Method and system for synthesizing fuel from carbon dioxide

Abstract

A method for producing a synthetic fuel includes the steps of: extracting carbon dioxide (CO2) from an atmospheric stream using a sorbent material to form a recovered carbon dioxide feed stream; extracting hydrogen (H2) from a hydrogen-containing feedstock to produce a hydrogen feed stream; treating the recovered carbon dioxide feed stream in a CO2 reduction reactor by applying an electrical potential to the CO2 reduction reactor and reducing at least a portion of the recovered carbon dioxide feed stream over a catalyst to form a carbon monoxide stream and an oxygen (O2) stream to produce a carbon monoxide (CO) stream; and reacting the carbon monoxide stream from the CO2 reduction reactor with the hydrogen feed stream to produce the synthetic fuel.

Description

[Technical field]

[0001] The present disclosure relates generally to methods and systems for synthesizing fuels from carbon dioxide (CO2). [Background technology]

[0002] Global incentives to reduce CO2 emissions are gaining momentum. Capturing carbon dioxide (CO2) from the atmosphere, also known as direct air capture (DAC), is one approach to mitigate greenhouse gas emissions and slow climate change. However, many technologies designed for capturing CO2 from point sources, such as flue gas from industrial facilities, are generally inefficient at capturing CO2 from the atmosphere due to the extremely low CO2 concentrations and the large volume of air required for processing. In recent years, progress has been made in finding technologies more suitable for capturing CO2 directly from the atmosphere. These techniques include the use of solid and liquid sorbents to extract and capture CO2 from dilute sources such as the atmosphere. After the CO2 has been captured and captured, there are several attractive utilization routes. Some highly encouraged uses are the synthesis of low carbon intensity fuels and chemicals, such as transportation fuels, using carbon sourced from atmospheric CO2.

[0003] It has been recognized that reducing emissions in the transportation sector is particularly challenging and costly. The majority of vehicles, including cars, ships, aircraft, and trains, burn high energy density hydrocarbon fuels, and there is an approximately $50 trillion infrastructure worldwide to produce, distribute, and consume these fuels. DAC provides a route to produce synthetic hydrocarbon fuels that have high energy density like conventional fuels, but with relatively low carbon intensity because they are produced using carbon atoms that have already been emitted. When incorporating renewable energy sources and optimized heat integration, these synthetic fuels can have low or zero carbon intensity. These synthetic fuels produce cleaner burning fuel products than fossil fuels because they are produced from atmospheric CO2 and clean feedstocks such as hydrogen. [Prior art documents] [Patent documents]

[0004] [Patent Document 1] U.S. Patent Application Serial No. 16 / 472,379 Summary of the Invention [Problem to be solved by the invention]

[0005] Thus, the demand for fuel and the need for reduced emissions can both be addressed by synthetic fuels and chemicals based on DAC. [Means for solving the problem]

[0006] In one implementation, a method for producing a synthetic fuel includes extracting carbon dioxide (CO) from an atmospheric stream using a sorbent material to form a recovered carbon dioxide feed stream; extracting hydrogen (H) from a hydrogen-containing feedstock to produce a hydrogen feed stream; treating the recovered carbon dioxide feed stream in a CO reduction reactor to produce a carbon monoxide (CO) stream by applying an electrical potential to the CO reduction reactor; and reducing at least a portion of the recovered carbon dioxide feed stream over a catalyst to form a carbon monoxide stream and an oxygen (O) stream; and reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream to produce the synthetic fuel.

[0007] In an embodiment compatible with this implementation, the step of extracting carbon dioxide from an atmospheric stream using a sorbent material to form a captured carbon dioxide feed stream includes reacting the carbon dioxide in the atmospheric stream with a CO2 capture solution to form a CO2-poor gas and a carbonate-rich capture solution; reacting the carbonate-rich capture solution with a calcium hydroxide stream to form at least a portion of the CO2 capture solution and precipitate calcium carbonate solids; and calcining at least a portion of the calcium carbonate solids to extract the captured carbon dioxide feed stream.

[0008] In another embodiment that may be combined with any of the preceding embodiments, reacting the carbon dioxide in the atmospheric stream with the CO2 capture solution includes reacting the carbon dioxide in the atmospheric stream with at least one of potassium hydroxide or sodium hydroxide.

[0009] In another embodiment that may be combined with any of the preceding embodiments, calcining at least a portion of the calcium carbonate solids includes combusting a fuel comprising at least one of natural gas or hydrogen.

[0010] In another embodiment that may be combined with any of the preceding embodiments, combusting the fuel comprising at least one of natural gas or hydrogen includes combusting at least a portion of the hydrogen feed stream.

[0011] In another aspect that may be combined with any of the preceding aspects, calcining at least a portion of the calcium carbonate solids comprises electrically heating the calcium carbonate solids.

[0012] In another embodiment that may be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream comprises: reacting the hydrogen feed stream with the carbon monoxide stream in a Fischer-Tropsch (FT) process to form a FT crude stream; and refining the FT crude stream to form a refined crude stream comprising naphtha; the method further comprises combusting at least a portion of the naphtha to generate thermal energy, and calcining at least a portion of the calcium carbonate solids comprises calcining at least a portion of the calcium carbonate solids with thermal energy.

[0013] In another aspect that may be combined with any of the preceding aspects, extracting hydrogen from a hydrogen-containing feedstock comprises electrolyzing water to form a hydrogen feed stream and an electrolyzer oxygen stream.

[0014] In another embodiment that may be combined with any of the preceding embodiments, extracting hydrogen from a hydrogen-containing feedstock comprises steam-methane reforming to form a hydrogen feed stream.

[0015] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream comprises reacting the hydrogen feed stream with the carbon monoxide stream in a Fischer-Tropsch (FT) process to form a FT crude stream.

[0016] In another embodiment that can be combined with any of the preceding embodiments, treating the recovered carbon dioxide feed stream in a CO2 reduction reactor, comprising conveying only a carbon monoxide stream from the CO2 reduction reactor to a Fischer-Tropsch (FT) process; and reacting the carbon monoxide stream from the CO2 reduction reactor with a hydrogen feed stream comprises reacting the carbon monoxide stream conveyed from the CO2 reduction reactor with a hydrogen feed stream in a FT process to form a FT crude stream.

[0017] Another embodiment that can be combined with any of the preceding embodiments further includes oxidizing at least a portion of the combustible gas in an autothermal reformer using the oxygen stream from the CO2 reduction reactor to form a synthesis gas stream.

[0018] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO2 reduction reactor with the hydrogen feed stream comprises reacting the carbon monoxide stream from the CO2 reduction reactor with the hydrogen feed stream in a Fischer-Tropsch (FT) process to form a FT crude stream and a FT tail gas stream; the method further comprises purifying the FT crude stream to produce a purified tail gas stream and a purified crude stream.

[0019] In another embodiment that may be combined with any of the preceding embodiments, oxidizing at least a portion of the combustible gas includes oxidizing at least one of an FT tail gas stream, a refinery tail gas stream, or a natural gas stream.

[0020] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream comprises reacting a syngas stream, a carbon monoxide stream, and a hydrogen feed stream from an autothermal reformer in a Fischer-Tropsch (FT) process to form a FT crude stream and a FT tail gas stream.

[0021] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream includes: purifying the FT crude stream to form a refined crude stream and a refined tail gas stream; and distilling the refined crude stream to form a synthetic fuel, the synthetic fuel comprising a liquid fuel stream and a chemicals stream.

[0022] In another embodiment that may be combined with any of the preceding embodiments, the step of extracting hydrogen from hydrogen compounds in the hydrogen feedstock to produce a hydrogen feed stream further comprises dissociating a water stream over a catalyst in the CO reduction reactor to form the hydrogen feed stream and a separate portion of the oxygen stream.

[0023] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream includes: reacting the hydrogen feed stream and the carbon monoxide stream via a Fischer-Tropsch (FT) process to form a FT tail gas stream and a FT crude stream; purifying the FT crude stream to form a purified tail gas stream and a purified crude stream; and calcining at least a portion of the calcium carbonate solids to extract the recovered carbon dioxide feed stream includes combusting at least one of the FT tail gas stream or the purified tail gas stream.

[0024] In another embodiment that may be combined with any of the preceding embodiments, the recovered carbon dioxide feed stream comprises excess oxygen; and the method further comprises removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream.

[0025] In another aspect that can be combined with any of the preceding aspects, removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream includes combusting at least a portion of the excess oxygen with a fuel, wherein a molar ratio of the fuel to the excess oxygen is equal to or greater than the combustion stoichiometric ratio.

[0026] In another embodiment that can be combined with any of the preceding embodiments, removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream comprises: catalytically oxidizing a combustible gas with at least a portion of the excess oxygen to form a catalytic oxidation product stream comprising carbon dioxide and water; and combining the carbon dioxide of the catalytic oxidation product stream with the recovered carbon dioxide feed stream, where the combustible gas comprises at least one of natural gas, Fischer-Tropsch tail gas, or refined tail gas.

[0027] In another aspect that may be combined with any of the preceding aspects, catalytically oxidizing the combustible gas with at least a portion of the excess oxygen includes: combusting at least a portion of the excess oxygen with the combustible gas at an autoignition temperature of the combustible gas.

[0028] Another embodiment that can be combined with any of the preceding embodiments further includes liquefying the recovered carbon dioxide feed stream; and maintaining at least a portion of the liquefied carbon dioxide feed stream in a liquid storage tank prior to processing the recovered carbon dioxide feed stream in the CO reduction reactor.

[0029] In another embodiment that can be combined with any of the preceding embodiments, liquefying the recovered carbon dioxide feed stream includes separating contaminants from the recovered carbon dioxide feed stream in at least one of a cryogenic distillation unit, a membrane separation unit, or a water knockout unit.

[0030] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream produces heat; the method further includes transferring at least a portion of the heat to extracting carbon dioxide from the atmospheric stream using a sorbent material to form a captured carbon dioxide feed stream.

[0031] In another aspect that can be combined with any of the preceding aspects, the step of extracting carbon dioxide from the atmospheric stream with a sorbent material to form the recovered carbon dioxide feed stream includes calcining calcium carbonate solids using at least a portion of the heat to extract the recovered carbon dioxide feed stream.

[0032] In another embodiment that can be combined with any of the preceding embodiments, extracting carbon dioxide from the atmospheric stream with a sorbent material to form a captured carbon dioxide feed stream includes transferring at least a portion of heat to a CO2 capture solution and reacting the carbon dioxide in the atmospheric stream with the CO2 capture solution.

[0033] In another embodiment that can be combined with any of the preceding embodiments, the step of extracting carbon dioxide from the atmospheric stream includes: maintaining at least one of solid calcium carbonate or solid calcium oxide in a solid buffer storage tank prior to treating the captured carbon dioxide feed stream in the CO reduction reactor.

[0034] Another embodiment that can be combined with any of the preceding embodiments further includes compressing a gaseous process stream by operating a single compressor assembly, the gaseous process stream comprising at least one of a recovered carbon dioxide feed stream, steam, carbon monoxide, hydrogen, Fischer-Tropsch tail gas, or purified tail gas.

[0035] In another embodiment that can be combined with any of the preceding embodiments, the step of extracting carbon dioxide from an atmospheric stream includes: reacting carbon dioxide in the atmospheric stream with a solid sorbent comprising at least one of a metal oxide or a metal hydroxide to form carbonate-containing solids; and calcining at least a portion of the carbonate-containing solids to extract a recovered carbon dioxide feed stream.

[0036] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream includes reacting the hydrogen feed stream and the carbon monoxide stream through a Fischer-Tropsch (FT) process to form a FT tail gas stream and a FT crude stream; and purifying the FT crude stream to form a purified tail gas stream and a purified crude stream, and calcining at least a portion of the carbonate-containing solids includes combusting at least one of the FT tail gas stream or the purified tail gas stream.

[0037] In another implementation, a method for producing a synthetic fuel includes: extracting carbon dioxide from an atmospheric stream using a sorbent material to form a recovered carbon dioxide feed stream; extracting hydrogen from a hydrogen-containing feedstock to produce a hydrogen feed stream; and: conveying a portion of the hydrogen feed stream and at least a portion of the recovered carbon dioxide feed stream to a CO2 reduction reactor; inputting thermal energy to the CO2 reduction reactor and reacting the portion of the hydrogen feed stream with the recovered carbon dioxide feed stream over a catalyst in the CO2 reduction reactor to produce a carbon monoxide stream and a water stream; treating the recovered carbon dioxide feed stream in a carbon dioxide (CO2) reduction reactor to produce a carbon monoxide (CO) stream, and reacting the carbon monoxide stream from the CO2 reduction reactor with the hydrogen feed stream to produce a synthetic fuel.

[0038] In another embodiment that can be combined with any of the preceding embodiments, the step of extracting carbon dioxide from an atmospheric stream using a sorbent material to form a captured carbon dioxide feed stream includes reacting carbon dioxide in the atmospheric stream with a CO2 capture solution to form a CO2-lean gas and a carbonate-rich capture solution; reacting the carbonate-rich capture solution with a calcium hydroxide stream to form at least a portion of the CO2 capture solution and to precipitate calcium carbonate solids; and calcining at least a portion of the calcium carbonate solids to extract the captured carbon dioxide feed stream.

[0039] In another embodiment that may be combined with any of the preceding embodiments, reacting the carbon dioxide in the atmospheric stream with the CO2 capture solution includes reacting the carbon dioxide in the atmospheric stream with at least one of potassium hydroxide or sodium hydroxide.

[0040] In another embodiment that may be combined with any of the preceding embodiments, calcining at least a portion of the calcium carbonate solids includes combusting a fuel comprising at least one of natural gas or hydrogen.

[0041] In another aspect that may be combined with any of the preceding aspects, calcining at least a portion of the calcium carbonate solids comprises electrically heating the calcium carbonate solids.

[0042] In another embodiment that may be combined with any of the preceding embodiments, the step of combusting a fuel comprising at least one of natural gas or hydrogen comprises at least a portion of the hydrogen feed stream.

[0043] In another embodiment that may be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream comprises: reacting the hydrogen feed stream with the carbon monoxide stream in a Fischer-Tropsch (FT) process to form a FT crude stream; and refining the FT crude stream to form a refined crude stream comprising naphtha; the method further comprises combusting at least a portion of the naphtha to generate thermal energy, and calcining at least a portion of the calcium carbonate solids comprises calcining at least a portion of the calcium carbonate solids with thermal energy.

[0044] In another aspect that may be combined with any of the preceding aspects, extracting hydrogen from a hydrogen-containing feedstock comprises electrolyzing water to form a hydrogen feed stream and an electrolyzer oxygen stream.

[0045] In another embodiment that may be combined with any of the preceding embodiments, extracting hydrogen from a hydrogen-containing feedstock comprises steam-methane reforming to form a hydrogen feed stream.

[0046] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream comprises reacting the hydrogen feed stream with the carbon monoxide stream in a Fischer-Tropsch (FT) process to form a FT crude stream.

[0047] In another embodiment that can be combined with any of the preceding embodiments, inputting thermal energy and reacting at least a portion of the hydrogen feed stream with the recovered CO2 feed stream in the CO2 reduction reactor includes performing a reverse water gas shift reaction.

[0048] In another aspect that may be combined with any of the preceding aspects, extracting hydrogen from a hydrogen-containing feedstock comprises electrolyzing water to form a hydrogen feed stream and an electrolyzer oxygen stream; the method further comprises oxidizing at least a portion of a combustible gas in an autothermal reformer using the electrolyzer oxygen stream to form a synthesis gas stream, the combustible gas comprising at least one of a Fischer-Tropsch (FT) tail gas stream, a refinery tail gas stream, or a natural gas stream.

[0049] In another embodiment that can be combined with any of the preceding embodiments, inputting thermal energy to the CO2 reduction reactor includes inputting thermal energy to react in the CO2 reduction reactor with the syngas stream from the autothermal reformer to form a carbon monoxide stream and a water stream.

[0050] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO2 reduction reactor with the hydrogen feed stream includes reacting the carbon monoxide stream with at least a portion of the hydrogen feed stream in a FT process to form a FT crude stream and a FT tail gas stream.

[0051] Another embodiment that can be combined with any of the preceding embodiments further includes refining the FT crude stream to form a refined crude stream and a refined tail gas stream; and distilling the refined crude stream to form a synthetic fuel, the synthetic fuel comprising a liquid fuel stream and a chemicals stream.

[0052] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream includes: reacting the hydrogen feed stream and the carbon monoxide stream via a Fischer-Tropsch (FT) process to form a FT tail gas stream and a FT crude stream; purifying the FT crude stream to form a purified tail gas stream and a purified crude stream; and calcining at least a portion of the calcium carbonate solids to extract the recovered carbon dioxide feed stream, comprising combusting at least one of the FT tail gas stream or the purified tail gas stream.

[0053] In another embodiment that may be combined with any of the preceding embodiments, the recovered carbon dioxide feed stream comprises excess oxygen; and the method further comprises removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream.

[0054] In another aspect that can be combined with any of the preceding aspects, removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream includes combusting at least a portion of the excess oxygen with a fuel, wherein a molar ratio of the fuel to the excess oxygen is equal to or greater than the combustion stoichiometric ratio.

[0055] In another embodiment that can be combined with any of the preceding embodiments, removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream comprises: catalytically oxidizing a combustible gas with at least a portion of the excess oxygen to form a catalytic oxidation product stream comprising carbon dioxide and water, the combustible gas comprising at least one of natural gas, FT tail gas, or refined tail gas; and combining the carbon dioxide of the catalytic oxidation product stream with the recovered carbon dioxide feed stream.

[0056] In another aspect that may be combined with any of the preceding aspects, catalytically oxidizing the combustible gas with at least a portion of the excess oxygen includes: combusting at least a portion of the excess oxygen with the combustible gas at an autoignition temperature of the combustible gas.

[0057] Another embodiment that can be combined with any of the preceding embodiments further includes liquefying the recovered carbon dioxide feed stream; and maintaining at least a portion of the liquefied carbon dioxide feed stream in a liquid storage tank prior to processing the recovered carbon dioxide feed stream in the CO reduction reactor.

[0058] In another embodiment that can be combined with any of the preceding embodiments, liquefying the recovered carbon dioxide feed stream includes separating contaminants from the recovered carbon dioxide feed stream in at least one of a cryogenic distillation unit, a membrane separation unit, or a water knockout unit.

[0059] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream produces heat; the method further includes transferring at least a portion of the heat to extracting carbon dioxide from the atmospheric stream using a sorbent material.

[0060] In another embodiment that may be combined with any of the preceding embodiments, the step of extracting carbon dioxide from the atmospheric stream with a sorbent material to form the recovered carbon dioxide feed stream includes calcining at least a portion of the calcium carbonate solids to extract the recovered carbon dioxide feed stream; the method further includes transferring at least a portion of the heat to the calcium carbonate solids.

[0061] In another embodiment that can be combined with any of the preceding embodiments, extracting carbon dioxide from the atmospheric stream with a sorbent material to form a captured carbon dioxide feed stream includes reacting the carbon dioxide in the atmospheric stream with a CO2 capture solution; the method further includes transferring at least a portion of heat to the CO2 capture solution.

[0062] In another embodiment that can be combined with any of the preceding embodiments, the step of extracting carbon dioxide from the atmospheric stream includes: maintaining at least one of solid calcium carbonate or solid calcium oxide in a solid buffer storage tank prior to treating the captured carbon dioxide feed stream in the CO reduction reactor.

[0063] Another embodiment that can be combined with any of the preceding embodiments further includes compressing a gaseous process stream by operating the single compressor assembly, the gaseous process stream comprising at least one of a recovered carbon dioxide feed stream, steam, carbon monoxide, hydrogen, Fischer-Tropsch tail gas, or purified tail gas.

[0064] In another embodiment that can be combined with any of the preceding embodiments, the step of extracting carbon dioxide from an atmospheric stream includes: reacting carbon dioxide in the atmospheric stream with a solid sorbent comprising at least one of a metal oxide or a metal hydroxide to form carbonate-containing solids; and calcining at least a portion of the carbonate-containing solids to extract a recovered carbon dioxide feed stream.

[0065] In another embodiment that can be combined with any of the preceding embodiments, reacting the carbon monoxide stream from the CO reduction reactor with the hydrogen feed stream includes reacting the hydrogen feed stream and the carbon monoxide stream via a FT process to form a FT tail gas stream and a FT crude stream; and purifying the FT crude stream to form a purified tail gas stream and a purified crude stream, and calcining at least a portion of the carbonate-containing solids includes combusting at least one of the FT tail gas stream or the purified tail gas stream.

[0066] In another implementation, a method of producing a synthetic fuel includes: extracting carbon dioxide from an atmospheric air stream using a sorbent material to form a captured carbon dioxide feed stream; treating the captured carbon dioxide feed stream in a carbon dioxide (CO) reduction reactor to produce a carbon monoxide (CO) stream by applying an electrical potential to the CO reduction reactor; and reducing at least a portion of the captured carbon dioxide feed stream over a catalyst to form a carbon monoxide stream and an oxygen (O) stream; and reacting the carbon monoxide stream from the CO reduction reactor with a hydrogen (H) stream to produce the synthetic fuel.

[0067] In another implementation, a method for producing a synthetic fuel includes: treating a CO2 feed stream generated by capturing CO2 from the atmosphere by applying an electric potential to a CO2 reduction reactor; and reducing at least a portion of the CO2 feed stream over a catalyst to form a carbon monoxide stream and an oxygen (O2) stream; in a carbon dioxide (CO2) reduction reactor to produce a carbon monoxide (CO) stream; and reacting the carbon monoxide stream from the CO2 reduction reactor with a hydrogen stream to produce a synthetic fuel.

[0068] In another implementation, a system for producing synthetic fuel includes: a carbon dioxide (CO2) capture subsystem configured to extract carbon dioxide from an atmospheric stream using a sorbent material to produce a captured carbon dioxide feed stream; a hydrogen production subsystem configured to extract hydrogen from a hydrogen-containing feedstock to produce a hydrogen feed stream; and a hydrocarbon production subsystem including a CO2 reduction reactor configured to process the captured carbon dioxide feed stream to produce a carbon monoxide (CO) stream, wherein the hydrocarbon production subsystem is configured to react the hydrogen feed stream with the carbon monoxide stream from the CO2 reduction reactor to produce the synthetic fuel.

[0069] In another embodiment that may be combined with any of the preceding embodiments, the adsorbent material includes a CO2 capture solution; the CO2 capture subsystem includes a pellet reactor fluidly connected to a calciner, the pellet reactor configured to react the CO2 capture solution to precipitate calcium carbonate solids, and the calciner configured to calcinate at least a portion of the calcium carbonate solids.

[0070] In another embodiment that can be combined with any of the preceding embodiments, the CO2 capture solution includes at least one of potassium hydroxide or sodium hydroxide.

[0071] In another aspect that may be combined with any of the preceding aspects, the calciner is configured to combust a fuel comprising at least one of a natural gas or a hydrogen fuel.

[0072] In another aspect that may be combined with any of the preceding aspects, the fuel comprises hydrogen fuel, and the hydrogen fuel is part of a hydrogen supply stream.

[0073] In another aspect that may be combined with any of the preceding aspects, the calciner includes an electric heater.

[0074] In another aspect that may be combined with any of the preceding aspects, the hydrogen production subsystem includes a water electrolyzer configured to form a hydrogen feed stream and an oxygen stream.

[0075] In another aspect that may be combined with any of the preceding aspects, the hydrogen production subsystem includes a steam-methane reformer operable to form a hydrogen feed stream and an oxygen stream.

[0076] In another embodiment that may be combined with any of the preceding embodiments, the hydrocarbon production subsystem includes a Fischer-Tropsch (FT) reactor fluidly connected to the CO2 reduction reactor to receive the carbon monoxide stream from the CO2 reduction reactor, the FT reactor configured to form a FT crude stream.

[0077] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a solid oxide electrolysis cell including a zirconia-containing electrolyte and electrodes including nickel or platinum.

[0078] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a molten carbonate electrolysis cell including a carbonate-containing electrolyte and electrodes including titanium or graphite.

[0079] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a polymer electrolyte membrane fuel cell that includes at least one of an alkaline aqueous solution or a solid membrane.

[0080] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor comprises a gas diffusion electrode and a catalyst comprising platinum or a non-noble metal.

[0081] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor is fluidly connected to a CO2 capture subsystem; and the hydrocarbon production subsystem includes an autothermal reformer fluidly connected to a Fischer-Tropsch (FT) reactor.

[0082] In another aspect that can be combined with any of the preceding aspects, the autothermal reformer includes a reactant inlet configured to receive a combustible gas comprising at least one of an FT tail gas from the FT reactor, a refined tail gas, or a natural gas stream.

[0083] In another embodiment that may be combined with any of the preceding embodiments, the FT reactor includes a syngas inlet configured to receive a syngas stream from the autothermal reformer.

[0084] In another embodiment that can be combined with any of the preceding embodiments, the FT reactor includes an FT catalyst that includes at least one of nickel, cobalt, iron, or ruthenium.

[0085] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes an oxygen outlet fluidly connected to the autothermal reformer and a carbon monoxide outlet fluidly connected to the FT reactor.

[0086] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes: a thermal energy source; at least one reactant inlet configured to receive the recovered carbon dioxide feed stream, a portion of the hydrogen feed stream, and the synthesis gas stream from the autothermal reformer; an outlet configured to flow the carbon monoxide stream to the FT reactor; and a catalyst including at least one of cobalt, iron, copper, zinc, or aluminum.

[0087] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor is a fixed bed reactor or a multi-tubular fixed bed reactor.

[0088] In another aspect that may be combined with any of the preceding aspects, the hydrogen production subsystem includes a water electrolyzer configured to provide a hydrogen feed stream to the CO2 reduction reactor and configured to provide an oxygen stream to the autothermal reformer, the autothermal reformer including: a plurality of inlets configured to receive a plurality of reactants, the plurality of reactants including a combustible gas and an oxygen stream from the water electrolyzer, the combustible gas including at least one of an FT tail gas from the FT reactor, a purified tail gas, or a natural gas stream; an outlet fluidly connected to the at least one reactant inlet of the CO2 reduction reactor, the outlet configured to flow a syngas stream to the CO2 reduction reactor; and a reformer supporting a catalyst including nickel, the reformer configured to oxidize at least a portion of the combustible gas with the oxygen stream to form a syngas stream.

[0089] In another embodiment that can be combined with any of the preceding embodiments, the FT reactor includes a reactor volume containing a catalyst and at least one outlet configured to flow the FT tail gas to an autothermal reformer and a FT crude stream.

[0090] In another embodiment that can be combined with any of the preceding embodiments, the FT reactor is one of a fixed packed bed reactor, a multi-tubular fixed bed reactor, a fluidized bed reactor, and a slurry phase reactor.

[0091] In another aspect that may be combined with any of the preceding aspects, the hydrocarbon production subsystem includes an autothermal reformer fluidly connected to a refinery, the refinery including at least one outlet configured to flow the refined tail gas to the autothermal reformer and to flow the refined crude to the distillation device, the distillation device configured to fractionate the refined crude into a synthetic fuel.

[0092] In another embodiment that can be combined with any of the preceding embodiments, the refinery crude includes naphtha; and the CO2 capture subsystem includes a calciner including a burner operable to combust the naphtha.

[0093] In another aspect that may be combined with any of the preceding aspects, the C0 capture subsystem includes a calciner configured to combust a combustible gas to provide thermal energy for calcining the calcium carbonate solids, the combustible gas including at least one of a Fischer-Tropsch (FT) tail gas or a refinery tail gas.

[0094] In another aspect that can be combined with any of the preceding aspects, the adsorbent material includes a CO2 capture solution; and the CO2 capture subsystem includes a burner configured to combust a combustible gas to provide thermal energy for heating the CO2 capture solution, the combustible gas including at least one of a Fischer-Tropsch (FT) tail gas or a refinery tail gas.

[0095] In another aspect that may be combined with any of the preceding aspects, the recovered carbon dioxide feed stream comprises excess oxygen; the system further comprises a catalytic oxidation reactor coupled to the CO2 capture subsystem, the catalytic oxidation reactor operable to remove at least a portion of the excess oxygen, the catalytic oxidation reactor comprising: a catalytic oxidation reactor volume containing a platinum-containing catalyst; and at least one inlet configured to receive the excess oxygen in the recovered carbon dioxide feed stream and to receive a combustible gas comprising at least one of natural gas, Fischer-Tropsch (FT) tail gas, or refinery tail gas, the catalytic oxidation reactor volume configured to react the excess oxygen with the combustible gas over the platinum-containing catalyst.

[0096] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a solid oxide electrolysis cell including a zirconia-containing electrolyte and electrodes containing nickel or platinum.

[0097] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a molten carbonate electrolysis cell including a carbonate-containing electrolyte and electrodes containing titanium or graphite.

[0098] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor includes a polymer electrolyte membrane fuel cell that includes at least one of an alkaline aqueous solution or a solid membrane.

[0099] In another embodiment that can be combined with any of the preceding embodiments, the CO2 reduction reactor comprises a gas diffusion electrode and a catalyst comprising platinum or a non-noble metal.

[0100] In another aspect that can be combined with any of the preceding aspects, the CO2 reduction reactor includes: a thermal energy source thermally coupled to a CO2 reduction reactor vessel supporting a CO2 reduction catalyst; at least one reactant inlet configured to receive reactants, the reactants including the recovered carbon dioxide feed stream, a portion of the hydrogen feed stream, and a syngas stream; an outlet configured to flow products, the products including a carbon monoxide stream, and the CO2 reduction reactor vessel configured to react the reactants over the CO2 reduction catalyst, the CO2 reduction catalyst including at least one of cobalt, iron, copper, zinc, or aluminum.

[0101] Another embodiment that can be combined with any of the preceding embodiments further includes a CO2 purification and compression system fluidly connected to a liquid buffer storage tank configured to be pressurized to a pressure in the range of 10 bar to 65 bar, and the CO2 capture subsystem is fluidly connected to the hydrocarbon subsystem by the CO2 purification and compression system and the liquid buffer storage tank.

[0102] In another embodiment that may be combined with any of the preceding embodiments, the CO2 purification and compression system includes at least one of a cryogenic distillation unit, a membrane separation unit, or a water knockout unit.

[0103] In another embodiment that may be combined with any of the preceding embodiments, the hydrocarbon production subsystem includes a Fischer-Tropsch (FT) reactor thermally coupled to the CO2 capture subsystem.

[0104] In another embodiment that can be combined with any of the preceding embodiments, the CO2 capture subsystem includes a calciner and a FT reactor thermally coupled to the calciner.

[0105] In another aspect that may be combined with any of the preceding aspects, the CO2 capture subsystem includes a calciner fluidly connected to at least one solid buffer storage tank configured to store at least one of calcium carbonate or calcium oxide.

[0106] Another embodiment that can be combined with any of the preceding embodiments further includes a single compressor assembly fluidly connected to the CO capture subsystem and the hydrocarbon production subsystem, the single compressor assembly including a multi-stage compressor-motor or at least two compressors coupled to a single motor shaft.

[0107] In another aspect that can be combined with any of the preceding aspects, the sorbent material of the CO2 capture subsystem is a solid sorbent including at least one of a metal oxide or a metal hydroxide, and the CO2 capture subsystem includes: a reactor configured to form a carbonate-containing solid by reacting carbon dioxide in the atmospheric stream with the solid sorbent; and a calciner operable to calcinate at least a portion of the carbonate-containing solid.

[0108] In another embodiment that may be combined with any of the preceding embodiments, the hydrocarbon production subsystem includes: a Fischer-Tropsch (FT) reactor operable to form a FT tail gas and a FT crude stream; a refinery is fluidly coupled to the FT reactor, the refinery being operable to form a purified tail gas and a purified crude stream; and a calciner configured to combust at least one of the FT tail gas or the purified tail gas.

[0109] The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, drawings, and claims. [Brief description of the drawings]

[0110] [Figure 1] FIG. 1 is a schematic block diagram of an example system for producing synthetic fuel from hydrogen and carbon dioxide, including a CO2 capture subsystem, a hydrogen production subsystem, and a synthetic fuel production subsystem, in accordance with the present disclosure. [Diagram 2] FIG. 1 is a schematic diagram of an example system for producing synthetic fuels from atmospheric CO that utilizes an electrocatalytic CO reduction reactor and an autothermal reformer. [Diagram 3] FIG. 1 is a schematic diagram of an example system for producing synthetic fuels from atmospheric CO2 utilizing a thermal catalytic CO2 reduction reactor and an autothermal reformer. [Figure 4] FIG. 1 is a schematic diagram of an example system for producing synthetic fuels from atmospheric CO2 utilizing an electrocatalytic CO2 reduction reactor and recycling FT tail gas and purified tail gas to a CO2 capture subsystem. [Diagram 5] FIG. 1 is a schematic diagram of an example system for producing synthetic fuels from atmospheric CO2 utilizing a thermal catalytic CO2 reduction reactor with Fischer-Tropsch (FT) tail gas and refined tail gas recirculation to a CO2 capture subsystem. [Figure 6] FIG. 1 is a schematic diagram of an example system for producing synthetic fuel from atmospheric CO2 that utilizes a buffer volume and recirculation of liquid synthetic fuel within the system. [Figure 7] FIG. 1 is a schematic diagram of an example system including a catalytic oxidation reactor and a calciner combustion control system for removing at least a portion of excess oxygen from a captured CO2 stream. [Figure 8] FIG. 1 is a schematic diagram of an example system for producing synthetic fuels from atmospheric CO utilizing a CO2 reduction reactor that produces a hydrogen stream and a CO stream. [Figure 9A] FIG. 1 is a schematic diagram of an exemplary electrocatalytic CO2 reduction reactor. [Figure 9B] FIG. 1 is a schematic diagram of an exemplary electrocatalytic CO2 reduction reactor. [Figure 10A] FIG. 1 is a schematic diagram of an exemplary thermal catalytic CO2 reduction reactor. [Figure 10B]FIG. 1 is a schematic diagram of an exemplary thermal catalytic CO2 reduction reactor. [Figure 11A] FIG. 1 is a schematic diagram of an exemplary hydrogen production subsystem. [Figure 11B] FIG. 1 is a schematic diagram of an exemplary hydrogen production subsystem. [Figure 12] FIG. 1 is a schematic diagram of an example CO2 capture subsystem including a liquid sorbent. [Figure 13] FIG. 1 is a schematic diagram of an example CO2 capture subsystem including a solid sorbent. [Figure 14] FIG. 1 is a schematic diagram of a control system (or controller) for a system for producing synthetic fuel from hydrogen and carbon dioxide. [Figure 15] 1 is a flow chart of an example method utilizing an electrocatalytic CO2 reduction reactor to produce synthetic fuels. [Figure 16] 1 is a flow chart of an example method of utilizing a thermal catalytic CO2 reduction reactor to produce synthetic fuels. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0111] This disclosure describes systems and methods for synthesizing fuels ("synthetic fuels") from a dilute CO2 source, such as from the atmosphere or another fluid source having a CO2 content of less than about 1% v / v. CO2 concentrations in the atmosphere are dilute in that they currently range from 400-420 parts per million ("ppm"), or approximately 0.04-0.042% v / v, and less than 1% v / v. These atmospheric concentrations of CO2 are at least an order of magnitude lower than the CO2 concentrations in point source emissions, such as flue gas, which may have CO2 concentrations in the range of 5-15% v / v depending on the emission source.

[0112] When combined with carbon capture, hydrogen produced using renewable energy or using conventional steam-methane reforming, CO2 capture from the atmosphere allows for the production of carbon-neutral synthetic fuels such as gasoline, diesel, and aviation turbine fuels that are compatible with today's fuel and transportation infrastructure. These synthetic fuels may also overcome some of the current limitations of oil and biomass-based biofuels, including, for example, feedstock security, scale limitations, fuel blending constraints, land use, and replacement of food crops. Furthermore, synthetic fuels produced via the methods described herein can compare favorably with other renewable diesel options in that they may have, for example, one or more of higher energy content, higher cetane values, lower NOx emissions, and no sulfur. High cetane synthetic diesel produced via the methods described herein may allow for blending with lower quality fossil stocks.

[0113] The carbon intensity of the synthetic fuels can be particularly reduced when the system uses air as a CO2 feedstock to operate the system and uses renewable zero and / or low carbon power sources. The use of such low carbon intensity synthetic fuels can enable emissions reductions in transportation applications where electricity, biofuels or other low carbon options are not practical, such as powering long-haul vehicles including trucks, airplanes, ships, and trains. Furthermore, low carbon intensity synthetic fuels produced via the methods described herein are likely to be eligible for a number of policy revenue and / or credit programs, including those from the LCFS, RIN, and RED programs.

[0114] The impact of renewable electricity and fuel, for example, used in the oxyfuel appliance on the carbon intensity of the produced synthetic fuel, was demonstrated through an example shown in Table 1. For simplicity, it was assumed that the fuel and electricity demand of the synthetic fuel production system is the main driver of the direct and indirect emissions of the system. Emissions resulting from the combustion of fuel used in the oxyfuel appliance in the system account for the direct emissions, while emissions related to the production, capture or transportation / distribution of fuel / electricity account for the indirect emissions. For 1 megajoule (MJ) of synthetic fuel produced, it was assumed that the oxyfuel process in the synthetic fuel production system utilizes 0.4 MJ of energy, and 0.6 KWh of electricity is used for other operations in the system.

[0115] The values ​​in Table 1 clearly show that electricity generation in coal-fired power plants is carbon intensive and significantly increases the carbon intensity of synthetic fuels, while using renewables such as hydroelectric, solar and wind power can significantly reduce the carbon intensity of the fuel, in some cases down to less than 10g CO2e / MJ fuel.

[0116] [Table 1]

[0117] The carbon intensity of alternative biodiesel ranges from 30-70 gCO2e / MJ for biodiesel, as high as 90-100 gCO2e / MJ for conventional gasoline and diesel. Synthetic fuels produced as described herein can have carbon intensities that are less than half that of typical biofuels, meaning that these synthetic fuels will garner high revenues from market-based emissions programs. Synthetic fuels, such as diesel and gasoline products, are drop-in compatible with current infrastructure and engines and can have energy densities up to about 30 times higher than batteries, as well as land / water usage impacts up to about 100 times lower than biofuels. Because off-the-shelf equipment is selected for most, if not all, of the devices described in the synthetic fuel systems, these systems can be highly scalable and therefore applicable to a range of markets, including the transportation fuel market.

[0118] Referring to Figure 1, an example system 10 shown in Figure 1 includes three subsystems, namely, a CO2 capture subsystem 11 (also referred to herein as a "direct air capture system" or "DAC system") for extracting CO2 molecules from a CO2 feedstock, a hydrogen production subsystem 13 for extracting hydrogen molecules from a hydrogen feedstock, and a hydrocarbon production subsystem 12 for producing synthetic fuel using the hydrogen molecules produced by the hydrogen production subsystem 13 and carbon from the CO2 molecules produced by the CO2 capture subsystem 11. Reference may be made to U.S. Patent Application No. 16 / 472,379, entitled "Method and system for synthesizing fuel from dilute carbon dioxide source," the entire contents of which are incorporated herein by reference.

[0119] With reference to FIG. 1, the CO2 capture subsystem 11 extracts CO2 from a dilute source, such as the atmosphere, and may include equipment such as an air contactor, a gas-liquid contactor, or a gas-liquid contactor of any other design form that contacts the gas with a capture solution or sorbent. As used herein, a "sorbent" refers to a material that causes sorption of a target species. As used herein, "sorption" refers to a process, physical, chemical, or a combination of both, whereby one substance attaches to another substance for a period of time. Examples of specific categories of sorption may include adsorption (the physical attachment or binding of ions and / or molecules to the surface of another material), absorption (the incorporation of one substance in one state - gas, liquid, solid - into another substance in a different state), and ion exchange (the exchange of ions between electrolytes or between an electrolyte solution and a complex). The CO2 capture subsystem 11 may operate with a liquid sorbent (also referred to herein as a "CO2 capture solution"), as described in more detail below with reference to FIG. 12. In some implementations, the CO2 capture subsystem 11 may operate using a solid sorbent, as described in more detail below with reference to FIG.

[0120] The hydrogen production subsystem 13 produces molecular hydrogen from a hydrogen-containing feedstock. The hydrogen-containing feedstock may include hydrogen compounds such as water, methane, or short-chain hydrocarbons, and is typically in a fluid state. In some implementations, as described in more detail below with reference to FIG. 11A, hydrogen may be produced using electrolysis in a water electrolyzer where an electric potential is applied to an electrolyte to extract molecular hydrogen. There are many hydrogen production routes for electrolysis, such as alkaline electrolysis, hydrogen ion exchange membrane (also known as polymer electrolyte membrane (PEM)), electrolytic hydrogen production and fuel cell technologies, and solid oxide electrolysis cell (SOEC) electrolysis. In some implementations, as described in more detail below with reference to FIG. 11B, hydrogen may be produced by steam-methane reforming of a methane-containing feedstock or a combustible gas. Steam-methane reforming utilizes the reaction of methane with water in a reformer via an endothermic reaction to produce hydrogen, carbon monoxide, and CO2. The CO2 product may be captured via CO2 capture subsystem 11 and processed downstream for uses such as synthetic fuel production, sequestration, or enhanced oil recovery.

[0121] The Hydrocarbon Production Subsystem 12 produces synthetic fuel from hydrogen produced by the Hydrogen Production Subsystem 13 and carbon from the CO2 extracted from the atmosphere by the CO2 Capture Subsystem 11. As used herein, "synthetic fuel" includes high quality petroleum products such as transportation fuels or petrochemicals. The terms "synthetic fuel," "fuel synthesis products," "Fischer-Tropsch (FT) fuel," "synfuel," and "solar fuel" are used interchangeably in this disclosure.

[0122] The hydrocarbon production subsystem 12 utilizes fuel synthesis technology (also referred to herein as "pathways") involving the reaction of hydrogen with carbon sourced from atmospheric CO2, with the atmosphere in this configuration being the carbon-containing feedstock. Some pathways use intermediates such as syngas (a mixture of carbon monoxide (CO) and hydrogen (H2)) to produce a "Fischer-Tropsch (FT) crude" that is similar in composition to crude gas oil. As used herein, syngas refers to a mixture of CO and H2 gas, but may contain small amounts of CO2, methane, and water vapor, as well as other trace gases. The hydrocarbon production subsystem 12 includes a CO2 reduction reactor, which can be electrocatalytic or thermocatalytic, to produce CO from the captured CO2 extracted from the atmosphere. The CO2 reduction reactor is described in more detail below with reference to Figures 9A-10B. The FT crude can be refined to yield a final commercially available synthetic fuel, such as synthetic natural gas, liquefied petroleum gas (LPG), gasoline, jet fuel, aviation turbine fuel, or diesel. The refinery process produces refined tail gas and refined crude products. It may be beneficial to use the refined tail gas and refined crude products as reactants or, where possible, to generate thermal energy in other devices of the system 10. The hydrocarbon production subsystem 12 is fluidly coupled to the CO2 capture subsystem 11, as described in more detail below with reference to Figures 2 through 5, and in some configurations disclosed herein, is also fluidly coupled to the hydrogen production subsystem 13 to produce synthetic fuels. In some cases, hydrogen may be provided to the hydrocarbon production subsystem 12 through another source external to the hydrogen production subsystem 13 (e.g., a hydrogen pipeline).

[0123] In some cases, it may be beneficial to remove water from certain process streams to reduce the impact of water on downstream equipment or to improve the concentration or purity of the process stream. Removing water from a stream may be accomplished through chemical or physical means, or through a combination of these means. An exemplary chemical means for removing water is contacting a gaseous stream (e.g., syngas production stream, calciner product gas) with a material, such as CaO, that can react with water to form another product, such as Ca(OH)2, or with some type of desiccant. Another exemplary chemical means for removing water is splitting water into H2 and O2 as part of a hydrogen production unit. Exemplary physical means for extracting water include cooling, condensation, filtration, or membrane separation. A water conduit serves as a form of product conduit containing water, such as steam, and may contain additional gaseous species, such as CO, H2, CO2, and O2. The transfer of materials produced in one subsystem to another subsystem or between units within a subsystem may serve as a material transfer link. Examples of material transfer connections include material transfer through a water conduit, an oxidant conduit, or a fuel conduit.

[0124] While the implementation of the hydrocarbon production subsystem 12 shown in FIG. 1 uses a CO2 to fuel synthesis pathway involving the generation of syngas, the hydrocarbon production subsystem 12 can synthesize fuels using other pathways, including CO2 to fuel synthesis pathways using renewable or low carbon energy sources, such as solar, wind, hydro, geothermal, nuclear, or combinations of these elements. Many of these pathways also utilize syngas as an intermediate component. However, synthetic fuels can also be produced using methanol synthesis from syngas, followed by methanol to gasoline (MTG) conversion. The MTG process uses a zeolite catalyst at approximately 400° C. and 10-15 bar. Methanol is first converted to di-methyl ether (DME), which is then converted to a blend of light olefins. These then react to produce a blend of hydrocarbon molecules.

[0125] The hydrocarbon production subsystem 12 can also use a route where synthetic fuels are produced using a methanol to olefins (MTO) process, which is similar to the MTG process but is optimized to produce olefins first. These are then fed to another zeolite catalyzed process, such as Mobil's Olefins to Gasoline and Distillates (MOGD) process, to produce gasoline. As used herein, the acronym "MTO" refers to the combination of MTO and MOGD. MTG and MTO produce a tighter distribution of carbon chain lengths than Fischer-Tropsch due to their more selective catalysts. This selectivity may reduce the need for post-processing / upgrading and create a more energy efficient conversion route.

[0126] The hydrocarbon production subsystem 12 can also use a route where synthetic fuels are produced by direct hydrogenation. Here, methanol is synthesized directly from CO2 and hydrogen, followed by MTG conversion. If a methanol synthesis process is used, synthetic fuels can then be produced using processes such as methanol to gasoline (MTG) or methanol to olefins (MTO). In yet further implementations, carbon dioxide from lean source capture can be fed directly to a hydrogenation process, combined with hydrogen, and then fed to a methanol-based fuel synthesis process. The above examples are illustrative and do not define implementations of the air-to-fuel processes described herein.

[0127] Table 2 illustrates some exemplary chemical reactions that may occur in the CO2 capture process, the H2 production process, and the hydrocarbon production process, along with the approximate heats of reaction. These pathways suggest how thermal energy and / or materials may be exchanged between the subsystems 11, 12, and 13 that implement these processes.

[0128] [Table 2A]

[0129] [Table 2B]

[0130] At least a portion of the energy (indicated by the black arrows in FIG. 1 ) and / or at least a portion of the fluids (indicated by the white arrows in FIG. 1 ) used by one subsystem can be obtained from another subsystem. In some implementations, water produced by the CO2 capture subsystem 11 and / or by the hydrocarbon production subsystem 12 is used by the hydrogen production subsystem 13 as a hydrogen feedstock. In some implementations, thermal energy produced by the CO2 capture subsystem 11 is used in processes in the hydrocarbon production subsystem 12 or the hydrogen production subsystem 13. In some implementations, thermal energy produced by the hydrocarbon production subsystem 12 is used to preheat a material stream flowing through the CO2 capture subsystem 11. In some implementations, reactions occurring within the CO2 capture subsystem 11 are used to remove water from a material stream in the hydrocarbon production subsystem 12. In some implementations, heat and oxygen produced by the hydrogen production subsystem 13 are used in combustion processes within the hydrocarbon production subsystem 12 and / or the CO2 capture subsystem 11.

[0131] In each of these implementations, it is expected that one or more of the overall system cost-effectiveness, operational efficiency, and operational flexibility may be improved by one subsystem using energy and / or fluids produced by another subsystem rather than obtaining the energy and / or fluids from an external source. Also, the system may be used in applications where it may be difficult to provide an external source of such energy and / or fluids, such as water-scarce locations. Additionally, the system may potentially reduce the carbon intensity of the produced synthetic fuels compared to traditional fossil fuels.

[0132] As mentioned above, thermal energy from one subsystem 11, 12, 13 may be used as input energy by another subsystem 11, 12, 13. The hydrocarbon production subsystem 12 may generate medium heat while performing fuel synthesis (e.g., Fischer-Tropsch about 250-350°C) that may be used by various machines in the system 10. For example, the hydrocarbon production subsystem 12 may include a CO2 reduction reactor that preheats the boiler feed water and a Fischer-Tropsch reactor that preheats the reactor feed stream. The CO2 capture subsystem 11 may also generate high heat (e.g., a calciner - about 850-950°C) that may be used by other process equipment. For example, the CO2 capture subsystem 11 may include a calciner that preheats the feed stream and a slaker that produces steam in a slake reaction. This medium and high heat may also be used to generate power as well as provide steam heat for downstream refining and distillation systems.

[0133] Similarly, fluids produced or released by one subsystem 11, 12, 13 may be used as a feedstock in another subsystem or for other processes. For example, the hydrocarbon production subsystem 12 produces steam (e.g., by a CO2 reduction reactor and a Fischer-Tropsch reactor) and the CO2 capture subsystem 11 produces water (e.g., by a combustion reaction in a calciner) that may be used by various machines in the system 10. For example, water produced by one or more of the subsystems 11, 12, 13 may be used to replace water losses due to evaporation, to produce process materials such as hydrated lime, to wash pellets to remove alkali content, to regenerate the sorbent in a sorbent regenerator to release CO2, to serve as hydrogen feedstock in the hydrogen production subsystem 13, or combinations thereof.

[0134] FIG. 2 is a schematic diagram of an example system 200 for producing synthetic fuel from CO2 in the atmosphere 204. The system 200 utilizes an electrocatalytic CO2 reduction reactor 222 and an autothermal reformer (ATR) 220. In some cases, the system 200 can produce synthetic fuel from CO2 sourced from gas mixtures other than the atmosphere, where other gas mixtures have a CO2 content of less than about 1 vol%. The system 200 includes a CO2 capture subsystem 280, a hydrogen production subsystem 225, and a hydrocarbon production subsystem 282 fluidly coupled to each other. The CO2 capture subsystem 280 extracts CO2 from the atmosphere 204, concentrates the CO2, and produces a captured CO2 stream 254 used in the downstream hydrocarbon production subsystem for fuel synthesis. The hydrogen production subsystem 225 extracts hydrogen molecules from the hydrogen feedstock 202 for hydrocarbon synthesis. In some implementations, the hydrocarbon production subsystem 282 can be fluidly coupled to a hydrogen source (e.g., a hydrogen pipeline) instead of or in addition to the hydrogen production subsystem 225. The Hydrocarbon Production Subsystem 282 uses the hydrogen 258 produced by the Hydrogen Production Subsystem 225 and the captured CO2 254 produced by the CO2 Capture Subsystem 280 to produce synthetic fuel.

[0135] Referring to FIG. 2, the CO2 capture subsystem 280 includes an air contactor 212 that utilizes a CO2 capture solution 246 as a sorbent material to capture CO2 from the atmosphere. Non-limiting examples of CO2 capture solutions include aqueous alkaline solutions (e.g., KOH, NaOH, or combinations thereof), aqueous amino acid salt solutions, non-aqueous amine solutions, aqueous carbonate and / or bicarbonate solutions, phenoxide / phenoxide salts, ionic liquids, non-aqueous solvents, or combinations thereof. In some cases, the CO2 capture solution 246 may include enhancers and / or additives to increase the CO2 uptake rate. Non-limiting examples of enhancers include carbonic anhydrase, amines (primary, secondary, tertiary), and boric acid. Non-limiting examples of additives include chlorides, sulfates, acetates, phosphates, and surfactants.

[0136] Referring to FIG. 2, the CO2 capture solution 246 includes an alkaline aqueous solution for capturing CO2 from the atmosphere. To regenerate the CO2 capture solution 246 and recover the CO2 for downstream use, the CO2 capture subsystem 280 has a regeneration system including the pellet reactor 214, the slaker 216, and the calciner 218. In this example, the input to the air contactor 212 includes air 204 (e.g., ambient air) and the CO2 capture solution 246 from the pellet reactor 214. The CO2 capture solution 246 may be rich in hydroxides (e.g., rich in KOH). The output from the air contactor 212 includes the CO2-containing solution 240 that flows to the pellet reactor 214 and the CO2-depleted air 206 that has a lower CO2 concentration than the air stream 204. The CO2-containing solution 240 may be rich in carbonates (e.g., K2CO3). In this example, the inputs to the pellet reactor 214 include a CO2-containing solution 240 from the air contactor 212 and a calcium hydroxide (Ca(OH)2) stream 244 from the slaker 216. The output from the pellet reactor 214 includes a calcium carbonate (CaCO3) stream 242 flowing to the calciner 218 and a CO2 capture solution 246 flowing to the air contactor 212. In this example, the inputs to the slaker 216 include a water stream 202 and a calcium oxide (CaO) stream 248 from the calciner 218. The output from the slaker 216 includes a calcium hydroxide (Ca(OH)2) stream 244 flowing to the pellet reactor 214. In this example of system 200, the inputs to calciner 218 include natural gas stream 210, oxygen (O2) stream 230a from hydrogen production subsystem 225, CaCO3 242 from pellet reactor 214, and optionally hydrogen (H2) fuel stream 258 from hydrogen production subsystem 225. The output from calciner 218 includes CaO 248, which is provided to slaker 216 and recovered CO2 stream 254. In some cases, oxygen stream 230a is an electrolyzer oxygen stream produced by a water electrolyzer.

[0137] In some implementations, the CO2 capture subsystem 280 may include multiple air contactors 212, multiple pellet reactors 214, and / or multiple slakers 216 to form respective trains / assemblies of equipment. The operations and reactions occurring in exemplary implementations of the CO2 capture subsystem 280 are described in more detail below, for example with reference to FIG. 12. In some implementations, the air contactors 212 of the CO2 capture subsystem 280 may include or utilize different adsorbents to capture CO2 from the atmosphere and / or different regenerators to capture the CO2 as the captured CO2 stream 254. Other configurations of the CO2 capture subsystem 280 are possible. Some example embodiments of alternative CO2 capture subsystem 280 are described in more detail below.

[0138] Although each of the aforementioned devices is shown diagrammatically as being an element of the CO2 capture subsystem 280 in FIG. 2, in some embodiments each device is independent and may be located relatively close to or relatively far from another device. For example, it may be beneficial to locate the calciner 218 near a particular device that is a component of the hydrocarbon production subsystem 282. In some embodiments, synergistic and unexpected results may result from locating certain elements or devices relatively close to each other, since a smaller distance between devices may reduce energy requirements for gas compression and reduce friction or heat losses in a flowing heat exchange medium (e.g., steam, cooling water systems, etc.). In some implementations, elements or devices are relatively close when the distance between different elements or devices is about 250 meters or less. The reduction in energy requirements and losses may significantly reduce operating costs.

[0139] In some implementations of the example shown in FIG. 2, the recovered CO2 stream 254 is sent to the CO2 purification and compression device 238 before flowing to the hydrocarbon production subsystem 282. In some embodiments, one or more of the CO2 purification and compression devices 238 may be located within the battery limit of the CO2 capture subsystem 280, within an auxiliary process area, between the CO2 capture subsystem 280 and the hydrocarbon production subsystem 282, or within the battery limit of the hydrocarbon production subsystem 282. The battery limit is an area that defines the boundary within which the equipment of a particular system is located. In an exemplary implementation, the CO2 purification and compression device 238 can receive the recovered CO2 stream 254 from the CO2 capture subsystem 280. The CO2 purification and compression device 238 functions to remove at least some impurities from the recovered CO2 stream 254 to achieve a recovered CO2 feed stream 256 that is substantially free of contaminants. In some cases, the recovered CO2 feed stream is at least 99 wt% CO2. Examples of impurities may include oxygen, inert gases (such as nitrogen and argon), water vapor, or combinations thereof. In some cases, the water vapor removed from the recovered CO2 feed stream 254 by the CO2 purification and compression unit 238 may be sent to a water treatment facility or another unit requiring water as an input stream. The CO2 purification and compression unit 238 may include a pressure swing absorber, a cryogenic distillation unit, a membrane separation unit, a single or multi-stage compression train, and a water knockout, or combinations thereof. The recovered CO2 feed stream 256 is sent to the hydrocarbon production subsystem 282.

[0140] Hydrogen is required to produce synthetic fuel according to the present disclosure. In an exemplary implementation, the hydrogen production subsystem 225 includes or is a water electrolyzer that electrolyzes water 202 to form electrolytic oxygen 230a (simply referred to herein as "oxygen stream 230a") and hydrogen stream 258. At least a portion of the oxygen stream 230a can be sent to the calciner 218 for generating thermal energy for calcination via oxy-combustion. In another possible implementation, the hydrogen production subsystem 225 includes or is a steam-methane reformer that reacts methane CH4 with water in an endothermic reaction to produce syngas and utilizes a water-gas shift reaction to produce primarily hydrogen 258. An example embodiment of the hydrogen production subsystem 225 is described in more detail below with reference to Figures 11A and 11B. In an exemplary implementation, at least a portion of the oxygen 230a and hydrogen 258 produced by the water electrolyzer of the hydrogen production subsystem 225 are sent to the hydrocarbon production subsystem 282. A portion of the oxygen 230a from the water electrolyzer is compressed and sent to the autothermal reformer 220. In some implementations, the water 202 includes or is a steam stream that is supplied to the water electrolyzer or other devices in the system 200.

[0141] In an exemplary implementation, the CO2 capture subsystem 280 includes a calciner 218 and the hydrogen production subsystem 225 includes a water electrolyzer. In some examples, the water electrolyzer may include a polymer electrolyte membrane (PEM) or a solid oxide electrolysis cell (SOEC). In some embodiments, the system 200 may utilize the oxygen O2 stream 230a from the water electrolyzer to oxy-fire the calciner 218. For example, the oxygen 230a from the water electrolyzer may be compressed and used as a feed stream to the calciner 218. In some embodiments, the CO2 capture subsystem 280 and the calciner 218 may be oxy-fired and may operate more efficiently by using substantially pure oxygen obtained from the water electrolyzer for combustion.

[0142] In some embodiments, the system 200 can utilize partial or complete replacement of natural gas 210 with H2 or H2-mixtures as fuel for the calciner 218. A portion of the hydrogen 258 from the hydrogen production subsystem 225 can be used to provide thermal energy by reaction with oxygen 230a in the calciner 218. For example, a portion of the hydrogen 258 can be blended with the natural gas 210 and combusted with oxygen 230a in the calciner 218 to generate heat for the calcination reaction. For example, a hydrogen 258 only stream can be oxidized in the calciner 218 to generate heat. By using hydrogen 258 as fuel for the calciner 218, the need for natural gas 210 can be reduced or eliminated, which can reduce the overall carbon intensity of the system 200.

[0143] 2, the hydrocarbon production subsystem 282 includes an electrocatalytic CO2 reduction reactor 222, an autothermal reformer 220, a Fischer-Tropsch (FT) reactor 224, a purification unit 226, and a distillation unit 228, which are fluidly coupled to one another. As with the equipment of the CO2 capture subsystem 280, the aforementioned equipment is shown diagrammatically as an element of the hydrocarbon production subsystem 282, but may benefit from being located in relative proximity to other equipment, thereby reducing energy requirements and friction or heat losses, thereby reducing operating costs.

[0144] Carbon monoxide (CO) is the main reactant in the hydrocarbon production subsystem because it provides the carbon atoms necessary to form the hydrocarbons that assemble synthetic fuels. Commercially available FT reactors are not suitable for directly converting CO2 to hydrocarbons, so they require that CO2 be first converted to a molecule that can be polymerized, such as CO. Some electrocatalytic CO2 reduction reactors operate at high temperatures to function efficiently. Unlike conventional approaches to form CO and / or syngas from CO2, electrochemical approaches that implement electrocatalytic reactors are electrically powered and do not use burners, thus avoiding the need to burn fossil fuels to heat the reactor to its operating temperature. Thus, the carbon intensity of an electrocatalytic CO2 reduction reactor can be lower than that of conventional reactors that require combustion.

[0145] The electrocatalytic CO2 reduction reactor 222 receives the recovered CO2 feed stream 256 from the CO2 capture subsystem 280. The electrocatalytic CO2 reduction reactor 222 produces carbon monoxide (CO) 262 and oxygen 230b by performing an electrochemical reduction reaction (CO2 → CO + 1 / 2O2) on a catalyst to CO2 in the recovered CO2 feed stream 256. In some cases, the electrocatalytic CO2 reduction reactor 222 can utilize one or more of the reactions listed in Table 2 (see reactions listed for the electrocatalytic CO2 reduction reactor). In some implementations, the electrocatalytic CO2 reduction reactor 222 can include a solid oxide electrolysis cell, a molten carbonate electrolysis cell, a polymer electrolyte membrane fuel cell, a low-temperature electrolysis cell, or a combination thereof. Some possible configurations of the electrocatalytic CO2 reduction reactor 222 are described in more detail below with reference to Figures 9A and 9B. The oxygen 230b produced by the electrocatalytic CO2 reduction reactor 222 can be used in the autothermal reformer 220, which can reduce or eliminate the need for other oxygen sources, such as an air separation unit (ASU). In some embodiments, the system 200 can be used to oxy-combust the calciner 218, utilizing the oxygen O2 stream 230a from the water electrolyzer and / or the CO2 reduction reactor 222.

[0146] Referring to FIG. 2, the FT reactor 224 receives a CO stream 262 from the electrocatalytic CO2 reduction reactor 222 and a hydrogen stream 258 from the hydrogen production subsystem 225. The FT reactor 224 also receives a synthesis gas 260 (consisting primarily of CO and hydrogen) from the ATR 220. The FT reactor 224 reacts the hydrogen and CO in the feed stream in a polymerization reaction (also referred to as "FT synthesis") to form FT tail gas 264 and FT crude 268 streams, which, when combined, contain a multi-component mixture of linear and branched hydrocarbons ranging from gas, liquid, and wax, as well as oxygenated products. In some implementations, the FT reactor 224 may operate at 200° C. to 350° C. and 10 bar to 60 bar. The FT synthesis process produces a combination of light and heavy end hydrocarbons, as defined below. In some embodiments, a portion of the FT tail gas 264 and FT crude 268 may have low aromaticity and low to zero sulfur content. The products of the FT reactor 224 may also include linear paraffins and olefins, i.e.: hydrogen and low molecular weight hydrocarbons (C1-C4), medium molecular weight hydrocarbons (C4-C13) and high molecular weight hydrocarbons (C13+). Hydrogen and low molecular weight hydrocarbons may be used to make combustion fuels, polymers and fine chemicals. Medium molecular weight hydrocarbons, for example with a composition similar to gasoline, may be used as feedstock for lubricants and diesel fuel. High molecular weight hydrocarbons may be waxes or paraffins and may be feedstock for lubricants and may be further refined or hydrocracked into diesel fuel.

[0147] Generally, the FT tail gas stream 264 comprises primarily light ends hydrocarbons, and the FT crude stream 268 comprises primarily heavy ends hydrocarbons. The FT reactor 224 may also produce water 236 as a product of the FT synthesis reaction. Some or all of the water 236 may be treated in a water treatment facility and / or recycled for use in other units in the system 200.

[0148] Light end hydrocarbons may be considered to be hydrocarbons that exist in the gas phase at standard room temperature and pressure. Light end hydrocarbons typically include short chain hydrocarbons (C1-C4) having relatively low molecular weights. For example, methane, butane, and propane are considered to be light end hydrocarbons. In some cases, a gaseous synthetic fuel stream containing light end hydrocarbons may include hydrogen. The hydrogen may be separated using a membrane and separately recycled as a feedstock to other units, such as the FT reactor 224. After purification, some synthetic fuel products that may be formed from the light end hydrocarbons include synthetic natural gas and liquefied petroleum gas (LPG).

[0149] The FT reactor 224 also produces heavy end hydrocarbons. Heavy end hydrocarbons may be considered as hydrocarbons that exist in a liquid phase (e.g., naphtha, distillate) or solid phase (e.g., wax) under standard room temperature and pressure. Heavy hydrocarbons typically include medium chain hydrocarbons (C4-C13) having a medium molecular weight and long chain hydrocarbons (C13+) having a high molecular weight. After refining, some synthetic fuel products that may be formed from the heavy end hydrocarbons include gasoline, diesel, jet fuel, aviation turbine fuel, and wax. The Fischer-Tropsch fuel synthetic products described herein may be further refined into specific fuel types that meet the requirements of certain fuel standards (e.g., standard specifications for fuels as set forth by ASTM). In some cases, the synthetic fuels may be further refined into petrochemicals or petroleum products such as plastics or polymers.

[0150] Referring to FIG. 2, the FT tail gas 264 contains primarily gaseous light-ended hydrocarbons (C1-C4), which may be useful inputs to devices that require combustion or oxidation to carry out a reaction. One such device is the ATR 220. The ATR 220 includes a vessel housing a burner, a combustion chamber, and a catalytic reaction region. The ATR 220 may include at least one inlet that receives a combustible gas, oxygen 230, and steam 202. The combustible gas may be a methane-containing feedstock, such as the FT tail gas 264. The combustible gas may be preheated by mixing steam 202 and oxygen in a burner, and the reaction may be initiated in the combustion chamber of the ATR 220. The catalytic reaction region may include a catalyst bed supporting a nickel-containing catalyst that converts the reactants to synthesis gas.

[0151] In an exemplary implementation, the ATR 220 functions to convert the FT tail gas 264 and the purified tail gas 266 to syngas 260. The ATR 220 receives the FT tail gas 264, steam 202, and oxygen streams 230a, 230b. In some implementations, as shown in FIG. 2, the ATR 220 receives oxygen streams 230a, 230b from both the electrocatalytic CO2 reducer 222 and the hydrogen production subsystem 225. In some cases, the ATR 220 may receive oxygen 230 from only one of the electrocatalytic CO2 reducer 222 or the hydrogen production subsystem 225. The ATR 220 oxidizes the FT tail gas 264 with oxygen 230a, 230b in the presence of steam 202 to produce syngas 260 for FT synthesis in the FT reactor 224 via reforming and shift reactions as described in Table 2. In some implementations, other light end components of the FT tail gas 264 may be partially converted to methane in the combustion chamber of the ATR 220 and then reformed to syngas 260 in the catalytic reaction zone of the ATR 220. The syngas 260 may be sent to the FT reactor 224 to close the FT tail gas recycle loop by producing FT crude 268 and FT tail gas 264.

[0152] In other configurations, such as systems 400 and 500 of Figures 4 and 5, respectively, the FT tail gas and / or purified tail gas are instead sent to a calciner and then combusted to CO2. In some cases, an increase in the capacity of the hydrogen production subsystem may be required to accommodate the additional CO2 resulting from the tail gas being sent from the hydrocarbon production subsystem to the CO2 capture subsystem (via the calciner). In some cases, it may be economical to return the recirculated tail gas via the ATR to the hydrocarbon production subsystem to produce syngas, as the capacity of the hydrogen production subsystem is less likely to be affected.

[0153] The FT crude 268 mainly comprises heavy end hydrocarbons that are liquid or solid. In the illustrated implementation of FIG. 2, the FT crude 268 is sent to a refinery or refinery that includes multiple refinery units 226 and / or distillation units 228, where the FT crude 268 is subjected to purification and separation. The refinery units 226 perform processes such as hydrocracking, hydrotreating, hydroisomerization, fluid catalytic cracking, thermal cracking, reforming, oligomerization, or combinations thereof to obtain petroleum products. Non-limiting examples of process units that make up the refinery (i.e., the refinery units 226 and the distillation columns 228) include process units that include atmospheric distillation units, vacuum distillation units, hydrocrackers, thermal crackers, catalytic crackers, reformers, hydrotreaters, cokers, visbreakers, or alkylators. These process units convert the FT crude 268 into multiple refinery products 270 and refinery tail gas 266. Similar to FT tail gas 264, refined tail gas 266 contains methane and other light ends and therefore may be oxidized in ATR 220 to produce synthesis gas. Refined products 270 may include primarily liquid and solid petroleum products such as naphtha, gasoline, kerosene, jet fuel, diesel, base oil, wax, and other chemicals. Refined products 270 are sent to distillation unit 228 where they are separated through distillation into individual or blended products such as liquid fuels 232 and chemicals 234. Non-limiting examples of liquid fuels 232 may include naphtha, gasoline, kerosene, jet fuel, diesel, fuel oil, or combinations thereof.

[0154] In the implementation of the hydrocarbon production subsystem 282 of FIG. 2 , the FT crude 268 is sent to the refinery 226 and from there to the distillation unit 228. In other possible implementations, the FT crude 268 may first be sent to the distillation unit 228 for separation before undergoing the refining process in the refinery 226. For example, the FT crude 268 may be sent to the atmospheric distillation unit 228 to separate the FT crude 268 into refined tail gas 266, naphtha, distillate, and residue / wax. The naphtha, distillate, and residue / wax may then be subjected to refining processes such as hydroisomerization, fluid catalytic cracking, thermal cracking, reforming, oligomerization, or combinations thereof to produce synthetic fuel products including liquid fuels 232 and chemicals 234. The purified tail gas 266 can flow to the ATR 220, which can oxidize methane CH4 in the purified tail gas 266 using an oxygen 230 stream in the presence of steam 202 to produce synthesis gas 260 for FT synthesis.

[0155] The use of the FT tail gas 264 from the FT reactor 224 and the purified tail gas 266 from the purification unit 226 in the ATR 220 helps reduce carbon emissions by recycling carbon atoms back into the system 200 that would otherwise be released to the atmosphere. Additionally, in some embodiments, the incineration and venting of the FT tail gas 264 and the purified tail gas 266 may be reduced or eliminated, which reduces the overall carbon intensity of the system 200. The FT tail gas 264 and the purified tail gas 266 (referred to herein as "tail gas") comprise gaseous hydrocarbons primarily in the C1-C4 range and may be reformed in the autothermal reformer 220 using oxygen and steam to produce the synthesis gas 260. In some implementations, the ATR 220 may oxidize methane in the FT tail gas 264 and / or the purified tail gas 266 using oxygen 230 in the presence of both steam 202 and CO2 to produce the synthesis gas 260. For example, a portion of the recovered CO 2 feed stream 256 can be sent to the ATR 220 , which can oxidize the tail gas in the presence of the recovered CO 2 feed stream 256 and steam 202 to produce synthesis gas 260 .

[0156] The hydrocarbon production subsystem 282 produces liquid fuel 232 and chemicals 234. Non-limiting examples of liquid fuel 232 may include jet fuel, aviation turbine fuel, diesel, or gasoline. Compared to similar products produced from traditional fossil fuels, liquid fuel 232 tends to have reduced contaminant content, such as sulfur, SOx, NOx, aromatic hydrocarbons, and particulate matter, because liquid fuel 232 is primarily comprised of paraffins, which burn cleaner (producing less particulate matter and hazardous pollutants). Because liquid fuel 232 of system 200 is relatively pure, it is more desirable as a transportation fuel source. Furthermore, synthetic fuels derived from atmospheric CO2, such as those that may be produced by system 200, tend to have fewer impurities to deal with in intermediate processing steps, because atmospheric CO2 generally does not have the same impurities as traditional carbon sources, such as natural gas, biomass, or coal.

[0157] In some embodiments, the system 200 can utilize heat integration between the CO2 capture subsystem 280 and the hydrocarbon production subsystem 282. For example, steam generated from the FT reactor 224 and / or the purification unit 226 can be used in the CO2 capture subsystem 280. In some embodiments, the hydrocarbon production subsystem 282 can produce high pressure steam and / or intermediate pressure steam that can be utilized in the CO2 capture subsystem 280. For example, the FT reactor 224 can produce high pressure steam. The steam can be used directly or indirectly (e.g., by using waste heat recovery methods) to heat process streams, evaporate water from the process streams, provide freeze protection, and preheat and / or dry materials (e.g., CaCO3 solids or CaO solids) in the CO2 capture subsystem 280. Utilizing waste heat can reduce the carbon intensity of the system 200 and its products, such as liquid fuels 232 and chemicals 234. Heat integration can improve the economics of the process by reducing energy needs and associated costs.

[0158] In some aspects, heat integration can also improve the functionality of certain process equipment and materials. For example, heating the CO2 capture solution 246 can improve capture kinetics, thereby allowing more CO2 to be captured from the air flowing through the air contactor 212 at a given air velocity. For example, heating the discharge of the pellet reactor 214 can improve the performance of downstream separation equipment, such as centrifuges and filtration equipment. In some embodiments, this can be accomplished by using waste heat to warm the pellet reactor discharge stream, the slip stream from the pellet reactor 214 or the filter / clarifier, and / or the feed stream to the filter / clarifier. For example, warm water has characteristics that allow for faster settling characteristics, i.e., lower density and viscosity, as shown by the following Stokes' law, which relates the properties (density, viscosity) of a liquid to the settling velocity of a solid:

[0159]

number

[0160] where V is the velocity at which a spherical particle settles out of suspension, and ρ p is the mass density of the fluid spherical particle (kg m -3 ) and ρ f is the mass density of the fluid (kg m -3 ), and g is the acceleration due to gravity (m sec -1 ), R is the particle radius (m), and μ is the fluid viscosity (kg m -1 ·Seconds -1 ).

[0161] In some embodiments, the system 200 can utilize process streams from the cooling water system and the CO2 capture subsystem 280 to cool other devices in the system 200. For example, devices in the hydrogen production subsystem 225 and the hydrocarbon production subsystem 282 generate heat, which can be transferred to the cooling water that constitutes a closed cooling water loop. The cooling water loop can be common to multiple devices across the CO2 capture subsystem 280, the hydrogen production subsystem 225, and / or the hydrocarbon production subsystem 282, thereby providing an integrated approach to serving the cooling needs of the system 200. For example, the CO2-containing capture solution 240 flowing from the air contactor 212 region can be sent to a heat exchanger where heat is transferred from the cooling water to the CO2-containing capture solution 240. The CO2-containing capture solution 240 can then flow to the pellet reactor 214. Thus, in some embodiments, the CO2 capture subsystem 280 operation can provide an opportunity to meet cooling demands in the subsystems that make up the system 200. This differs from conventional thermal management approaches, where cooling systems for equipment operation external to a particular subsystem (e.g., a CO2 capture subsystem) are typically separate. By integrating cooling systems across system 200, capital and operating costs, as well as the carbon intensity of system 200, may be reduced.

[0162] In some embodiments, in cold climates, supplemental heating can be provided to the capture solution (Stream 646, Stream 640) by utilizing waste heat from other units in system 600, such as the calciner 618, the CO2 reduction reactor, the autothermal reformer, the FT reactor, the purification unit, or combinations thereof. Heat can be transferred from one process unit to another via a common cooling water system.

[0163] In some embodiments, system 200 can generate electricity / energy using waste heat from the hydrocarbon production subsystem 282. For example, the waste heat from the hydrocarbon production subsystem 282 can be used to generate power by utilizing devices such as a heat recovery steam generator that uses the thermal energy to produce steam that is used in a steam turbine generator to produce electricity. By using waste heat from the process to produce electricity, the need for imported electricity for the process can be reduced, thereby reducing the capital and operating costs, as well as the carbon intensity of system 200.

[0164] In some embodiments, the system 200 can utilize heat integration between the CO2 capture subsystem 280 and the hydrogen production subsystem 225. For example, the hydrogen production subsystem 225 can include a water electrolyzer or a steam-methane reformer that produces heat that can be used in the CO2 capture subsystem 280. The CO2 capture subsystem 280 has multiple uses for using low-grade waste heat, such as to heat process streams and improve the performance of process equipment. For example, heating a slurry stream can improve the performance of filters and / or centrifuges. Using waste heat from the hydrogen production subsystem 225 can reduce the carbon intensity of the system 200.

[0165] In some embodiments, the system 200 can consolidate water treatment for the hydrogen production subsystem 225 and the CO2 capture subsystem 280. In some embodiments, the hydrogen production subsystem 225 can include a water electrolyzer, and the water source (e.g., domestic water, groundwater, wastewater, etc.) is purified in a water treatment facility or purification system before being fed to the water electrolyzer. The purification process can reduce fouling or degradation of the water electrolyzer. For example, the purification process can remove chloride ions and produce brine as a by-product. The brine by-product can then be recovered and used as a process water constituent in the CO2 capture subsystem 280. For example, the brine can be introduced to the CO2 capture subsystem 280 via the saturator 216. Using the by-product brine can reduce the net water demand of the process and reduce water disposal costs while consolidating water treatment for the CO2 capture subsystem 280 and the hydrogen production subsystem 225.

[0166] In some embodiments, the system 200 can utilize the water 236 produced by the FT reactor 224 in the CO2 capture subsystem 280. At least a portion of the produced water 236 from the FT reactor 224 can be recovered and treated to meet the water quality requirements for the CO2 capture subsystem 280. For example, after treatment, the water 236 can be reused as a water constituent in the CO2 capture subsystem 280 where it can be used in the slaking reaction in the slaking reactor 216 and / or used to wash the calcium carbonate CaC03 solids discharged from the pellet reactor 214.

[0167] In some embodiments, the system 200 may utilize the water 236 produced by the FT reactor 224 in the hydrogen production subsystem 225. For example, at least a portion of the produced water 236 from the FT reactor 224 may be recovered and treated to meet water quality requirements for the water electrolyzer of the hydrogen production subsystem 225. After treatment, the water 236 may be used as a feedstock to produce hydrogen 258 and oxygen 230 through water electrolysis instead of or in addition to the water 202. Using the produced water 236 elsewhere in the system 200 may reduce the overall water demand of the system 200 and reduce water disposal costs.

[0168] In some embodiments, the hot exhaust stream from the calciner 218 exhaust stream can preheat the recovered CO2 feed stream 256 that is fed to the CO2 reduction reactor 222. For example, a hot gas-to-gas heat exchanger can be used to exchange heat between the calciner 218 exhaust stream and the recovered CO2 feed stream 256 that is fed to the CO2 reduction reactor 222. In some cases, waste heat from the hydrogen production subsystem 225 (which can include a steam-methane reformer), the CO2 reduction reactor 222, the ATR 220, or a combination thereof can be used to preheat the recovered CO2 feed stream 256.

[0169] Some electrocatalytic CO2 reduction reactors 222 operate at high temperatures (e.g., about 600°C to 900°C) because certain electrochemical properties of these reactors (e.g., current density, cell potential, etc.) are desirable at high temperatures. For those electrocatalytic CO2 reduction reactors 222 operating at high temperatures, the energy load required from the electrocatalytic CO2 reduction reactor 222 can be reduced by preheating the recovered CO2 feed stream 256 (e.g., heat transferred from the calciner 218) before it is fed to the electrocatalytic CO2 reduction reactor 222. For example, the recovered CO2 feed stream 256 can be at room temperature to 100°C and then gradually heated via a preheating step using a heat exchanger.

[0170] In some embodiments, the system 200 can recover heat from the product gas (e.g., CO2 62 and oxygen 230) of the CO2 reduction reactor 222 to preheat the recovered CO2 feed stream 256. For example, at least one stage of heat exchange or at least one heat exchanger can be used to preheat the recovered CO2 feed stream 256. The first stage can include a metal heat exchanger that operates at a cooler temperature, and the second stage can include a ceramic heat exchanger due to metal dusting that can occur when dealing with hot syngas and / or CO2 62. The ceramic heat exchanger can reduce or eliminate metals that come into contact with the process stream, thus eliminating metal dusting. In some embodiments, recovering heat from the hot syngas and / or CO2 62 to preheat the recovered CO2 feed stream 256 can reduce the energy demand and operating costs of the system 200.

[0171] In some embodiments, the system 200 can recover heat from the CaO248 to preheat the recovered CO2 feed stream 256 that is fed to the CO2 reduction reactor 222. For example, the recovered CO2 feed stream 256 can be preheated while in contact with the CaO248 to exchange heat in the cooling train of the calciner 218, thereby cooling the CaO248. In some embodiments, a high temperature baghouse installed downstream of the calciner 218 can reduce the amount of dust carried over from the calciner 218 to the CO2 reduction reactor 222. To manage the large pressure difference between the recovered CO2 feed stream 256 and the pressure of the CaO248 multi-stage loop, seals can be utilized to create a pressure difference through a pressure drop across a fluid bed. Recovering heat from the cooled CaO248 to preheat the recovered CO2 feed stream 256 can also reduce the energy demand and cost of the system 200. Such integration efficiencies are typically not available in conventional systems because a reformer such as the CO2 reduction reactor 222 is typically not co-located with another process unit, such as the calciner 218, that discharges solids at the temperatures at which the CO2 reduction reaction occurs.

[0172] In some embodiments, system 200 can utilize process facility layout design to facilitate heat and material integration. For example, the land footprint of the hydrocarbon production subsystem 282 can be smaller compared to the land footprint of the CO2 capture subsystem 280. The process equipment of system 200 can be strategically located to enjoy the benefits of heat and material integration and reduce the overall facility footprint. For example, the CO2 reduction reactor 222 and the calciner 218, both operating in a similar high temperature range (800-950°C), can be co-located (e.g., relatively close, such as within approximately 250 meters to the minimum distance permitted by legal requirements for electrical installations in hazardous locations) to allow for close heat integration and minimize heat losses and pressure drops. Co-location of the calciner 218 and the hydrocarbon production subsystem 282 is feasible due to the integration of the DAC and fuel synthesis processes.

[0173] In some embodiments, the system 200 can combine the compression needs of one or more subsystems by utilizing a multi-function compressor. For example, the FT recycle compression of the hydrocarbon production subsystem 282 can be combined with the CO2 compression and purification unit 238. The syngas 260 flowing from the ATR 220, the recovered CO2 stream 254 flowing from the CO2 capture subsystem 280, and the hydrogen 258 flowing from the hydrogen production subsystem 225 may each need to be compressed before flowing to their respective downstream devices. Instead of utilizing separate compressors to compress each of these streams, a single compressor assembly 239 can be used. The single compressor assembly 239 can have multiple stages. For example, the electrocatalytic CO2 reduction reactor 222 can only convert a portion of the recovered CO2 feed stream 256 to CO2 62. In some cases, the unconverted CO2 can be recycled to the inlet of the electrocatalytic CO2 reduction reactor 222 and may need to be compressed. The CO2 recycle can be fed to the compressor assembly 239 and combined with the captured CO2 feed stream 256 at the appropriate compressor stage. In implementations where the streams that require compression remain separate from the captured CO2 feed stream 256, the compressor assembly 239 can include an integral gear compressor, and they can be compressed in separate stages of the integral gear compressor. In another implementation where the streams remain separate from the captured CO2 feed stream 256, the compressor assembly 239 can include a multi-stage compressor assembly, where a first compressor is driven by the same motor shaft as a second compressor (e.g., the main CO2 compressor), and the captured CO2 feed stream 256 is compressed in the first compressor, while the other streams are compressed in the second compressor. In some cases, this can result in lower capital costs, since one large compressor can be less expensive than two individual smaller compressors.

[0174] Other configurations of the system for producing synthetic fuels from atmospheric CO2 are possible. In some cases, a thermal catalytic CO2 reduction reactor may be used instead of the electrocatalytic CO2 reduction reactor 222, which may require some differences in the process stream flows compared to the system 200 of FIG. 2. In some implementations, the thermal catalytic CO2 reduction reactor may utilize an improved gas-to-liquid platform that can convert CO2 and hydrogen to syngas through a process known as reverse water gas shift (RWGS) before sending the syngas to the FT reactor to produce synthetic hydrocarbons. This allows for the integration of the DAC (e.g., CO2 capture subsystem 280) with developed FT technology, which may lead to easier scale-up of the system and methods for producing synthetic fuels from DAC-derived CO2 sources.

[0175] 3 is a schematic diagram of an example system 300 for producing synthetic fuels from atmospheric CO2 utilizing a thermal catalytic CO2 reduction reactor 322 and an autothermal reformer 320. The system 300 includes a CO2 capture subsystem 380, a hydrogen production subsystem 325, and a hydrocarbon production subsystem 382, ​​fluidly coupled to each other. The descriptions, features, reference numbers, and associated advantages provided above of the CO2 capture subsystem 280, the hydrogen production subsystem 225, the hydrocarbon production subsystem 282, and other similar elements of the system 200 of FIG. 2 apply mutatis mutandis to the CO2 capture subsystem 380, the hydrogen production subsystem 325, the hydrocarbon production subsystem 382, ​​and other similar elements, respectively, of the system 300 of FIG.

[0176] In an exemplary implementation of the system 300 of FIG. 3, the hydrogen production subsystem 325 flows the hydrogen stream 358 to the thermal catalytic CO2 reduction reactor 322 and the FT reactor 324. The thermal catalytic CO2 reduction reactor 322 can react a variety of feedstocks, including but not limited to hydrogen, CO2, methane, natural gas, oxygen, steam, light end hydrocarbons, and biomethane, to produce synthesis gas. In some cases, the thermal catalytic CO2 reduction reactor 322 can utilize one or more of the reactions listed in Table 2 (see reactions listed for the thermal catalytic CO2 reduction reactor). With reference to FIG. 3, the thermal catalytic CO2 reduction reactor 322 produces a CO stream 362 and steam 336 by performing the RWGS reaction (CO2+H2⇔CO+H2O) on the hydrogen 358 and the recovered CO2 feed stream 357 from the CO2 capture subsystem 380. In some implementations, the thermal catalytic CO2 reduction reactor 322 includes a catalyst bed in a packed bed reactor, a multi-tubular fixed bed reactor, or a combination thereof. In some implementations, the CO2 thermal catalytic reduction reactor 322 may produce CO and H2 via one or more of the reactions described in Table 2 above, and may receive a hydrocarbon (e.g., methane) stream as a feedstock. The thermal catalytic CO2 reduction reactor 322 may operate at high temperatures, such as above 500°C, at either atmospheric pressure or higher pressures up to 200 bar, and may incorporate a variety of catalysts to participate in the main reactions. An embodiment of the thermal catalytic CO2 reduction reactor 322 is described in more detail below with reference to Figures 10A and 10B. In contrast to the electrocatalytic CO2 reduction reactor, the thermal catalytic CO2 reduction reactor 322 produces steam 336 (i.e., water) instead of oxygen.

[0177] In some embodiments, the system 300 can utilize water 336 from the thermal catalytic CO2 reduction reactor 322 as a process water constituent in the CO2 capture subsystem 380. The water 336 can be recovered and treated before being used in the CO2 capture subsystem 380. Water treatment can include removing dissolved species (gas or particulates) and balancing acidity. In some embodiments, the produced water 336 can be reused elsewhere in the system 300 to reduce overall water demand and water disposal costs.

[0178] The thermal catalytic CO2 reduction reactor 322 flows CO 362 to the FT reactor 324. The FT reactor 324 receives hydrogen 358 from the hydrogen production subsystem 325 and reacts the CO 362 with the hydrogen 358 in a polymerization reaction to form FT tail gas 364 and FT crude 368. The FT crude 368 flows to the purification unit 326 which processes the FT crude 368 into purified tail gas 366 and a number of purified products 370. With reference to FIG. 2, the descriptions, features, reference numbers, and associated advantages of the FT reactor 224, FT tail gas 264, FT crude 268, refinery 226, refinery tail gas 266, refinery product 270, liquid fuel 232, and chemicals 234 provided above apply mutatis mutandis to the FT reactor 324, FT tail gas 364, FT crude 368, refinery 326, refinery tail gas 366, refinery product 370, liquid fuel 332, and chemicals 334, respectively, of FIG. 3.

[0179] In some cases, if light hydrocarbons are contaminating the feed, the thermal catalytic CO2 reduction reactor 322 may be susceptible to coke formation. Coke formation can occur when hydrogen atoms are removed from the hydrocarbons, forming a layer of elemental carbon. Coke formation is problematic because it can reduce the active area of ​​the catalyst bed in the thermal catalytic CO2 reduction reactor 322, thereby reducing the efficiency of CO2 conversion to syngas. An example reaction that can form coke is 3C2H4→2C+2C2H6.

[0180] In some cases, the ATR 320 can reduce coke formation in the thermal catalytic CO2 reduction reactor 322 and produce additional synthesis gas (i.e., in addition to the hydrogen 358 formed by the hydrogen production subsystem 325 and the CO 362 formed by the thermal catalytic CO2 reactor 322). The FT tail gas 364 and the purified tail gas 366 (referred to herein simply as "tail gas 364, 366") contain primarily light end hydrocarbons (C1-C4) and flow to the ATR 320. In the ATR 320, in the presence of steam 302 and oxygen 330, at least a portion of the tail gas 364, 366 can be reformed to synthesis gas 361 (CH4+1 / 2xO2+yCO2+(1-xy)H2O←→(y+1)CO+(3-xy)H2), thereby producing additional synthesis gas. The synthesis gas 361 can then flow to the thermal catalytic CO2 reduction reactor 322. For the ATR 320, it is optional to react the tail gas 364, 366 to form syngas 361 and flow the syngas 361 to the thermal catalytic CO2 reduction reactor 322, but alternatives may be to send the tail gas directly to the thermal catalytic CO2 reduction reactor 322, which may result in coke formation, or to incinerate / vent the tail gas 364, 366 to the atmosphere. Additionally, the light end hydrocarbons in the tail gas 364, 366 are generally petroleum products with lower value than the target product such as liquid fuel 332, but this allows them to potentially be processed indirectly to liquid fuel via syngas formation as an intermediate step. In some cases, the syngas 361 can flow directly from the ATR 320 to the FT reactor 324, thereby bypassing the thermal catalytic CO2 reduction reactor 322.

[0181] The thermal catalytic CO2 reduction reactor 322 can receive thermal energy input from electrical heating or by combustion of a fuel. For example, thermal energy can be generated from burning hydrogen 358, natural gas 310, or a combination thereof.

[0182] In some embodiments, the thermal catalytic CO2 reduction reactor 322 can operate in an intermediate pressure range (about 50-400 psi) to simplify reactor design and operation. For example, instead of compressing the feed to the thermal catalytic CO2 reduction reactor 322 to a high pressure range (about 400-500 psi) and operating the hydrocarbon production subsystem 382 at a similar high pressure, the feed streams to the FT reactor 324 and the thermal catalytic CO2 reduction reactor 322 can be compressed to an intermediate pressure. The pressure can be low enough to reduce the capital cost of the equipment by reducing the challenges associated with the metallurgical limitations of the thermal catalytic CO2 reduction reactor, yet high enough to achieve sufficient reaction kinetics while still maintaining a reasonable land footprint. The thermal catalytic CO2 reduction reactor 322 and / or the autothermal reformer 320 can be operated in an intermediate pressure range.

[0183] Operating the thermal catalytic CO2 reduction reactor 322 at an intermediate pressure range may have other advantages. In some cases, the CO stream 362 flowing from the thermal catalytic CO2 reduction reactor 322 may be compressed (to an intermediate pressure range) to knock out at least some water vapor that may be residual, and then compressed to a supply pressure higher than the intermediate pressure range required for the FT reactor 324. This may reduce the capital cost of the thermal catalytic CO2 reduction reactor 322 and / or the autothermal reformer 320, since high temperature (approximately 900° C.) and high pressure operation may pose challenges for the metallurgy of the reforming tubes and / or the tubes carrying the catalyst. The intermediate pressure range may be selected by determining the obtainable reactor construction material parameters of the thermal catalytic CO2 reduction reactor 322 and / or the autothermal reformer 320, such as design stress, yield stress, and ultimate tensile strength (UTS). For example, the intermediate pressure range may be selected by evaluating the pressures at which a lower grade steel forming the thermocatalytic CO2 reduction reactor 322 can function safely and be deemed acceptable from hazard and operability studies while maintaining approximately the same ratio of design stress to yield stress and / or UTS. In some embodiments, the intermediate pressure range or lower operating pressures allow for the use of less expensive materials (e.g., some steel alloys) for the construction of the thermocatalytic CO2 reduction reactor 322 and / or the autothermal reformer 320 as opposed to more expensive materials (e.g., stainless steels).

[0184] The reforming tubes of the thermal catalytic CO2 reduction reactor 322 and / or the ATR 320 are relatively large, which typically increases their cost. As mentioned above, reducing the operating pressure may allow for cost savings in reforming tube materials, offsetting some of the increased cost associated with the large size. In some cases, the autothermal reformer 320 is operated within an intermediate pressure range because these intermediate pressures are favorable for the products of the reforming reaction.

[0185] With reference to FIG. 2, in addition to the heat integration approaches described above, the steam generated from the thermal catalytic CO2 reduction reactor 322 can be used in the CO2 capture subsystem 380. For example, the thermal catalytic CO2 reduction reactor 322 can produce high pressure steam that can be used in the ATR 220. Another example of heat integration between the CO2 capture subsystem 380 and the hydrocarbon production subsystem 382 is the transfer of heat generated in the calciner 318 to the recovered CO2 stream 354. In some embodiments, the calciner 318 can be fluidly connected to a ceramic baghouse that removes dust (e.g., CaCO3 and CaO particles). The ceramic baghouse can be used at the discharge of the second cyclone of the calciner 318, which can operate at about 900° C., to remove dust from the recovered CO2 stream 354. With the dust removed, the recovered CO2 stream 354 can be sent directly to the thermal catalytic CO2 reduction reactor 322 without the need for cooling and reheating, thus reducing or eliminating the thermal energy requirement and improving the process energy efficiency. This is in contrast to conventional designs that may require cooling the CO2 stream from 900° C. to 50° C. for storage and delivery, and then reheating the CO2 stream to about 900° C. to feed the thermal catalytic CO2 reduction reactor 322. In conventional designs, processing the CO2 stream to meet these varying temperature requirements may result in energy inefficiencies.

[0186] Further configurations of the system for producing synthetic fuel from atmospheric CO2 are possible. In some cases, the tail gas in the hydrocarbon production subsystem can be used in the CO2 capture subsystem. For example, the tail gas can be combusted in the burner of the calciner to generate at least a portion of the heat energy required for the calcination reaction. If the tail gas is sent to the calciner, then an autothermal reformer may not be needed. Using the tail gas in the calciner can be an alternative to venting or incinerating the tail gas to the atmosphere, since this approach does not cause emissions, but recycles the carbon to another process unit in the system. Figures 4 and 5 show an example system in which the tail gas is used in the calciner instead of being vented, thereby reducing the carbon emissions from the system per unit (i.e., reducing the carbon intensity) of the synthetic fuel produced. Additionally, flowing the tail gas from the hydrocarbon production subsystem to the calciner may allow for the elimination of the autothermal reformer, thus potentially reducing capital costs.

[0187] 4 is a schematic diagram of an example system 400 that utilizes an electrocatalytic CO2 reduction reactor 422 and recycles FT tail gas 464 and purified tail gas 466 to a CO2 capture subsystem 480. The system 400 includes a CO2 capture subsystem 480, a hydrogen production subsystem 425, and a hydrocarbon production subsystem 482, fluidly connected to each other. The descriptions, features, reference numbers, and associated advantages provided above of the CO2 capture subsystem 280, 380, the hydrogen production subsystem 225, 325, the hydrocarbon production subsystem 282, 382, ​​and other elements of the systems 200, 300 of FIG. 2 and FIG. 3 apply mutatis mutandis to the CO2 capture subsystem 480, the hydrogen production subsystem 425, the hydrocarbon production subsystem 482, and other similar elements of the system 400 of FIG. 4.

[0188] 4, FT tail gas 464 and / or purified tail gas 466 (referred to herein as "tail gas 464, 466") flow from the FT reactor 424 and FT refinery 426, respectively, for utilization in the calciner 418 of the CO2 capture subsystem 480. The tail gas 464, 466 comprises gaseous hydrocarbons primarily in the C1-C4 range and may be combusted in the calciner 418 with an oxygen stream 430a. In some cases, the calciner 418 may combust both the natural gas 410 stream and the tail gas 464, 466 with oxygen 430a. In some cases, the oxygen stream 430a is an electrolyzer oxygen stream.

[0189] The tail gases 464, 466 provide thermal energy for the calcination reaction in the calciner 418 to obtain a recovered CO stream 454 for feeding the electrocatalytic CO reduction reactor 422. Combustion of the tail gases 464, 466 can replace at least a portion of the natural gas 410 feed to the calciner 418, thereby reducing the associated fossil fuel-based CO emissions, while still meeting the CO feed specifications required by the electrocatalytic CO reduction reactor 422. This can reduce the carbon intensity of the system 400 and the liquid fuels 432 or chemicals 434 produced by the system 400.

[0190] Further configurations of the system for producing synthetic fuels from atmospheric CO2 are possible. The above-mentioned approach of reusing the FT tail gas and the purified tail gas (referred to herein as "tail gas") in the calciner can also be applied to implementations including a thermal catalytic CO2 reduction reactor. If the tail gas is sent to the calciner instead of the autothermal reformer, the autothermal reformer may not be required because there is no risk of the light end hydrocarbons in the tail gas causing coke formation in the thermal catalytic CO2 reduction reactor. This is because the tail gas undergoes combustion in the calciner to generate heat energy, rather than undergoing reforming reactions in the thermal catalytic CO2 reduction reactor to produce synthesis gas. 5 is a schematic diagram of an example system 500 that utilizes a thermal catalytic CO2 reduction reactor 522 to recycle FT tail gas 564 and purified tail gas 566 to a CO2 capture subsystem 580. The system 500 includes a CO2 capture subsystem 580, a hydrogen production subsystem 525, and a hydrocarbon production subsystem 582 that are fluidly connected to each other. The FT tail gas 564 and purified tail gas 566 flow from the FT reactor 524 and the purification unit 526, respectively, to the calciner 518 of the CO2 capture subsystem 580 in a configuration similar to the flow of the FT tail gas 464 and purified tail gas 466 from the FT reactor 424 and the purification unit 426 to the calciner 418 of the CO2 capture subsystem 480 in FIG. 4. The hydrocarbon production subsystem 582 includes a thermal catalytic CO2 reduction reactor 522 similar to the thermal catalytic CO2 reduction reactor 322 of FIG. 3. An example of a thermal catalytic CO2 reduction reactor is described with reference to FIG. 10A and FIG. 10B. The descriptions, features, reference numbers, and associated advantages provided above of the CO2 capture subsystem 280, 380, 480, hydrogen production subsystem 225, 325, 425, hydrocarbon production subsystem 282, 382, ​​482, and other elements of the systems 200, 300, 400 of Figures 2 to 4 apply mutatis mutandis to the CO2 capture subsystem 580, hydrogen production subsystem 525, hydrocarbon production subsystem 582, and other similar elements of the system 500 of Figure 5, respectively.

[0191] Operational flexibility and material consolidation are important design considerations for DAC-based fuel production systems. It may be beneficial to implement buffer capacity such that certain units can continue to operate while other units are not operating or are operating below their design capacity. For example, a first process unit may be coupled to a second process unit through a buffer unit. The second process unit may need to be taken offline for modification or maintenance, but the first process unit can continue to operate as long as the buffer unit has the capacity to store the material produced by the first process unit. The buffer capacity allows the system to continue steady-state operation and reduce the impact on units upstream or downstream of the offline unit in the event of a process upset by isolating the unit.

[0192] 6 is a schematic diagram of an example system 600 utilizing a buffer volume and recirculation of liquid synthetic fuel within the system. The system 600 includes a CO2 capture subsystem 680, a hydrogen production subsystem 625, and a hydrocarbon production subsystem 682, fluidly connected to each other. The descriptions, features, reference numbers, and associated advantages of the hydrogen production subsystem 225, 325, 425, 525, the CO2 purification and compression device 238, 338, 438, 538, and the hydrocarbon production subsystem 282, 382, ​​482, 582 of FIG. 6 provided above apply mutatis mutandis to the hydrogen production subsystem 625, the CO2 purification and compression device 638, and the hydrocarbon production subsystem 682, respectively.

[0193] 6, the CO2 capture subsystem 680 of the system 600 includes at least one solid buffer storage tank 690 fluidly connected to the calciner 618. The solid buffer storage tank 690 can provide a buffer capacity that isolates the operation of equipment upstream and / or downstream of the calciner 618 (e.g., the air contactor 612, the pellet reactor 614, and the slaker 616). For example, the solid buffer storage tank 690 fluidly connected to the pellet reactor 614 and the calciner 618 can collect calcium carbonate CaC03 to allow the pellet reactor 614 and equipment upstream of the pellet reactor 614 to continue operation if the calciner 618 needs to operate at a reduced capacity or be taken offline. For example, a solids buffer storage tank 690 fluidly connected to the calciner 618 and the slaker 616 can collect calcium oxide CaO to allow the pellet reactor 614 and the calciner 618 to continue operation if the slaker 616 and / or the air contactor 612 need to operate at a reduced capacity or be taken offline. The solids buffer storage tank 690 can reduce the gap between the supply demand and intermediate production of individual unit operations in the system 600. As a result, each process unit can be operated at conditions that are optimal for its design with minimal or no impact from other units in the system 600.

[0194] In some aspects, the system 600 may enable a unique mode of operating the system's wet and dry loops. In some embodiments, the CO2 capture subsystem 680 includes integrated wet and dry process loops. For example, the air contactor 612, pellet reactor 614, and slaker 616 utilize and / or regenerate the capture solution 646 and are equipment operations that are sensitive to temperature fluctuations. During extended cold periods, such as winter, when low room temperature air reduces the process solution temperature to below -5°C, these equipment may experience operational challenges, whereas the calciner 218 and the hydrocarbon production subsystem 682 are less sensitive to temperature. By incorporating a solid buffer storage tank 690, calcium carbonate CaC03 or calcium oxide CaO can be held and the calciner 618 can continue to operate when one or more of the air contactor 612, pellet reactor 614, and slaker 616 are at reduced capacity or offline.

[0195] Buffer capacity for fluids can be equally as important as buffer capacity for solids and can have similar advantages. The system 600 includes a liquid buffer storage tank 692 fluidly connected to the CO2 purification and compression device 638 and the hydrocarbon production subsystem 682. The liquid buffer storage tank 692 can receive the captured CO2 stream 656 liquefied in the CO2 purification and compression device 638. The liquefied CO2 can also be referred to as "CO2 rundown". For example, the CO2 purification and compression device 638 can include a cryogenic distillation device that liquefies the CO2, and the CO2 rundown can flow to the liquid buffer storage tank 692. The liquid buffer storage tank 692 is pressurized. The liquid buffer storage tank 692 can provide a temporary buffer between the CO2 capture subsystem 680 and the hydrocarbon production subsystem 682.

[0196] With regard to materials integration, in some cases there are certain non-gaseous hydrocarbons formed in the Hydrocarbon Production Subsystem 682 that may be compatible with the CO 2 Capture Subsystem 680 .

[0197] In some embodiments, the system 600 may include a recycle of naphtha stream 684 from the Hydrocarbon Production Subsystem 682 to the calciner 618 of the CO2 Capture Subsystem 680. For example, the FT reactor and refinery of the Hydrocarbon Production Subsystem 682 may produce a FT crude and refinery product stream, respectively, each of which may include naphtha (e.g., naphtha stream 684). The chemical composition of the naphtha may vary depending on the process conditions under which it was formed, but typically includes C5-C10 hydrocarbon chains and is in the liquid phase. In the FT crude, the naphtha may include primarily linear alkenes and oxygenates. After being processed by the refinery into refinery products, the naphtha may include branched hydrocarbons and may be substantially free of oxygenates. The naphtha may include linear alkenes, oxygenates, branched hydrocarbons, or combinations thereof. The naphtha stream 684 may flow from the Hydrocarbon Production Subsystem 682 to the CO2 Capture Subsystem 680 for utilization. For example, naphtha stream 684 may flow from the FT reactor and / or refinery to the calciner 618 and be combusted.

[0198] The naphtha stream 684 can provide thermal energy for the calcination reaction through combustion with oxygen 630, thereby obtaining a recovered CO2 stream 654 for feeding the CO2 reduction reactor. The calciner 618 includes a burner system, which may require modification to use the naphtha stream 684 as a fuel. For example, the burner system of the calciner 618 can include an atomizer coupled to the burner, which can atomize the fuel (e.g., naphtha 684) into liquid fuel droplets and deliver them to the burner of the calciner 618. Combustion of the naphtha stream 684 can replace at least a portion of the natural gas combusted in the calciner 618, thereby reducing the associated fossil fuel-based CO2 emissions and the carbon intensity of the system 600 and the hydrocarbon products produced thereby.

[0199] For safety and product quality considerations, it may be important that the captured CO2 stream produced by the CO2 generation subsystem be substantially free of impurities or residual gases (e.g., excess oxygen, water vapor, inert gases, etc.). For example, the target product composition of the captured CO2 stream may consist of at least 99 wt% CO2. These impurities or residual gases can be removed so that the captured CO2 stream meets CO2 quality requirements for storage, transportation, and use in syngas production.

[0200] 7 is a schematic diagram of an example system 700 including a catalytic oxidation reactor 741 and a calciner combustion control system 720 for removing at least a portion of excess oxygen from a calciner exhaust stream 740 including a recovered CO2 stream 754. Some implementations include one or both of the catalytic oxidation reactor 741 or the calciner combustion control system 720. The system 700 includes a CO2 capture subsystem 780, a hydrogen production subsystem 725, and a hydrocarbon production subsystem 782 fluidly coupled to each other. The descriptions, features, reference numbers and associated advantages of the CO2 capture subsystem 280, 380, 480, 580, 680, hydrogen production subsystem 225, 325, 425, 525, 625, CO2 purification and compression unit 238, 338, 438, 538, 638, and hydrocarbon production subsystem 282, 382, ​​482, 582, 682 of Figures 2 to 6 provided above apply mutatis mutandis to the CO2 capture subsystem 780, hydrogen production subsystem 725, CO2 purification and compression unit 738, and hydrocarbon production subsystem 782 of Figure 7, respectively.

[0201] In some embodiments, calciner exhaust stream 740 can include recovered CO2 stream 754, excess oxygen 745, and inerts 755. Excess oxygen 745 includes oxygen remaining unreacted from the combustion reaction in calciner 718. Non-limiting examples of inerts 755 can include nitrogen, water vapor, and argon. Excess oxygen 745 and inerts 755 can be mixed with recovered CO2 755 and released from calciner 718 as calciner exhaust stream 740.

[0202] The system 700 includes a calciner combustion control system 720 communicatively coupled to the control system 999 and the burners 719 in the calciner 718. The calciner combustion control system 720 may include temperature indicators, flow indicators, flow transmitters, flow ratio indicators, and other instruments coupled to pipes carrying process streams flowing to the calciner burners 719. For example, pipes carrying natural gas, air, oxygen, fluidized gases, or combinations thereof may be in fluid communication with the temperature indicators and flow transmitters in communication with the control system 999. The calciner combustion control system 720 may also include combustion indicators for the burners or flames within the burners 719, differential pressure indicators. In some cases, switches, alarm devices, and pressure tap nozzles may also be included in the calciner combustion control system 720. The calciner combustion control system 720 reduces the amount of excess oxygen 745 in the calciner exhaust stream 740, thereby reducing the amount of excess oxygen 745 in the recovered CO2 stream 754 flowing to the hydrocarbon production subsystem 782. For example, the calciner combustion control system 720 signals the burner 719 and flow control system coupled to the calciner 718 to operate the calciner 718 in a fuel-rich, oxygen-poor mode. A fuel-rich, oxygen-poor mode is a mode in which the feed gas molar ratio (e.g., the molar ratio of fuel to oxygen) is equal to or greater than the stoichiometric ratio required for the combustion reaction. Because there is a lower oxygen content than is required for combustion (i.e., there is excess fuel), the amount of excess oxygen 745 in the calciner exhaust stream 740 is reduced (compared to a calciner operating with a feed gas molar ratio lower than the stoichiometric ratio required for combustion). By operating in this manner, the demand for the CO2 purification and compression device 738 is reduced or eliminated.

[0203] In some implementations, the system 700 may include a catalytic oxidation reactor 741. The catalytic oxidation reactor 741 may include a catalyst bed within the catalytic oxidation reactor volume and an inlet for receiving the combustible gas, oxygen, CO2, water, or a combination thereof. In some cases, the catalyst bed supports a catalyst including platinum. The calciner exhaust stream 740 enters the catalytic oxidation reactor 741 and reacts with the combustible gas 742 (e.g., natural gas or tail gas 743 from the hydrocarbon production subsystem 782) on the catalyst bed. Excess oxygen 745 in the calciner exhaust stream 740 may react with the combustible gas 742 or tail gas 743 to form CO2 and water 736. By implementing the catalytic oxidation reactor 741, the demand for the CO2 purification and compression device 738 may be reduced or eliminated. This may provide an efficient means of bridging the quality of the CO2 product from the CO2 capture subsystem 780 and the feed gas specifications of the hydrocarbon production subsystem 782.

[0204] In some embodiments, the catalytic oxidation reactor 741 of the system 700 can utilize FT tail gas and / or refined tail gas (referred to herein as "tail gas 743") produced in the hydrocarbon production subsystem 782, or low-value combustible products (i.e., combustible hydrocarbons that are not the target products) to consume excess oxygen 745 in the calciner exhaust stream 740. In some implementations, the CO2 capture subsystem 780 can be operated in a manner where the fuel to oxygen ratio is lower than the stoichiometric ratio required for combustion (i.e., there is an excess of oxygen 745). At least a portion of the tail gas 743 or other low-value combustible products can be combusted to remove the excess oxygen 745 in the calciner exhaust stream 740 (so that the recovered CO2 product feed stream 756 fed to the CO2 reduction reactor meets the required specifications). In some implementations, the excess tail gas 743 and low-value combustible products can be fed to the catalytic oxidation reactor 741 to ensure that the excess oxygen 745 is consumed during the reaction. In some implementations, at least a portion of the feed gas, including the calciner exhaust stream 740 and tail gas 743 or low value combustible gases, is preheated to a temperature above the autoignition temperature of the tail gas and / or other combustible gases. Preheating the feed gas can improve the performance of the CO2 reduction reactor, thereby reducing operating costs.

[0205] In some embodiments, the system 700 can utilize techniques to manage the accumulation of inerts. The hydrocarbon production subsystem 782 can include a closed gas loop, where tail gas 743 (C1-C4) from the FT reactor and / or refinery is returned to the CO2 reduction reactor or autothermal reformer for conversion to CO and H2. The tail gas 743 in the hydrocarbon production subsystem 782 can contain inert gases 746, such as nitrogen and argon, that do not react in the CO2 reduction reactor, Fischer-Tropsch synthesis, and subsequent refinery steps. Due to the closed gas loop design, inerts 755 can accumulate in the process stream and reduce production rates by displacing reactants. A conventional approach to address the accumulation of inerts is to periodically purge the tail gas and inert gases from the system. Periodic purging via venting to the atmosphere (with or without incineration) is common in conventional chemical processes, but because tail gas contains hydrocarbons, purging can increase the emissions and carbon intensity of the system.

[0206] In some embodiments, to reduce or eliminate the need for a carbon-exhaust purge cycle, the process stream containing the tail gas 743 and inerts 755 may instead be sent to the catalytic oxidation reactor 741 and / or recycled via the calciner 718 to the CO2 capture subsystem 780, where the tail gas 743 may be combusted to produce CO2. In some cases, the combusted CO2 may be captured. The inert gas 743 may be carried over with the CO2 from the catalytic oxidation reactor 741 and / or the calciner 718 and removed in the CO2 purification and compression system 738. The removed inert gas 746 contains little or no carbon and may then be vented to the atmosphere without contributing to the carbon intensity of the system 700.

[0207] Still other configurations of the system for producing synthetic fuel from atmospheric CO2 are possible. If a CO2 reduction reactor capable of producing both hydrogen and carbon monoxide is implemented in the system, a hydrogen production subsystem may not be necessary. This can also eliminate the need for an autothermal reformer, as syngas can be produced in a single unit, rather than requiring the integration of multiple process units. This can reduce capital costs and simplify the operation of the system.

[0208] 8 is a schematic diagram of an example system 800 utilizing a CO2 reduction reactor 822 to produce a hydrogen 858 stream and a CO 862 stream. The system 800 includes a CO2 capture subsystem 880 and a hydrocarbon production subsystem 882 fluidly coupled to each other. The descriptions, features, reference numbers, and associated advantages provided above of the CO2 capture subsystem 280, 380, 480, 580, 680, 780, hydrogen production subsystem 225, 325, 425, 525, 625, 725, and other elements of the systems 200, 300, 400, 500, 600, 700 of FIG. 2-7 apply mutatis mutandis to the CO2 capture subsystem 880, hydrocarbon production subsystem 882, and other similar elements of the system 800 of FIG.

[0209] The hydrocarbon production subsystem 882 includes a CO2 reduction reactor 822 that reacts the water stream 802 with the recovered CO2 feed stream 856 to form hydrogen 858, CO 862, and oxygen stream 830. In some implementations, the CO2 reduction reactor 822 includes a solid oxide electrolysis cell (SOEC), and is thus a possible configuration of the electrocatalytic CO2 reduction reactor disclosed herein. SOECs are electrochemical devices that can utilize solid materials as electrolytes and can operate at high temperatures, approximately 800° C. The SOEC produces hydrogen 858 and CO 862 by electrolyzing water and reducing CO2 over a catalyst. In some cases, the catalyst includes zirconia. An embodiment of the SOEC is described in more detail below with reference to FIG. 9A. In some implementations, the CO2 reduction reactor 822 produces a sufficient amount of syngas (i.e., hydrogen 858, CO 862) to feed the FT reactor 824.

[0210] The FT reactor 824 and the plurality of purification units 826 can form a FT tail gas 864 and a purified tail gas 866, respectively. In some embodiments, the FT tail gas 864 and the purified tail gas 866 (referred to herein as "tail gas") flow from the Hydrocarbon Production Subsystem 882 to the calciner 818 of the CO2 Capture Subsystem 880. In some implementations, an autothermal reactor is not required, and thus the tail gas may be used in the calciner 818 instead.

[0211] Electrochemical methods for reducing CO2 to CO can be used in systems for producing synthetic fuels from atmospheric CO2. For example, if renewable or low carbon emission energy sources could be used to implement electrochemical CO2 reduction in a DAC-to-fuel system, the overall carbon intensity of the system could be reduced.

[0212] 9A and 9B are schematic diagrams of example electrocatalytic CO2 reduction reactors 900, 901 that include an anode 902, a cathode 904, and an electrolyte 906. Typically, the anode 902 and / or the cathode 904 support a catalytic material that facilitates the reduction reaction to occur.

[0213] 9A, the electrocatalytic CO2 reduction reactor 900 includes an anode 902 fluidly and electrically coupled to a cathode 904 by an electrolyte 906. In some implementations, the electrocatalytic CO2 reduction reactor 900 can operate at a temperature of approximately 800°C.

[0214] In some cases, the electrocatalytic CO2 reduction reactor 900 may be a solid oxide electrolysis cell (SOEC), and the electrolyte 906 includes solid CO2 from the captured CO2 feed stream 256, 456, 656, 756, 856 of the CO2 capture subsystem 280, 480, 680, 780, 880, which may enter the electrocatalytic CO2 reduction reactor 900 at the cathode side. A potential is applied to the anode 902 and the cathode 904 (referred to herein as "electrodes"), and the CO2 is reduced to CO molecules and oxygen ions. In some implementations, the applied potential may include a voltage in the range of 0.95V to 1.35V. The oxygen ions are then oxidized to oxygen molecules at the anode 902 side. In some cases, hydrogen may also be produced in the solid oxide electrolysis cell by splitting water into hydrogen molecules and oxygen ions at the cathode 904. In some implementations, the electrolyte 906 may include zirconia. In some implementations, the anode 902 and / or the cathode 904 may include nickel or platinum.

[0215] In some cases, the electrocatalytic CO2 reduction reactor 900 may be a molten carbonate electrolysis cell, with the electrolyte 906 including carbonate. CO2 from the recovered CO2 feed stream of the CO2 capture subsystem may be used to replenish the carbonate ions in the electrolyte 906. A potential is applied to the anode 902 and cathode 904, and carbonate ions from the electrolyte 906 are reduced to CO molecules and oxygen ions. The oxygen ions are then oxidized to oxygen molecules at the anode 902 side. In some implementations, the anode 902 and / or cathode 904 may include titanium or graphite.

[0216] 9B, the electrocatalytic CO2 reduction reactor 901 includes an anode 902 fluidly and electrically connected to a cathode 904 by an electrolyte 906. The electrodes may be sandwiched by fluidic channels 910 that allow reactants and products to flow to and from the electrocatalytic CO2 reduction reactor 901. In some implementations, the electrocatalytic CO2 reduction reactor 901 may operate at temperatures below 100°C.

[0217] In some cases, the electrocatalytic CO2 reduction reactor 901 can be a low-temperature electrolysis cell or a polymer electrolyte membrane cell, where the electrolyte 906 includes an aqueous solution or membrane, and the fluid channels 910a, 910b can carry the liquid electrolyte. For example, the electrolyte 906 can be an alkaline liquid electrolyte, a cation exchange polymer membrane, or an anion exchange polymer membrane. A potential is applied to the anode 902 and the cathode 904, and the CO2 from the recovered CO2 feed stream is reduced to CO molecules and oxygen ions. The oxygen ions can move through the electrolyte 906 to the anode 902 where they are oxidized to oxygen molecules. The electrolyte 906 can allow the movement or transfer of charge carriers, such as hydroxide OH- ions, from the cathode 904 to the anode 902, allowing the production of CO and oxygen. In some cases, the anode 902 or the cathode 904 can be gas diffusion electrodes. For example, the cathode 904 can be a gas diffusion electrode that allows CO to diffuse out of the reactor. In such cases, the fluid channel 910b may be a gas channel that allows for the inflow of CO2 and the outflow of CO. In some cases, the CO2 reduction reactor 901 may include a catalyst including iron, platinum, a non-precious metal, or a combination thereof.

[0218] In some implementations, any of the electrocatalytic CO2 reduction reactors 900, 901 can be combined with any of the elements described herein. For example, the systems 200, 400, 800 of Figures 2, 4, and 8 can include the electrocatalytic CO2 reduction reactors 900, 901 of Figures 9A and 9B.

[0219] Thermal catalytic methods to produce CO from CO2 can produce synthetic fuels from atmospheric CO2. In some cases, thermal catalytic methods may be more advanced than electrochemical methods because they are based on improved technologies adapted from the traditional FT synthesis process. For example, thermal catalytic methods may implement the RWGS reaction (CO2+H2⇔CO+H2O) as described in Table 2 to produce CO from CO2.

[0220] 10A and 10B are schematic diagrams of examples of thermal catalytic CO2 reduction reactors 1000, 1001. The thermal catalytic CO2 reduction reactors 1000, 1001 each include a CO2 reduction reactor vessel carrying a CO2 reduction catalyst 1006. The CO2 reduction reactor vessel has a number of openings forming a combination of inlets and outlets. The thermal catalytic CO2 reduction reactors 1000, 1001 include a reactant inlet 1008 through which a feed gas mixture 1002 containing CO2 and hydrogen recovered from the atmosphere can flow, and a product outlet 1010 through which a product mixture 1004 containing CO and water can flow. In some cases, the components of the feed gas mixture 1002 are mixed and then preheated before flowing to the reactant inlet 1008. In some implementations, there may be two or more reactant inlets 1008 that receive respective gas species. The feed gas mixture 1002 can enter the CO2 reduction reactor and react on the CO2 reduction catalyst 1006 to produce a product gas mixture 1004. In some implementations, the catalyst 1006 can include cobalt, iron, copper, zinc, aluminum, or a combination thereof. The RWGS reaction can require thermal energy produced from a thermal energy source 1012 that is part of a cooling / heating system, such as a natural gas burner, an electric heater, a heat exchanger, or a combination thereof. In some cases, the feed gas mixture 1002 can be preheated by the thermal energy source 1012 before entering the CO2 reduction reactor. In some cases, a heat transfer medium, such as water vapor or nitrogen, can be used (either directly or indirectly) to transfer heat from the thermal energy source 1012 to the feed gas mixture 1002. In some cases, the heat transfer medium can be a heating jacket that houses the outer shell of the CO2 reduction reactor. The heat transfer medium can enter the thermal catalytic CO2 reduction reactor 1000, 1001 through the thermal energy input 1014 and exit through the thermal energy outlet 1016.

[0221] Referring to FIG. 10A, the thermal catalytic CO2 reduction reactor 1000 is an example of a packed bed reactor. The CO2 reduction catalyst 1006 may be packed into a fixed catalyst bed in the CO2 reduction reactor vessel. The catalyst bed is heated by a thermal energy source 1012 to a sufficient reaction temperature (e.g., in the range of 180° C. to 850° C. depending on the catalyst). As a feed gas mixture 1002 containing CO2 captured from the atmosphere flows through the cavity of the CO2 reduction reactor vessel and over the catalyst 1006, an output mixture 1004 containing CO is produced and released from the reactor.

[0222] Referring to FIG. 10B, the thermal catalytic CO2 reduction reactor 1001 is an example of a multi-tubular fixed bed reactor. A CO2 reduction catalyst 1006 may fill a bundle of catalyst tubes 1018 forming a catalyst bed within the CO2 reduction reactor vessel. The catalyst bed is heated by a thermal energy source 1012 to a sufficient reaction temperature (e.g., in the range of 180° C. to 850° C. depending on the catalyst). In some cases, a heat transfer medium carrying heat from the thermal energy source 1012 may flow through the cavity of the CO2 reduction reactor vessel (i.e., the "shell" side of the thermal catalytic reactor 1001). A feed gas mixture 1002 containing CO2 captured from the atmosphere flows into the bundle of catalyst tubes 1018 and forms a product mixture 1004 as it flows through the length of the catalyst tubes 1018. The product mixture 1004 containing CO is exhausted from the reactor.

[0223] In some implementations, any of the thermal catalytic CO2 reduction reactors 1000, 1001 can be combined with any of the elements described herein. For example, the systems 300, 500 of Figures 3 and 5 can include the thermal catalytic CO2 reduction reactors 1000, 1001 of Figures 10A and 10B.

[0224] Hydrogen is required to produce synthetic fuels. There are various feedstocks that can be used to produce hydrogen. Non-limiting examples of such feedstocks include water, methane, and light hydrocarbons. To reduce the carbon intensity of systems that produce synthetic fuels from atmospheric CO2, it is possible to use hydrogen production methods that are powered by renewable energy and / or linked to carbon capture systems.

[0225] 11A and 11B are schematic diagrams of example hydrogen production subsystems 1100, 1101. Hydrogen can be produced using electrochemical approaches, reforming approaches combined with carbon capture, or a combination thereof. These approaches are commonly referred to in the hydrogen production industry as "green hydrogen" and "blue hydrogen," respectively.

[0226] 11A, the hydrogen production subsystem 1100 may be a water electrolyzer that includes a membrane 1106 disposed between an anode 1102 and a cathode 1104. The membrane 1106 is permeable and conductive to hydrogen ions (protons) and may include a polymer electrolyte membrane. Water is supplied to the water electrolyzer and an electrical potential is applied to the anode 1102 and the cathode 1104. The electrical potential difference splits the water into oxygen and protons. The membrane 1106 conducts the protons to the cathode 1104 where hydrogen molecules are generated from the protons. The hydrogen may then be sent to the hydrocarbon production subsystem to produce synthetic fuels and the oxygen may be utilized in other process devices in the system.

[0227] Referring to FIG. 11B, the hydrogen production subsystem 1101 may be a steam-methane reformer including a burner 1112 thermally coupled to a plurality of reformer tubes 1114 in a reformer furnace 1120. The burner receives a gas mixture 1110 including natural gas and oxygen and combusts it to generate heat energy. A feed gas 1108 including methane and steam enters the reformer tubes 1114 with a steam to methane ratio in the range of 3-5, and heat energy is transferred to initiate the steam-methane reforming reaction (CH4+H2O←→CO+3H2) as described in Table 2. The reformer tubes 1114 may support a catalyst including nickel. For example, the catalyst may include Ni / MgAl2O4. As the reaction occurs along the length of the tubes 1114, a hydrogen stream 1116 is produced and released from the steam-methane reformer. The steam-methane reformer may operate at temperatures ranging from 600°C to 950°C. In some cases, other reactions and device operations may be implemented to increase the amount of hydrogen produced. For example, a water gas shift reaction (CO+H2O←→CO2+3H2) and a pressure swing absorber may be implemented. The pressure swing absorber removes at least some of the CO2 and impurities to obtain a relatively pure hydrogen stream. The CO2 from the combustion reaction initiated by the burner 1112 may flow through the standpipe 1122. In some implementations, the standpipe 1122 is fluidly connected to a carbon capture and sequestration system 1124 that extracts, compresses, and cools the CO2 to a supercritical fluid and injects it into a permanent storage location (e.g., a saline formation, a depleted reservoir, etc.). This may reduce the carbon intensity of the hydrogen production subsystem 1101.

[0228] In some implementations, the hydrogen production subsystem 1101 may include a gasifier that processes biomass, coal, or coke, and the gasifier is fluidly coupled to the carbon capture and sequestration system 1124. In some implementations, the hydrogen production subsystem 1100, 1101 may include a hydrogen pipeline that flows liquid or gaseous hydrogen. In some cases, the hydrogen pipeline may flow hydrogen from a source located outside the battery limits of the CO2 capture subsystem and the hydrocarbon production subsystem.

[0229] In some implementations, the hydrogen production subsystem 1100 of FIG. 11A can be combined with any of the elements described herein. For example, the system 200 of FIG. 2 can include the hydrogen production subsystem 1100 of FIG. 11A. In some implementations including the hydrogen production subsystem 1101 of FIG. 11B, an oxygen source may be required to supply device operations that require oxygen as a reactant. For example, the oxygen source may include an air separation unit, an electrolysis cell that provides oxygen, or a combination thereof. In some cases, the oxygen source may be located outside the battery limits of the CO2 capture subsystem and the hydrocarbon production subsystem.

[0230] In some implementations, the CO2 capture subsystem of a system for synthesizing fuel from a CO2 source may function by contacting air with a liquid sorbent that extracts CO2 from the air. For example, the liquid sorbent may include an aqueous solution of alkali, amine, amino acid, carbonate and / or bicarbonate, with or without a promoter such as carbonic anhydrase. FIG. 12 shows an example CO2 capture subsystem 1200 that utilizes a liquid sorbent (also referred to herein as a "CO2 capture solution"). The CO2 capture subsystem 1200 may be operated in a system (and associated process) for synthesizing fuel from a dilute CO2 source such as air, similar to system 100.

[0231] The CO2 capture subsystem 1200 may include an air contactor 1204 that utilizes a CO2 capture solution 1212 to extract CO2 directly from the atmosphere 1202, according to a non-limiting example of the use of the air contactor 1204. The air contactor 1204 uses the CO2 capture solution 1212 to absorb a portion of the CO2 from the atmosphere 1202 to form a CO2-rich solution 1208. In some implementations, the CO2 capture solution 1212 may include a solution of potassium hydroxide (KOH), sodium hydroxide (NaOH), or a combination thereof. The hydroxide-containing CO2 capture solution may react with CO2 from the atmosphere to form a CO2-rich solution 1208 that includes a solution of potassium carbonate (K2CO3), sodium carbonate (Na2CO3), potassium bicarbonate (KHCO3), sodium bicarbonate (NaHCO3), or a combination thereof.

[0232] The CO2 capture solution 1212 may need to be regenerated from the CO2-rich capture solution 1208, which may be performed by a regeneration system 1230 as part of the CO2 capture subsystem 1200. The regeneration system 1230 functions to process the CO2-rich capture solution 1208 (e.g., spent capture solution) to recover and / or concentrate the CO2 content contained in the CO2-rich capture solution 1208.

[0233] In the example regeneration system 1230, the CO2-rich solution 1208 flows from the air contactor 1204 to a pellet reactor 1210 of the CO2 capture subsystem 1200. The pellet reactor 1210 may include equipment such as a fluidized bed reactive crystallizer. Calcium hydroxide (Ca(OH)2) 1224 is injected into the pellet reactor 1210. Reaction of the CO2-rich solution with the calcium hydroxide 1224 occurs in the pellet reactor 1210. Ca(OH)2 is extracted from the calcium hydroxide 1224. 2+ is the CO3 from the CO2-rich solution 1208 2- in the pellet reactor 1210 to form calcium carbonate (CaCO) solids and hydroxide solution as the CO2 capture solution, thereby regenerating the CO2 capture solution 1212. For example, K2CO3 reacts with Ca(OH)2 to form CaCO3 and KOH, thereby regenerating the CO2 capture solution 1212 with KOH.

[0234] The reaction of the CO2-rich solution with Ca(OH)2 causes precipitation of CaCO3 on the calcium carbonate particles in the pellet reactor 1210, growing calcium carbonate solids 1214. Further processing of the calcium carbonate solids 1214 may occur, including but not limited to filtering, washing, dewatering, or drying. The calcium carbonate solids 1214 are transported from the pellet reactor 1210 to the calciner 1216 of the CO2 capture subsystem 1200.

[0235] The calciner 1216 calcines the calcium carbonate solids 1214 from the pellet reactor 1210 and recovers a stream of gaseous CO2 1218 (also referred to herein as the "recovered carbon dioxide feed stream") to form calcium oxide (CaO) 1220. The calcination reaction is carried out at high temperatures (typically in the range of about 550-1150°C). The thermal energy required for calcination may be generated by oxy-combustion of a fuel source in the calciner 1216. In some implementations, the thermal energy for calcination may be generated electrically and / or the calciner 1216 may be thermally coupled to an electric heater. The recovered CO2 stream 1218 is processed in downstream equipment such as compression and purification systems. The recovered CO2 1218 may be used to synthesize fuels in a hydrocarbon production subsystem, such as the hydrocarbon production subsystem of the present disclosure. The calcium oxide (CaO) stream 1220 is slaked via a hydration reaction with water in a slaker 1222 of the CO2 capture subsystem 1200 to produce calcium hydroxide 1224 that is provided to the pellet reactor 1210. The slaker 1222 may include a stay-in slaker, a high temperature hydrator, a steam slaker, a paste slaker, a lime hydrator, or a combination thereof. The CO2 capture subsystem 1200 may include a plurality of air contactors 1204 that make up a train / assembly of air contactors 1204. The CO2 capture subsystem 1200 may also include solids removal and cleanup equipment to remove water and / or impurities from the material stream and may include a baghouse, electrostatic precipitator, chiller, heat exchanger, condenser, or a combination thereof.

[0236] In some implementations, the CO2 capture solution 1212 can be regenerated using various regeneration systems. The regeneration system 1230 can be part of the air contactor 1204 or separate from the air contactor. In an example of the regeneration system 1230, the CO2-rich solution 1208 can flow to an electrochemical system that includes a cell stack that can include one or more sets of membranes and sets of electrodes. The electrochemical system can regenerate the CO2 capture solution 1212 from the CO2-rich solution 1208 by applying a potential to an electrolyte that contains the CO2-rich solution 1208. The potential difference causes an ion exchange to form the captured CO2 1218 and regenerate the CO2 capture solution 1212. In an example of the regeneration system 1230, the CO2-rich solution 1208 can flow to a thermal stripping column that uses steam to desorb CO2 from the CO2-rich solution 1208, thereby forming a recovered CO2 stream 1218 and regenerating a CO2 capture solution (e.g., a CO2-poor liquid).

[0237] The regeneration system 1230 may include intermediate elements such as liquid distribution piping, solid handling equipment, filtration systems, storage vessels, and / or assemblies of elements that function in cooperation to regenerate the CO2 capture solution 1212. The regeneration system 1230 also includes pumps to flow liquids to and from the regeneration system 1230.

[0238] In some implementations, the CO2 capture subsystem 1200 of FIG. 12 can be combined with or substituted for any of the CO2 capture subsystems disclosed herein.

[0239] Solid sorbents can be used to extract CO2 from the atmosphere. The capture mechanisms for solid sorbents may differ from those of some liquid sorbents. Methods for desorbing / capturing CO2 and regenerating solid sorbents can utilize different chemistries and equipment operations. Some non-limiting examples of solid sorbents are described below.

[0240] FIG. 13 is a schematic diagram of an example CO2 capture subsystem 1300 including a solid sorbent. CO2-containing air 1302 (e.g., ambient air) may flow into an air contactor 1304 carrying a solid sorbent. The CO2-containing air 1302 may transfer at least a portion of the CO2 to the solid sorbent via absorption or adsorption to form a CO2-lean air stream 1306, which is released outside the air contactor 1304. The air contactor 1304 may be fluidly connected to a regeneration system 1318 that desorbs the CO2 as a captured CO2 stream 1320 and regenerates the solid sorbent. In one possible implementation, the regeneration system 1318 includes a calciner to produce a captured CO2 stream 1320 and regenerate the solid sorbent. The captured CO2 stream 1320 may then be sent to a CO2 reduction reactor of the hydrocarbon production subsystem and processed into synthetic fuels as described above.

[0241] A number of solid sorbents are illustrated in Figure 13. Although the solid sorbents are generally used independently of one another, in some cases, the CO2 capture subsystem 1300 may use a combination of multiple sorbents. In some implementations, the air contactor 1304 of the CO2 capture subsystem 1300 may contact the air 1302 with a solid sorbent material, including, but not limited to, non-carbonaceous origins (zeolites 1316, silica, metal organic frameworks 1314 and porous polymers, alkali metals, and metal oxide carbonates), as well as carbonaceous origins (activated carbon and / or carbon fibers, graphene, ordered porous carbon, fibers), solid structures with chemical sorption materials including functional amine-based materials 1308 with or without cellulose, solid polymer-based materials including polyethyleneimine silica, ion exchange resins 1312, or any combination of the above. In some implementations, the regeneration system 1318 of the CO2 capture subsystem may include a thermal swing desorber, a pressure swing desorber, a humidity swing desorber, a vacuum pump, a heat or steam stripper, a calciner, an electrochemical cell, or a combination thereof. For example, the CO2-containing air 1302 may contact a solid sorbent including calcium oxide CaO or calcium hydroxide Ca(OH)2 in an air contactor 1304 to form calcium carbonate CaCO3 as an intermediate material. The CaCO3 may then flow to a calciner in the regeneration system 1318 and undergo a calcination reaction to form a captured CO2 stream 1320 that is released from the CO2 capture subsystem 1300. The captured CO2 stream 1320 may then be processed into synthetic fuels via a hydrocarbon production subsystem.

[0242] In some implementations, the CO2 capture subsystem 1300 of FIG. 13 can be combined with or substituted for any of the CO2 capture subsystems disclosed herein.

[0243] The systems 200, 300, 400, 500, 600, 700, 800 may also include a control system (or flow control system) 999 integrated with and / or communicatively coupled to one or more elements of the respective systems 200, 300, 400, 500, 600, 700, 800. For example, the process streams in the system 200 may be flowed using one or more flow control systems (e.g., control system 999) implemented throughout the system 200. The flow control system may include one or more flow pumps, fans, blowers, or solids movers that move the process streams, one or more flow pipes through which the process streams are flowed, and one or more valves that regulate the flow rate of the streams through the pipes. Each of the configurations described herein may include at least one variable frequency drive (VFD) coupled to a respective pump that may control at least one liquid flow rate. In some implementations, the liquid flow rate is controlled by at least one flow control valve.

[0244] In some embodiments, the flow control systems may be manually actuated. For example, an operator may set the flow rates for each pump or moving device and set the open / closed positions of the valves to regulate the flow of the process stream through the pipes in the flow control systems. Once an operator sets the flow rates and open / closed positions of the valves for all flow control systems distributed throughout the system, the flow control systems may cause the stream to flow under certain flow conditions, e.g., certain volumetric flow rates or other flow conditions. To change the flow conditions, an operator may manually actuate the flow control systems, for example, by changing the pump flow rates or the open / closed positions of the valves.

[0245] In some embodiments, the flow control system may be operated automatically. For example, the flow control system may be connected to a computer or control system (e.g., control system 999) to operate the flow control system. The control system may include a computer-readable medium having stored thereon instructions (e.g., flow control instructions and other instructions) executable by one or more processors to perform operations (e.g., flow control operations). An operator may use the control system to set the flow rates and open / closed positions of valves for all flow control systems distributed throughout the facility. In such an embodiment, an operator may manually change the flow conditions by providing inputs through the control system. Also, in such an embodiment, the control system may control one or more of the flow control systems automatically (i.e., without manual intervention), for example, using a feedback system connected to the control system. For example, sensors (e.g., pressure, temperature, or other sensors) may be connected to pipes through which the process stream flows. The sensors may monitor and provide the flow conditions (e.g., pressure, temperature, or other flow conditions) of the process stream to the control system. In response to a flow condition exceeding a threshold (such as a pressure threshold, a temperature threshold, or other threshold), the control system can automatically act. For example, if the pressure or temperature in a pipe exceeds a pressure or temperature threshold, respectively, the control system can send a signal to a pump to reduce flow, a signal to open a valve to relieve pressure, a signal to stop the flow of a process stream, or other signal.

[0246] Figure 14 is a schematic diagram of a control system (or controller) 1400 for a system that produces synthetic fuels, such as system 200 shown in Figure 2. System 1400 may be used, for example, as or as part of control system 999 or other controllers described herein, and for operations described in connection with any of the computer-implemented methods described hereinbefore.

[0247] System 1400 is intended to include various forms of digital computers, such as laptops, desktops, workstations, personal digital assistants, servers, blade servers, mainframes, and other suitable computers. System 1400 may also include mobile devices, such as personal digital assistants, mobile phones, smart phones, and other similar computing devices. Additionally, the system may include a portable storage medium, such as a Universal Serial Bus (USB) flash drive. For example, a USB flash drive may store an operating system and other applications. A USB flash drive may include input / output components, such as a wireless transmitter or a USB connector that may be inserted into a USB port of another computing device.

[0248] The system 1400 includes a processor 1410, a memory 1420, storage devices 1430, and input / output devices 1440. Each of the components 1410, 1420, 1430, and 1440 are interconnected using a system bus 1450. The processor 1410 can process instructions for execution within the system 1400. The processor can be designed using any of a number of architectures. For example, the processor 1410 can be a CISC (Complex Instruction Set Computer) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimum Instruction Set Computer) processor.

[0249] In one implementation, the processor 1410 is a single-threaded processor. In some implementations, the processor 1410 is a multi-threaded processor. The processor 1410 is capable of processing instructions stored in the memory 1420 or storage device 1430 and displaying graphical information for a user interface on the input / output device 1440.

[0250] The memory 1420 stores information within the system 1400. In one implementation, the memory 1420 is a computer-readable medium. In one implementation, the memory 1420 is a volatile memory device. In some implementations, the memory 1420 is a non-volatile memory device.

[0251] The storage device 1430 is capable of providing mass storage for the system 1400. In one implementation, the storage device 1430 is a computer-readable medium. In various different implementations, the storage device 1430 may be a floppy disk device, a hard disk device, an optical disk device, or a tape device.

[0252] The input / output devices 1440 provide input / output operations to the system 1400. In one implementation, the input / output devices 1440 include a keyboard and / or a pointing device. In some implementations, the input / output devices 1440 include a display device for displaying a graphical user interface.

[0253] Referring to FIG. 15, a method 1500 for producing synthetic fuel is disclosed. At 1501, the method 1500 includes extracting carbon dioxide from an atmospheric stream (e.g., streams 204, 404 of FIG. 2 and FIG. 4, respectively) using a sorbent material to form a captured carbon dioxide feed stream (e.g., captured carbon dioxide feed streams 256, 456 of FIG. 2 and FIG. 4, respectively). At 1502, the method 1500 includes extracting hydrogen from a hydrogen-containing feedstock to produce a hydrogen feed stream (e.g., hydrogen feed streams 258, 458 of FIG. 2 and FIG. 4, respectively). The method 1500 includes processing the captured carbon dioxide feed stream in a CO2 reduction reactor to produce a CO2 stream by using an electrocatalytic CO2 reduction reactor. At 1504, the method 1500 includes applying an electric potential to the CO2 reduction reactor (e.g., CO2 reduction reactors 222, 422 of FIG. 2 and FIG. 4, respectively). At 1506, the method 1500 includes reducing at least a portion of the recovered CO2 feed stream over a catalyst to form a CO stream (e.g., CO streams 262, 462 of Figures 2 and 4, respectively) and an oxygen stream (e.g., oxygen streams 230, 430 of Figures 2 and 4, respectively). At 1508, the method 1500 includes reacting the CO stream from the CO2 reduction reactor with the hydrogen feed stream to produce a synthetic fuel.

[0254] Referring to FIG. 16, a method 1600 for producing synthetic fuel is disclosed. At 1601, the method 1600 includes extracting carbon dioxide from an atmospheric stream (e.g., streams 304, 504 of FIG. 3 and FIG. 5, respectively) using a sorbent material to form a captured carbon dioxide feed stream (e.g., captured carbon dioxide feed streams 356, 556 of FIG. 3 and FIG. 5, respectively). At 1602, the method 1600 includes extracting hydrogen from a hydrogen-containing feedstock to produce a hydrogen feed stream (e.g., hydrogen feed streams 358, 558 of FIG. 3 and FIG. 5, respectively). The method 1600 includes processing the captured carbon dioxide feed stream in a CO2 reduction reactor to produce a CO2 stream by using a thermal catalytic CO2 reduction reactor. At 1604, the method 1600 includes conveying a portion of the hydrogen feed stream to a CO2 reduction reactor (e.g., CO2 reduction reactors 322, 522 of FIG. 3 and FIG. 5, respectively). At 1606, the method 1600 includes inputting thermal energy to a CO2 reduction reactor and reacting a portion of the hydrogen feed stream with the recovered CO2 feed stream over a catalyst in the CO2 reduction reactor to produce a CO stream (e.g., CO streams 362, 562 of FIGS. 3 and 5, respectively) and a water stream (e.g., water streams 336, 536 of FIGS. 3 and 5). At 1608, the method 1600 includes reacting the CO stream from the CO2 reduction reactor with the hydrogen feed stream to produce a synthetic fuel.

[0255] The particular features described may be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or combinations thereof. The apparatus may be implemented in a computer program product tangibly embodied in an information carrier, such as a machine-readable storage device, for execution by a programmable processor; the method steps may be performed by the programmable processor executing a program of instructions to perform the functions of the described implementation by operating on input data and generating output data. The features described may be advantageously implemented in one or more computer programs executable on a programmable system including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. A computer program is a collection of instructions that can be used directly or indirectly by a computer to perform an activity or bring about a result. Computer programs may be written in any type of programming language, including compiled or interpreted languages, and may be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other apparatus suitable for use in a computing environment.

[0256] Processors suitable for executing a program of instructions include, by way of example, both general purpose and special purpose microprocessors, and the sole processor or one of multiple processors of any kind of computer. Typically, a processor receives instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a processor for executing instructions and one or more memories for storing instructions and data. Typically, a computer also includes, or is operatively linked to communicate with, one or more mass storage devices for storing data files; such devices include magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and optical disks. Storage devices suitable for tangibly embodying computer program instructions and data include, by way of example, semiconductor memory devices, such as EPROM, EEPROM, and flash memory devices; magnetic disks, such as internal hard disks and removable disks; magneto-optical disks; and all forms of non-volatile memory, including CD-ROM and DVD-ROM disks. The processor and memory may be supplemented by or incorporated in an ASIC (Application Specific Integrated Circuit).

[0257] To provide for interaction with a user, the features may be implemented in a computer having a display device, such as a CRT (cathode ray tube) or LCD (liquid crystal display) monitor, for displaying information to the user, and a keyboard and pointing device, such as a mouse or trackball, by which the user provides input to the computer. In addition, such activity may be implemented via touch screen flat panel displays and other suitable mechanisms.

[0258] The features may be implemented in a control system that includes back-end components such as a data server, or a control system that includes middleware components such as an application server or an Internet server, or a control system that includes a front-end component such as a client computer having a graphical user interface or an Internet browser, or any combination thereof. The components of the system may be connected by any form or medium of digital data communication, such as a communications network. Examples of communications networks include a local area network ("LAN"), a wide area network ("WAN"), a peer-to-peer network (with ad-hoc or static members), a grid computing infrastructure, and the Internet.

[0259] As used in this description, the term "couple" and its variations such as "coupled", "couples" and "connected" are intended to include indirect and direct connections unless otherwise indicated. For example, when a first device is coupled to a second device, the coupling may be through a direct connection or through an indirect connection via other devices and connections. Similarly, when a first device is communicatively coupled to a second device, the communication may be through a direct connection or through an indirect connection via other devices and connections. In particular, a fluid coupling means that a direct or indirect path is provided for fluid to flow between two fluidly coupled devices. Also, a thermal coupling means that a direct or indirect path is provided for thermal energy to flow between the thermally coupled devices.

[0260] Although this specification contains many specific implementation details, these should not be construed as limiting the scope of any invention or what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features described herein in the context of separate implementations may also be implemented in combination in a single implementation. Conversely, various features described in the context of a single implementation may also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as working in a particular combination and may even initially be claimed as such, one or more features from a claimed combination may in some cases be removed from the combination, and the claimed combination may be directed to a subcombination or a variation of the subcombination.

[0261] Similarly, although acts are shown in a particular order in the figures, this should not be understood as requiring that such acts be performed in the particular order shown, or in any sequential order, or that all of the acts illustrated be performed, to achieve desirable results. In certain situations, it may be advantageous to perform multiple tasks and process them in parallel. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the program components and systems described may generally be integrated together in a single software product or multiple packaged software products.

[0262] A number of implementations have been described. Nevertheless, it should be understood that various modifications may be made without departing from the spirit and scope of the present disclosure. For example, the example operations, methods, or processes described herein may include more or fewer steps than those described. Furthermore, the steps in the example operations, methods, or processes may be performed in a different sequence than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims. [Explanation of symbols]

[0263] 11 CO2 Capture Subsystem 12 Hydrocarbon Production Subsystem 13 Hydrogen Production Subsystem 202 Hydrogen Feedstock 204 Atmosphere 220 Autothermal Reformer (ATR) 222 Electrocatalytic CO2 reduction reactor 224 Fischer-Tropsch (FT) Reactor 225 Hydrogen Production Subsystem 232 Liquid fuel 238 CO2 purification and compression equipment 246 CO2 capture solution 254 Captured CO2 258 Hydrogen 280 CO2 Capture Subsystem 282 Hydrocarbon Production Subsystem 318 Calciner 320 Autothermal Reformer 322 Thermal catalytic CO2 reduction reactor 324 FT Reactor 325 Hydrogen Production Subsystem 332 Liquid fuel 338 CO2 purification and compression equipment 358 Hydrogen Flow 380 CO2 Capture Subsystem 382 Hydrocarbon Production Subsystem 418 Calciner 422 Electrocatalytic CO2 Reduction Reactor 424 FT reactor 425 Hydrogen Production Subsystem 432 Liquid fuel 438 CO2 purification and compression equipment 458 Hydrogen Feed Stream 480 CO2 Capture Subsystem 482 Hydrocarbon Production Subsystem 518 Calciner 522 Thermal catalytic CO2 reduction reactor 524 FT Reactor 525 Hydrogen Production Subsystem 538 CO2 purification and compression equipment 558 Hydrogen Feed Stream 580 CO2 Capture Subsystem 582 Hydrocarbon Production Subsystem 618 Calciner 625 Hydrogen Production Subsystem 638 CO2 purification and compression equipment 680 CO2 Capture Subsystem 682 Hydrocarbon Production Subsystem 690 Solid Buffer Storage Tank 718 Calciner 719 Burner 720 Calciner Combustion Control System 725 Hydrogen Production Subsystem 738 CO2 purification and compression equipment 741 Catalytic Oxidation Reactor 780 CO2 Capture Subsystem 782 Hydrocarbon Production Subsystem 818 Calciner 822 CO2 reduction reactor 880 CO2 Capture Subsystem 882 Hydrocarbon Production Subsystem 902 Anode 904 Cathode 906 Electrolyte 910 Fluid Channel 999 Control System 1000 Thermal catalytic CO2 reduction reactor 1001 Thermal catalytic CO2 reduction reactor 1006 CO2 reduction catalyst 1018 Catalyst tube 1100 Hydrogen Production Subsystem 1101 Hydrogen Production Subsystem 1102 Anode 1104 Cathode 1106 Membrane 1120 Reformer 1124 Carbon Capture and Sequestration Systems 1200 CO2 Capture Subsystem 1204 Air Contactor 1210 Pellet Reactor 1216 Calciner 1230 Playback System 1300 CO2 Capture Subsystem 1304 Air Contactor 1318 Playback System

Claims

1. 1. A method for producing a synthetic fuel, comprising: Extract carbon dioxide (CO) from atmospheric streams using adsorbent materials 2 ) to form a recovered carbon dioxide feed stream; Hydrogen (H 2 ) to produce a hydrogen feed stream; CO 2 applying a potential to the reduction reactor; and At least a portion of the recovered carbon dioxide feed stream is reduced over a catalyst to produce a carbon monoxide stream and oxygen (O 2 ) flow; by The captured carbon dioxide feed stream is treated with CO 2 treating in a reduction reactor to produce a carbon monoxide (CO) stream; CO 2 reacting the carbon monoxide stream from the reduction reactor with the hydrogen feed stream to produce a synthetic fuel.

2. extracting carbon dioxide from the atmospheric stream with a sorbent material to form a captured carbon dioxide feed stream; Carbon dioxide in the atmospheric stream is CO 2 React with the capture solution to CO 2 forming a low-gas and carbonate-rich capture solution; The carbonate-rich capture solution is reacted with a calcium hydroxide stream to release at least a portion of the CO 2 forming a capture solution and precipitating calcium carbonate solids; and calcining at least a portion of the calcium carbonate solids to extract the recovered carbon dioxide feed stream.

3. Carbon dioxide in the atmospheric stream is CO 2 3. The method of claim 2, wherein reacting with a capture solution comprises reacting the carbon dioxide in the atmospheric stream with at least one of potassium hydroxide or sodium hydroxide.

4. 3. The method of claim 2, wherein calcining at least a portion of the calcium carbonate solids comprises burning a fuel comprising at least one of natural gas or hydrogen.

5. 5. The method of claim 4, wherein combusting a fuel comprising at least one of natural gas or hydrogen comprises combusting at least a portion of the hydrogen feed stream.

6. 3. The method of claim 2, wherein calcining at least a portion of the calcium carbonate solids comprises electrically heating the calcium carbonate solids.

7. CO 2 reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed stream comprising: reacting a hydrogen feed stream with a carbon monoxide stream in a Fischer-Tropsch (FT) process to form an FT crude stream; refining the FT crude stream to form a refined crude stream comprising naphtha; 3. The method of claim 2, further comprising combusting at least a portion of the naphtha to produce thermal energy, and wherein calcining at least a portion of the calcium carbonate solids comprises calcining at least a portion of the calcium carbonate solids with the thermal energy.

8. 10. The method of claim 1, wherein extracting hydrogen from a hydrogen-containing feedstock comprises electrolyzing water to form a hydrogen feed stream and an electrolyzer oxygen stream.

9. 10. The method of claim 1, wherein extracting hydrogen from a hydrogen-containing feedstock comprises steam-methane reforming to form a hydrogen feed stream.

10. CO 2 10. The method of claim 1, wherein reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed stream comprises reacting the hydrogen feed stream and the carbon monoxide stream in a Fischer-Tropsch (FT) process to form an FT crude stream.

11. The captured carbon dioxide feed stream is treated with CO 2 a carbon monoxide stream in a reduction reactor to convert only the carbon monoxide stream into CO 2 conveying the mixture from the reduction reactor to a Fischer-Tropsch (FT) process; and CO 2 In the FT process, the step of reacting the carbon monoxide stream from the reduction reactor with the hydrogen feed stream is 2 reacting the carbon monoxide stream conveyed from the reduction reactor with the hydrogen feed stream to form a FT crude stream; 2. The method of claim 1, comprising:

12. At least some of the flammable gases are 2 10. The method of claim 1, further comprising the step of using the oxygen stream from the reduction reactor to oxidize in an autothermal reformer to form a synthesis gas stream.

13. CO 2 The step of reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed is 2 reacting the carbon monoxide stream from the reduction reactor with the hydrogen feed stream to form a FT crude stream and a FT tail gas stream; 13. The method of claim 12, further comprising purifying the FT crude stream to produce a purified tail gas stream and a purified crude stream.

14. 14. The method of claim 13, wherein oxidizing at least a portion of the combustible gas comprises oxidizing at least one of an FT tail gas stream, a refinery tail gas stream, or a natural gas stream.

15. CO 2 13. The method of claim 12, wherein reacting the carbon monoxide stream from the reduction reactor with the hydrogen feed stream comprises reacting a synthesis gas stream, a carbon monoxide stream, and a hydrogen feed stream from an autothermal reformer in a Fischer-Tropsch (FT) process to form an FT crude stream and an FT tail gas stream.

16. CO 2 reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed stream comprising: refining the FT crude stream to form a purified crude stream and a purified tail gas stream; distilling a refined crude stream to form a synthetic fuel, the synthetic fuel comprising a liquid fuel stream and a chemicals stream; 16. The method of claim 15, comprising:

17. extracting hydrogen from hydrogen compounds in the hydrogen feedstock to produce a hydrogen feed stream; CO 2 10. The method of claim 1, further comprising dissociating the water stream over a catalyst in a reduction reactor to form a hydrogen feed stream and a separate portion of an oxygen stream.

18. CO 2 reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed stream comprising: reacting a hydrogen feed stream with a carbon monoxide stream via a Fischer-Tropsch (FT) process to form a FT tail gas stream and a FT crude stream; refining the FT crude stream to form a purified tail gas stream and a purified crude stream; calcining at least a portion of the calcium carbonate solids to extract a recovered carbon dioxide feed stream, the calcination step comprising combusting at least one of the FT tail gas stream or the purified tail gas stream; 3. The method of claim 2, comprising:

19. the recovered carbon dioxide feed stream comprises excess oxygen; 10. The method of claim 1, further comprising removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream.

20. removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream; 20. The method of claim 19, including combusting at least a portion of the excess oxygen with a fuel, wherein the molar ratio of fuel to excess oxygen is equal to or greater than the combustion stoichiometric ratio.

21. removing at least a portion of the excess oxygen in the recovered carbon dioxide feed stream; catalytically oxidizing the combustible gas with at least a portion of the excess oxygen to form a catalytic oxidation product stream comprising carbon dioxide and water; combining the carbon dioxide of the catalytic oxidation product stream with the recovered carbon dioxide feed stream; 20. The method of claim 19, wherein the combustible gas comprises at least one of natural gas, Fischer-Tropsch tail gas, or refinery tail gas.

22. catalytically oxidizing the combustible gas with at least a portion of the excess oxygen, said step comprising:

22. The method of claim 21, including the step of combusting at least a portion of the excess oxygen with the combustible gas at the autoignition temperature of the combustible gas.

23. liquefying the recovered carbon dioxide feed stream; The captured carbon dioxide feed stream is treated with CO 2 maintaining at least a portion of the liquefied carbon dioxide feed stream in a liquid storage tank prior to processing in the reduction reactor; The method of claim 1 further comprising:

24. 24. The method of claim 23, wherein liquefying the recovered carbon dioxide feed stream comprises separating contaminants from the recovered carbon dioxide feed stream in at least one of a cryogenic distillation unit, a membrane separation unit, or a water knockout unit.

25. CO 2 reacting the carbon monoxide stream from the reduction reactor with a hydrogen feed stream to produce heat; 10. The method of claim 1, further comprising transferring at least a portion of the heat to the step of extracting carbon dioxide from the atmospheric stream using a sorbent material to form a captured carbon dioxide feed stream.

26. 10. The method of claim 1, further comprising: compressing a gaseous process stream by operating a single compressor assembly, the gaseous process stream comprising at least one of a recovered carbon dioxide feed stream, steam, carbon monoxide, hydrogen, a Fischer-Tropsch tail gas, or a purified tail gas.

27. 1. A method for producing a synthetic fuel, comprising: extracting carbon dioxide from the atmospheric stream using a sorbent material to form a captured carbon dioxide feed stream; CO 2 applying a potential to the reduction reactor; and At least a portion of the recovered carbon dioxide feed stream is reduced over a catalyst to produce a carbon monoxide stream and oxygen (O 2 ) flow; by The recovered carbon dioxide feed stream is treated with carbon dioxide (CO 2 ) treating the carbon monoxide (CO) stream in a reduction reactor to produce a carbon monoxide (CO) stream; CO 2 The carbon monoxide stream from the reduction reactor is converted to hydrogen (H 2 and reacting the sulphur dioxide gas with the sulphur dioxide gas stream to produce a synthetic fuel.

28. 1. A system for producing synthetic fuels, comprising: a carbon dioxide (CO) extractor configured to extract carbon dioxide from an atmospheric stream using an adsorbent material to produce a captured carbon dioxide feed stream; 2 ) capture subsystem and; a hydrogen production subsystem configured to extract hydrogen from the hydrogen-containing feedstock and produce a hydrogen feed stream; a CO meter configured to process the recovered carbon dioxide feed stream to produce a carbon monoxide (CO) stream; 2 a hydrocarbon production subsystem including a reduction reactor; The hydrocarbon production subsystem converts the hydrogen feed stream into CO 2 The system is configured to react with the carbon monoxide stream from the reduction reactor to produce a synthetic fuel.

29. The adsorbent material is 2 containing a capture solution; CO 2 The capture subsystem includes a pellet reactor fluidly connected to the calciner, the pellet reactor generating CO 2 30. The system of claim 28, wherein the capture solution is configured to react to precipitate calcium carbonate solids, and the calciner is configured to calcinate at least a portion of the calcium carbonate solids.

30. 30. The system of claim 28, wherein the hydrogen production subsystem includes a water electrolyzer configured to form a hydrogen feed stream and an oxygen stream.

31. The hydrocarbon production subsystem 2 to receive the carbon monoxide stream from the reduction reactor. 2 30. The system of claim 28, comprising a Fischer-Tropsch (FT) reactor fluidly connected to the reduction reactor, the FT reactor configured to form an FT crude stream.

32. CO 2 30. The system of claim 28, wherein the reduction reactor comprises a solid oxide electrolysis cell comprising a zirconia-containing electrolyte and electrodes comprising nickel or platinum.

33. CO 2 30. The system of claim 28, wherein the reduction reactor comprises a molten carbonate electrolysis cell comprising a carbonate-containing electrolyte and electrodes comprising titanium or graphite.

34. CO 2 30. The system of claim 28, wherein the reduction reactor comprises a polymer electrolyte membrane fuel cell comprising at least one of an alkaline aqueous solution or a solid membrane.

35. CO 2 30. The system of claim 28, wherein the reduction reactor comprises a gas diffusion electrode and a catalyst comprising platinum or a non-noble metal.

36. CO 2 The reduction reactor 2 fluidly coupled to the capture subsystem; 30. The system of claim 28, wherein the hydrocarbon production subsystem comprises an autothermal reformer fluidly connected to the Fischer-Tropsch (FT) reactor.

37. 37. The system of claim 36, wherein the autothermal reformer comprises a reactant inlet configured to receive a combustible gas comprising at least one of an FT tail gas from the FT reactor, a purified tail gas, or a natural gas stream.

38. 37. The system of claim 36, wherein the FT reactor comprises a syngas inlet configured to receive a syngas stream from the autothermal reformer.

39. 37. The system of claim 36, wherein the FT reactor comprises an FT catalyst comprising at least one of nickel, cobalt, iron, or ruthenium.

40. CO 2 37. The system of claim 36, wherein the reduction reactor comprises an oxygen outlet fluidly connected to the autothermal reformer and a carbon monoxide outlet fluidly connected to the FT reactor.

41. 37. The system of claim 36, wherein the FT reactor comprises a reactor volume containing a catalyst and at least one outlet configured to flow the FT tail gas to the autothermal reformer and the FT crude stream.

42. 42. The system of claim 41, wherein the FT reactor is one of a fixed packed bed reactor, a multi-tubular fixed bed reactor, a fluidized bed reactor, and a slurry phase reactor.

43. 30. The system of claim 28, wherein the hydrocarbon production subsystem comprises an autothermal reformer fluidly connected to a refinery, the refinery being fluidly connected to a distillation device, the refinery comprising at least one outlet configured to flow a purified tail gas to the autothermal reformer and to flow a purified crude to the distillation device, the distillation device being configured to fractionate the purified crude into synthetic fuel.

44. The adsorbent material is 2 containing a capture solution; CO 2 The capture subsystem burns the combustible gas to produce CO 2 30. The system of claim 28, comprising a burner configured to provide thermal energy to heat the capture solution, and wherein the combustible gas comprises at least one of a Fischer-Tropsch (FT) tail gas or a refinery tail gas.

45. the recovered carbon dioxide feed stream comprises excess oxygen; CO 2 further comprising a catalytic oxidation reactor coupled to the capture subsystem, the catalytic oxidation reactor operable to remove at least a portion of the excess oxygen, the catalytic oxidation reactor comprising: a catalytic oxidation reactor volume containing a platinum-containing catalyst; and at least one inlet configured to receive excess oxygen in the recovered carbon dioxide feed stream and to receive a combustible gas comprising at least one of natural gas, a Fischer-Tropsch (FT) tail gas, or a refinery tail gas; 30. The system of claim 28, wherein the catalytic oxidation reactor volume is configured to react excess oxygen with the combustible gas over a platinum-containing catalyst.

46. CO fluidly connected to a liquid buffer storage tank configured to be pressurized to a pressure in the range of 10 bar to 65 bar. 2 The CO 2 The capture subsystem 2 30. The system of claim 28, fluidly connected to the hydrocarbon subsystem by a purification and compression system and a liquid buffer storage tank.

47. CO 2 47. The system of claim 46, wherein the purification and compression system includes at least one of a cryogenic distillation unit, a membrane separation unit, or a water knockout unit.

48. The hydrocarbon production subsystem 2 30. The system of claim 28, comprising a Fischer-Tropsch (FT) reactor thermally coupled to the capture subsystem.

49. CO 2 49. The system of claim 48, wherein the capture subsystem comprises a calciner, an FT reactor thermally coupled to the calciner.

50. CO 2 30. The system of claim 28, further comprising a single compressor assembly fluidly coupled to the capture subsystem and the hydrocarbon production subsystem, the single compressor assembly comprising a multi-stage compressor-motor or at least two compressors coupled to a single motor shaft.

Images