Integrated production of hydrogen, electricity and heat

Abstract

A method and system for the co-production of hydrogen, power and thermal energy. An exemplary method includes desulfurizing a feed stream to form a desulfurized feed stream, reforming the desulfurized feed stream to form a methane-rich gas, and feeding the methane-rich gas to a membrane separator. A hydrogen stream is produced in the permeate from the membrane separator. A residue stream from the membrane separator is provided to a solid oxide fuel cell (SOFC). The SOFC generates power from the residue stream.

Description

[Technical field]

[0001] This application claims priority to U.S. Patent Application No. 17 / 191,992, filed March 4, 2021, the entire contents of which are incorporated herein by reference. [Background technology]

[0002] Atmospheric carbon dioxide (CO2) is steadily increasing, exacerbating environmental problems such as climate change and ocean acidification around the world. CO2 alone accounts for more than 75% of greenhouse gases. To slow down the potential negative impacts of CO2 on the environment, scientific research is focusing on the capture, transformation and sequestration of CO2 from sectors that account for the majority of emissions, such as transportation and power generation.

[0003] The electrification of the transportation sector is progressing rapidly with the rise of hydrogen fuel cell electric vehicles and battery electric vehicles, making it possible to eliminate emitting sources such as passenger cars and heavy duty vehicles. However, addressing the infrastructure requirements to supply hydrogen and electricity to these new applications is a particular challenge. An efficient global hydrocarbon distribution infrastructure already exists in many parts of the world, and the present invention makes it possible to economically utilize this infrastructure to address new market demands for energy while the hydrogen and electricity infrastructure is established. Summary of the Invention

[0004] Embodiments described herein provide a method for the coproduction of hydrogen, power and thermal energy. The method includes desulfurizing a feed stream to form a desulfurized feed stream, reforming the desulfurized feed stream to form a methane-rich gas, and feeding the methane-rich gas to a membrane separator. A hydrogen stream is produced in the permeate from the membrane separator. A retantate stream from the membrane separator is provided to a solid oxide fuel cell (SOFC). In the SOFC, power is generated from the retantate stream.

[0005] Another embodiment described herein provides a trigeneration facility including a desulfurization unit for removing sulfur from a hydrocarbon feed stream forming a desulfurized feed stream, a pre-reformer for converting the desulfurized feed stream to a methane-rich gas, a membrane separator for removing at least a portion of the hydrogen from the methane-rich gas in the permeate, and a solid oxide fuel cell (SOFC) for generating power from a residue from the membrane separator. [Brief description of the drawings]

[0006] [Figure 1] FIG. 1 is a schematic diagram of a trigeneration facility incorporating a hydrogen membrane separator.

[0007] [Diagram 2] FIG. 1 is a schematic diagram of a trigeneration facility incorporating a hydrogen membrane separator integrated with a water gas shift reactor.

[0008] [Diagram 3] 1 is a flow chart of a process using a hydrocarbon feed stream to produce hydrogen, electricity, and heat in a trigeneration facility incorporating a hydrogen membrane separator.

[0009] [Figure 4] 1 is a flow chart of a process using a hydrocarbon feed stream to produce hydrogen, electricity and heat in a trigeneration facility incorporating a hydrogen membrane separator integrated with a water gas shift reactor.

[0010] [Diagram 5] A simplified process model of a trigeneration plant incorporating a hydrogen membrane separator.

[0011] [Figure 6] A simplified process model of a trigeneration plant incorporating a hydrogen membrane separator integrated with a water-gas shift reactor. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0012] The systems described herein address the technical, systemic, and infrastructure challenges faced by the transportation industry in achieving improved efficiency and sustainability. Examples described herein provide a trigeneration facility that includes a desulfurization unit, a pre-reformer, a membrane separator, and a solid oxide fuel cell (SOFC). In the desulfurization unit, sulfur and other impurities are removed from a hydrocarbon feed stream, typically having 12 or fewer carbon atoms and, for example, a boiling point below about 200° C. The resulting desulfurized stream is processed in a pre-reformer to produce a methane-rich gas stream containing hydrogen.

[0013] The reformate from the pre-reformer flows through a membrane separator that removes hydrogen from the reformate. The hydrogen can be used as a zero carbon product for transportation, power generation, and other uses, such as chemical plants. A portion of the hydrogen may be used for hydrodesulfurization, for example in a desulfurization unit. After removing at least a portion of the hydrogen, the remaining reformate is fed to a SOFC to generate power. The thermal energy produced in the SOFC can be used in other processes, such as steam generation. At least a portion of the thermal energy may be used to heat the remaining reformate stream to the operating temperature of the SOFC before introducing it into the SOFC. The waste stream from the SOFC, including CO2, can be purified for use in CO2 conversion processes or sequestration.

[0014] In this facility, hydrocarbon feed streams are directly processed to produce power, hydrogen, and heat. In addition to power, these technologies can be used to produce syngas and potentially hydrogen. If low carbon footprint operations are the goal, the CO2 in the waste streams can be captured and used or stored.

[0015] 1 is a schematic diagram of a trigeneration system 100 incorporating a hydrogen membrane separator 102. The trigeneration system 100 has a hydrocarbon feed 104 that may include any number of light hydrocarbons. In various embodiments, the hydrocarbon feed 104 includes natural gas, liquefied petroleum gas (city gas), or naphtha having a boiling range up to 200° C.

[0016] 1, the desulfurization unit 106 removes sulfur and other impurities, for example, by a hydrodesulfurization or hydrodemetalization process. In some embodiments, the desulfurization is performed by an adsorbent at ambient temperature. These embodiments may provide easier operation and maintenance when the amount of sulfur in the gas is relatively low, for example, less than about 1%, less than about 0.5%, less than about 1500 ppm, less than about 500 ppm, or less.

[0017] In embodiments using a desulfurization catalyst, the hydrogen stream may be fed to a desulfurization unit 106. In the desulfurization unit 106, contaminants such as metals, sulfur, and nitrogen may be removed by passing the hydrocarbon feed 104 through a series of layered catalysts that perform one or more of the catalytic functions of demetalization, desulfurization, and denitrogenation. In some embodiments, the series of catalysts for performing hydrodemetalization (HDM) and hydrodesulfurization (HDS) may include a hydrodemetalization catalyst, an intermediate catalyst, a hydrodesulfurization catalyst, and a final catalyst.

[0018] The intermediate catalyst can be used to transition between the hydrodemetallization and hydrodesulfurization functions. The intermediate catalyst can have an intermediate metal loading and pore size distribution. The catalyst in the desulfurization unit 106 can be an alumina-based support in the form of extrudates, at least one catalytic metal from Group VI (e.g., molybdenum, tungsten, or both), at least one catalytic metal from Group VIII (e.g., nickel, cobalt, or both), or a combination of any two or more thereof. The catalyst can contain at least one dopant, such as one or more of boron, phosphorus, halogen, and silicon. The intermediate catalyst can be about 140 m. 2 / g~about 200m 2 / g surface area of ​​at least about 0.6 cm 3 / g and mesoporous pores with sizes from about 12 nm to about 50 nm.

[0019] The catalyst for desulfurization is approximately 180 m 2 / g ~ approx. 240m 2 The higher surface area of ​​the HDS catalyst may include a gamma alumina-based support material having a surface area in the higher end of the HDM range, such as between 1 cm3 / g. The higher surface area of ​​the HDS catalyst may have a pore volume of approximately 1 cm3 / g. 3 The catalyst contains at least one element from Group VI, such as molybdenum, and at least one element from Group VIII, such as nickel. The catalyst also contains at least one dopant, such as one or more of boron, phosphorus, silicon, and a halogen. In some examples, cobalt (Co) can be used to provide a relatively high level of desulfurization. The metal loading on the active phase is higher for higher desired activity, such that the molar ratio of Ni:(Ni+Mo) is about 0.1 to about 0.3, and the molar ratio of (Co+Ni):Mo is about 0.25 to about 0.85.

[0020] As described herein, the desulfurization unit 106 treats the hydrocarbon feed 104 with hydrogen, for example, from the hydrogen membrane separator 102. This hydrogen may be added as a proportion of the hydrocarbon feed 104 at 0.1 mol %, 0.5 mol %, 1 mol %, 5 mol %, or more.

[0021] The desulfurization unit 106 can operate at a temperature between about 300° C. and about 450° C., such as about 300° C., about 350° C., about 400° C., about 450° C., or another temperature. The desulfurization unit 106 can operate at a pressure between about 30 bar and about 180 bar, such as about 30 bar, about 60 bar, about 90 bar, about 120 bar, about 150 bar, about 180 bar, or another pressure.

[0022] The desulfurized stream 108 from the desulfurization unit 106 has steam 110 added before being reformed in a pre-reformer 112, for example with a Ni-based catalyst. As used herein, a pre-reformer generally converts a hydrocarbon stream into a methane-rich stream containing CH4, H2, CO, CO2, and water steam. A reformer is generally designated to completely convert the hydrocarbon stream into a synthesis gas containing primarily H2, CO, CO2, steam, and small amounts of CH4.

[0023] In the pre-reformer 112, the hydrocarbons react with the steam 110. The pre-reformer 112 can operate at a pressure between about 0.01 bar and about 50 bar, such as about 0.01 bar, about 0.1 bar, about 0.5 bar, about 1 bar, about 5 bar, about 10 bar, about 20 bar, about 30 bar, about 40 bar, about 50 bar, or another pressure. The molar ratio of hydrogen to hydrocarbons at the outlet of the pre-reformer 112 can be between about 1:1 and about 10:1, such as about 1:1, about 2:1, about 4:1, about 6:1, about 8:1, about 10:1, or another ratio. The pre-reformer 112 can operate at a temperature between about 300° C. and about 550° C., such as about 300° C., about 400° C., about 450° C., about 500° C., about 550° C., or another temperature.

[0024] The pre-reformer 112 is a process for converting at least nearly all of the C2 + The pre-reformer 112 converts the hydrocarbons to C1 to produce a methane-rich gas or reformate 114. The reformate 114 from the pre-reformer 112 is sent to the hydrogen membrane separator 102. The hydrogen membrane separator 102 utilizes a hydrogen-selective membrane that operates at high temperatures. In some embodiments, the hydrogen membrane separator 102 operates at a temperature between about 300° C. and about 550° C. In some embodiments, the hydrogen membrane separator 102 includes a proton-conducting material that is electrically driven to transport hydrogen to the permeate side.

[0025] In various embodiments, the hydrogen-selective membrane comprises palladium, a palladium alloy, a carbon-based membrane, or a zeolite-based membrane. The membrane selectively removes hydrogen from the reformate 114 in the permeate stream 116. The choice of membrane can be based on cost, ease of manufacture, lifetime, and other factors such as hydrogen flux.

[0026] The hydrogen is further processed, for example, as needed, to reach purity specifications for fuel cell applications such as vehicles. According to ISO FDIS 1467-2, hydrogen purity is typically at least 99.97%. For example, a pressure swing adsorption (PSA) system (not shown) may be included in the trigeneration facility 100 for hydrogen purification. In these embodiments, the permeate stream 116 is sent to the PSA system. The PSA system may include two columns filled with zeolite absorbent, one active column and one regenerator. The permeate stream 116 flows through the active column, which absorbs impurities from the hydrogen stream. In embodiments, the purity of hydrogen in the permeate stream 116 is about 80 vol.% or more, about 90 vol.% or more, about 95 vol.% or more, or more. When impurities start to pass through the active column, the flow is switched to the regenerator, which then becomes the active column. The previous active column is then regenerated.

[0027] After purification, the hydrogen is compressed to 400-900 bar as needed to supply the fuel cell vehicle. The flow of hydrogen in the permeate stream 116 can be increased by controlling the permeate pressure or the membrane surface area. Increasing the pressure of the reformate 114 increases the hydrogen flux through the membrane, resulting in an increased flow rate of the permeate stream 116. Alternatively, increasing the pressure of the reformate 114 coupled with a higher surface area results in an increased flow rate of the permeate stream 116.

[0028] The residue stream 118 from the membrane separator is sent to the anode side of a solid oxide fuel cell (SOFC) 124. In some embodiments, a heat exchanger 120 is used to adjust the temperature of the residue stream 118 forming a temperature-controlled stream 122. The temperature of the temperature-controlled stream 122 can be elevated to minimize the temperature gradient between the anode and cathode sides and to avoid thermal shock (since SOFCs operate at much higher temperatures). Air or another oxidant is fed to the cathode side of the SOFC 124, and an electrochemical reaction produces electricity 126. The hydrocarbons in the residue stream 118 can be further reformed in the SOFC 124 to increase the amount of synthesis gas in the anode exhaust 128. The anode exhaust 128 can be recycled back to the membrane reactor or can be used to generate heat 130 to preheat a feed stream, such as flowing through the heat exchanger 120 to increase the temperature of the reformate 118 and form the temperature-controlled stream 122. Because the electricity generated in the SOFC 124 is exothermic, other techniques can be used to remove the heat 130 from the SOFC 124, such as passing more air over the cathode side of the SOFC 124, surrounding the SOFC 124 with a heat exchanger, or including cooling coils within the structure of the SOFC 124. Thus, the trigeneration system 100 allows for optimization of the production of hydrogen in the permeate stream 116, electricity 126, and heat 130.

[0029] Figure 2 is a schematic diagram of a trigeneration system 200 incorporating a hydrogen membrane separator with an integrated water-gas shift reactor. Like numbered items are as described with respect to Figure 1. Additionally, the trigeneration system 200 of Figure 2 can also include a PSA system for purifying the hydrogen in the permeate 116.

[0030] In this example, the reformate 114 is sent to a membrane reactor 202 that is packed with a water gas shift catalyst along with a high temperature membrane. In some embodiments, the water gas shift catalyst can be a high temperature iron oxide based or a low to medium temperature copper oxide based catalyst. The presence of the water gas shift catalyst allows for the conversion of carbon monoxide in the reformate 114 to hydrogen and CO2.

[0031] FIG. 3 is a flow chart of a method 300 for producing hydrogen, electricity, and heat using a hydrocarbon feed stream in a trigeneration facility incorporating a hydrogen membrane separator. The method 300 begins with desulfurization of the hydrocarbon feed stream in block 302. As described herein, this can be performed using a desulfurization catalyst or, if the amount of sulfur is low, using an adsorbent. In various embodiments, the adsorbent includes activated carbon, CuO / ZnO / Al2O3, Ag-zeolite, or Ag / CeO2, among others. The adsorbent does not need to operate at high temperatures, but can operate at ambient temperatures, such as from about 5° C. to about 50° C. The choice of adsorbent depends on the type of sulfur compound and the hydrocarbon feedstock. For example, various adsorbents can be used for H2S, COS, sulfur-containing heteroatomic hydrocarbons, etc. Low temperature techniques are economical for small scale and simplified maintenance, such as replacing a sulfur adsorbent cartridge in a passenger vehicle.

[0032] In block 304, the desulfurized feed stream is reformed, for example in a pre-reformer. Steam is added to the desulfurized feed stream upstream of the pre-reformer.

[0033] Hydrogen is separated from the reformate as a permeate stream in a membrane separator at block 306. As described herein, the membrane separator may be operated at high temperatures.

[0034] In block 308, the residue stream from the membrane separator is provided to the anode of a SOFC where electricity is generated from the residue stream and the oxidant stream provided to the cathode. In block 304, a portion of the anode exhaust stream is mixed with the desulfurization feed stream and can be recycled to provide the necessary steam to the pre-reformer, processed for carbon dioxide sequestration, or processed to recover the remaining fuel value for heat.

[0035] In block 310, the permeate stream can be processed to purify hydrogen, for example for use in transportation applications. This purification can be accomplished by pressure swing adsorption, among other methods.

[0036] In block 312, process heat from the SOFC is provided to other process units, such as a heat exchanger used to increase the temperature of the residue stream before providing it to the anode of the SOFC. In another embodiment, the process heat is used to generate steam for a chemical plant.

[0037] Figure 4 is a flow chart of a method 400 for producing hydrogen, electricity and heat using a feed stream in a trigeneration facility incorporating a hydrogen membrane separator with an integrated water-gas shift reactor. Items as described with respect to Figure 3 are similarly numbered. In this method 400, a water-gas shift reaction is performed on the reformate at block 402 prior to or during separation of the hydrogen. In some embodiments, a water-gas shift catalyst is included in the membrane separator to increase the yield of hydrogen and CO2.

[0038] Working Example

[0039] Process Simulation

[0040] Process models were built using Aspen plus (version 10) for the embodiments described with respect to Figures 1 and 2, where all components of the process are modeled to determine mass and energy flows. These process models include detailed routing of various flows that can satisfy pre-heating or cooling of process streams by matching the available heat content of the hot streams with the pre-heating heat load requirements of the process components. Also, since these embodiments are not standard "plug and play" modeling modules in the Aspen plus library, these embodiments show how the hydrogen-selective membranes in the hydrogen membrane separators 102 and 202, as well as the SOFC 124, can be represented on the Aspen plus modeling platform.

[0041] FIG. 5 is a simplified process model 500 of a trigeneration facility incorporating a hydrogen membrane separator. Modeling results for S / C=3 are shown in Tables 1-3, and modeling results for S / C=4 are shown in Tables 4-6. S / C is the steam-to-carbon ratio and is defined as the molar flow rate of steam multiplied by the molar flow rate of the hydrocarbon feed multiplied by its carbon number; for example, when S / C=3, the molar flow rate of steam divided by the sum of the molar flow rate of propane multiplied by 3 and the molar flow rate of butane multiplied by 4 is 3.

[0042] [Table 1]

[0043] [Table 2]

[0044] [Table 3]

[0045] [Table 4]

[0046] [Table 5]

[0047] [Table 6]

[0048] A simplified process model of a trigeneration plant incorporating a hydrogen membrane separator with an integrated water-gas shift reactor is shown in Figure 6. In a simulation based on the trigeneration plant of Figure 6, the pre-reformer is operated at a temperature of 493°C and a pressure of 10 bar. Modeling results for a system with S / C=3, where there is a water-gas shift reaction prior to the hydrogen separation membrane, are shown in Tables 7-12.

[0049] [Table 7]

[0050] [Table 8]

[0051] [Table 9]

[0052] [Table 10]

[0053] [Table 11]

[0054] [Table 12]

[0055] Tables 13 to 18 show the modeling results for a system with S / C=4 in which a water gas shift reaction exists before the hydrogen separation membrane.

[0056] [Table 13]

[0057] [Table 14]

[0058] [Table 15]

[0059] [Table 16]

[0060] [Table 17]

[0061] [Table 18]

[0062] Exemplary embodiments

[0063] Embodiments described herein provide a method for co-producing hydrogen, electrical power, and thermal energy. The method includes desulfurizing a feed stream to form a desulfurized feed stream, reforming the desulfurized feed stream to form a methane-rich gas, and feeding the methane-rich gas to a membrane separator. A hydrogen stream is produced in the permeate from the membrane separator. A residue stream from the membrane separator is provided to a solid oxide fuel cell (SOFC). The SOFC generates electrical power from the residue stream.

[0064] In one aspect, the method includes mixing the feed stream with hydrogen prior to desulfurizing the feed stream. In one aspect, a portion of the hydrogen stream is mixed with the feed stream prior to desulfurizing the feed stream. In one aspect, the method includes desulfurizing the feed stream in an adsorption unit.

[0065] In one embodiment, the method includes compressing the hydrogen stream for use as a product.In one embodiment, the method includes heating the residue stream to an operating temperature of the SOFC prior to feeding the residue stream to the SOFC.

[0066] In one embodiment, the method includes utilizing heat generated in the SOFC. In one embodiment, the method includes heating a residue stream with heat generated in the SOFC. In one embodiment, the method includes generating steam using heat generated in the SOFC.

[0067] Another embodiment described herein provides a trigeneration facility, the trigeneration facility including a desulfurization unit for removing sulfur from a hydrocarbon feed stream forming a desulfurized feed stream, a pre-reformer for converting the desulfurized feed stream to a methane-rich gas, a membrane separator for removing at least a portion of the hydrogen from the methane-rich gas in the permeate, and a solid oxide fuel cell (SOFC) for generating power from a residue from the membrane separator.

[0068] In one embodiment, the trigeneration facility includes a heat exchanger for utilizing thermal energy from the SOFC. In one embodiment, the trigeneration facility includes a heat exchanger for heating the residue to the operating temperature of the SOFC.

[0069] In one embodiment, the pre-reformer comprises a steam reformer comprising a nickel catalyst. In one embodiment, the pre-reformer operates at a temperature between about 300° C. and about 550° C. In one embodiment, the steam reformer operates at a pressure between about 2 bar and about 30 bar.

[0070] In one embodiment, the trigeneration facility includes a water gas shift catalyst for increasing the amount of hydrogen in the methane rich gas. In one embodiment, the water gas shift catalyst includes iron oxide or copper oxide.

[0071] In one embodiment, the membrane separator is a high temperature hydrogen selective membrane. In one embodiment, the membrane separator comprises palladium, a palladium alloy, or both. In one embodiment, the membrane separator comprises a carbon-based membrane, a zeolite-based membrane, or both. In one embodiment, the membrane separator comprises an integrated water gas shift catalyst. In one embodiment, the membrane separator comprises an electrically driven proton conducting material to transport hydrogen to the permeate side.

[0072] In one embodiment, the feed stream comprises propane, butane, or both. In one embodiment, the feed stream comprises liquefied natural gas. In one embodiment, the feed stream comprises raw (unprocessed) natural gas.

[0073] Other implementations are within the scope of the following claims.

Claims

1. A trigeneration facility comprising: a desulfurization unit for removing sulfur from a hydrocarbon feed stream to form a desulfurized feed stream, the desulfurization unit comprising a desulfurization catalyst comprising a gamma alumina based support, at least one catalytic metal from Group VI, at least one catalytic metal from Group VIII, and at least one dopant selected from the group consisting of boron, phosphorus, halogens, and silicon; a pre-reformer for converting the desulfurized feed stream to a methane rich gas, the pre-reformer comprising a steam reformer comprising a nickel catalyst; a membrane separator for removing at least a portion of the hydrogen from the methane-rich gas in a permeate stream, the membrane separator comprising a water-gas shift catalyst that increases the amount of hydrogen in the methane-rich gas; a pressure swing adsorption unit for purifying hydrogen in the permeate stream and providing a purified stream; a compressed hydrogen stream at about 400 bar to 900 bar, said compressed hydrogen stream being a fuel stream from said refinery stream to a fuel cell vehicle; and a solid oxide fuel cell (SOFC) for producing power and heat from a residue stream from the membrane separator, the residue stream comprising methane; Trigeneration facility.

2. A heat exchanger for utilizing the generated heat. The trigeneration facility according to claim 1 .

3. A heat exchanger that uses the generated heat to heat the residual stream to the operating temperature of the SOFC. The trigeneration facility according to claim 1 .

4. The pre-reformer operates at a temperature between about 300°C and 550°C. The trigeneration facility according to claim 1 .

5. The steam reformer operates at a pressure between about 2 bar and 30 bar. The trigeneration facility according to claim 1 .

6. The water-gas shift catalyst comprising iron oxide or copper oxide. The trigeneration facility according to claim 1 .

7. The membrane separator is a high temperature hydrogen selective membrane. The trigeneration facility according to claim 1 .

8. The membrane separator comprises palladium, a palladium alloy, or both. The trigeneration facility according to claim 7.

9. The membrane separator comprising a carbon-based membrane, a zeolite-based membrane, or both. The trigeneration facility according to claim 7.

10. The membrane separator comprises a water-gas shift catalyst. The trigeneration facility according to claim 1 .

11. The membrane separator comprising a proton conducting material electrically driven to transport the hydrogen to a permeate side. The trigeneration facility according to claim 1 .

12. The feed stream comprising propane, butane or both. The trigeneration facility according to claim 1 .

13. The method of claim 12, wherein the feed stream comprises liquefied natural gas. The trigeneration facility according to claim 1 .

14. The process of claim 13, wherein the feed stream comprises unprocessed natural gas. The trigeneration facility according to claim 1 .

15. A trigeneration facility comprising: a desulfurization unit for removing sulfur from the hydrocarbon feed stream to form a desulfurized feed stream; a pre-reformer for converting the desulfurized feed stream into a methane rich gas; a membrane separator for removing at least a portion of the hydrogen from the methane-rich gas in a permeate stream, the membrane separator comprising a water-gas shift catalyst that increases the amount of hydrogen in the methane-rich gas; a compressed hydrogen stream at about 400 bar to 900 bar, said compressed hydrogen stream being a fuel stream from said trigeneration facility to a fuel cell vehicle; a solid oxide fuel cell (SOFC) for producing power and heat from a residue stream from the membrane separator, the residue stream comprising methane; Trigeneration facility.

16. A trigeneration facility comprising: a desulfurization unit operating at a temperature of about 300° C. to 550° C. for removing sulfur from the hydrocarbon feed stream to form a desulfurized feed stream; a pre-reformer for converting said desulfurized feed stream into a methane rich gas, said pre-reformer operating at a temperature of about 300° C. to 550° C. a membrane separator for removing at least a portion of the hydrogen from said methane-rich gas in a permeate stream, said membrane separator operating at a temperature between about 300° C. and 550° C., said membrane separator including a water-gas shift catalyst that increases the amount of hydrogen in the methane-rich gas; a compressed hydrogen stream at about 400 bar to 900 bar, said compressed hydrogen stream being a fuel stream from said trigeneration facility to a fuel cell vehicle; a solid oxide fuel cell (SOFC) for producing power and heat from a residue stream from the membrane separator, the residue stream comprising methane; Trigeneration facility.

17. The process of claim 16, further comprising the steps of: desulfurizing a feed stream to form a desulfurized feed stream; pre-reforming the desulfurized feed stream to form a methane-rich gas, the pre-reforming being carried out at a steam-to-carbon ratio (S / C) of about 3-4; feeding the methane-rich gas to a membrane separator containing a water-gas shift catalyst for increasing the amount of hydrogen in the methane-rich gas, the membrane separator being operated at a temperature between about 300° C. and 550° C.; producing a hydrogen stream in a permeate stream from the membrane separator, the hydrogen being compressed to about 400 bar to 900 bar and supplied to a fuel cell vehicle; providing a retentate stream from the membrane separator to a solid oxide fuel cell (SOFC); producing power and heat from the residue stream in the SOFC. A method for co-producing hydrogen, electricity and thermal energy.

18. The process of claim 17, further comprising the step of mixing a portion of the hydrogen stream with the feed stream prior to the step of desulfurizing the feed stream.

20. The method of claim 17.

19. The method of claim 18, further comprising the step of desulfurizing the feed stream in an adsorption unit.

20. The method of claim 17.

20. The method of claim 1, further comprising the step of heating the residual stream to an operating temperature of the SOFC prior to the step of supplying the residual stream to the SOFC.

20. The method of claim 17.

21. A process for utilizing the heat generated in the SOFC.

20. The method of claim 17.

22. The method of claim 21, further comprising the step of heating the residual stream with the heat produced by the SOFC.

22. The method of claim 21.

23. A process for generating steam using the heat generated by the SOFC.

22. The method of claim 21.

24. The water-gas shift catalyst comprising iron oxide or copper oxide.

20. The method of claim 17.

25. The pre-reforming step is operated at a temperature between about 300° C. and 550° C.

20. The method of claim 17.

26. The membrane separator comprising palladium, a palladium alloy, or both.

20. The method of claim 17.

27. The membrane separator comprising a carbon-based membrane or a zeolite-based membrane.

20. The method of claim 17.

28. The feed stream comprising propane or butane.

20. The method of claim 17.

29. The method of claim 20, wherein the feed stream comprises liquefied natural gas or unprocessed natural gas.

20. The method of claim 17.

30. The process of claim 30, further comprising the steps of: desulfurizing a feed stream to form a desulfurized feed stream; pre-reforming the desulfurized feed stream to form a methane-rich gas, the pre-reforming being carried out at a steam-to-carbon ratio (S / C) of about 3-4; feeding the methane-rich gas to a membrane separator containing a water-gas shift catalyst for increasing the amount of hydrogen in the methane-rich gas, the membrane separator being operated at a temperature between about 300° C. and 550° C.; generating a hydrogen stream in the permeate stream from the membrane separator; providing a retentate stream from the membrane separator to a solid oxide fuel cell (SOFC); producing power and heat from the residue stream in the SOFC. A method for co-producing hydrogen, electricity and thermal energy.

31. The hydrogen stream having a hydrogen purity of 80 vol% or greater, the method further comprising purifying the hydrogen stream. The method of claim 30.

32. The method of claim 31, wherein the purifying step comprises passing the hydrogen stream through a pressure swing adsorption (PSA) system comprising an adsorption column packed with a zeolite adsorbent.

32. The method of claim 31 .

33. The method of claim 32, further comprising compressing the purified hydrogen stream to about 400 bar to 900 bar.

32. The method of claim 31 .

34. The process of claim 33, further comprising the steps of: desulfurizing a feed stream to form a desulfurized feed stream; pre-reforming the desulfurized feed stream to form a methane-rich gas, the pre-reforming being carried out at a steam-to-carbon ratio (S / C) of about 3-4; feeding the methane-rich gas to a membrane separator containing a water-gas shift catalyst for increasing the amount of hydrogen in the methane-rich gas, the membrane separator being operated at a temperature between about 300° C. and 550° C.; generating a hydrogen stream in the permeate stream from the membrane separator; compressing the hydrogen stream to about 400 bar to 900 bar; supplying the compressed hydrogen stream to a fuel cell vehicle; providing a retentate stream from the membrane separator to a solid oxide fuel cell (SOFC); producing power and heat from the residue stream in the SOFC. A method for co-producing hydrogen, electricity and thermal energy.

35. The methane-rich gas has a hydrogen to hydrocarbon molar ratio of 1:1 to 10:

1.

35. The method of claim 34.

36. The method of claim 35, further comprising the step of heating the residual stream to an operating temperature of the SOFC using the heat generated in the SOFC prior to the step of supplying the residual stream to the SOFC.

35. The method of claim 34.

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