Process and system for producing hydrocarbon fuels with high carbon conversion efficiency

Abstract

To provide a process and a system for producing fuel from biomass with high carbon conversion efficiency.SOLUTION: The processes and systems described herein use specific combinations of components, process flows, and recycle streams to provide highly efficient processes for producing hydrocarbons from biomass with very low greenhouse gas (GHG) emissions. The processes and systems described herein provide greater than 95% carbon conversion efficiency with little to no GHG in the flue gas due to the novel arrangement of components, and utilize renewable energy to power some components. The system reuses water and carbon dioxide produced in the process flow and recycles the naphtha and tail gas streams to other units in the system for additional conversion to syngas that produces hydrocarbon-based fuels.SELECTED DRAWING: Figure 1

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 256,264, filed October 15, 2021, the disclosure of which is incorporated herein by reference in its entirety.

[0002] The present disclosure relates to processes and systems for processing renewable feedstocks to produce hydrocarbon-based fuels. More specifically, the present disclosure provides a highly efficient process for producing hydrocarbon-based fuels from biomass with very low greenhouse gas (GHG) emissions using a specific combination of components and process flows. [Background technology]

[0003] In order to reduce dependence on petroleum energy sources and reduce greenhouse gas emissions, several studies have been conducted to explore alternative petroleum-free processes for producing liquid fuels. These alternative studies include the production of synthetic liquid hydrocarbons from biomass, coal, and natural gas using synthesis gas ("syngas") intermediates. These energy processes have emerged as viable options due to their ability to produce liquid fuels from domestically available carbon-based energy sources. However, a common feature of these synthetic processes is the large amount of CO2 emitted from the system.

[0004] Conventional processes for converting natural gas feedstocks to synthesis gas typically involve autothermal reforming or steam methane reforming. Converting natural gas or biomass feedstocks to liquid fuels is referred to as natural gas to liquids (GTL) and biomass to liquids (BTL), respectively. Common processes involve converting feedstocks, such as biomass and / or natural gas, to a mixture of synthesis gas ("syngas," containing H2 and CO), which is then converted to liquid hydrocarbons via the Fischer-Tropsch process. The liquid hydrocarbons are subsequently upgraded, for example, via distillation, hydrocracking, and / or isomerization, to form end products (e.g., diesel or synthetic petroleum kerosene (SPK)). In both feedstock-to-synthesis gas conversion steps, intermediate processing steps remove impurities and excess CO2 that can be detrimental to the FT catalytic process to produce the final fuel product. Of particular concern are sulfur-containing compounds, such as H2S, COS, SO2, or mercaptans, because sulfur irreversibly deactivates the FT catalyst. Other unwanted contaminants, such as HO and CO, can also affect the performance of the FT catalyst through dilution of the primary synthesis reactants (e.g., H and CO) and / or temporary deactivation by oxidation of the active metals. Because HO is one of the products of the FT reaction, the presence of water affects the chemical equilibrium for the formation of the desired hydrocarbon products. To optimize carbon efficiency (the ratio of carbon produced to carbon fed), several recycle loops are added to the process configuration.

[0005] A key concern in hydrocarbon synthesis is maximizing utilization of input carbon from the feedstock—that is, converting as much of it as possible into product carbon while using an acceptable amount of energy (regardless of source) and while still maintaining acceptable amounts of produced water for environmental emissions, primarily CO2 emissions and trace pollutant treatment. Currently, CO2 capture and sequestration is based on a trade-off between additional energy for capturing and compressing the CO2 to be sequestered and reducing CO2 emissions. However, these additional processing steps to reduce CO2 emissions require additional energy and resources, substantially increasing energy consumption and introducing inefficiencies into the hydrocarbon synthesis process as additional CO2 is captured and sequestered. Because the aforementioned capture, compression, and sequestration processes utilize energy, these steps can also increase greenhouse gas emissions, thereby offsetting some of the benefits derived from sequestration.

[0006] In view of the above, there is a need to optimize the conversion of carbon emissions from processes that produce hydrocarbon-based fuels, thereby reducing and / or eliminating CO2. Summary of the Invention

[0007] The embodiments covered by the present disclosure are defined by the claims, not by this Summary. This Summary is a high-level overview of various aspects of the present invention and introduces some of the concepts that are further described in the Detailed Description section below. This Summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used alone to determine the scope of the claimed subject matter. The subject matter should be understood by reference to the entire specification, any or all drawings, and appropriate portions of each claim.

[0008] In some embodiments, the present disclosure provides a system for producing a hydrocarbon-based fuel. The system includes a biomass feedstock processing unit configured to remove waste products from the feedstock to produce a treated feedstock; a gasification unit in communication with the biomass feedstock processing unit and configured to convert the treated feedstock into a syngas comprising carbon dioxide, carbon monoxide, and hydrogen; a reactor downstream of the gasification unit operated at suitable conditions to promote conversion of a portion of the syngas to produce a suitable ratio of hydrogen to CO; a scrubber in communication with the reformer for removing carbon dioxide from the syngas and producing a purified syngas having a hydrogen:carbon monoxide ratio of at least 1.5:1; a Fischer-Tropsch reactor for receiving the purified syngas, the Fischer-Tropsch reactor converting the purified syngas into a Fischer-Tropsch liquor, product water, and tail gas; a water purification system for purifying product water for electrolysis; and an electrolysis unit configured to receive purified product water from the Fischer-Tropsch reactor and convert the purified product water into an oxygen stream and a hydrogen stream. A portion of the oxygen stream produced from the electrolysis unit is recycled to the gasification unit, the methane reformer, or a combination thereof. The system achieves at least 90% carbon conversion of the feedstock. In some embodiments, the system includes a reverse water-gas shift reactor. A portion of the carbon dioxide removed from the syngas in the scrubber is recycled to the reverse water-gas shift reactor. In some embodiments, a portion of the hydrogen stream produced by the electrolysis unit is fed to the reverse water-gas shift reactor. The reverse water-gas shift reactor is configured to produce carbon monoxide, which is fed to the Fischer-Tropsch reactor. In some embodiments, the syngas stream and the hydrogen stream are pressurized before being fed to the Fischer-Tropsch reactor. In some embodiments, the tail gas from the Fischer-Tropsch reactor is recycled to the reformer.In some embodiments, the system includes a hydrocracking unit, a fractionation unit, or a combination thereof configured to upgrade the Fischer-Tropsch liquid into various fuels, wherein a by-product of the hydrocracking unit includes a tail gas and a by-product of the fractionation unit includes naphtha. In some embodiments, the tail gas, naphtha, or both are recycled to the reformer. In some embodiments, the system includes a flue gas scrubber configured to scrub any flue gas produced by the system. In some embodiments, the system includes a carbon dioxide processing and compression system, wherein carbon dioxide produced from the scrubber and the flue gas scrubber is processed in the carbon dioxide processing and compression system to produce a purified carbon dioxide stream, and the purified carbon dioxide stream is recycled to the reformer, the reverse water-gas shift reactor, the CO2 electrolysis unit, or a combination thereof. In some embodiments, the feedstock comprises one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, switchgrass, wood chips, lignin, and cellulosic materials. In some embodiments, the feedstock comprises woody biomass. In some embodiments, the system includes a pre-reformer and an autothermal reforming unit or steam methane reformer configured to convert the natural gas feedstock into syngas. In some embodiments, the system includes a CO2 electrolysis unit configured to convert CO2 recovered from the system into carbon monoxide and O2. In some embodiments, O2 from the CO2 electrolysis may be sent to a gasifier, a reactor (e.g., a reformer), or other unit in the system that uses O2 in its process. Carbon monoxide may be sent to a Fischer-Tropsch reactor.

[0009] In some embodiments, the present disclosure provides a process for producing hydrocarbon-based fuels. The process includes gasifying a biomass feedstock to produce a first crude syngas stream containing carbon dioxide, hydrogen, and carbon monoxide; reforming the first crude syngas stream to produce a hydrogen-enriched syngas stream; separating the carbon dioxide from the hydrogen-enriched syngas stream in a separation unit to produce a carbon dioxide stream and a purified syngas stream having a hydrogen-to-carbon monoxide ratio of at least 1.5:1; enriching the purified syngas stream with additional hydrogen obtained via water electrolysis; reacting the purified syngas stream and the hydrogen-enriched syngas stream in a Fischer-Tropsch reactor to produce a Fischer-Tropsch liquor, water, and tail gas; recycling a portion of the water produced from the Fischer-Tropsch reactor to a water purification step and then to an electrolysis unit; and electrolyzing the purified water in the electrolysis unit to produce an oxygen stream and a hydrogen stream. In some embodiments, the process includes purifying the carbon dioxide stream produced from the separation unit to produce a purified carbon dioxide stream. In some embodiments, the process includes recycling the purified carbon dioxide stream to a "dry" reforming unit, a reverse water gas shift reactor, or a combination thereof. In some embodiments, the process includes recycling a portion of the oxygen stream and a portion of the hydrogen stream to a gasification step, a dry reforming step, a Fischer-Tropsch reactor, or a combination thereof. In some embodiments, the process includes recycling a portion of the hydrogen stream and a portion of the purified carbon dioxide stream to the reverse water gas shift reactor to produce carbon monoxide, augment the syngas in the Fischer-Tropsch reactor, increase carbon utilization, and produce additional Fischer-Tropsch liquor. In some embodiments, the process includes feeding the carbon monoxide produced from the reverse water gas shift reactor to the Fischer-Tropsch reactor to augment the syngas to the Fischer-Tropsch reactor and produce additional Fischer-Tropsch liquor. In some embodiments, the process includes treating natural gas in a reformer to produce a second syngas stream that is fed to the Fischer-Tropsch reactor.In some embodiments, the electrolysis unit is powered by solar energy, wind energy, hydroelectric energy, off-peak grid power, nuclear energy, or tidal energy. In some embodiments, the biomass feedstock comprises one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, switchgrass, wood chips, lignin, and cellulosic material. In some embodiments, the process comprises treating water produced from the Fischer-Tropsch reactor to produce boiler-quality feedwater, wherein the boiler-quality feedwater is electrolyzed in the electrolysis unit.

[0010] Further aspects, objects and advantages will become apparent from a consideration of the detailed description and figures that follow. [Brief explanation of the drawings]

[0011] [Figure 1] FIG. 1 shows a schematic diagram of a system for producing hydrocarbon fuel according to some embodiments of the present disclosure. [Figure 2] FIG. 1 shows a schematic diagram of a hydrocarbon synthesis process integrated with a CO electrolysis unit, according to some embodiments of the present disclosure. DETAILED DESCRIPTION OF THE INVENTION

[0012] Introduction The present disclosure relates to processes and systems for producing fuels (e.g., liquid jet fuel and / or diesel fuel) from biomass (e.g., forestry waste, railroad ties, greasewood, algae, agricultural waste, municipal waste, etc.) and renewable hydrogen feedstocks. In some embodiments, the biomass includes one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, switchgrass, wood chips, lignin, and / or cellulosic materials. For example, forest waste and residues can be used for fuel production, which are typically treated as waste feedstocks with minimal carbon footprints. Specifically, the processes and systems described herein provide a high-carbon utilization, highly efficient process for producing hydrocarbons from biomass and renewable hydrogen and / or natural gas with very low greenhouse gas (GHG) emissions using specific combinations of components and process flows described herein. In some embodiments, the processes and systems described herein provide carbon conversion efficiencies greater than 95% with little to no GHG in the flue gas due to the addition of renewable hydrogen and novel arrangements of components and process flows. For example, the systems beneficially reuse water and carbon dioxide produced in the process flows and recycle naphtha and tail gas streams to other units in the system (e.g., partial oxidation reformer and / or biomass gasifier) ​​for further conversion to syngas for producing hydrocarbon-based fuels.

[0013] Conventional processes for producing synthesis gas (e.g., H and CO) for conversion to liquid hydrocarbons are inherently inefficient because they involve energy-intensive CO and water (e.g., wastewater) removal processes. In fact, these processes require additional energy and resources to convert or remove the CO, adding inefficiencies and GHG emissions to the process. Such conventional processes do not effectively convert feedstocks to hydrocarbon-based fuels because they require significant amounts of energy to convert or remove the CO and to recycle the water produced in the hydrocarbon synthesis process, resulting in significant additional emissions.

[0014] As described herein, the processes and systems described herein achieve unexpectedly high carbon conversion efficiencies while maintaining very low GHG emissions through a novel arrangement of components and process flows, and the optional addition of renewable hydrogen. In some embodiments, the described processes and systems provide a gasification process in which a feedstock is converted to a synthesis gas ("syngas") comprising carbon monoxide, carbon dioxide, and hydrogen, and the synthesis gas is then converted to hydrocarbon fuels using a Fischer-Tropsch process. The process may include processing biomass in a gasification unit to form a first crude synthesis gas stream, processing the synthesis gas stream in a reactor (e.g., a reformer, a water-gas shift reactor, or a reverse water-gas shift reactor) to produce a second synthesis gas stream comprising hydrogen, carbon monoxide, and carbon dioxide, separating carbon dioxide from either or both of the first and second crude synthesis gas streams in a separation unit to form a carbon dioxide stream and a substantially CO2-free synthesis gas stream, purifying the carbon dioxide stream, and recycling the purified carbon dioxide to the dry reformer. The process may include reacting a synthesis gas stream in a Fischer-Tropsch reactor to produce hydrocarbon products and water. In some embodiments, the process includes purifying the product water and electrolyzing the purified water and / or carbon dioxide in an electrolysis unit to produce hydrogen and / or carbon monoxide.

[0015] In some embodiments, the process may include converting carbon dioxide to form synthesis gas by feeding hydrogen and CO from the electrolysis unit to a reverse water-gas shift reactor. In some embodiments, the hydrocarbon-based fuel produced in the Fischer-Tropsch reactor is upgraded in a hydrocracking unit and / or fractionation unit. The Fischer-Tropsch reactor can produce synthetic paraffinic kerosene and / or diesel fuel as a primary product, with tail gas and / or light ends, such as naphtha, produced as by-products recycled to a gasification unit or reactor (e.g., a reformer). The combination of these specific process steps, coupled with the addition of renewable hydrogen, provides a process with high carbon conversion efficiency, as output streams that would normally be discharged are recycled to generate additional synthesis gas.

[0016] Additionally, the present disclosure provides processes and systems for converting carbon dioxide and product water to syngas using an electrolysis unit. In some embodiments, the system includes a high-temperature co-electrolysis unit (HTCE). The HTCE unit can be configured to electrolyze CO and HO to convert them into additional syngas. The HTCE unit can convert CO and water (e.g., product water from a Fischer-Tropsch reactor) into additional syngas that can be used to produce additional hydrocarbons. For example, the system utilizes an HTCE unit to convert CO emitted from a hydrocarbon synthesis process into syngas in combination with water generated from the same process. The syngas produced from the HTCE unit can also be subjected to Fischer-Tropsch synthesis to produce more hydrocarbon-based fuels. Furthermore, the additional energy for the conversion to additional syngas (via co-electrolysis) can be provided from a non-carbon-based power source (e.g., a green energy source), resulting in a reduction in overall GHG emissions associated with the conversion of CO.

[0017] The systems and processes described herein can significantly reduce CO2 emissions by incorporating renewable hydrogen to enrich biomass-derived syngas and by recycling waste streams and byproducts to produce more hydrocarbon-based fuel per unit of biomass converted. In some embodiments, the systems may include an HTCE unit that converts product water and CO2 into hydrogen, carbon monoxide, and oxygen, a (reverse) water-gas shift reactor that converts hydrogen, oxygen, and CO2 into syngas, or a combination thereof. The systems and processes described herein beneficially contribute to the overall carbon efficiency of the process by providing a high conversion rate of the feedstock to useful product carbon associated with the final liquid fuel product. Advantageously, the additional energy required to convert CO2 and product water to syngas is offset by improved carbon efficiency of the process, since more liquid fuel is produced per unit of biogenic carbon fed to the process. In some embodiments, the additional energy required for the HTCE conversion of CO2 and product water to syngas is provided from green energy sources, such as solar energy, wind power, hydroelectric power, etc. By utilizing green energy sources, no additional CO2 emissions are generated when CO2 and water are converted by direct electrolysis. In some embodiments, the process uses green energy, preferably through highly efficient HTCE electrolysis (power efficiency >95%), although higher efficiencies may be possible depending on the heat available from the rest of the system. CO2 and product water, both unwanted by-products from the hydrocarbon synthesis process, are converted to syngas and then processed into additional hydrocarbon fuels.

[0018] Additionally, the processes and systems described herein provide a sustainable pathway to reduce GHG impacts on the environment by utilizing renewable energy and converting by-products (e.g., produced water and carbon dioxide) to maximize biogenic carbon conversion efficiency and reduce product emissions by utilizing produced water. Furthermore, the processes and systems described herein introduce other non-food biomass feedstocks in place of the primary natural gas feedstock selected for conventional synthetic fuel plant operations. In addition to the carbon and produced water usage benefits of the present process, the potential for using these alternative sources of low-cost biogenic carbon may be valuable given the uncertain pricing of natural gas in the long term and the availability of alternative, location-specific non-food biomass feedstocks.

[0019] In some embodiments, the present disclosure provides a system for producing hydrocarbon-based fuels. The system includes a biomass feedstock processing unit configured to remove waste materials from the feedstock and produce a conditioned feedstock with controlled physical properties and therefore suitable for combustion or gasification. The system includes a gasification unit in communication with the biomass feedstock processing unit. The gasification unit is configured to convert the processed feedstock into a crude syngas. The crude syngas includes carbon dioxide, carbon monoxide, hydrogen, and nitrogen, along with tars and volatiles. In some embodiments where pure oxygen is utilized, the crude syngas may not include nitrogen. The system includes a reactor downstream of the gasification unit. The reactor is operated under appropriate conditions to promote conversion of a portion of the syngas to produce an appropriate ratio of hydrogen to CO with limited CO2 concentration, allowing for thermodynamically favorable operating conditions for the reverse water gas shift reaction. In some embodiments, the system may include a heat recovery steam generation (HRSG) system for cooling the hydrogen-rich syngas. The system may include an acid gas scrubber configured to remove carbon dioxide from the syngas to produce a purified syngas having a hydrogen-to-carbon monoxide ratio of at least 1.5:1. In some embodiments, the purified syngas is further enriched by combining it with a hydrogen-rich stream, preferably green hydrogen obtained by renewable energy-powered water electrolysis, to increase the H2 / CO ratio to at least 2:1. The resulting hydrogen-rich syngas is sent to a Fischer-Tropsch reactor, which converts the purified syngas into Fischer-Tropsch liquid, water, and tail gas. The product water from the Fischer-Tropsch reactor, combined with other water purges from the system, may be processed in a water treatment unit to achieve zero emissions and minimal water intake make-up requirements, followed by an electrolysis unit to convert a portion of the purified water into oxygen and hydrogen streams. Some or all of the oxygen stream produced from the electrolysis unit is recycled to the gasification unit, the autothermal reformer, or a combination thereof. In some embodiments, the system includes a reverse water-gas shift reactor.A portion of the carbon dioxide removed from the syngas in the scrubber is recycled to the reverse water-gas shift reactor. In some embodiments, a portion of the hydrogen stream is fed to the reverse water-gas shift reactor. The reverse water-gas shift reactor is configured to produce carbon monoxide, which is fed to the Fischer-Tropsch reactor. Alternatively, a portion of the removed carbon dioxide, combined with steam, can be converted to syngas with an additional H:CO ratio in a CO electrolysis unit. Depending on the configuration, the system can achieve carbon conversion of the feedstock to liquid fuel products of at least 65% and up to 95%. In some embodiments, the syngas stream and hydrogen stream are pressurized before being fed to the Fischer-Tropsch reactor. In some embodiments, tail gas from the Fischer-Tropsch reactor is recycled to the reformer. In some embodiments, the system includes a hydrocracking unit, a fractionation unit, an isomerization unit, and other hydrocarbon processes, or combinations thereof, configured to upgrade Fischer-Tropsch liquids to fuels, wherein a by-product of the hydrocracking unit includes tail gas and a by-product of the fractionation unit includes naphtha. In some embodiments, the tail gas, naphtha, or both are recycled to the reformer. In some embodiments, the system includes a flue gas scrubber configured to scrub any flue gas produced by the system. In some embodiments, the system includes a carbon dioxide processing and compression system, wherein carbon dioxide produced from the scrubber and the flue gas scrubber is processed in the carbon dioxide processing and compression system to produce a purified carbon dioxide stream, and the purified carbon dioxide stream is recycled to the reformer, the reverse water-gas shift reactor, the high-temperature co-electrolysis unit, or combinations thereof. In some embodiments, the feedstock includes one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, switchgrass, wood chips, lignin, and cellulosic material. In some embodiments, the feedstock comprises woody biomass. In some embodiments, the system comprises a pre-reformer and an autothermal reforming unit configured to convert the natural gas feedstock into synthesis gas.

[0020] In some embodiments, the disclosure provides a process for producing hydrocarbon-based fuels, the process comprising: gasifying a biomass feedstock to produce a raw syngas stream comprising carbon dioxide, carbon monoxide, and hydrogen, along with tars and volatiles; reforming the raw syngas stream to produce a hydrogen-enriched syngas stream; separating the carbon dioxide from the hydrogen-enriched syngas stream in a separation unit to produce a carbon dioxide stream and a purified syngas stream having a hydrogen to carbon monoxide ratio of at least 1.5:1; combining the purified syngas stream with hydrogen from a renewable source to enrich the purified syngas stream to a hydrogen to carbon monoxide ratio of at least 2.1; reacting the purified syngas stream and the hydrogen-enriched syngas stream in a Fischer-Tropsch reactor to produce a Fischer-Tropsch liquor, water, and a tail gas; recycling the water produced from the Fischer-Tropsch reactor to a zero-discharge water treatment unit; and electrolyzing the purified water in an electrolysis unit to produce an oxygen stream and a hydrogen stream. In some embodiments, the process includes purifying the carbon dioxide stream produced from the separation unit to produce a purified carbon dioxide stream. In some embodiments, the process includes recycling the purified carbon dioxide stream to a gasification step, a reforming step, or a combination thereof. In some embodiments, the process includes recycling a portion of the oxygen stream and a portion of the hydrogen stream to a gasification step, a reforming step, or a combination thereof. In some embodiments, the process includes recycling a portion of the hydrogen stream and a portion of the purified carbon dioxide stream to a reverse water gas shift reactor and / or a CO2 electrolysis unit. In some embodiments, products (e.g., carbon monoxide) from the reverse water gas shift reactor and / or the CO2 electrolysis unit may be fed to a Fischer-Tropsch reactor to convert the synthesis gas to Fischer-Tropsch liquids. In some embodiments, the process includes processing natural gas in a reformer to produce a second crude synthesis gas stream that is fed to a Fischer-Tropsch reactor.In some embodiments, the electrolysis unit is powered by solar energy, wind energy, hydroelectric energy, nuclear energy, or tidal energy. In some embodiments, the biomass feedstock comprises one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, harvest residues, switchgrass, wood chips, lignin, and cellulosic material. In some embodiments, the process comprises treating water produced from a Fischer-Tropsch reactor to produce boiler-quality feedwater, wherein the boiler-quality feedwater is electrolyzed in an electrolysis unit. In some embodiments, the water from the Fischer-Tropsch reactor is treated to remove hydrocarbons and alcoholates.

[0021] Definitions and Explanations As used herein, the terms "invention," "the invention," "this invention," and "the present invention" are intended to refer broadly to all of the subject matter of this patent application and the claims that follow. Statements containing these terms should not be understood to limit the subject matter described herein, nor to limit the meaning or scope of the claims that follow.

[0022] As used herein, the meanings of "a," "an," or "the" include the singular and the plural, unless the context clearly indicates otherwise.

[0023] As used herein, "carbon conversion efficiency" refers to the carbon content in the feedstock that is converted to hydrocarbon fuel.

[0024] As used herein, a "unit" refers to a part of a system and can include, for example, a unit operation, a system, or a group of unit operations.

[0025] As used herein, "flow" refers to any fluid or solid that moves, directly or indirectly, from one place to another.

[0026] As used herein, "syngas" may include a combination of carbon monoxide, hydrogen, carbon dioxide, and possibly other components, including but not limited to water vapor, sulfur- or nitrogen-containing compounds, methane and other alkanes, hydrocarbons, acid gases, halogens, particulates, and the like.

[0027] As used herein, the term "room temperature" refers to temperatures between about 15°C and about 30°C, such as about 15°C, about 16°C, about 17°C, about 18°C, about 19°C, about 20°C, about 21°C, about 22°C, about 23°C, about 24°C, about 25°C, about 26°C, about 27°C, about 28°C, about 29°C, or about 30°C.

[0028] All ranges disclosed herein should be understood to encompass the endpoints and any subranges subsumed therein. For example, a stated range of "1 to 10" should be considered to include all subranges between (and including) the minimum value of 1 and the maximum value of 10, i.e., all subranges beginning with a minimum value of 1 or more, e.g., 1 to 6.1, and ending with a maximum value of 10 or less, e.g., 5.5 to 10.

[0029] Process Configuration FIG. 1 shows a schematic diagram of a system for producing hydrocarbon fuels according to some embodiments of the present disclosure. System 100 provides an overall system for producing hydrocarbon-based fuels with high carbon conversion efficiency. System 100 provides a continuous process for converting biomass and optionally natural gas into synthesis gas ("syngas"). The syngas is ultimately converted into a hydrocarbon-based fuel, such as jet fuel, via hydrocarbon synthesis using a Fischer-Tropsch process and, optionally, fuel upgrading. As noted above, the conversion of biomass to liquids is often referred to as "BTL," and the conversion of natural gas to liquids is often referred to as "GTL." In some embodiments, the system incorporates both BTL and GTL processes to produce syngas.

[0030] In some embodiments, the system 100 may be configured to convert a feedstock 105 (e.g., biomass) into a hydrocarbon-based fuel. The system 100 may include a feedstock processing unit 110. The feedstock 105 may be fed to the feedstock processing unit 110. In some embodiments, the feedstock processing unit 110 may be a biomass feedstock processing unit. The feedstock processing unit 110 is configured to separate materials from the feedstock for further processing. In some embodiments, the feedstock processing unit 110 is configured to adjust the physical characteristics of the feedstock, i.e., its moisture content and maximum particle size, and to separate unwanted materials from the feedstock for further processing. For example, non-biological carbonaceous materials and non-carbonaceous materials (e.g., waste) may be removed from the feedstock. In the feedstock processing unit 110, the waste may be sized, separated, and processed to remove materials that are not useful to the process or that may reduce the efficiency of the process. For example, the feedstock processing unit 110 removes metals, inorganic materials, and other materials to produce a processed feedstock 115.

[0031] In some embodiments, the majority of the feedstock comprises biomass (e.g., railroad ties or another cellulosic material), and optionally a small amount of natural gas. In some embodiments, the biomass feedstock may comprise corn stover, bagasse, switchgrass, forest thinnings, slash, wood chips, lignin, or other carbohydrates, cellulosic material, or combinations thereof. In some embodiments, the biomass may comprise one or more of railroad ties, greasewood, corn stover, forest thinnings, slash, or orchard prunings.

[0032] The system 100 may include a gasification unit 120 that receives the processed feedstock 115. The gasification unit 120 may be a biomass gasification unit. The gasification unit 120 converts the processed feedstock 115 into a raw syngas stream 125. For example, the gasification unit 120 converts the processed biomass into the raw syngas stream 125 by one or more steps of steam reforming, carbon oxidation, or gasification, and hydrocarbon reforming. The raw syngas stream 125 produced from the gasification unit 120 may include carbon monoxide, hydrogen, carbon dioxide, argon, nitrogen, tars, and volatiles.

[0033] The system 100 may include a high-temperature non-catalytic reforming unit 130 for partially oxidizing methane and other hydrocarbons contained in the raw syngas stream 125 with an oxygen-containing gas. The resulting raw syngas stream 125 is a high-biogenic content syngas. In some embodiments, the reforming unit 130 includes a partial oxidation reformer, a steam reformer, an autothermal reformer, or a combination thereof (although other types of reformers may also be used). In some embodiments, the reforming unit 130 utilizes oxygen separated from air using cryogenic separation, pressure swing absorption, membrane separation (e.g., ion transport membrane, ITM), and combinations thereof. In some cases, the partial oxidation reformer utilizes an oxidizing gas selected from the group including air, oxygen-enriched air, pure oxygen, and combinations thereof. The oxygen supplied to the reforming unit 130 may be pure oxygen to reduce the amount of energy required to filter unwanted components (e.g., nitrogen from air). In some embodiments, the oxygen supplied to the reforming unit 130 is supplied from a water electrolysis unit 155, as described further below. In some embodiments, waste heat from the reforming unit 130 may be recovered in a waste heat recovery unit and reused in the reforming unit 130 or other units in the system 100. In some embodiments, the treated syngas stream 135 from the reforming unit 130 may be processed in a syngas conditioning unit to further purify the syngas before being combined with green hydrogen or renewable hydrogen and fed to the Fischer-Tropsch reactor.

[0034] In some embodiments, the processed syngas stream 135 may be compressed in one or more compressor(s) 140. The compressor(s) 140 are configured to compress the processed syngas stream 135 to a predetermined level to produce a compressed syngas stream 145. In some embodiments, the final pressure of the compressed syngas stream 145 may be within a range acceptable for a Fischer-Tropsch synthesis process.

[0035] The compressed syngas stream 145 may be sent to a scrubber 150 to remove contaminants (e.g., carbon dioxide and other acid gases) before being fed to the Fischer-Tropsch reactor 180. In some embodiments, the scrubber 150 is a carbon dioxide scrubber. The scrubber 150 is configured to remove contaminants from the compressed syngas stream 145 to produce a purified syngas stream 151. For example, the scrubber 150 may remove carbon dioxide and other contaminants that may degrade the performance of the Fischer-Tropsch reactor. The scrubber 150 may receive the compressed syngas stream 145 and a solvent or solution (e.g., alkaline solution, ammine, cold methanol, etc.) to absorb contaminants from the compressed syngas stream 145 by a reversible chemical absorption process. The loaded solvent from the absorber may be regenerated in a stripping unit, where the carbon dioxide is released and the lean solvent is recovered and recycled to the absorber in a closed loop.

[0036] The carbon dioxide stream 152 separated from the compressed syngas stream 145 can be fed to a carbon dioxide processing and compression system 160. The carbon dioxide processing and compression system 160 can remove contaminants from the carbon dioxide stream 152 to produce purified carbon dioxide 165. The purified carbon dioxide 165 produced from the carbon dioxide processing and compression system 160 can be recycled to other units in the system 100 to produce additional syngas or sent to a CO2 sequestration well. Within the limits provided by mass and energy balance, the purified carbon dioxide 165 from the carbon dioxide processing and compression system 160 can be recycled to the dry reforming unit 130, the RWGS reactor, the HTCE unit, or a combination thereof. This recycle stream utilizes carbon dioxide that would normally be emitted as flue gas and reuses the carbon dioxide to produce additional syngas.

[0037] In some embodiments, a portion of the purified carbon dioxide 166 from the carbon dioxide processing and compression system 160 may be processed in a (reverse) water-gas shift reactor 170. This CO is combined with H from the water electrolysis unit 155 to provide a syngas stream 171 for further processing in the FT reactor system 180. In some embodiments, the reverse water-gas shift reactor 170 is a Johnson Matthey HyCOgen unit. The reverse water-gas shift reactor 170 converts the recovered CO and H back into CO and HO that can be used by the system 100. The purified and compressed syngas stream 151 from the carbon dioxide processing and compression system 160 is also fed to the FT reactor system 180, where it is combined with the other syngas input streams and H produced by the water electrolysis unit 155. In some embodiments, the target H / CO ratio may be in the range of 0.5 to 10.0.

[0038] The purified syngas stream 151 may be fed to the Fischer-Tropsch reactor 180 as the primary or sole carbon-containing feedstock. In some embodiments, the secondary syngas stream 171 is also a feedstock for the Fischer-Tropsch reactor 180. Additionally, a portion of the water electrolysis hydrogen production is also combined with the entire syngas stream for hydrocarbon synthesis. The Fischer-Tropsch reactor 180 synthetically produces higher hydrocarbon liquids by catalytically converting the syngas in a highly exothermic process. Therefore, the FT reactor may require significant heat removal, which is typically achieved by generating medium-pressure steam through the vaporization of boiler feedwater. The Fischer-Tropsch reactor 180 produces a mixture of linear paraffinic hydrocarbon molecules with carbon numbers varying between C1 and C30 or higher as the primary product, and product water as a by-product. The FT reaction is a heterogeneously catalytic reaction characterized by a combination of vapor-phase reactants and liquid and gaseous products, which are recovered separately as medium FT liquids (MFTL) and heavy FT liquids (HFTL), water, and FT tail gas (FT tail gas). FT tail gas 185 typically contains a mixture of unreacted hydrogen and carbon monoxide, as well as the reaction by-products methane and CO2, and can be recycled to other units in the system, where it can be reformed and converted back into additional syngas. For example, FT tail gas 185 can be recycled to the reforming unit 130. In some embodiments, the system can include a hydrocracking unit 190 and / or fractionation unit 195 to upgrade the FT liquids. For example, the hydrocracking unit 190 employs a high-temperature, high-pressure catalytic process to upgrade the HFTL and MFTL hydrocarbon streams 181 into transportation fuels or blending components with suitable chemical and physical properties. The tail gas 191 produced from the hydrocracking unit 190 and the naphtha 196 produced from the fractionation unit 195 may be recycled to the system (eg, the reformer 130).

[0039] System 100 includes a water electrolysis unit 155. Water produced from the aforementioned units in system 100 (e.g., gasifier, Fischer-Tropsch reactor, etc.) may be treated in a water treatment unit and then supplied to water electrolysis unit 155. The water treatment unit may produce boiler-quality water that is supplied to water electrolysis unit 155 as well as some cooling or heat recovery systems where steam is produced. For example, purified water stream 182 from Fischer-Tropsch reactor 180 may be supplied to water electrolysis unit 155. Water electrolysis unit 155 may convert purified water into oxygen stream 156 and hydrogen stream 157, which may be supplied to other units in system 100. For example, oxygen stream 156 produced from water electrolysis unit 155 may be supplied to gasification unit 120, reforming unit 130, reverse water-gas shift reactor 170, or a combination thereof. In some embodiments, oxygen stream 156 is supplied to water electrolysis unit 155 before being supplied to reverse water-gas shift reactor 170. The hydrogen stream 157 produced from the water electrolysis unit 155 may be fed to a reverse water gas shift reactor 170. In some embodiments, the hydrogen stream 157 is compressed before being fed to the reverse water gas shift reactor 170. The reverse water gas shift reactor 170 may be configured to provide a catalytic process that converts hydrogen and CO2 to carbon monoxide (CO), which is combined with additional hydrogen to form synthesis gas. The synthesis gas 171 produced from the reverse water gas shift reactor 170 may then be fed to a Fischer-Tropsch reactor 180 to produce additional hydrocarbon fuels.

[0040] In some embodiments, the electrolysis unit is powered by solar energy, wind energy, hydroelectric energy, nuclear energy, or tidal energy. In some embodiments, the process includes scrubbing a carbon dioxide stream in a carbon dioxide scrubber to produce purified carbon dioxide, where the purified carbon dioxide is electrolyzed in an electrolysis unit. In some embodiments, the process includes boiling water produced from a Fischer-Tropsch reactor to produce boiler-quality feedwater, where the boiler-quality feedwater is electrolyzed in an electrolysis unit. In some embodiments, the process includes reacting additional synthesis gas in a Fischer-Tropsch reactor to produce additional hydrocarbons. In some embodiments, the process includes sequestering additional CO2 produced in the process.

[0041] In some embodiments, the approximate additional power for the electrolysis of water produced in the system ranges from 30 MW to 80 MW per ton of hydrogen produced from the reverse fuel cell or electrolysis unit. When the energy for electrolysis is provided from a conventional energy source, such as natural gas, an "efficient" combined cycle mode generates approximately 450 grams CO2 / kWh. However, when green energy (e.g., solar power) is employed, CO2 emissions associated with power generation are less than 100 grams CO2 / kWh, less than 90 grams CO2 / kWh, less than 50 grams CO2 / kWh, or less than 20 grams CO2 / kWh, and as low as 17.5 grams CO2 / kWh for highly efficient sources. For CO2 electrolysis, the power required may be 0.05-0.80 MWh / ton, e.g., 0.05-0.70 MWh / ton, 0.10-0.70 MWh / ton, 0.15-0.60 MWh / ton, 0.20-0.50 MWh / ton, 0.20-0.40 MWh / ton, or about 0.232 MWh / ton, and if the power is supplied from a green energy source rather than a traditional natural gas source, overall CO2 emissions are also reduced.

[0042] Electricity generated on-site (either by using steam generated on-site to power a steam turbine generator or by installing solar or wind turbine generation) may be used as the power source to drive water electrolysis to produce a portion of the hydrogen and oxygen required for plant process operations. Biomass gasification, conversion to liquids, and related purification processes require additional hydrogen beyond that present in the biomass feedstock. The electrolysis process splits water into its hydrogen and oxygen components, thereby providing a portion of the oxygen required for overall plant operation. In some embodiments, the processes and systems described herein use renewable energy sources (e.g., solar, wind, etc.) to power individual units within the system. Additionally, where economically feasible, waste heat is recovered and used to generate electricity for reuse within the system.

[0043] Figure 2 is a schematic diagram of a hydrocarbon synthesis process integrated with a CO electrolysis unit according to some embodiments of the present invention. As shown in Figure 2, the process encompasses both BTL and GTL processes for producing syngas. As discussed herein, systems and processes are disclosed for combusting a wide variety of hydrocarbon feedstocks to produce thermal energy, liquid fuels, and other valuable products with little or no emissions. Hydrocarbon and solid carbon-containing feedstocks, such as natural gas and biomass, are processed via reforming, gasification, and oxidation, respectively, to produce syngas. The syngas is fed to a Fischer-Tropsch synthesis process for conversion to hydrocarbons and, optionally, upgraded to form fuels, such as diesel fuel and other liquid hydrocarbons. The system / process employs an electrolysis unit to reduce CO emissions while improving overall carbon efficiency and minimizing environmental emissions by forming additional hydrocarbons. The electrolysis process is preferably powered, at least in part, by green energy.

[0044] In some embodiments, the majority of the feedstock comprises biomass (e.g., railroad ties or another cellulosic material), and optionally a small amount of natural gas. In some aspects, the biomass feedstock may include switchgrass, forest thinnings, slash, wood chips, lignin, or other carbohydrate and / or cellulosic material. The biomass may include one or more of railroad ties, greasewood, corn stover, forest thinnings, slash, or orchard prunings. For example, unit 220 (biomass feedstock) provides a biomass feedstock that is gasified to form syngas.

[0045] As shown in Figure 2, natural gas is supplied to the system via unit 200 (gas distribution network). The natural gas from unit 200 can be split into a portion for conversion to hydrocarbon-based fuels ("feed natural gas" sent to unit 210) and a portion for turbine-based power generation ("power natural gas" sent to unit 500). A natural gas preheater and unit 210 (e.g., a sulfur removal unit) heat the natural gas and remove sulfur-containing compounds to provide the natural gas feedstock that is utilized to produce synthesis gas. The amount of natural gas used for turbine-based power generation varies depending on the amount of green energy, e.g., solar energy, available for the process. In some embodiments, at least 20 MW, e.g., at least 40 MW, or at least 60 MW of solar power is available for 8 hours to supplement the total power requirements, which may range from 50 to 200 MW, e.g., 50 to 200 MW, 60 to 180 MW, 75 to 160 MW, 80 to 150 MW, 90 to 140 MW, 100 to 130 MW, or approximately 128.15 MW. Geographical considerations may influence the supplemental green energy requirements. In some embodiments, the green energy source may be one or more of wind energy, hydroelectric energy, nuclear energy, tidal energy, or another green energy source. In some embodiments, additional natural gas is utilized in the process to power the production process for the entire 16-hour period when direct green energy, e.g., solar energy, is unavailable.

[0046] As described above, unit 200 provides a natural gas distribution network that distributes natural gas to unit 210 and / or unit 500. This configuration advantageously minimizes capital for solar energy storage in the process. In some embodiments, the process produces synthetic jet fuel with overall CO2 emissions that are at least 20% lower than those associated with conventional crude oil refining, e.g., at least 40% lower, or at least 60% lower. As will be appreciated, there are numerous variations on this configuration based on the selection of the amount of natural gas, the amount of solar power generation, and the proportion of natural gas and biomass in the feed.

[0047] Returning to unit 210, the natural gas feedstock, in this particular configuration, is combined with vapor-phase products (e.g., unconverted H and CO) and H (produced by electrolysis in unit 320). In some embodiments, the natural gas feedstock is combined with vapor-phase products and H in unit 260A (an autothermal reforming unit) to produce syngas, which is subsequently fed to unit 205B (a syngas processing unit). As shown, a CO2-enriched stream is optionally routed from syngas processing unit 205B to unit 363 (a CO2 absorber unit), which is described in further detail below. The syngas, which is converted to hydrocarbons in unit 310 (a Fischer-Tropsch unit), contains light hydrocarbons produced via Fischer-Tropsch synthesis and undergoes upgrading (e.g., hydrocracking and / or isomerization steps) in unit 240 to produce end products, such as synthetic jet fuel. Other configurations can use H2 obtained from the electrolysis of CO2 in unit 360 (a CO2 electrolysis unit) or from more conventional methods based on H2 separation from the effluent syngas from either the reforming unit 260A or the gasification unit 230.

[0048] In some embodiments, unit 210 (natural gas feedstock) produces a reformer, an effluent that is directed to unit 260A. In some aspects, unit 260A is an autothermal reforming unit (ATR). The ATR converts the effluent from unit 210 with steam and oxygen to produce syngas. This syngas may contain undesirable components, such as reactive nitrogen and undesirably high levels of CO. Syngas processing typically includes a removal system to remove or convert these undesirable components. In some embodiments, the H / CO ratio is in the range of 0.5 to 10.0.

[0049] In some embodiments, biomass is fed to unit 220 (biomass feedstock) and processed for size reduction and moisture removal in unit 225 (biomass feedstock processing). The processed biomass is then gasified using any suitable conversion technology that is energy-efficient, minimizes CO2, and produces syngas with an appropriate H2 / CO ratio, typically between 0.5 and 1.0, e.g., 0.55, 0.60, 0.65, 0.70, 0.75, 0.80, 0.85, 0.90, 0.95, or 1.0. In some embodiments, the H2 / CO ratio is in the range of 0.8 to 1.0. Due to the high oxygen content of the feed, biomass gasification produces large amounts of CO2. As a result, the biomass-derived syngas passes through unit 205A (CO2 removal unit). The CO2 then passes through unit 363 (CO2 absorption unit) to remove trace hydrocarbons and CO contained in the scrubbed CO2, producing purified CO2.

[0050] The resulting syngas, with significantly reduced CO2 content, is combined with syngas from unit 205B and hydrogen from unit 320 (a water electrolysis unit), and the combined syngas is sent to unit 310 for Fischer-Tropsch synthesis. After Fischer-Tropsch synthesis, the products include a variety of hydrocarbons, ranging from methane to heavy waxes, with the heaviest alkanes having boiling points above 800°F (427°C). In some embodiments, light hydrocarbons (typically C1-C8) and unreacted syngas are sent to unit 425 (turbine / heater), where a portion of the products are used, for example, as fuel for the turbine and process-fired heater (i.e., units 110, 250, 260A, and 240). In some embodiments, the remaining products not used as fuel are recycled to units 250 and 260A for conversion to additional syngas.

[0051] In some embodiments, the heavier Fischer-Tropsch products (C 9+ ) is sent to unit 240 (fuel reforming unit) where it is combined with H2 for processing via hydrotreating into final hydrocarbon products, such as jet fuel or diesel products. In unit 240, some materials may be converted to light hydrocarbons contained in the fuel reforming unit purge gas, which is combined with the Fischer-Tropsch purge gas and recycled to produce further synthesis gas.

[0052] CO2 emissions Figure 2 shows exemplary CO emissions for various units in a hydrocarbon synthesis process. In some embodiments, the primary sources of CO in the process / system are as follows: · Natural gas turbine flue gas (500 units); · Process heater flue gas (unit 425); CO2 removed from biomass-derived syngas (unit 205A); and · ATR derived synthesis gas (unit 205B).

[0053] In the above process / system configuration, CO2 generated through the natural gas turbine (unit 500) and directly emitted as flue gas is the largest source of CO2 emissions. Unit 500 is responsible for the majority of air emissions, as shown in the center highlighted box in Figure 2. The second largest source of CO2 emissions is CO2 removed from biomass-derived syngas (unit 205A). CO2 emissions from unit 205A account for the majority of sequestered CO2. Flue gas CO2 (from internally generated fuel gas) passes through a treatment system (unit 235) to capture additional CO2 for sequestration. Uncaptured CO2 emitted from unit 235 contributes a small amount to air emissions. In some embodiments, a portion of the total CO2 produced is sent to CO2 electrolysis unit 360, which then converts it to syngas using electrical power.

[0054] Integration of CO2 and water electrolysis As discussed herein, in some embodiments, the present invention provides a process for converting carbon dioxide and product water into syngas in a hydrocarbon production process. The process may include treating natural gas in an autothermal reforming unit to form a first syngas stream, treating a biomass feedstock in a gasification unit to form a second syngas stream, processing the first and second syngas streams in a syngas processing unit to produce a feed syngas stream (wherein the syngas processing unit removes carbon dioxide from either or both of the first and second syngas streams), reacting the feed syngas stream in a Fischer-Tropsch reactor to produce hydrocarbons and water, and electrolyzing the carbon dioxide and water (e.g., after purification) in an electrolysis unit to produce carbon monoxide and hydrogen, which may be fed to the FT reactor. In some aspects, the electrolysis unit is powered by a green energy source. The green energy source may include one or more of solar energy, wind energy, hydroelectric energy, nuclear energy, or tidal energy. In some embodiments, at least 40 MW of solar power is supplied to the electrolysis unit for an 8-hour period.

[0055] In some embodiments, the process further comprises scrubbing the carbon dioxide removed from the syngas processing unit in a carbon dioxide scrubber to produce purified carbon dioxide, which is electrolyzed in an electrolysis unit. In some embodiments, the process further comprises treating (e.g., boiling) product water from the Fischer-Tropsch reactor to produce boiler-quality feed water, which is electrolyzed in an electrolysis unit to produce carbon monoxide. In some embodiments, the process further comprises sending the carbon monoxide to the Fischer-Tropsch reactor to produce additional hydrocarbons.

[0056] When applying GTL and BTL technologies to hydrocarbon synthesis, total CO2 emissions depend on many factors. For example, total CO2 emissions depend primarily on the feed rate of natural gas and biomass, the carbon conversion efficiency, and the CO2 emissions associated with the power of the conversion process. In some embodiments, the carbon conversion efficiency may be relatively low, allowing a significant portion of the feedstock energy to be converted into power through a combustion process. However, in this scenario, total CO2 emissions may be relatively high unless the process utilizes non-fossil fuels, such as biomass. Unless CO2 sequestration is employed to mitigate CO2 emissions, total CO2 emissions associated with power and fuel production may exceed the threshold for total allowable CO2 emissions.

[0057] In some embodiments, the present invention utilizes green energy, e.g., solar energy, as a power source to provide the energy for converting CO2 to syngas and then converting it to transportation fuel. Many process configurations are possible to demonstrate that electrolysis of CO2 and product water to syngas, which is then converted to transportation fuel, can reduce overall CO2 emissions. For example, CO2 sequestration can be performed simultaneously with CO2 reduction. However, due to the need for pipelines and relatively low-cost transportation, sequestration may not be a viable option at many locations in the process. Converting CO2 and steam to syngas provides an opportunity to use electricity to convert the carbon and hydrogen in unwanted by-products into transportation fuel (energy storage). The CO2 emissions associated with the additional electricity for this conversion are significantly less than the CO2 that would be emitted without the electrolysis system.

[0058] Figure 2 shows two potential sources for CO2 / water electrolysis. In some embodiments, unit 360 co-processes CO2 and water to produce syngas and oxygen, while unit 320 processes only water to produce H2 and O2. In some embodiments, unit 320 can provide a source of H2 for the process. Alternatively, H2 can be separated from the ATR syngas using capture techniques. The trade-off between H2 sources involves preferences for carbon balance and energy consumption.

[0059] In some embodiments, the systems described herein include a partial oxidation reformer that converts natural gas into syngas containing hydrogen and carbon monoxide, a biomass gasifier that converts various types of biomass materials into syngas containing primarily hydrogen and carbon monoxide, an electrolysis unit that converts water to hydrogen and oxygen gas, an optional desalination system that supplies purified water to the electrolysis unit, a reverse water-gas shift reactor that converts carbon dioxide and hydrogen into carbon monoxide and water, a syngas processing system that conditions and purifies the syngas, a Fischer-Tropsch reactor that converts the syngas into liquid hydrocarbon fuels, and a fuel upgrading system that further removes carbon dioxide from the liquid hydrocarbon fuels. The systems may also include solar panels that convert sunlight into electricity to power units within the system (e.g., the electrolysis unit), and a steam turbine generator system that produces electricity from the waste heat of the gasification and natural gas-to-liquid conversion systems. The systems recycle naphtha and / or carbon dioxide produced in the natural gas and biomass liquefaction process to the partial oxidation gasifier for conversion to liquid fuels. In some embodiments, the (reverse) water-gas shift reactor is replaced with a carbon dioxide electrolysis system to convert the carbon dioxide into syngas, which is then sent to a Fischer-Tropsch reactor to produce additional liquid hydrocarbon fuels. Both of these options for CO2 recycling impact the power required. The reverse water-gas shift option increases the consumption of hydrogen produced by water electrolysis, while CO2 electrolysis directly consumes electricity. Thus, there is a trade-off between the carbon efficiency of the overall system and the power input per unit of synthetic fuel produced. Depending on the carbon intensity of the available electricity, CO2 recycling via one option or the other may be more or less attractive from the perspective of the carbon intensity of the synthetic fuel. [Example]

[0060] CO2 emissions can be compared for BTL and GTL process configurations using greenhouse gas emission factors (GHG-CO2), which can be measured by methods known to those skilled in the art. As shown in Table 1, in conventional refinery operations, the amount of CO2 emitted per megajoule (MJ) of fuel energy is typically 50 to 500 grams of CO2 per MJ of fuel produced, or approximately 89.12 grams of CO2 per MJ of fuel produced. This is sometimes referred to as a CO2 life cycle assessment. Many factors contribute to the total CO2 emissions per unit of fuel energy shown in Table 1. For example, factors such as biogenic uptake, upstream biomass, emissions from process solar power, and emissions from natural gas turbines each contribute to the CO2 emissions per unit value of product energy, e.g., SPK. In the BTL / GTL process shown in Figure 2, the primary contributors to CO2 emissions are the actual combustion of SPK and the electrical energy associated with the natural gas turbine.

[0061] It is now known that including CO2 sequestration in CO2 / water electrolysis (e.g., Unit 360) can significantly reduce overall CO2 emissions compared to conventional refineries. See Table 1 (89.12 g CO2 / MJ SPK for baseline petroleum fuel; 59.84 g CO2 / MJ SPK for baseline operation using CO2 electrolysis combined with natural gas turbine power and CO2 sequestration). In this scenario, the primary CO2 reduction comes from the greater amount of CO2 sequestered (323,970 MTPY) compared to the amount electrolyzed (148,900 MTPY). The use of a flue gas scrubber to capture CO2 from the combustion process (Unit 235) also helps mitigate overall CO2 emission levels, especially when the energy for CO2 capture is in the range of 700–800 kcal / kg CO2 captured.

[0062] In one embodiment, the present invention further mitigates GHG-CO emissions by using solar energy to reduce the total power generation from a natural gas turbine, thereby reducing the total CO2 emissions associated with the power generation. For example, Table 1 shows operation using a natural gas turbine and 40 MW solar power compared to a baseline petroleum fuel. In some embodiments, providing solar energy at 40 MW for 8 hours per day further reduces overall CO2 emissions by over 60% compared to the petroleum baseline (33.9 g CO2 / MJ fuel compared to the baseline case's 89.12 g CO2 / MJ fuel value). This reduction is due to the lower GHG-CO2 emissions associated with solar power (e.g., less than 100 g CO2 / kWh, less than 50 g CO2 / kWh, or less than 20 g CO2 / kWh, optionally about 17.5 g CO2 / kWh) compared to the CO2 emissions of a natural gas turbine, which can be as much as 420 g CO2 / kWh. For example, average CO2 emissions from electricity generated on the US power grid range from 500-600g CO2 / kWh. Solar, wind, and hydroelectric power are significantly lower, ranging from 17.5-90g CO2 / kWh. As a result, sourcing electricity from green sources enables additional production of products, while emitting 30-60% less overall GHG-CO2 emissions than conventional refineries, which range from 89.12g CO2 / MJ of fuel. [Table 1]

[0063] While the present invention has been described in detail, modifications within the spirit and scope of the present invention will be readily apparent to those skilled in the art. In view of the foregoing discussion, the relevant knowledge in the art, and the references cited above in connection with the "Background" and "Detailed Description," the disclosures of which are incorporated herein by reference in their entirety. In addition, it should be understood that the embodiments of the present invention, as well as some of the various embodiments and various features described below and / or in the appended claims, can be combined in whole or in part or interchanged. In the foregoing description of various embodiments, embodiments referring to separate embodiments can be combined as appropriate.

Claims

1. 1. A system for producing a hydrocarbon-based fuel, comprising: a biomass feedstock processing unit configured to remove waste materials from the feedstock to produce a processed feedstock; a gasification unit in communication with the biomass feedstock processing unit, the gasification unit configured to convert the processed feedstock into a synthesis gas comprising carbon dioxide, carbon monoxide, and hydrogen; a reactor downstream of the gasification unit, the reactor being operated at conditions suitable to promote conversion of a portion of the synthesis gas to produce a suitable ratio of hydrogen to CO; a scrubber in communication with the reactor for removing carbon dioxide from the synthesis gas to produce a purified synthesis gas having a hydrogen / carbon monoxide ratio of at least 1.5:1; a Fischer-Tropsch reactor for receiving the purified synthesis gas, the Fischer-Tropsch reactor converting the purified synthesis gas into a Fischer-Tropsch liquid, water, and a tail gas; and an electrolysis unit configured to receive water from the Fischer-Tropsch reactor, the electrolysis unit converting the water into an oxygen stream and a hydrogen stream; Including, a portion of the oxygen stream is recycled to the gasification unit, the reactor, or a combination thereof; The system achieves at least 90% carbon conversion of the feedstock.

2. 10. The system of claim 1, further comprising a reverse water gas shift reactor, wherein a portion of the carbon dioxide removed from the synthesis gas in the scrubber is recycled to the reverse water gas shift reactor.

3. 3. The system of claim 2, wherein a portion of the hydrogen stream produced by the electrolysis unit is fed to the reverse water gas shift reactor, the reverse water gas shift reactor configured to produce carbon monoxide that is fed to the Fischer-Tropsch reactor.

4. 4. The system of claim 3, wherein the synthesis gas stream and the hydrogen stream are pressurized before being fed to the Fischer-Tropsch reactor.

5. The system of claim 1 , wherein the tail gas from the Fischer-Tropsch reactor is recycled to the reactor.

6. 10. The system of claim 1, further comprising a hydrocracking unit, a fractionation unit, an isomerization unit, or a combination thereof configured to upgrade the Fischer-Tropsch liquid to a fuel, wherein a by-product of the hydrocracking unit comprises tail gas and a by-product of the fractionation unit comprises naphtha.

7. The system of claim 6 , wherein the tail gas, naphtha, or both are recycled to the reactor.

8. 3. The system of claim 2, further comprising a flue gas scrubber configured to scrub any flue gas produced by the system, and wherein the reactor is a dry reformer.

9. a carbon dioxide processing and compression system, wherein carbon dioxide produced from the scrubber and the flue gas scrubber is processed in the carbon dioxide processing and compression system to produce a purified carbon dioxide stream, and wherein the purified carbon dioxide stream is passed through the dry reformer, the reverse water gas shift reactor, the CO ２ 9. The system of claim 8, wherein the wastewater is recycled to the electrolysis unit, the electrolysis unit, or a combination thereof.

10. 10. The system of claim 1, wherein the feedstock comprises one or more of railroad ties, greasewood, corn stover, orchard prunings, forest thinnings, slash, switchgrass, wood chips, lignin, and cellulosic material.

11. The system of claim 1 , wherein the feedstock comprises woody biomass.

12. The system of claim 1 , further comprising a pre-reformer and an autothermal reformer configured to convert the natural gas feedstock into synthesis gas.

13. a CO 2 detector configured to convert a portion of the carbon dioxide and water removed from the system into carbon monoxide and hydrogen; ２ The system of claim 1 further comprising an electrolysis unit.

14. 1. A process for producing a hydrocarbon-based fuel, comprising: gasifying the biomass feedstock to produce a synthesis gas stream comprising carbon dioxide, hydrogen, and carbon monoxide; reforming the syngas stream to produce a hydrogen-enriched syngas stream; separating carbon dioxide from the hydrogen-enriched syngas stream in a separation unit to produce a carbon dioxide stream and a purified syngas stream having a hydrogen / carbon monoxide ratio of at least 1.5:1; enriching the purified synthesis gas with additional hydrogen; reacting the purified syngas stream and the hydrogen-enriched syngas stream in a Fischer-Tropsch reactor to produce a Fischer-Tropsch liquid, water, and a tail gas; recycling a portion of the water from the Fischer-Tropsch reactor to an electrolysis unit; and electrolyzing the water in the electrolysis unit to produce an oxygen stream and a hydrogen stream; The process comprising:

15. 15. The process of claim 14, further comprising purifying the carbon dioxide stream produced from the separation unit to produce a purified carbon dioxide stream, and recycling the purified carbon dioxide stream to the reforming step.

16. 15. The process of claim 14, further comprising recycling a portion of the oxygen stream and a portion of the hydrogen stream to the gasification step, the reforming step, or a combination thereof.

17. 16. The process of claim 15, further comprising recycling a portion of the hydrogen stream and a portion of the purified carbon dioxide stream to a reverse water gas shift reactor to produce carbon monoxide.

18. 15. The process of claim 14, further comprising processing natural gas in a reforming unit to produce a second synthesis gas stream that is fed to the Fischer-Tropsch reactor.

19. 15. The process of claim 14, wherein the electrolysis unit is powered by solar energy, wind energy, hydroelectric energy, nuclear energy, or tidal energy.

20. 15. The process of claim 14, further comprising treating the water from the Fischer-Tropsch reactor to produce purified water, wherein the purified water is electrolyzed in the electrolysis unit.

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