feed(s) via a reforming reaction to form carbon oxides, hydrogen, methane, and water as a reformate, which can be further reacted via a water gas shift reaction to form additional carbon dioxide and hydrogen from carbon monoxide and water in the reformate. Outlet streams from the HHR module 100 can include a platform gas 114 via a first outlet 106, a combustion flue gas 156 via a second outlet 107, and steam 126 via a third outlet 108. The combustion flue gas 156 and the steam 126 can be fed to the combustion carbon dioxide separator 200A, thereby forming a carbon dioxiderich stream 206A. The combustion carbon dioxide separator 200A can be an amine separator in which the steam 126 provides the heat for the amine process fluid therein to remove carbon dioxide. The platform gas 114 can be fed to the produced carbon dioxide separator 200B to provide a carbon dioxide-rich stream 206B to be combined with the carbon dioxide-rich stream 206A, which together form a carbon dioxide system product stream 76. After carbon dioxide separation in the separator 200B, a methane/hydrogen mixture can be withdrawn as an intermediate product stream 212 and fed to the hydrogen separator 300 to form a hydrogen-rich stream as a high purity hydrogen gas 72. Tail gas 312 exiting the hydrogen separator 300 is then compressed in a compressor 320 to provide a compressed tail gas 322 output, which in turn can be fed to the methanation reactor (or SNG reactor) 400 to form synthetic natural gas 422 including methane as a product stream 74 and water 439 that can be recycled back to the HHR module 110 and/or a water/steam stream thereof.

[00107] Figures 2, 3, and 9 include a process flow diagrams illustrating representative unit operations and streams in various embodiments of an HHR module 100 for use in the of the disclosed gas conversion system 50 related methods.

[00108] As illustrated in Figure 2, the HHR module 100 can include a first (HHR) inlet 102 for a hydrocarbon feed, a first (HHR) outlet 106 for platform gas 114, and a second (HHR) outlet 107 for combustion flue gas 156, and third (HHR) outlet 108 for steam 126. A hydrocarbon gas feed 62 with one or more non-methane hydrocarbons such as an alcohol (e.g., ethanol), oxygenate, or other liquid-phase hydrocarbon feed is fed to a mixer 130 which receives (recycled) system water 163 from a cooler or water separation unit 160 (e.g., a condensate drum 166 component thereof). The mixer 130 outputs a corresponding feed stream 131 containing one or more non-methane hydrocarbons and water in admixture (e.g., a liquid phase mixture). Recuperative heat exchangers (HEX) 170, for example illustrated as a third heat exchanger 173, can be included downstream of the mixer 130 to adjust the temperature of the feed stream 131 using heat from a reformate stream 152 as the hot side heat exchange fluid. The feed stream 131 is then fed to a vaporizer 140, which vaporizes the liquid feed stream 131 and outputs a feed gas 132 (e.g., a gas phase mixture of non- methane hydrocarbons and steam) at a selected temperature. The reformate stream 152 can be used as a hot side heat exchange fluid to provide heat energy to the vaporizer 140. The feed gas 132 is then fed to a first (HHR) reactor 150. As illustrated, the feed gas 132 can be further heated to its desired inlet temperature to the reactor 150 by passing through additional heat exchangers, for example a second heat exchanger 172 and a first heat exchanger 171 in series, which use the reformate stream 152 and a combustion flue gas 156 as the hot side heat exchange fluids, respectively. The first (HHR) reactor 150 contains a catalyst adapted to react at least a portion of non-methane hydrocarbons in the superheated feed gas 132 into carbon oxides, hydrogen, and methane via equilibrium steam reformation and methanation reactions. Suitable catalysts for the reformation (HHR) and methanation (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). Heat/energy can be provided to the reactor 150 via an inlet heat exchange stream 154 to maintain a desired temperature profile in the reactor (e.g., approximately isothermal or otherwise), which can be withdrawn an outlet heat exchange stream 156 such as combustion flue gas 156.

[00109] 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 vaporizer 140, the recuperative heat exchangers 170, optionally a water gas shift (WGS) reactor 158, and then to a cooler or water separation unit 160 to remove water, which can be recycled as system water 163. As illustrated, the reformate stream 152 can be fed to the WGS reactor 158 to increase the hydrogen content (and increased carbon dioxide content, with reduced water and carbon monoxide content) in a corresponding shifted reformate stream 159. As illustrated, the reformate stream 152 and/or the shifted reformate stream 158 can be used as a hot side heat exchange fluid in any of the second heat exchanger 172 (e.g., to increase the feed gas 132 temperature), the third heat exchanger 173 (e.g., to increase the liquid feed stream 131 temperature), and a fourth, fifth, or sixth heat exchanger 174, 175, 176 (e.g., to increase the system water 163 temperature). In the embodiment shown in Figure 2, the cooler 160 (or more generally a collection of water separation unit operations) can include a first water separator 166 such as a condensate drum to remove water, form the system water 163 stream, and form a dried reformate 167 with a substantially reduced water content. The system water 163 can be split and/or fed to one or more of a cooling tower 164, a deaerator 165 (e.g., to separate and remove some reformate compounds (e.g., minor amounts of methane, carbon dioxide, hydrogen), recuperative heat exchangers 170, the mixer 130 (e.g., to provide the desired water content in the liquid feed stream 131), and a steam generator 120. System water 163 can fed to the steam generator 120 along with the combustion flue gas 156 as a hot side heat exchange fluid, thereby form a steam 126 output and a (cooled) combustion flue gas 156 output. 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. The combustion flue gas 156 can be withdrawn via the second outlet 107, and the steam 126 can be withdrawn via the third outlet 108. [00110] Figure 3 includes a generalized illustration of the HHR module 100 in which the various unit operations of the cooler or water separation unit 160 are illustrated generically as a water recycle operation to provide the system water 163 to one or more of the feed stream 131, the steam generator 120, and the heat exchangers 170. Similarly, Figure 3 illustrates that relatively fewer (or more; not shown) heat exchangers 170 can be used relative to the embodiment illustrated in Figure 2.

[00111] Figure 9 illustrates an alternative embodiment to that illustrated in Figures 2 and 3 in which an additional hydrocarbon feed steam 64 such as a gas-phase hydrocarbon feed (e.g., ethane) is fed to the HHR module 100 via a second (HHR) inlet 104. The additional hydrocarbon feed steam 64 can be fed to heater 142 to a desired temperature such that an additional hydrocarbon feed gas 133 can then be combined/mixed with the liquid feed stream 131 (i.e., pre-vaporizer 140) and/or the feed gas 132 (i.e., post-vaporizer 140) such that the final feed gas 132 fed to the reactor 150 includes the non-methane hydrocarbons in the hydrocarbon feed stream 62 (e.g., ethanol), the additional hydrocarbons in the feed steam 64 (e.g., ethane), and steam (e.g., originally present in the feed stream 62 and/or added from the system water 163). As further illustrated, the HHR module 100 can include a third (HHR) inlet 105 to receive makeup water (e.g., to be mixed with the system water 163) to provide the additional water needed for the reformation reaction with the additional hydrocarbon feed steam 64.

[00112] Figures 4-8 and 10 illustrate various embodiments of the gas conversion system 50 in which the platform gas 114, the combustion flue gas 156, and the steam 126 outlet/output streams from the HHR module 100 can be further separated, reacted, and/or blended to provide desired product streams 70 with desired compositions and/or target fuel properties (e.g., designer fuels).

[00113] Figure 4 illustrates a subset of the embodiment in Figure 1 , in which all of the platform gas 114 is optionally treated in a dehydration unit (“dehy”) to remove residual water, and is then fed to the carbon dioxide separator 200B and the hydrogen separator 300 in series to provide product streams 70 including the high purity hydrogen gas 72, the tail gas product stream 74, and the carbon dioxide system product stream 76. In this embodiment, no methanation or other post-HHR module 100 reaction is required.

[00114] Figure 5 illustrates an alternative embodiment relative to Figure 4 in which a first flow splitter 116 downstream of the cooler 160 (or condensate drum 166) can partition the platform gas 114 as desired between the first and second portions. In limiting cases, the first flow splitter 116 can deliver all of the platform gas to the carbon dioxide separator 200B and the hydrogen separator 300 in series (resulting in the products from Figure 4), or all of the platform gas 114 directly as the product gas (i.e., without any further separation or reaction). In cases where the platform gas 114 is portioned between the two portions, the product stream 74 can be any desired mixture/blend of the platform gas 114 and the tail gas 312.

[00115] Figure 6 illustrates an alternative embodiment relative to Figure 5 in which a second flow splitter 118 between the carbon dioxide separator 200B and the hydrogen separator 300 can partition the carbon dioxide-removed platform gas 212 as desired between the hydrogen separator 300 and the product gas 74. In limiting cases, the first flow splitter 116 can deliver all of the platform gas 114 to the carbon dioxide separator 200B and the hydrogen separator 300 in series, or all of the platform gas 114 directly as the product gas 74 (i.e., without any further separation or reaction). In further limiting cases, the second flow splitter can deliver all of the carbon dioxide-removed platform gas 212 to the hydrogen separator 212, or all of the carbon dioxide-removed platform gas 212 directly as the product gas 212 (i.e., without any further separation or reaction). In cases where the platform gas 114 is portioned between the three portions from the first and second flow splitters 116, 118, the product stream 74 can be any desired mixture/blend of the platform gas 114, the carbon dioxide-removed platform gas 212, and the tail gas 312.

[00116] Figure 7 illustrates a more detailed version of the embodiment in Figure 1, in which all of the platform gas 114 is optionally treated in a dehydration unit (“dehy”) to remove residual water, and is then fed to the carbon dioxide separator 200B, the hydrogen separator 300, and the methanation reactor 400 in series to provide product streams 70 including the high purity hydrogen gas 72 (e.g., fuel cell-grade), the synthetic natural gas (SNG) product stream 74, and the carbon dioxide system product stream 76.

[00117] Figure 8 illustrates a combination of the embodiments from Figure 6 and Figure 7 in which one or both of the flow splitters 116, 118 are included in the embodiment of the Figure 7 with the carbon dioxide separator 200B, the hydrogen separator 300, and the methanation reactor 400. In this case, the feed to the methanation reactor 400 can include any desired combination/mixture of the platform gas 114, the carbon dioxide-removed platform gas 212, and the tail gas 312 to provide the synthetic natural gas (SNG) product stream 74 with desired properties and in a desired amount relative to the high purity hydrogen gas 72 (e.g., any desired distribution between all-hydrogen product, all-SNG product, or a desired proportion of separate hydrogen and SNG products).

[00118] Figure 10 illustrates an alternative embodiment relative to Figure 6 in which a natural gas 66 or other external gaseous stream can be blended with one or more of the platform gas 114, the carbon dioxide-removed platform gas 212, and the tail gas 312 to provide the product stream 74 with desired a desired composition and/or fuel properties.

[00119] The unit operations and apparatus for the carbon dioxide separators 200A, 200B, the hydrogen separator 300, and the methanation reactor 400 are not particularly limited and are generally known in the art. Example carbon dioxide separators 200A, 200B can include scrubbers (e.g., amine scrubbers), membrane separators, etc. The methanation reactor 400 can include an SNG reactor with any suitable catalyst (e.g., as described above) to drive a reverse reformation reaction (e.g., net formation of methane and water from carbon monoxide and hydrogen) along with a suitable water separator to provide a dry synthetic natural gas product and a water stream for recycle to/use in the HHR module 100. Example hydrogen separators 300 can include pressure-swing adsorption (PSA) separators, membrane separators, etc.

[00120] Figure 11 illustrates an alternative embodiment relative to Figure 6 in which one or more of the platform gas 114 or component(s) thereof, the carbon dioxide-removed platform gas 212, and/or the tail gas 312 can be fed to a downstream methanol production reactor 500 or corresponding methanol production process. The synthesis of methanol from products of the HHR module 100 can be variously referenced as blue methanol, green methanol, renewable methanol, eMethanol, and/or bio-methanol. Product streams or components from the HHR module 100 and/or one or more downstream unit operations, such as syngas (CO+H2), carbon dioxide, and/or fuel-cell grade hydrogen could be used as feed to a methanol synthesis process. Methanol production reactors with suitable catalyst, reactor vessel, etc. are known in the art, and they perform a variety of chemical reactions to produce methanol, typically from syngas or other platform gas components. Representative reactions for catalytic conversion (e.g., with catalysts including one or more of copper, zinc, aluminum, magnesium, and oxides thereof) from syngas/platform gas components include 2 H2 + CO — CH3OH and 3 H2 + CO2 — CH3OH + H2O. Catalytic oxidation of methane (e.g., in the platform gas) to form methanol is also possible. Accordingly, the system reformate 152 (or platform gas 114) can be used to produce multiple products at the same plant, for example one or more of fuel cell grade hydrogen, methanol, and renewable/synthetic natural gas from same feedstock and HHR module 100. For example, a methanol reactor outlet stream 502 can include a mixture of methanol (e.g., produced from CO, H2, and/or CO2 in the feed streams 114, 212, and/or 312), unreacted methane (e.g., from the platform gas 114 or other split/separated streams), and optionally unreacted or byproduct components (e.g., carbon oxides, hydrogen, and/or water). The outlet stream 502 can be passed through one or more separators 510 (e.g., methane separator, water separator) to provide two product streams including a methanol product stream 74A and a renewable/synthetic natural gas stream 74B. The methanol product stream 74A can have a methanol content of at least 80, 85, 90, 95, 98, 99, 99.5. 99.9, 99.97, or 99.99 mol.% or wt.% and/or up to 98, 99, 99.5, 99.8, 99.9, 99.97, 99.99, 99.999, or 100 mol.% or wt.%. The renewable/synthetic natural gas stream 74B (or stream 74 in Figures 7-8) can have a methane content of at least 80, 85, 90, 95, 98, 99, 99.5. 99.9, 99.97, or 99.99 mol.% and/or up to 98, 99, 99.5, 99.8, 99.9, 99.97, 99.99, 99.999, or 100 mol.%. Similarly, the product stream 74B can have a content of carbon oxides, hydrogen, or carbon oxides and hydrogen combined in an amount of about 0.1-20 mol.%, for example at least 0.1, 1 , 2, 5, or 10 mol.% and/or up to 1, 2, 3, 5, 7, 10, 15, or 20 mol.%. In some embodiments, a low Carbon Intensity (Cl) methanol produced from the platform gas 114 of the HHR module 100 can be blended with grey methanol (high Cl) to produce a targeted-CI methanol depending on desired specifications for a given market, customer, and/or end use.

[00121] Figure 12 illustrates an alternative embodiment relative to Figure 6 in which one or more of the platform gas 114 or component(s) thereof, the carbon dioxide-removed platform gas 212, and/or the tail gas 312 can be fed to a heavy hydrocarbon production reactor 600 (e.g., a sustainable aviation fuel (SAF) synthesis reactor as illustrated) to produce a heavy hydrocarbon gas stream as product stream 74 (e.g., a SAF product stream). In embodiments, the heavy hydrocarbon production reactor 600 can include one or more of a reverse water gas shift (rWGS) reactor, a Fischer-T ropsch (FT) reactor, and/or a hydrotreater (or hydrodesulfurization reactor) in series to provide the heavy hydrocarbon gas stream. The rWGS reactor is adapted to perform a reverse water gas shift reaction favoring formation of additional carbon monoxide and water relative to that in the platform gas 114, for example to adjust the H₂:CO ratio to a desired value/range for a subsequent FT process in which an (average) carbon number of the resulting hydrocarbons correlate to the H₂:CO molar ratio in the FT reactor feed. FT and rWGS reactors with suitable catalyst, reactor vessel, etc. are known in the art. The heavy hydrocarbon gas stream generally contains a distribution of hydrocarbons having a range of different carbon atoms per hydrocarbon molecule. Depending on the carbon number distribution, the heavy hydrocarbon gas stream can be useful as a variety of fuels (e.g., renewable fuels), such as gasoline, diesel, aviation fuel (e.g., sustainable aviation fuel (SAF), jet fuel as well as other hydrocarbon-based commodity chemicals, which can be in liquid form after cooling/condensation of the heavy hydrocarbons as initially formed in a gas phase reaction. In embodiments, the heavy hydrocarbon gas stream output of the reactor 600 can be separated and/or fractionated in one or more unit operations (not shown) to provide one or more product streams 74 having a desired carbon range for a specific fuel product (e.g., SAF, diesel, gasoline, etc.). The hydrocarbons in the heavy hydrocarbon gas stream (or a subsequently separated or fractionated stream) can have at least 4, 5, 6, 8, 9, 10, 12, or 15 carbon atoms and/or up to 7, 10, 12, 14, 15, 16, 18, 20, or 25 carbon atoms, for example including one or more of linear alkanes, branched alkanes, linear or branched alkenes, and/or linear or branched alcohols. The heavy hydrocarbon product stream 74 can have a heavy hydrocarbon content (e.g., all heavy hydrocarbons combined) of at least 80, 85, 90, 95, 98, 99, 99.5. 99.9, 99.97, or 99.99 mol.% orwt.% and/or up to 98, 99, 99.5, 99.8, 99.9, 99.97, 99.99, 99.999, or 100 mol.% or wt.%.

[00122] The foregoing options to produce methanol and/or heavy hydrocarbon fuels (e.g., SAF) from the platform gas 114 illustrate the flexibility and advantages of the HHR module 100 to form a wide range of desired products based on a given installation’s or user’s needs. As described above, the platform gas 114 can be used as a single source/single gas feed for methanol and/or hydrocarbon fuel production, in addition to the hydrogen, SNG, carbon dioxide, and other product streams 70 described above. In contrast, typical technologies used to form methanol, SAF, or other synthetic/renewable hydrocarbon fuel must source hydrogen and carbon dioxide separately, and then combine the two gases for use as feedstock. In contrast, when the feedstock includes ethanol (e.g., or other oxygenate with or without other hydrocarbons such as ethane), the resulting platform gas 114 includes both green/renewable hydrogen and renewable carbon dioxide in the single platform gas 114 for use as a single feed to product renewable methanol and SAF.

[00123] U.S. Publication No. 2022/0009773 is incorporated herein by reference in its entirety.

[00124] 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.

[00125] 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.

[00126] 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.

[00127] 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

50 hydrocarbon (or gas) conversion system

60 system feed stream (s)

62 hydrocarbon feed stream

64, 66 additional hydrocarbon feed or bypass/enrichment stream(s)

70 system product stream(s)

72 hydrogen gas stream

74 product gas stream

76 additional product stream(s)

100 heavy hydrocarbon reactor (HHR) module

102 first inlet (hydrocarbon feed)

104 second inlet (additional hydrocarbon feed)

105 third inlet (makeup water)

106 first outlet (platform gas)

107 second outlet (combustion flue gas)

108 third outlet (steam)

114 platform gas

116 (first) flow splitter

118 (second) flow splitter

120 steam generator

126 output steam

130 mixer

131 (liquid) feed stream (hydrocarbon+water feed stream)

132 feed gas (hydrocarbon gas feed stream)

133 additional hydrocarbon feed gas

140 vaporizer

142 heater first reactor or heavy hydrocarbon reactor (HHR) first (wet) reformate inlet heating fluid or heat exchange stream outlet heating fluid (combustion flue gas) water gas shift (WGS) reactor shifted first (wet) reformate cooler water separator (condensate drum) system water cooling tower de- aerator first (dried) reformate recuperative heat exchangers -176 first, second, third, fourth, fifth, sixth heat exchanger carbon dioxide separator (CO2) separator or module carbon dioxide (CO2) stream intermediate product stream hydrogen separator (H2) separator or module tail gas compressor compressed tail gas synthetic natural gas (SNG) reactor or module (wet or dried) synthetic natural gas methanol production reactor methanol reactor outlet stream separator (e.g., methane separator) heavy hydrocarbon production reactor

Claims

What is claimed is:

1. 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 one or more non-methane hydrocarbons, water, and optionally methane, the method comprising: feeding the one or more non-methane hydrocarbons to a hydrocarbon conversion system comprising a heavy hydrocarbon reforming (HHR) module comprising: a first inlet for receiving the one or more non-methane hydrocarbons; a first outlet for delivering a platform gas comprising methane and hydrogen; a second outlet for delivering a combustion flue gas; a third outlet for delivering steam; at least one of a vaporizer and a heater adapted to (i) receive a feed stream comprising in admixture the one or more non-methane hydrocarbons and water, and (ii) output the feed stream as the hydrocarbon gas feed stream at a predetermined temperature; a first reactor containing a first catalyst and being adapted to (i) receive the hydrocarbon gas feed stream in fluid communication with the first reactor and (ii) receive an inlet heating fluid, wherein the first reactor and the first catalyst are adapted to thereby (i) form a first reformate comprising the carbon oxides, the hydrogen, the methane, and water, and (ii) form an outlet heating fluid; 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; and a steam generator adapted to (i) receive the recycled system water stream, (ii) receive the outlet heating fluid, and (iii) output steam; receiving the one or more non-methane hydrocarbons at the first inlet in combination with at least one of (i) water co-fed with the one or more non-methane hydrocarbons at the first inlet and (ii) water added to the one or more non-methane hydrocarbons to provide a feed stream comprising in admixture the one or more non-methane hydrocarbons and the water; feeding the feed stream to the at least one of the vaporizer and the heater, thereby forming a hydrocarbon gas feed stream at a predetermined temperature; feeding (i) the hydrocarbon gas feed stream and (ii) an inlet heating fluid to the first reactor to react at least a portion of the non-methane hydrocarbons in the hydrocarbon gas feed stream, thereby forming (i) a first reformate comprising carbon oxides, hydrogen, methane, and water, and (ii) an outlet heating fluid; separating at least a portion of the water from the first reformate in the cooler, thereby providing (i) a dried first reformate and (ii) a recycled system water stream; feeding at least a portion of (i) the recycled system water stream and (ii) the outlet heating fluid to the steam generator, thereby forming steam; delivering the dried first reformate as a platform gas via the first outlet, the platform gas comprising at least one of (i) a hydrogen gas stream and (ii) a product gas stream; delivering the outlet heating fluid from the steam generator as a combustion flue gas via the second outlet; delivering the steam from the steam generator via the third outlet; 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.

2. The method of claim 1, wherein the one or more non-methane hydrocarbons 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.

3. The method of claim 1, wherein: the one or more non-methane hydrocarbons received at the first inlet comprise at least one liquid-phase non-methane hydrocarbon; and the feed stream comprises liquid water co-fed with the one or more non-methane hydrocarbons at the first inlet.

4. The method of claim 3, wherein: the at least one liquid-phase non-methane hydrocarbon comprises ethanol; and the one or more non-methane hydrocarbons received at the first inlet further comprise at least one gas-phase non-methane hydrocarbon comprising ethane.

5. The method of claim 3, wherein: the HHR module further comprises: a second inlet for receiving one or more additional gaseous non-methane hydrocarbons; and the heater and the vaporizer, in which the heater is adapted (i) to receive and heat the one or more additional gaseous non-methane hydrocarbons from the second inlet, and (ii) to feed the heated one or more additional gaseous non-methane hydrocarbons to the vaporizer along with the feed stream; the method further comprises: receiving the one or more additional gaseous non-methane hydrocarbons at the second inlet; feeding the one or more additional gaseous non-methane hydrocarbons to the heater, thereby forming the heated one or more additional gaseous non-methane hydrocarbons at a predetermined temperature; and combining the heated one or more additional gaseous non-methane hydrocarbons with one or both of (i) the feed stream before feeding both to the vaporizer to form the hydrocarbon gas feed stream, and (ii) the hydrocarbon gas feed stream downstream of the vaporizer.

6. The method of claim 1, wherein: the one or more non-methane hydrocarbons received at the first inlet comprise at least one gas-phase non-methane hydrocarbon; and the feed stream comprises water added to the one or more non-methane hydrocarbons downstream of the first inlet.

7. The method of claim 6, wherein: the one or more non-methane hydrocarbons received at the first inlet further comprise at least one liquid-phase non-methane hydrocarbon.

8. The method of claim 1, wherein the combustion flue gas comprises elemental nitrogen, carbon dioxide, elemental oxygen and water.

9. The method of claim 1, comprising: feeding the hydrocarbon gas feed stream to the first reactor at first operating conditions having a selected steam:carbon ratio and having a selected reaction temperature favoring methane production in the first reactor, in the resulting first reformate, and in the resulting platform gas; wherein: the steam:carbon ratio for the first operating conditions is up to 2.6; the reaction temperature for the first operating conditions is characterized by an inlet temperature to the first reactor in a range of 400°C to 550°C; the reaction temperature for the first operating conditions is characterized by an outlet temperature of the first reactor within 100°C of the inlet temperature; and the platform gas has: a methane content in a range of 40 mol.% to 70 mol.%; a hydrogen content in a range of 10 mol.% to 30 mol.%; a carbon dioxide content in a range of 10 mol.% to 30 mol.%; optionally a carbon monoxide content in a range of 0.01 mol.% to 5 mol.%; and optionally a water content in a range of 0.01 mol.% to 5 mol.%.

10. The method of claim 1, comprising: feeding the hydrocarbon gas feed stream to the first reactor at second operating conditions having a selected steam:carbon ratio and having a selected reaction temperature favoring hydrogen production in the first reactor, in the resulting first reformate, and in the resulting platform gas; the steam:carbon ratio for the second operating conditions is in a range of 3 to 8; the reaction temperature for the second operating conditions is characterized by an inlet temperature to the first reactor in a range of 400°C to 850°C; the reaction temperature for the second operating conditions is characterized by an outlet temperature of the first reactor that is 50°C to 350°C higher than the inlet temperature; and the platform gas has: a methane content up to 30 mol.%; a hydrogen content of at least 50 mol.%; a carbon dioxide content in a range of 10 mol.% to 30 mol.%; optionally a carbon monoxide content in a range of 0.01 mol.% to 10 mol.%; and optionally a water content in a range of 0.01 mol.% to 10 mol.%.

11. The method of claim 9 or 10, further comprising: operating the first reactor under at least one of the first operating conditions favoring methane production and the second operating conditions favoring hydrogen production; and subsequently operating under the other of the first operating conditions favoring methane production or the second operating conditions favoring hydrogen production.

12. The method of claim 9 or 10, further comprising: operating the first reactor under the first operating conditions favoring methane production as an isothermal reactor; and operating the first reactor under the second operating conditions favoring hydrogen production as a temperature increase-controlled reactor.

13. The method of claim 1, comprising: operating the first reactor as an adiabatic reactor, an isothermal reactor, a temperature increase-controlled reactor, or a temperature decrease-controlled reactor.

14. The method of claim 1, comprising: feeding the inlet heating fluid to the first reactor cocurrent to the hydrocarbon gas feed stream.

15. The method of claim 1, comprising: feeding the inlet heating fluid to the first reactor countercurrent to the hydrocarbon gas feed stream.

16. The method of claim 1, comprising: 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 and optionally having one or more targeted fuel parameters selected from the group consisting of Wobbe Index, methane number, heating value, and combinations thereof.

17. The method of claim 1, further comprising: feeding the platform gas to at least one of a methane separator, a carbon dioxide separator, a hydrogen separator, and a methanation reactor in series to provide the at least one of the hydrogen gas stream and the product gas stream.

18. The method of claim 17, comprising: feeding the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream.

19. The method of claim 17, comprising: feeding a first portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream; and combining a second portion of the platform gas with a hydrogen-rich tail gas stream from the hydrogen separator to form the product gas stream.

20. The method of claim 17, comprising: feeding a first portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream; and combining a second portion of the platform gas with (i) a portion of the carbon dioxide separator outlet stream, and (ii) a hydrogen-rich tail gas stream from the hydrogen separator and optionally an external gaseous stream to form the product gas stream.

21. The method of claim 17, comprising: feeding the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream; and feeding the hydrogen-rich tail gas stream to the methanation reactor to provide a methane-rich product gas.

22. The method of claim 17, comprising: feeding a first portion of the platform gas to the carbon dioxide separator and the hydrogen separator in series to provide a fuel cell-grade hydrogen gas stream and a hydrogen-rich tail gas stream; and feeding at least one of (i) the hydrogen-rich tail gas stream, (ii) a second portion of the platform gas, and (iii) a portion of the carbon dioxide separator outlet stream to the methanation reactor to provide a methane-rich product gas.

23. The method of claim 17, comprising: feeding the platform gas to the methanation reactor to provide a methane-rich product gas.

24. The method of claim 1, further comprising: feeding the combustion flue gas and the steam to a combustion carbon dioxide separator, thereby forming a carbon dioxide-rich stream.

25. The method of claim 1, further comprising: feeding the platform gas to at least one of a reverse water gas shift (rWGS) reactor, a Fischer-Tropsch (FT) reactor, and a hydrotreater (or hydrodesulfurization reactor) in series to provide a heavy hydrocarbon gas stream.

26. The method of claim 25, wherein the heavy hydrocarbon gas stream comprises a fuel selected from the group consisting of gasoline, diesel, aviation fuel, and jet fuel.

27. The method of claim 1, further comprising: feeding one or more components of the platform gas to a methanol production process for the synthesis of methanol from products of the HHR module.

28. The method of claim 1 , The method of claim 1 , wherein: the HHR module further comprises: a water gas shift (WGS) reactor positioned between the first reactor and the cooler, the water gas shift reactor being adapted to (i) receive the first reformate from the first reactor, (ii) perform a water gas shift reaction favoring formation of additional hydrogen in the first reformate to form a hydrogen-enriched first reformate, and (iii) feed the hydrogen- enriched first reformate to the cooler; and the method further comprises: operating the first reactor under second operating conditions favoring hydrogen production; feeding the first reformate to the water gas shift reactor, thereby performing a water gas shift reaction favoring formation of additional hydrogen in the first reformate to form a hydrogen-enriched first reformate; and feeding the hydrogen-enriched first reformate to the cooler.

29. The method of claim 1 , wherein the HHR module does not contain a water gas shift reactor.

30. The method of claim 1 , wherein: the HHR module further comprises: a second steam generator adapted to (i) receive at least one of the recycled system water and fresh water fed to the HHR module, and (ii) output steam; and a super heater adapted to (i) receive the one or more non-methane hydrocarbons in gaseous form and the steam from the second steam generator, which together form the feed stream, and (ii) superheat the feed stream to the predetermined temperature range as the hydrocarbon gas feed stream; the method further comprises: outputting steam from the second steam generator; admixing the steam from the second steam generator with the one or more nonmethane hydrocarbons, thereby forming the feed stream; superheating the feed stream in the superheater, thereby forming the hydrocarbon gas feed stream; feeding the hydrocarbon gas feed stream from the superheater to the first reactor.

31. The method of claim 1 , wherein: the HHR module comprises the vaporizer; the method further comprises: feeding the first reformate to the vaporizer as a hot fluid vaporizing the feed stream to form the hydrocarbon gas feed stream, thereby cooling the first reformate.

32. The method of claim 1, wherein: the HHR module comprises the vaporizer; and the HHR module further comprises: one or more heat exchangers in series positioned upstream or downstream of the vaporizer, the one or more heat exchangers being adapted to heat the at least one of the feed steam and the hydrocarbon gas feed stream before entering at least one of the vaporizer and the first reactor by using the first reformate as a hot heat exchange fluid.

33. The method of claim 1, wherein: the HHR module further comprises: one or more heat exchangers in series positioned between (i) the at least one of the vaporizer and the heater, and (ii) the first reactor, the one or more heat exchangers being adapted to heat the hydrocarbon gas feed stream before entering the first reactor by using the outlet heating fluid as a hot heat exchange fluid.

34. The method of claim 1, wherein: the HHR module further comprises: one or more heat exchangers in series positioned between (i) the first reactor, and (ii) the cooler, the one or more heat exchangers being adapted to heat the recycled system water by using the first reformate as hot heat exchange fluid.

35. The method of claim 1, further comprising: establishing a direct connection between the HHR module and an ethanol production facility, wherein: (i) an ethanol and water mixture having an ethanol content in a range of 25- 35% (v/v) and a water content in a range of 65-75% (v/v) is obtained from one or more ethanol production process streams in the ethanol production facility, and (ii) the ethanol and water mixture is received at the first inlet as the feed stream.

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 ethanol and water, the method comprising: establishing a direct connection between a first (HHR) reactor and an ethanol production facility wherein an ethanol and water mixture with a target ethanol concentration is obtained from one or more ethanol production process streams; suppling the ethanol and water mixture with the target ethanol concentration directly to a hydrocarbon conversion system comprising the first reactor for use as a feed stream to the first reactor; optionally adding water and/or additional hydrocarbons to the ethanol and water mixture to achieve a target steam to carbon ratio for the hydrocarbon feed stream; and feeding the hydrocarbon feed stream in gaseous form to the first reactor, thereby reacting at least a portion of the hydrocarbon feed stream to form a first reformate comprising carbon oxides, hydrogen, methane, and water.

37. The method of claim 36, wherein the ethanol and water mixture has a water concentration of about 70% (v/v).

38. The method of claim 36, wherein the ethanol and water mixture has a water concentration of about 1-99% (v/v).

39. A hydrocarbon conversion system for converting a hydrocarbon gas feed stream comprising one or more non-methane hydrocarbons, water, 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 one or more non-methane hydrocarbons; a first outlet for delivering a platform gas comprising methane and hydrogen; a second outlet for delivering a combustion flue gas; a third outlet for delivering steam; at least one of a vaporizer and a heater adapted to (i) receive a feed stream comprising in admixture the one or more non-methane hydrocarbons and water, and (ii) output the feed stream as the hydrocarbon gas feed stream at a predetermined temperature; a first reactor containing a first catalyst and being adapted to (i) receive the hydrocarbon gas feed stream in fluid communication with the first reactor and (ii) receive an inlet heating fluid, wherein the first reactor and the first catalyst are adapted to react at least a portion of the non-methane hydrocarbons in the hydrocarbon gas feed stream into carbon oxides, hydrogen, methane, and water, thereby (i) forming a first reformate comprising the carbon oxides, the hydrogen, the methane, and water, and (ii) forming an outlet heating fluid; 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; and a steam generator adapted to (i) receive the recycled system water stream, (ii) receive the outlet heating fluid, and (iii) output steam.

40. The hydrocarbon conversion system of claim 39, wherein: the HHR module further comprises: a water gas shift (WGS) reactor positioned between the first reactor and the cooler, the water gas shift reactor being adapted to (i) receive the first reformate from the first reactor, (ii) perform a water gas shift reaction favoring formation of additional hydrogen in the first reformate to form a hydrogen-enriched first reformate, and (iii) feed the hydrogen- enriched first reformate to the cooler.

41. The hydrocarbon conversion system of claim 39, wherein: the HHR module further comprises: a second steam generator adapted to (i) receive at least one of the recycled system water and fresh water fed to the HHR module, and (ii) output steam; and a super heater adapted to (i) receive the one or more non-methane hydrocarbons in gaseous form and the steam from the second steam generator, which together form the feed stream, and (ii) superheat the feed stream to the predetermined temperature range as the hydrocarbon gas feed stream.

42. The hydrocarbon conversion system of claim 39, wherein: the HHR module further comprises: a second inlet for receiving one or more additional gaseous non-methane hydrocarbons; and the heater and the vaporizer, in which the heater is adapted (i) to receive and heat the one or more additional gaseous non-methane hydrocarbons from the second inlet, and (ii) to feed the heated one or more additional gaseous non-methane hydrocarbons to one or both of (A) the vaporizer along with the feed stream, and (B) the hydrocarbon gas feed stream downstream of the vaporizer.

43. The hydrocarbon conversion system of claim 39, wherein: the HHR module comprises the vaporizer, the vaporizer being adapted to receive the first reformate as a hot fluid vaporizing the feed stream to form the hydrocarbon gas feed stream.

44. The hydrocarbon conversion system of claim 39, wherein: the HHR module comprises the vaporizer; and the HHR module further comprises: one or more heat exchangers in series positioned upstream or downstream of the vaporizer, the one or more heat exchangers being adapted to heat the at least one of the feed steam and the hydrocarbon gas feed stream before entering at least one of the vaporizer and the first reactor by using the first reformate as a hot heat exchange fluid.

45. The hydrocarbon conversion system of claim 39, wherein: the HHR module further comprises: one or more heat exchangers in series positioned between (i) the at least one of the vaporizer and the heater, and (ii) the first reactor, the one or more heat exchangers being adapted to heat the hydrocarbon gas feed stream before entering the first reactor by using the outlet heating fluid as a hot heat exchange fluid.

46. The hydrocarbon conversion system of claim 39, wherein: the HHR module further comprises: one or more heat exchangers in series positioned between (i) the first reactor, and (ii) the cooler, the one or more heat exchangers being adapted to heat the recycled system water by using the first reformate as hot heat exchange fluid.