Process and system for producing hydrocarbon fuels with high carbon conversion efficiency - Patents.com

Abstract

The present disclosure relates to processes and systems for producing fuels from biomass with high carbon conversion efficiencies. The processes and systems described herein use a specific combination of components, process flows, and recycle streams to provide a highly efficient process for producing hydrocarbons from biomass with very low greenhouse gas (GHG) emissions. The processes and systems described herein provide greater than 95% carbon conversion efficiencies with little to no GHG in the flue gas due to a novel arrangement of components, and utilize renewable energy to power some components. The system recycles water and carbon dioxide produced in the process flows and recycles naphtha and tail gas streams to other units in the system for additional conversion to synthesis gas to produce hydrocarbon-based fuels.

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 dependency on petroleum energy sources and reduce greenhouse gas emissions, several studies have been conducted to explore alternative petroleum-free processes to produce 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 synthesis processes is the large amount of CO2 emitted from the system.

[0004] Conventional processes for converting natural gas feedstocks to synthesis gas typically include 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 include converting feedstocks, e.g., biomass and / or natural gas, to a mixture of synthesis gas ("syngas", containing H2 and CO) for conversion to liquid hydrocarbons via the Fischer-Tropsch process. The liquid hydrocarbons are subsequently upgraded, e.g., 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 end fuel product. Of particular concern are sulfur-containing compounds such as H2S, COS, SO2, or mercaptans, since sulfur irreversibly deactivates the FT catalyst. Other undesired contaminants such as H2O and CO2 can also affect the performance of the FT catalyst through dilution of the primary synthesis reactants (e.g., H2 and CO) and / or temporary deactivation by oxidation of active metals. Since H2O 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 the carbon efficiency (ratio of carbon produced to carbon fed), several recycle loops are added to the process configuration.

[0005] A major concern in hydrocarbon synthesis is to maximize the utilization of input carbon from the feedstock, i.e., to convert as much of the feed carbon into product carbon as possible while using an acceptable amount of energy (whatever the source) while leaving acceptable produced water required for environmental emissions, mainly CO2 emissions and treatment of trace pollutants. Currently, CO2 capture and sequestration is based on a trade-off between additional energy for the capture and compression of the CO2 to be sequestered and the reduction of CO2 emissions. However, these additional processing steps to reduce CO2 emissions require additional energy and resources, thus 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 utilize energy, these steps can also increase greenhouse gas emissions, thereby offsetting some of the benefits gained 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 summary 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 materials from the feedstock to produce a treated feedstock; a gasification unit in communication with the biomass feedstock processing unit 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 facilitate conversion of a portion of the syngas to produce a suitable ratio of hydrogen to CO; a scrubber in communication with the reformer to remove carbon dioxide from the syngas and produce 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, the electrolysis unit converting 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 that 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, where the by-product of the hydrocracking unit includes a tail gas and the 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, where 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, switch grass, wood chips, lignin, and cellulosic materials. In some embodiments, the feedstock comprises woody biomass. In some embodiments, the system comprises 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 comprises 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 disclosure provides a process for producing a hydrocarbon-based fuel. The process includes gasifying a biomass feedstock to produce a first crude syngas stream comprising 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 electrolysis of water; reacting the purified syngas stream and the hydrogen-enriched syngas stream in a Fischer-Tropsch reactor to produce a Fischer-Tropsch liquid, 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 a 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 a 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 power, 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 materials. In some embodiments, the process comprises treating produced water from the Fischer-Tropsch reactor to produce boiler quality feedwater, and the boiler quality feedwater is electrolyzed in the electrolysis unit.

[0010] Further aspects, objects and advantages will become apparent from consideration of the detailed description and figures that follow. [Brief description 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. [Diagram 2] FIG. 1 shows a schematic diagram of a hydrocarbon synthesis process integrated with a CO2 electrolysis unit according to some embodiments of the present disclosure. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[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 materials with minimal carbon footprints. In particular, 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 a specific combination of components and process flows described herein. In some embodiments, the processes and systems described herein provide carbon conversion efficiencies of greater than 95% with little to no GHG in the flue gas through the addition of renewable hydrogen and novel arrangements of components and process flows. For example, the system beneficially reuses water and carbon dioxide produced in the process flows and recycles naphtha and tail gas streams to other units in the system (e.g., partial oxidation reformer and / or biomass gasifier) ​​for additional conversion to syngas to produce hydrocarbon-based fuels.

[0013] Conventional processes for producing synthesis gas (e.g., H2 and CO) for conversion to liquid hydrocarbons are inherently inefficient because they involve energy-intensive CO2 and water (e.g., wastewater) removal processes. In fact, these processes require additional energy and resources to convert or remove the CO2, thus adding inefficiencies and GHG emissions to the process. Such conventional processes do not effectively convert feedstocks to hydrocarbon-based fuels because they require large amounts of energy to convert or remove the CO2 and to recycle the water produced in the hydrocarbon synthesis process, resulting in large amounts of additional emissions.

[0014] As described herein, the processes and systems described herein achieve unexpectedly high carbon conversion efficiencies while remaining very low in GHGs due to a novel arrangement of components and process flows, and the optional addition of renewable hydrogen. In some embodiments, the processes and systems described 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 converted to a hydrocarbon fuel 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 synthesis gas stream that is substantially free of CO2, 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 CO2 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 may produce synthetic paraffinic kerosene and / or diesel fuel as a primary product, and tail gas and / or light ends such as naphtha produced as by-products are recycled to a gasification unit or reactor (e.g., reformer). The combination of these specific process steps, coupled with the addition of renewable hydrogen, provides a process with high carbon conversion efficiency because output streams that would normally be discharged are recycled to produce 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 CO2 and H2O to convert them into additional syngas. The HTCE unit can convert CO2 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 CO2 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. Additionally, the additional energy for the conversion to additional syngas (via co-electrolysis) can be provided from a non-carbon based power source (e.g., green energy source), which results in a reduction in the overall GHG emissions associated with the conversion of CO2.

[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 by-products to produce more hydrocarbon-based fuels per unit of biomass converted. In some embodiments, the systems may include an HTCE unit that converts product water and CO2 to hydrogen, carbon monoxide, and oxygen, a (reverse) water-gas shift reactor that converts hydrogen, oxygen, and CO2 to 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 for converting 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 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, and the like. By utilizing green energy sources, no additional CO2 emissions are generated when converting CO2 and water 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 produced water, both unwanted by-products from the hydrocarbon synthesis process, are converted to synthesis gas 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. Additionally, 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 non-food biomass feedstocks that are site-specific.

[0019] In some embodiments, the present disclosure provides a system for producing a hydrocarbon-based fuel. The system includes a biomass feedstock processing unit. The biomass feedstock processing unit is configured to remove waste materials from the feedstock and generate 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 at suitable conditions to promote conversion of a portion of the syngas to generate a suitable ratio of hydrogen to CO, with limited CO2 concentration, taking into account 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, together with other water purges from the system, may be treated in a water treatment unit to achieve zero emissions and minimal water intake make-up requirements, and then in an electrolysis unit to convert a portion of the purified water into an oxygen stream and a hydrogen stream. 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 that is fed to the Fischer-Tropsch reactor. Alternatively, a portion of the removed carbon dioxide combined with steam can be converted to syngas with additional H2:CO ratio in a CO2 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 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, an isomerization unit, and other hydrocarbon processes, or combinations thereof, configured to upgrade Fischer-Tropsch liquids to fuels, where the by-products of the hydrocracking unit include tail gas, and the by-products of the fractionation unit include 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, where 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 materials. 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 syngas.

[0020] In some embodiments, the disclosure provides a process for producing a hydrocarbon-based fuel, 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-rich syngas stream; separating the carbon dioxide from the hydrogen-rich 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 concentrate the purified syngas stream to a hydrogen to carbon monoxide ratio of at least 2.1; reacting the purified syngas stream and the hydrogen-rich syngas stream in a Fischer-Tropsch reactor to produce a Fischer-Tropsch liquid, 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 the gasification step, the 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 the gasification step, the 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 the reverse water gas shift reactor and / or the 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 the 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 materials. In some embodiments, the process comprises treating water produced from the Fischer-Tropsch reactor to produce boiler quality feedwater, where the boiler quality feedwater is electrolyzed in the electrolysis unit. In some embodiments, the water from the Fischer-Tropsch reactor is treated to remove hydrocarbons and alcohol acid salts.

[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 as limiting the subject matter described herein, nor as limiting the meaning or scope of the claims that follow.

[0022] As used herein, the meanings of "a," "an," or "the" include the singular and 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 a 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 combinations 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 meaning of "room temperature" can include temperatures from about 15°C to 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 include both 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. The system 100 provides an overall system for producing hydrocarbon-based fuels with high carbon conversion efficiency. The 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 utilizing a Fischer-Tropsch process and, optionally, fuel upgrading. As discussed 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 materials) may be removed from the feedstock. In the feedstock processing unit 110, the waste materials 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 materials, 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 a 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 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 processed 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 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 carbon dioxide is released and lean solvent is recovered and recycled in a closed circuit to the absorber.

[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 limits given 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 discharged 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 CO2 is combined with H2 157 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 HyCOgen unit manufactured by Johnson Matthey. The reverse water gas shift reactor 170 converts the recovered CO2 and H2 back to usable CO and H2O for 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 H2 157 produced by the water electrolysis unit 155. In some embodiments, the target H2 / CO ratio may range from 0.5 to 10.0.

[0038] The purified syngas stream 151 may be fed to the Fischer-Tropsch reactor 180 as the main or only carbon-containing feedstock. In some embodiments, the secondary syngas stream 171 is also a feedstock for the Fischer-Tropsch reactor 180. In addition, 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 strongly exothermic process. Thus, the FT reactor may require significant heat removal, which is typically achieved by medium pressure steam generation via vaporization of boiler feed water. The Fischer-Tropsch reactor 180 produces a mixture of linear paraffinic hydrocarbon molecules with carbon numbers varying between C1 and C30 and above as the main product, and product water as a by-product. The FT reaction is a heterogeneous catalytic reaction characterized by a combination of gas phase reactants and liquid and gas products that are separately recovered as medium FT liquids (MFTL) and heavy FT liquids (HFTL), water, and FT tail gas (or FT tail gas). The FT tail gas 185 typically contains a mixture of unreacted hydrogen and carbon monoxide, as well as the by-products of the reaction, methane and CO2, and may be recycled to other units in the system where it may be reformed back into additional synthesis gas. For example, the FT tail gas 185 may be recycled to the reforming unit 130. In some embodiments, the system may include a hydrocracking unit 190 and / or a fractionation unit 195 to upgrade the FT liquids. For example, the hydrocracking unit 190 employs a high temperature, high pressure catalytic process that upgrades the HFTL and MFTL hydrocarbon streams 181 into transportation fuels or blending components that meet 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] The system 100 includes a water electrolysis unit 155. Water produced from the aforementioned units in the system 100 (e.g., gasifier, Fischer-Tropsch reactor, etc.) may be treated in a water treatment unit and then fed to the water electrolysis unit 155. The water treatment unit may produce boiler quality water that is fed to the water electrolysis unit 155, as well as some cooling or heat recovery systems where steam is produced. For example, a purified water stream 182 from the Fischer-Tropsch reactor 180 may be fed to the water electrolysis unit 155. The water electrolysis unit 155 may convert the purified water into an oxygen stream 156 and a hydrogen stream 157, which may be fed to other units in the system 100. For example, the oxygen stream 156 produced from the water electrolysis unit 155 may be fed to the gasification unit 120, the reforming unit 130, the reverse water gas shift reactor 170, or a combination thereof. In some embodiments, the oxygen stream 156 is mixed with water before being fed to the reverse water gas shift reactor 170. The hydrogen stream 157 generated 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 to convert hydrogen and CO2 to carbon monoxide (CO), which is combined with additional hydrogen to form synthesis gas. The synthesis gas 171 generated 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, and 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, and 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 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, e.g., natural gas, an "efficient" combined cycle mode generates about 450 grams CO2 / kWh. However, when green energy (e.g., solar power) is employed, the 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 green energy sources rather than traditional natural gas sources, 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 a power source to drive electrolysis of water to produce a portion of the hydrogen and oxygen required for the plant's process operations. Biomass gasification, conversion to liquids, and associated purification processes require additional hydrogen beyond the amount present in the biomass feedstock. The electrolysis process breaks water down into its hydrogen and oxygen components, thus providing a portion of the oxygen required for the overall plant operation. In some embodiments, the processes and systems described herein use renewable energy resources (e.g., solar, wind, etc.) to power the individual units in the system. Additionally, where economically feasible, waste heat is recovered and used to generate electricity for reuse in the system.

[0043] FIG. 2 is a schematic diagram of a hydrocarbon synthesis process integrated with a CO2 electrolysis unit according to some embodiments of the present invention. As shown in FIG. 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 to produce syngas via reforming, gasification, and oxidation, respectively. 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 CO2 emissions while improving overall carbon efficiency and minimizing environmental emissions by forming additional hydrocarbons. The electrolysis process is preferably at least partially powered 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 comprise switchgrass, forest thinnings, slash, wood chips, lignin, or other carbohydrate and / or cellulosic materials. The biomass may comprise 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 a 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 ("power natural gas" sent to unit 500). A natural gas preheater and unit 210 (e.g., sulfur removal unit) heats the natural gas and removes sulfur-containing compounds to provide a natural gas feedstock that is utilized to produce syngas. The amount of natural gas for turbine-based power 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 requirement, which may range from 50-200 MW, e.g., 50-200 MW, 60-180 MW, 75-160 MW, 80-150 MW, 90-140 MW, 100-130 MW, or about 128.15 MW. Geographical considerations may influence the supplemental green energy requirement. 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 provide power for the entire production process, e.g., 16 hours, when direct green energy, e.g., solar energy, is not available.

[0046] As discussed 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 emissions 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, and the ratio of natural gas to biomass in the feed.

[0047] Returning to unit 210, the natural gas feedstock is combined in this particular configuration with gas phase products (e.g., unconverted H2 and CO) and H2 (produced by electrolysis in unit 320). In some embodiments, the natural gas feedstock is combined with the gas phase products and H2 in unit 260A (autothermal reforming unit) to produce syngas, which is then fed to unit 205B (syngas processing unit). As shown, a CO2 enriched stream is optionally directed from syngas processing unit 205B to unit 363 (CO2 absorber unit), which is described in more detail below. The syngas, which is converted to hydrocarbons in unit 310 (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 water steam and oxygen to produce syngas. This syngas may contain undesirable components, such as reactive nitrogen and undesirably high levels of CO2. Typically, syngas processing includes a removal unit to remove or convert these undesirable components. In some embodiments, the H2 / 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 a syngas with an appropriate H2 / CO ratio, e.g., typically 0.5-1.0, 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 0.8-1.0. 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 traces of hydrocarbons and CO contained in the scrubbed CO2 and produce purified CO2.

[0050] The resulting syngas, with a significantly reduced CO2 content, is combined with the 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, the 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 heaters (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, e.g., jet fuel or diesel products. In unit 240, some materials may be converted to lighter 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 FIG. 2 shows exemplary CO2 emissions of various units in a hydrocarbon synthesis process. In some embodiments, the main sources of CO2 emissions in the above 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 · Syngas from ATR (Unit 205B).

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

[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 to syngas in a hydrocarbon production process. The process may include processing natural gas in an autothermal reforming unit to form a first syngas stream, processing 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 that may be sent 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, the total CO2 emissions depend on many factors. For example, the total CO2 emissions mainly depend 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, the 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, the total CO2 emissions associated with power and fuel production may exceed the threshold of the total allowable CO2 emissions.

[0057] In some embodiments, the present invention utilizes green energy, e.g., solar energy, as a power source to provide energy for converting CO2 to syngas and then to transportation fuels. Many process configurations are possible to demonstrate that CO2 and product water can be electrolyzed and converted to syngas and then to transportation fuels, thereby reducing overall CO2 emissions. For example, CO2 sequestration can be done at the same time as CO2 reduction. However, sequestration may not be a viable option at many locations in the process because it requires pipelines and relatively low-cost transportation. Converting CO2 and steam to syngas provides an opportunity to use electricity to convert carbon and hydrogen in the unwanted by-products to transportation fuels (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 tradeoff between sources of H2 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 a syngas containing hydrogen and carbon monoxide, a biomass gasifier that converts various types of biomass materials into a syngas containing primarily hydrogen and carbon monoxide, an electrolysis unit that converts water to hydrogen gas and oxygen gas, an optional desalination system that feeds 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 for converting the syngas into liquid hydrocarbon fuels, and a fuel upgrading system for further removing carbon dioxide from the liquid hydrocarbon fuels. The system may include solar panels for converting sunlight into electricity to power units in the system (e.g., the electrolysis unit), and a steam turbine generator system for producing electricity from the waste heat of the gasification and natural gas to liquefaction conversion system. The system recycles 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 by a carbon dioxide electrolysis system to convert the carbon dioxide into syngas, which is sent to a Fischer-Tropsch reactor to produce additional liquid hydrocarbon fuels. Both of these options for recycling the CO2 have an impact on the power required. The reverse water-gas shift option increases the consumption of hydrogen produced by the electrolysis of water, while the electrolysis of CO2 directly consumes power. Thus, a trade-off occurs 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, recirculation of CO2 via one option or the other may be more or less attractive from the perspective of the carbon intensity of the synthetic fuel. EXAMPLES

[0060] CO2 emissions can be compared for each of the 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 50-500 grams CO2 per MJ of fuel produced, or about 89.12 grams 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 capture, 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 main contributions to the CO2 emissions are the actual combustion of the 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 a conventional refinery; see Table 1 (89.12g CO2 / MJ SPK for baseline petroleum fuel; 59.84g CO2 / MJ SPK for baseline operation using CO2 electrolysis combined with natural gas turbine power and CO2 sequestration). In this scenario, the main CO2 reduction comes from the higher amount of CO2 sequestered (323,970 MTPY) compared to the amount of CO2 electrolyzed (148,900 MTPY (tonnes per year)). The use of a flue gas scrubber to capture CO2 from the combustion process (unit 235) also helps mitigate overall CO2 emission levels, especially if 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-CO2 emissions by using solar energy to reduce the total power generation from a natural gas turbine, 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 / 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 value of 89.12 g CO2 / MJ fuel). 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, the average CO2 emissions of electricity generated on the US 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 allows for additional production of products, while the overall GHG-CO2 emissions are 30-60% lower than a conventional refinery, which ranges from 89.12g CO2 / MJ of fuel. [Table 1]

[0063] Although 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 consideration of the above discussion, the relevant knowledge in the art, and the references mentioned above in connection with the "Background" and "Description of the Invention", the disclosures of which are all incorporated herein by reference. 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 above description of various embodiments, the embodiments referring to different embodiments can be appropriately combined.

Claims

1. A system for producing a hydrocarbon-based fuel, comprising: a biomass feedstock treatment unit configured to remove waste from a feedstock and produce a treated feedstock; a gasification unit in communication with the biomass feedstock treatment unit, the gasification unit configured to convert the treated feedstock into a synthesis gas comprising carbon dioxide, carbon monoxide, and hydrogen; a reactor downstream of the gasification unit, the reactor configured to promote conversion of a portion of the synthesis gas and to be operated under conditions appropriate to produce an appropriate ratio of hydrogen to CO; a scrubber in communication with the reactor, the scrubber configured to remove carbon dioxide from the synthesis gas and produce a purified synthesis gas having a hydrogen / carbon monoxide ratio of at least 1.5:1; a Fischer-Tropsch reactor configured to receive the purified synthesis gas, the Fischer-Tropsch reactor configured to convert the purified synthesis gas into a Fischer-Tropsch liquid, water, and tail gas; an electrolysis unit configured to receive water from the Fischer-Tropsch reactor, the electrolysis unit configured to convert the water into an oxygen stream and a hydrogen stream; a reverse water gas shift reactor, wherein a portion of the carbon dioxide removed from the synthesis gas by the scrubber is recycled to the reverse water gas shift reactor; comprising: wherein a portion of the oxygen stream is recycled to the gasification unit, the reactor, or a combination thereof; the system achieving at least 90% carbon conversion of the feedstock.

2. The system of claim 1, wherein a portion of the hydrogen stream produced by the electrolysis unit is supplied to the reverse water gas shift reactor, the reverse water gas shift reactor configured to produce carbon monoxide for supply to the Fischer-Tropsch reactor.

3. The system of claim 2, wherein the synthesis gas stream and the hydrogen stream are pressurized prior to being supplied to the Fischer-Tropsch reactor.

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

5. The system according to claim 1, further comprising a hydrocracking unit, a fractionation unit, an isomerization unit, or a combination thereof configured to improve the Fischer-Tropsch liquid as fuel, wherein the by-product of the hydrocracking unit includes tail gas, and the by-product of the fractionation unit includes naphtha.

6. The system according to claim 5, wherein the tail gas, naphtha, or both are recycled to the reactor.

7. The system according to claim 1, further comprising a flue gas scrubber configured to clean any flue gas generated by the system, wherein the reactor is a dry reformer.

8. Further comprising a carbon dioxide treatment and compression system, wherein the carbon dioxide generated from the scrubber and the flue gas scrubber is processed by the carbon dioxide treatment and compression system to generate a purified carbon dioxide stream, and the purified carbon dioxide stream is recycled to the dry reformer, the water-gas shift reactor, the CO ２ The system according to claim 7, which is recycled to an electrolysis unit, or a combination thereof.

9. The system according to claim 1, wherein the feedstock includes one or more of railroad ties, greenwood, corn stover, pruned branches of orchards, thinned wood of forests, slash, switchgrass, wood chips, lignin, and cellulosic materials.

10. The system according to claim 1, wherein the feedstock includes lignocellulosic biomass.

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

12. A CO configured to convert a part of the carbon dioxide and water removed from the system into carbon monoxide and hydrogen ２ The system according to claim 1, further comprising an electrolysis unit.

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

14. The process according to claim 13, further comprising purifying the carbon dioxide stream generated from the separation unit to produce a purified carbon dioxide stream and recycling the purified carbon dioxide stream to the reforming step.

15. The process according to claim 13, 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.

16. The process according to claim 13, further comprising treating natural gas in a reforming unit to produce a second syngas stream that is supplied to the Fischer-Tropsch reactor.

17. The process according to claim 13, wherein the electrolysis unit is driven by solar energy, wind energy, hydro energy, nuclear energy, or tidal energy.

18. The process according to claim 13, further comprising treating the water from the Fischer-Tropsch reactor to produce purified water, and electrolyzing the purified water in the electrolysis unit.

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