Hydrocarbon synthesis process

Abstract

A process for synthesizing hydrocarbons is described, the process comprising: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) cooling the crude synthesis gas to condense water and removing water and optionally carbon dioxide from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; and (c) passing the feed stream through a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons. and (d) upgrading the product stream in an upgrading unit to produce an upgraded product stream, wherein a naphtha stream is separated from the product stream or the upgraded product stream, at least a portion of the tail gas stream is supplied with steam to a first de-enrichment vessel containing a de-enrichment catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is supplied with hydrogen and steam to a second de-enrichment vessel containing a de-enrichment catalyst to form a second gas mixture containing methane, and the first and second gas mixtures containing methane are supplied to a reverse water gas shift unit. A system for carrying out this process is also provided.

Description

[Technical Field]

[0001] The present invention relates to a process for synthesizing hydrocarbons from synthesis gas containing hydrogen and carbon monoxide prepared using the reverse water gas shift reaction. [Background technology]

[0002] Processes for synthesizing hydrocarbons from synthesis gas containing hydrogen and carbon monoxide prepared using the reverse water-gas shift reaction are known. For example, International Publication No. 2022 / 079407(A1) discloses a process for synthesizing hydrocarbons, in which at least a portion of a carbon dioxide stream recovered from a carbon dioxide removal unit and a portion of a hydrogen stream produced by an electrolysis unit are fed to a reverse water-gas shift unit to produce a carbon monoxide stream, and at least a portion of the carbon monoxide stream from the reverse water-gas shift unit is fed to a Fischer-Tropsch hydrocarbon synthesis unit. A tail gas containing one or more of methane, ethane, propane, butane, and C5-C10 hydrocarbons can be recovered from the Fischer-Tropsch hydrocarbon synthesis unit and subjected to a separate de-enrichment step to form a de-enriched tail gas. The de-enriched tail gas can be fed to the Fischer-Tropsch hydrocarbon synthesis unit and / or the reverse water-gas shift unit. Summary of the Invention

[0003] The inventors have recognized that process efficiency can be improved by adding at least a portion of the tail gas recovered from a hydrocarbon synthesis or upgrading unit and a portion of the naphtha stream to a de-enrichment stage to produce a methane-containing gas for use in a reverse water gas shift unit to produce additional synthesis gas. The inventors have further recognized that different de-enrichment vessels and conditions are required to efficiently utilize the tail gas and naphtha fractions.

[0004] Accordingly, the present invention provides a process for synthesizing hydrocarbons, the process comprising the steps of: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) cooling the crude synthesis gas to condense water and removing water (and optionally carbon dioxide) from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; and (c) passing the feed stream through a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to produce a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons. and (d) upgrading the product stream in an upgrading unit to produce an upgraded product stream, wherein a naphtha stream is separated from the product stream or the upgraded product stream, at least a portion of the tail gas stream is supplied together with steam to a first de-enrichment vessel containing a de-enrichment catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is supplied together with hydrogen and steam to a second de-enrichment vessel containing a de-enrichment catalyst to form a second gas mixture containing methane, and the first gas mixture and the second gas mixture containing methane are supplied to a reverse water gas shift unit.

[0005] The present invention further provides a system for carrying out the process, the system comprising: (a) a reverse water gas shift unit configured to receive a gas mixture comprising hydrogen and carbon dioxide and to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) a cooling and separation apparatus configured to receive the crude synthesis gas and to cool the crude synthesis gas to condense water and remove water (and optionally carbon dioxide) from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; (c) a hydrocarbon synthesis unit including a reactor containing a Fischer-Tropsch catalyst to receive the feed stream and to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons; and (d) a hydrocarbon synthesis unit configured to receive the feed stream and to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons. and an upgrading unit to which the product stream is supplied and configured to produce an upgraded product stream, wherein a separation facility is provided for separating a naphtha stream from the product stream or the upgraded product stream, wherein a first de-enrichment vessel containing a de-enrichment catalyst is configured to be supplied with at least a portion of the tail gas stream and steam, and a second de-enrichment vessel containing a de-enrichment catalyst is configured to be supplied with a portion of the naphtha stream, steam, and hydrogen, in each case to provide a gas mixture containing methane, and the first de-enrichment vessel and the second de-enrichment vessel are coupled to a reverse water gas shift unit to supply the gas mixture containing methane from the first de-enrichment vessel and the second de-enrichment vessel to the reverse water gas shift unit.

[0006] In the present invention, carbon dioxide is combined with hydrogen and used in a reverse water gas shift unit to form a crude synthesis gas. After cooling, water and optionally carbon dioxide are removed, and optionally hydrogen is added, to produce a feed gas for a hydrocarbon synthesis unit. The hydrocarbon synthesis unit supplies the hydrocarbon product mixture to an upgrading unit. A naphtha product stream is recovered from the hydrocarbon synthesis unit or the upgrading unit. Additionally, a tail gas stream containing unreacted carbon monoxide and hydrogen and a co-product water stream are recovered from the hydrocarbon synthesis unit. At least a portion of the tail gas stream and a portion of the naphtha stream are supplied, along with steam, to two or more de-enrichment vessels containing a de-enrichment catalyst, which convert the C2+ hydrocarbons therein to a gas mixture containing methane, which is supplied to the reverse water gas shift unit. Conditions in the de-enrichment vessels are different, and hydrogen is additionally supplied to the de-enrichment vessel to which naphtha is supplied. [Brief explanation of the drawings]

[0007] The present invention will now be described with reference to the accompanying drawings. [Figure 1] 1 shows a flowsheet of one embodiment of the present invention having separate tail gas and upgraded naphtha de-rich vessels. [Figure 2] 1 shows a flowsheet of a further embodiment of the present invention having separate tail gas and upgraded naphtha de-rich vessels. [Figure 3] 1 shows a flowsheet of a further embodiment of the present invention having separate tail gas, hydrocarbon off-gas, and upgraded naphtha de-enrichment vessels. [Figure 4] 1 shows a flowsheet of a further embodiment of the present invention having separate tail gas and hydrocarbon synthesis unit naphtha de-enrichment vessels.

[0008] The drawings are schematic and those skilled in the art will understand that in a commercial plant additional equipment may be required, such as reflux drums, compressors, pumps, vacuum pumps, columns, heat exchangers, temperature sensors, pressure sensors, pressure relief valves, control valves, flow controllers, level controllers, etc. Providing such ancillary equipment does not form part of the present invention and is in accordance with conventional chemical engineering practice. DETAILED DESCRIPTION OF THE INVENTION

[0009] As described in the Summary of the Invention section, the present specification provides a process for synthesizing hydrocarbons, the process comprising: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) cooling the crude synthesis gas to condense water and removing water (and optionally removing carbon dioxide) from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; and (c) passing the feed stream through a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to produce liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons. (d) upgrading the product stream in an upgrading unit to produce an upgraded product stream, wherein the naphtha stream is separated from the product stream or the upgraded product stream, at least a portion of the tail gas stream is supplied together with steam to a first de-enrichment vessel containing a de-enrichment catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is supplied together with hydrogen and steam to a second de-enrichment vessel containing a de-enrichment catalyst to form a second gas mixture containing methane, and the first and second gas mixtures containing methane are supplied to a reverse water gas shift unit.

[0010] The present specification also provides a system for carrying out the process, the system comprising: (a) a reverse water gas shift unit configured to receive a gas mixture comprising hydrogen and carbon dioxide and to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) a cooling and separation device configured to receive the crude synthesis gas and to cool the crude synthesis gas to condense water and remove water (and optionally remove carbon dioxide) from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; (c) a hydrocarbon synthesis unit including a reactor containing a Fischer-Tropsch catalyst to receive the feed stream and to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons; and d) an upgrading unit to which the product stream is supplied and configured to produce an upgraded product stream, wherein a separation facility is provided for separating a naphtha stream from the product stream or the upgraded product stream, wherein a first de-enrichment vessel containing a de-enrichment catalyst is configured to be supplied with at least a portion of the tail gas stream and steam, and a second de-enrichment vessel containing a de-enrichment catalyst is configured to be supplied with a portion of the naphtha stream, steam, and hydrogen, in each case to provide a gas mixture containing methane, and the first de-enrichment vessel and the second de-enrichment vessel are connected to a reverse water gas shift unit to supply the gas mixture containing methane from the first de-enrichment vessel and the second de-enrichment vessel to the reverse water gas shift unit.

[0011] The reverse water gas shift unit may include any suitable reactor or combination of reactors that performs the reverse water gas shift reaction. The reverse water gas shift unit may include a reactor containing a reverse water gas shift catalyst. Alternatively, the reverse water gas reactor unit may operate non-catalytically, i.e., without a catalyst. Thus, the process may include subjecting a gas mixture comprising hydrogen and carbon dioxide to a catalytic or non-catalytic reverse water gas shift reaction. The reverse water gas shift reaction may be expressed as follows:

[0012] [ka]

[0013] The reverse water gas shift process is therefore advantageous at high temperatures. The reverse water gas shift reactor can be plasma-heated or electrically heated. Thus, a gas mixture containing hydrogen and carbon dioxide can be subjected to an electrically heated reverse water gas shift reaction or a plasma-heated reverse water gas shift reaction. A gas mixture containing hydrogen and carbon dioxide can be subjected to an autothermal reverse water gas shift reaction. A particularly preferred reverse water gas shift unit includes an autothermal shift reactor, in which hydrogen and carbon dioxide are supplied as a mixture or separately to a burner in a reverse water gas shift vessel, where they are partially combusted with oxygen to produce a heated gas containing hydrogen, water vapor, carbon monoxide, and carbon dioxide, which passes through a bed of reverse water gas shift catalyst disposed downstream of the burner. Such a configuration is described in WO 2022 / 079408 A1. Hydrogen is combusted in the reverse water gas shift vessel to generate heat for the reverse water gas shift reaction. Therefore, in this configuration, hydrogen should be provided in excess of carbon dioxide so that sufficient hydrogen remains after combustion to drive the reaction over the reverse water gas shift catalyst. Excess hydrogen is also desirable given the potential end use of carbon monoxide-containing gas in the Fischer-Tropsch synthesis of hydrocarbons, where the H:CO ratio is preferably approximately 2:1. The molar ratio of hydrogen to carbon dioxide in the gas mixture fed to the burner can range from 1:1 to 5:1. This ratio can vary depending on the carbon dioxide conversion achieved in the reverse water gas shift unit and the desired hydrogen to carbon monoxide ratio for downstream processes.

[0014] The gas mixture containing carbon dioxide and hydrogen supplied to the burner may contain 15 to 50% by volume, preferably 25 to 40% by volume, of carbon dioxide. The gas mixture containing carbon dioxide and hydrogen supplied to the burner preferably contains less than 10% by volume in total of other gases such as water vapor, nitrogen, carbon monoxide, and methane.

[0015] Any suitable hydrogen source may be used. Two or more hydrogen sources may be used. The process preferably utilizes non-fossil fuel-based hydrogen. Thus, hydrogen may be produced by catalytic or non-catalytic partial oxidation of biomass or plastic, optionally followed by steam reforming of the partial oxidation product gas. Alternatively, hydrogen may be provided by water decomposition. Preferably, the hydrogen is electrolytic hydrogen, e.g., hydrogen formed by water electrolysis. Intermediate hydrogen storage may be used to reduce any fluctuations in hydrogen production from electrolysis. In some embodiments, co-product water from a hydrocarbon synthesis unit may be subjected to electrolysis to generate an electrolytic hydrogen stream used in the process. Such water electrolysis may advantageously use electricity from renewable sources, such as solar, wind, or tidal power. By using renewable electricity, the overall carbon intensity of the process may be negative, resulting in overall negative carbon dioxide emissions.

[0016] Any suitable carbon dioxide source may be used. Thus, the carbon dioxide stream may be a stream recovered from a conventional ammonia plant using a hydrocarbon or carbonaceous feed, or it may be recovered from the flue gas of a furnace or boiler heated by the combustion of a carbonaceous fuel, such as natural gas or coal, biomass, or carbonaceous waste, such as plastic. Alternatively, the carbon dioxide may be a CO stream separated from air or seawater. Preferably, at least a portion of the carbon dioxide is recycled downstream of the reverse water-gas shift unit after processing of crude synthesis gas in a downstream process that produces carbon dioxide as a by-product, such as a carbon dioxide removal unit and / or a Fischer-Tropsch hydrocarbon synthesis unit.

[0017] In some configurations, carbon dioxide may be at least partially recovered from a syngas stream produced by a syngas production unit upstream of the reverse water gas shift unit, with the advantage that the syngas production unit provides additional hydrogen and carbon monoxide for use in the hydrocarbon synthesis unit.

[0018] A syngas production unit can be any unit that converts a feedstock into a synthesis gas containing hydrogen, carbon monoxide, and carbon dioxide. Depending on the nature of the feedstock, various synthesis gas production technologies may be preferred. For example, if the feedstock is natural gas, the synthesis gas production unit preferably includes a catalytic partial oxidation unit, a non-catalytic partial oxidation unit, or an autothermal reformer. Alternatively, if the feedstock is coal, biomass, municipal solid waste, or the like containing non-biogenic carbon, the synthesis gas production unit preferably includes a gasifier. Any known gasification technology may be used. Preferably, gasification is carried out by partial oxidation, which involves burning the feedstock under substoichiometric conditions with air or oxygen at high temperatures, generally between 800°C and 1600°C, to obtain crude synthesis gas. If nitrogen-free synthesis gas is desired, this method uses oxygen. Gasification produces synthesis gas and a residual fraction containing tar oil. Synthesis gas is generally a gas mixture containing carbon monoxide, hydrogen, steam, and carbon dioxide. Additionally, synthesis gas typically contains sulfur-, nitrogen-, and halogen-containing impurities. Common sulfur-containing impurities are carbonyl sulfide (COS) and hydrogen sulfide (HS). These impurities, if present, are desirably removed upstream of the Fischer-Tropsch hydrocarbon synthesis unit using one or more contaminant removal stages, such as by scrubbing (absorption), by passing the crude synthesis gas through one or more beds of a suitable adsorbent, or a mixture thereof. Synthesis gas purification can occur in one or more stages before and / or after the carbon dioxide removal unit.

[0019] The reverse water gas shift unit and syngas production unit, if present, may use oxygen. The oxygen may be recovered from the air using an air separation unit (ASU), which may be powered by a renewable power source or steam generated in a reformed gas boiler, or other sources, including from downstream processes. Preferably, the oxygen used in the process comprises electrolytic oxygen, e.g., oxygen formed by electrolysis of water in an electrolysis unit. This has the advantage of reducing capital investment in the air separation plant and / or, if desired, reducing power consumption by the air separation plant.

[0020] Thus, both hydrogen and oxygen for the process are preferably produced using an electrolysis unit supplied with a water source. The water may include condensate recovered from the crude syngas mixture produced by the reverse water-gas shift unit or condensate recovered in an upstream syngas production unit, and / or water recovered from a downstream conversion unit, such as a Fischer-Tropsch hydrocarbon synthesis unit. Optionally, the water may be treated to remove contaminants, such as organic compounds or salts, that may adversely affect the electrolysis unit.

[0021] Desirably, the electricity for the electrolysis unit is not derived from the combustion of fossil fuels. Power for electrolysis may be provided by nuclear power, or preferably by renewable power sources such as photovoltaic solar energy, wind energy, tidal energy, hydroelectric or hydroelectric, marine energy sources, geothermal energy, and / or biomass. Electricity for electrolysis may also be provided using turbines driven by steam generated using heat recovered from product gas streams created by the partial oxidation of biomass or plastic waste. Power may be stored in intermediate facilities such as pumped hydroelectric storage or battery storage to provide a more constant supply of power to the electrolysis unit.

[0022] The carbon dioxide stream and the hydrogen stream, or the gas mixture containing carbon dioxide and hydrogen, may be compressed to a pressure in the range of 0.8 to 6.5 MPag, preferably 1.2 to 5.5 MPag, as required.

[0023] The gas stream fed to the reverse water gas shift unit may be preheated before compression, preferably after compression. The preheat temperature of the feed gas to the autothermal reverse water gas shift vessel is preferably in the range of 400-1000°C, preferably 450-800°C, to sustain combustion and minimize carbon formation. The hydrogen and carbon dioxide streams may be premixed before preheating, or may be preheated and then mixed. Preheating the feed to the preheat temperature may be performed by exchange with a crude syngas mixture and / or by steam heating, or by using a fired heater, or by electrical heating, or a combination of two or more of these. Preferably, the feed gas mixture comprising carbon dioxide and hydrogen is heated by exchange with a crude syngas mixture, optionally supplemented by electrical heating.

[0024] In the present invention, carbon dioxide is converted to carbon monoxide by subjecting it to a reverse water gas shift reaction in a reverse water gas shift unit comprising a reverse water gas shift vessel containing a reverse water gas shift catalyst.

[0025] A preferred reverse water gas shift unit includes an autothermal reverse water gas shift vessel containing a burner and a fixed bed of reverse water gas shift catalyst. The burner is supplied with a carbon dioxide-containing gas and an oxygen stream to combust a portion of the hydrogen and any hydrocarbons present in the carbon dioxide-containing gas, thereby generating heat for the endothermic reverse water gas shift reaction.

[0026] Oxygen and a gas mixture containing carbon dioxide and hydrogen are supplied to a burner located within the reverse water gas shift vessel. Any burner design, such as a burner used in an autothermal reformer, may be used. Combustion generates a flame in a combustion zone upstream of the catalyst within the reverse water gas shift vessel. Local conditions in the combustion section, particularly the flame front region, may be controlled by managing the momentum of the oxidant flow and the gas flow. The water gas shift vessel may be oriented so that the combustion zone is above a bed of reverse water gas shift catalyst. Such a configuration is used in an autothermal reforming vessel and may be used in the present process, which may be referred to as autothermal reverse water gas shift. However, other configurations of the burner and catalyst may also be used.

[0027] The gas mixture is heated by combustion, typically to a temperature in the range of 800-1300°C. Oxygen is consumed. The heated gas mixture, containing carbon monoxide, carbon dioxide, water vapor, and unreacted hydrogen, then passes through a bed of reverse water gas shift catalyst located in a reverse water gas shift vessel downstream of the burner.

[0028] The reverse water gas shift catalyst may be any suitable transition metal oxide catalyst, such as a nickel oxide, iron oxide, or chromium oxide-based catalyst, although other catalysts commonly used as reverse water gas shift catalysts may also be used. Preferably, the catalyst is a nickel oxide-based catalyst. Such catalysts are active for reverse water gas shift catalysis, but are advantageously provided by a de-riching vessel, for steam reforming methane present in a gas mixture containing hydrogen and carbon dioxide. Therefore, the catalyst preferably comprises nickel oxide on a suitable refractory metal oxide support. Refractory metal oxide supports may include zirconia, alumina, calcium aluminate, magnesium aluminate, titania-magnesia, or mixtures thereof. More preferably, the catalyst comprises nickel oxide on zirconia, nickel oxide on α-alumina, nickel oxide on calcium aluminate, or nickel oxide on magnesium aluminate. The nickel content, expressed as NiO, may range from 3 to 20 wt.%.

[0029] The reverse water gas shift catalyst may be in particulate form, e.g., in the form of shaped units such as pellets, rings, or extrudates, which may be leaf- or groove-shaped. The catalytically active metal, e.g., nickel, may be dispersed throughout the particulate catalyst or may be present only in an eggshell layer 200 to 1000 micrometers thick on the surface of a refractory support. Alternatively, the catalyst may comprise one or more monolithic supports, such as metal or ceramic foams or honeycombs, supporting the catalytically active metal. Preferably, the catalyst is a particulate catalyst, more preferably a four-hole cylinder, especially one that is leaf- or groove-shaped to provide a higher geometric surface area (GSA) than a solid cylinder of similar size. 400 to 550 m per cubic meter. 2 Catalysts having a GSA in the range of

[0030] If desired, a layer of zirconia balls, pellets, or tiles may be placed on top of the reverse water gas shift catalyst to protect the catalyst surface from irregularities in the combustion gas flow. The benefit of this layer is that it prevents disturbances to the surface of the catalyst bed.

[0031] By controlling the preheat temperature and the amount of oxygen supplied to the burner, it is possible to control the outlet temperature of the reverse water gas shift vessel, which can be in the range of 700°C to 1050°C, preferably 750°C to 950°C.

[0032] In the present invention, in addition to producing a carbon monoxide gas stream by the reverse water gas shift reaction, the reverse water gas shift vessel is used to convert methane produced from a waste stream from a downstream process to carbon monoxide. Thus, the reverse water gas shift vessel is supplied with methane-containing gas streams from a first de-enrichment vessel and a second de-enrichment vessel. The first de-enrichment vessel is supplied with at least a portion of the tail gas recovered from a Fischer-Tropsch hydrocarbon synthesis unit. The second de-enrichment vessel is supplied with a portion of naphtha recovered from a hydrocarbon synthesis unit or an upgrading unit connected to the hydrocarbon synthesis unit.

[0033] The de-rich vessels operate by adiabatic steam reforming of hydrocarbons in the tail gas and naphtha streams. Therefore, a supply of steam to the de-rich vessel is also required. Additionally, a source of hydrogen is also supplied to the second de-rich vessel to adequately steam reform the naphtha without catalyst deactivation due to carbon formation.

[0034] In the present invention, at least a portion of the tail gas stream is supplied together with steam to a first de-enrichment vessel containing a de-enrichment catalyst to form a gas mixture containing methane, and at least a portion of the naphtha stream is supplied together with hydrogen and steam to a second de-enrichment vessel containing a de-enrichment catalyst to form a second gas mixture containing methane. The introduction of steam may be carried out by direct injection of steam and / or by saturating the feed gas by contact with a heated water stream. The heated water may include condensed water from a downstream process containing soluble organic compounds. Alternatively, the steam used for direct injection may be used to strip organic compounds from condensed water from the downstream process. In this way, the organic compounds may be converted to hydrogen and carbon oxides in the de-enrichment vessel, and the wastewater treatment burden for the downstream process may be reduced.

[0035] The amount of steam introduced can be such that the steam to carbon molar ratio in the feed to the de-riching vessel is between 0.1:1 and 5:1, where steam to carbon molar ratio refers to the molar ratio of steam to the sum of carbon-containing components in the feed, including hydrocarbons, CO, and CO2.

[0036] The de-enrichment vessel feed gas typically has an inlet temperature in the range of 250-650°C. The feed gas can be passed adiabatically through a bed of de-enrichment catalyst, such as a particulate nickel catalyst having a high nickel content, for example, greater than 40 wt%. Such catalysts are commercially available. The same or different catalysts can be used in the first and second de-enrichment vessels.

[0037] A hydrogen stream is fed to the second de-richment vessel along with the naphtha to ensure conversion of the naphtha to methane. The hydrogen may be a pure hydrogen stream or may contain a suitably high hydrogen content to provide hydrogen for de-richment. In some embodiments, the pure hydrogen stream may be supplemented with hydrogen-containing off-gas from the hydrocarbon synthesis unit and / or upgrading unit.

[0038] During the de-enrichment step, any hydrocarbons higher than methane react with the steam to produce a mixture of methane, carbon oxides, and hydrogen.

[0039] In some configurations, the first de-riching vessel operates at an inlet temperature in the range of 250-650°C, preferably 300-400°C, and a steam to carbon molar ratio of 0.1:1 to 5:1.

[0040] If desired, the first de-riching vessel may be operated at a pressure in the range of 1.0 to 7.0 MPa g, preferably 1.5 to 6.6 MPa g.

[0041] In some configurations, the second de-riching vessel operates at an inlet temperature in the range of 400-550°C, a steam to carbon molar ratio of 1:1 to 5:1, and a minimum H2 content of 0.001 kg H2 per kg of carbon-containing component in the feed.

[0042] If desired, the second de-riching vessel may be operated at a pressure in the range of 1.0 to 7.0 MPa, preferably 1.5 to 6.6 MPa. The operating pressures of the first and second de-riching vessels may be the same or different.

[0043] Producing a methane-containing gas mixture is preferred over feeding the tail gas, hydrocarbon off-gas, and naphtha stream directly to the reverse water gas shift unit to reduce the risk of undesirable carbon formation in the reverse water gas shift vessel or on the reverse water gas shift catalyst.

[0044] In the present invention, the methane-containing gas mixture recovered from the de-enrichment vessel is supplied to a reverse water gas shift unit. The methane-containing gas mixture can be supplied separately from the de-enrichment vessel to the reverse water gas shift unit, or can be mixed with one or both of the hydrogen and carbon dioxide feed streams. The methane-containing gas mixture can optionally be preheated. The methane-containing gas mixture can be preheated separately or can be combined with the hydrogen and carbon dioxide feed streams at once. When using an autothermal reverse water gas shift reactor, the methane-containing gas mixture can be preheated to a temperature in the range of 400 to 1000°C, preferably 450 to 800°C, to maintain combustion and minimize carbon formation.

[0045] The hydrocarbon synthesis unit produces a product stream that is upgraded in the upgrading unit. The product stream comprises a mixture of gaseous and liquid hydrocarbons. In some configurations, a naphtha stream of the hydrocarbon synthesis unit can be separated from the product stream upstream of the upgrading unit. The naphtha stream can be recovered by cooling the product stream and separating it using one or more gas-liquid separators. The naphtha stream recovered from the hydrocarbon synthesis unit typically comprises a mixture of C3 to C9 hydrocarbons with an approximate final boiling point below 240°C.

[0046] Additionally, the hydrocarbon synthesis unit may be operated to produce a hydrocarbon synthesis unit hydrocarbon off-gas stream by physically separating light gaseous hydrocarbons, e.g., C1, C2, C3 and C4 hydrocarbons, from heavier liquid hydrocarbons and co-product water, which are fed to one or more gas-liquid separators in the FT unit.

[0047] The upgrading unit may be configured to produce an upgraded naphtha stream from the product stream. The upgraded naphtha stream may be recovered in the upgrading unit from one or more distillation columns in which the feed is heated and the hydrocarbons are separated based on their boiling points. The naphtha product stream recovered from the upgrading unit typically contains saturated hydrocarbons, typically C5 to C11, having boiling points in the range of 30 to 220°C.

[0048] Generally, the second de-enrichment vessel is fed with either naphtha from a hydrocarbon synthesis unit or naphtha from an upgrading unit. Thus, a naphtha stream from a hydrocarbon synthesis unit or an upgrading unit may be compressed, vaporized, mixed with steam and hydrogen, and fed to the second de-enrichment vessel.

[0049] The upgrading unit may be configured to further produce an upgraded hydrocarbon off-gas stream. The upgraded hydrocarbon off-gas stream may be recovered in the upgrading unit from a letdown vessel in which the pressure of the mixed hydrocarbon feed is reduced to flash or vaporize light hydrocarbons, or from one or more distillation columns in which the feed is heated to separate hydrocarbons based on their boiling points. The letdown vessel and one or more distillation columns may be downstream of the hydrotreating unit. The upgraded off-gas typically contains saturated hydrocarbons, hydrogen, methane, carbon monoxide, carbon dioxide, and inert contaminants such as nitrogen.

[0050] One or both of the hydrocarbon off-gas streams may be usefully recycled to the process to further improve the carbon efficiency of the process and minimize carbon-containing streams sent to fuel that ultimately result in carbon dioxide emissions. Because the off-gas streams may be produced at similar pressures, it may be advantageous to compress them together, rather than individually, before feeding them to the de-riching vessel.

[0051] Thus, the upgraded hydrocarbon off-gas and, optionally, the hydrocarbon synthesis unit's hydrocarbon off-gas may be supplied to the first de-enrichment vessel and / or the second de-enrichment vessel. Alternatively, one or more additional de-enrichment vessels may be provided for processing one or both of the hydrocarbon off-gas streams. The destination of the off-gas streams depends on the proportions of C2, C3, and C4 hydrocarbons present when these streams are combined with the tail gas or naphtha stream. For operational flexibility and optimized operating conditions, it may be advantageous to supply the off-gas to a third de-enrichment vessel. Thus, in some configurations, at least a portion of the upgraded hydrocarbon off-gas, steam, and, optionally, a portion of the hydrocarbon synthesis unit's hydrocarbon off-gas are supplied to a third de-enrichment vessel containing a de-enrichment catalyst to produce a further gas mixture containing methane, which is supplied to the reverse water gas shift unit. If desired, a hydrogen stream may be supplied to one or more additional de-enrichment vessels to improve de-enrichment of the off-gas stream.

[0052] In some configurations, the one or more additional de-riching vessels may be configured to operate at an inlet temperature in the range of 300-500°C, a steam to carbon molar ratio of 1:1 to 5:1, and a minimum H2 content of 0.001 kg H2 per kg of carbon-containing component in the feed.

[0053] If desired, the one or more further de-riching vessels may be operated at a pressure in the range of 1.0 to 7.0 MPa, preferably 1.5 to 6.6 MPa. The pressure in the one or more further de-riching vessels may be the same as or different from the first and second de-riching vessels.

[0054] The upgrading unit may also be operated to further produce a light hydrocarbon liquid stream that may be recycled to the first de-enrichment vessel, the second de-enrichment vessel, or one or more further de-enrichment vessels, as desired. The light hydrocarbon liquid stream comprises primarily C3 and C4 saturated hydrocarbons. If used, the light hydrocarbon liquid requires compression and vaporization before being fed to the one or more further de-enrichment vessels.

[0055] The proportions of naphtha, tail gas, off-gas, and the light hydrocarbon stream fed to the de-riching vessel will vary depending on the product list produced from the upgrading unit and the tail gas recycle ratio in the hydrocarbon synthesis unit. The tail gas mass fraction is expected to be greater than the off-gas stream, and there will be enough hydrogen in the tail gas to avoid the need for further hydrogen addition to the first de-riching vessel if off-gas is also fed.

[0056] If sulfur contaminants are present in the naphtha and upgraded hydrocarbon off-gas streams in the upgrading unit, they may be removed by subjecting the naphtha and upgraded off-gas streams, preferably after compression, to a desulfurization step upstream of the de-enrichment step. This may be accomplished using any suitable desulfurization method, for example, a method comprising absorbing sulfur compounds by passing the stream through a bed of zinc oxide absorbent.

[0057] The upgraded hydrocarbon off-gas may be recovered at a pressure in the range of 0.1 to 1.0 MPa g. The hydrocarbon off-gas from the hydrocarbon synthesis unit may be recovered at a pressure in the range of 0.1 to 1.0 MPa g. If desired, the upgraded hydrocarbon off-gas and the hydrocarbon off-gas from the hydrocarbon synthesis unit may be compressed to a pressure in the range of 1.0 to 7.0 MPa g. The off-gases may be compressed separately or, preferably, combined and compressed.

[0058] The methane-containing gas mixture from the first de-enrichment vessel, the second de-enrichment vessel, and the one or more additional de-enrichment vessels contains unreacted water vapor. If desired, although not typically required, the water vapor can be condensed by cooling the de-enriched gas mixture below its dew point and recovering the condensate to produce a dehydrated, de-enriched gas feed to the reverse water-gas shift unit. Removing the water vapor can improve the reverse water-gas shift equilibrium. The recovered condensate can be usefully used to generate water vapor for the process or can be used to produce hydrogen by water electrolysis.

[0059] The methane-containing gas mixture may optionally be compressed before being fed to the inlet of the reverse water gas shift unit. Compression may be carried out before or, preferably, after any dehydration step.

[0060] The gas mixture feed comprising hydrogen and carbon dioxide for the reverse water gas shift unit may be preheated and combined with the methane-containing gas stream from the de-riching vessel, or the methane-containing gas stream may be optionally preheated and fed separately to the reverse water gas shift reactor.

[0061] The reverse water gas shift unit converts carbon dioxide to carbon monoxide and consumes some hydrogen via the reverse water gas shift reaction described above. The reverse water gas shift unit produces a crude synthesis gas mixture.

[0062] The crude syngas mixture from the reverse water-gas shift vessel contains water vapor formed by the reverse water-gas shift reaction and, optionally, water vapor added with the methane-containing gas mixture. Water is recovered from the crude syngas mixture by cooling the product gas mixture below its dew point and separating the condensate, for example, using one or more conventional gas-liquid separators. Removal of the water condensate from the crude syngas mixture produces a dehydrated product gas. Cooling can be achieved by raising the water vapor and / or by preheating one or more of the hydrogen stream, the carbon dioxide stream, the mixed gas stream containing hydrogen and carbon dioxide, and, optionally, the de-riching vessel feed gas. Further cooling with chilled water and / or air may also be performed. The process steam produced by cooling may be used in the de-riching step or in downstream processes and / or for power generation.

[0063] The condensate may be at least partially recycled to the process, if desired. The condensate may be used as boiler feedwater, after treatment, if desired. Additionally, or alternatively, the condensate, optionally after treatment for use of contaminants, may be fed to an electrolysis unit used to generate hydrogen for the process. Thus, in some embodiments, a water stream recovered from the crude syngas mixture may be fed to the electrolysis unit. The condensate may also be used as boiler feedwater, again, after treatment, if desired.

[0064] The crude syngas mixture contains carbon dioxide, which is removed from the dehydration product gas using a carbon dioxide removal unit. The majority of the carbon dioxide can be separated using a membrane, a solid absorbent, or preferably a scrubbing system, for example, a system that operates by countercurrently contacting the crude syngas mixture or the dehydration product gas with an absorbing liquid over packing in a column. The absorbing liquid can be a physical solvent such as potassium carbonate (sold as the Benfield process), methanol (sold as the Rectisol process), or glycol (sold as the Selexol process), or a chemical solvent such as an amine. Thus, the carbon dioxide removal unit may include one or more vessels providing a physical or reactive scrubbing system, preferably a reactive scrubbing system, particularly an amine scrubbing system. Carbon dioxide may also be removed by a conventional acid gas recovery unit (AGRU). In a conventional AGRU, the dehydrated gas stream is contacted with a suitable absorbing liquid, such as an amine, for example, monoethanolamine (MEA), methyldiethanolamine (MDEA), or dimethylethanolamine (DMEA), particularly a stream of aqueous solution containing methyldiethanolamine (MDEA), resulting in carbon dioxide absorption into the liquid to produce a loaded absorbing liquid and a gas stream with reduced carbon dioxide content. The loaded absorbing liquid is then regenerated by heating and / or depressurization to desorb the carbon dioxide and produce a regenerated absorbing liquid, which is then recycled to the carbon dioxide adsorption stage. Heat from the regeneration of the loaded absorbent can be recovered from within the process. For example, a portion of the crude syngas mixture or steam generated by cooling the crude syngas mixture can be used to heat the loaded absorbent.

[0065] Alternatively, instead of washing with an amine, cold methanol or glycol may be used in the same manner as the amine to remove carbon dioxide.

[0066] The recovered carbon dioxide obtained from the carbon dioxide removal unit is preferably recompressed, if necessary, and returned to the reverse water gas shift vessel to increase the overall carbon monoxide conversion.

[0067] The recovered carbon dioxide may be combined with the carbon dioxide feed, hydrogen gas feed, or a gas mixture containing hydrogen and carbon monoxide prior to preheating, and is preferably combined with the carbon dioxide feed stream prior to its compression.

[0068] Removal of carbon dioxide from the dehydration product gas produces a gas stream containing carbon monoxide. Hydrogen is also present in the product gas, the amount of which depends on the excess amount of hydrogen fed to the reverse water gas shift vessel. If desired, one or more purification units can be provided downstream of the carbon dioxide removal unit to remove contaminants from the carbon monoxide-containing gas stream.

[0069] The carbon monoxide-containing gas stream comprises carbon monoxide and hydrogen, and the hydrogen to carbon monoxide molar ratio may be in the range of 1.0 to 2.5:1, preferably 1.2 to 2.5:1, and more preferably 1.6 to 2.2, which is particularly suitable for hydrocarbon synthesis by the Fischer-Tropsch reaction.

[0070] In the present invention, the product gas is fed to a Fischer-Tropsch hydrocarbon synthesis unit which synthesizes a mixture of hydrocarbon products.

[0071] The Fischer-Tropsch hydrocarbon synthesis unit may include one or more Fischer-Tropsch reactor vessels containing a Fischer-Tropsch catalyst. The Fischer-Tropsch conversion step may be carried out according to any one of known processes and using any one of known catalysts, but is advantageously applied to a process using a cobalt catalyst.

[0072] The Fischer-Tropsch process is ideally carried out according to the equation (C n H 2n+2This involves a series of chemical reactions that produce various hydrocarbons with different structures. The more useful reactions produce alkanes as follows: (2n+1)H2+nCO→C n H 2n+2 +nH2O In the formula, n is typically 5 to 100 or more, with preferred products having n in the range of 10 to 20.

[0073] The Fischer-Tropsch reaction can be carried out using one or more reactors, such as fixed-bed reactors, slurry-phase reactors, bubble column reactors, loop reactors, or fluidized-bed reactors. The process can operate at pressures ranging from 0.1 to 10 MPa and temperatures ranging from 170 to 350 °C. The gas-hourly-space velocity (GHSV) for continuous operation ranges from 1,000 to 25,000 h . -1The Fischer-Tropsch synthesis is preferably carried out using one or more fixed-bed reactors, i.e., reactors with a catalyst bed fixed within a vessel through which purified synthesis gas passes. While any Fischer-Tropsch catalyst can be used, cobalt-based Fischer-Tropsch catalysts are preferred over iron-based catalysts due to their lower carbon dioxide selectivity. While suitable cobalt Fischer-Tropsch catalysts are known, the preferred catalyst for this process contains 9-20 wt.% Co supported on a suitable support material. Thus, suitable catalysts include aggregates, pellets, or extrudates comprising metal oxides such as alumina, zinc oxide, titania, or silica, or mixtures thereof, onto which a catalytically active metal, preferably cobalt, is deposited. In a particularly preferred configuration, the Fischer-Tropsch catalyst is used in combination with a catalyst support suitable for use in a tubular Fischer-Tropsch reactor, in which the catalyst-containing catalyst support is placed within one or more tubes that are cooled by circulating a coolant, such as water, under pressure. "Catalyst support" refers to a catalyst vessel, e.g., in the form of a cup or can, configured to allow gas and / or liquid to flow into and out of the support and through a bed of catalyst or catalyst precursor disposed within the support. Any suitable catalyst support may be used. In one configuration, the catalyst support is one described in WO 2011 / 048361, the contents of which are incorporated herein by reference. In an alternative configuration, the catalyst support may comprise a catalyst monolith such as that disclosed in WO 2012 / 136971, the contents of which are also incorporated herein by reference. In yet another alternative configuration, the catalyst support may be one disclosed in WO 2016 / 050520, the contents of which are also incorporated herein by reference. In a preferred embodiment, the Fischer-Tropsch hydrocarbon synthesis unit comprises a tubular reactor in which a catalyst support containing a Fischer-Tropsch catalyst is disposed within one or more tubes that are cooled by a cooling medium.

[0074] Typically, a portion of the carbon monoxide is converted in one or more Fischer-Tropsch reactors to produce a mixture of liquid hydrocarbon products, co-product water, a gaseous mixture containing unreacted hydrogen and carbon monoxide, carbon dioxide, and gaseous light hydrocarbons, including methane, ethane, propane, and butane. The reaction product mixture may be cooled, and aqueous and liquid hydrocarbon streams may be separated from the gas mixture using one or more gas-liquid separators. The co-product water may be separated using a known hydrocarbon-water separator. The separated gas mixture may be referred to as "tail gas" and may be used in a number of ways. Preferably, a first portion of the tail gas is recycled to one or more Fischer-Tropsch reactors in the synthesis loop to increase the overall conversion of carbon monoxide to hydrocarbons. The fraction recycled to form the loop may be configured to control the accumulation of inert gases, such as methane, in the Fischer-Tropsch hydrocarbon synthesis unit to an acceptable level. The remaining fraction still contains a valuable carbon source. Thus, in the present invention, a portion of the tail gas is recycled to the reverse water gas shift unit via a first de-enrichment vessel containing a de-enrichment catalyst that converts any C2+ higher hydrocarbons present in a second portion of the tail gas to methane. Steam is added to the second portion to provide a suitable steam-to-carbon ratio for the de-enrichment step. The portion not recycled to the reverse water gas shift unit may be referred to as "purge gas" and may be removed from the process to prevent the accumulation of inert gases. The purge gas may be delivered as fuel or used within the process in a combustion heater or thermal oxidizer to heat the feed to the reverse water gas shift vessel or to superheat steam.

[0075] The liquid hydrocarbons recovered from the hydrocarbon synthesis unit are subjected to upgrading in an upgrading unit to provide more valuable hydrocarbon products. The upgrading unit may be fed with one or more liquid hydrocarbon streams produced by the hydrocarbon synthesis unit, including, but not limited to, molten hydrocarbon wax and light hydrocarbon condensates that are liquid at ambient temperatures.

[0076] Desirably, the hydrocarbon synthesis unit is operated to produce molten hydrocarbon wax liquids, which are subjected to upgrading processing in a hydroprocessing unit to produce liquid fuels. Thus, in some embodiments, at least a portion, preferably all, of the liquid hydrocarbon mixture resulting from hydrocarbon synthesis is supplied as a feedstock to an upgrading unit, including a hydroprocessing unit, in the presence of hydrogen. The hydroprocessing unit may perform various transformations, such as hydroisomerization, hydrogenation, hydrodeoxygenation, and / or hydrocracking, using one or more vessels containing suitable catalysts. Hydrogen is required in the hydroprocessing unit. This can be provided by a variety of sources, but is desirably provided by an electrolysis unit to minimize carbon dioxide emissions from the process. Thus, in some embodiments, a portion of the hydrogen stream from the electrolysis unit is supplied to the hydroprocessing unit.

[0077] The hydrotreating unit may generally operate at a temperature of 200-450°C, preferably 250-450°C, more preferably 300-450°C, and most preferably 320-420°C, a pressure of 0.2-15MPag, preferably 0.5-10MPag, and more preferably 1-9MPag, a liquid hourly space velocity of 0.1-10h-1, preferably 0.2-7h-1, and more preferably 0.5-5.0h-1, and the hydrogen content may be 100-2000 liters H2 per liter of feed, preferably 150-1500 liters H2 per liter of feed.

[0078] The hydrotreating step may suitably be carried out under conditions such that the conversion per pass of products boiling above 370°C to products boiling below 370°C is greater than 40% by weight, more preferably at least 50% by weight, thereby obtaining middle distillates (gas oils and kerosenes) with sufficiently good low temperature properties (pour point, freezing point) to meet the specifications in force for this type of fuel.

[0079] The catalysts used in this step are known. For example, hydroisomerization and hydrocracking can be carried out using any one of known catalysts and according to any one of known processes, and are not limited to a specific process or catalyst. Most catalysts suitable for hydroisomerization / hydrocracking are bifunctional, combining acid and hydrogenation functionalities. The acid functionality is generally provided via a support with a high specific surface area (generally 150-800 m / g) that exhibits surface acidity, such as halogenated (especially chlorinated or fluorinated) alumina, phosphorus-containing alumina, a combination of boron oxide and aluminum oxide, or silica / alumina. The hydrogenation functionality is generally provided either by one or more metals from Group VIII of the periodic table, such as iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum, or by a combination of at least one metal from Group VI, such as chromium, molybdenum, and tungsten, with at least one metal from Group VIII. Most conventional hydrocracking catalysts are composed of weakly acidic supports such as silica / alumina. These systems are typically used to produce middle distillates of very good quality. Many catalysts on the hydrocracking market are based on silica / alumina in combination with metals from Group VIII. These systems have very good selectivity for middle distillates, and the products formed are of good quality. According to a preferred embodiment, the hydroisomerization / hydrocracking catalyst comprises at least one hydrogenation-dehydrogenation element selected from Group VIII noble metals, preferably platinum and / or palladium, and at least one amorphous refractory oxide support, preferably silica / alumina.

[0080] The hydrocarbon products recovered from the hydroprocessing unit may be fed to a separation unit to recover valuable hydrocarbon products. The separation unit may comprise one or more atmospheric distillation columns, and optionally one or more vacuum distillation columns, which separate the upgraded hydrocarbon off-gas, a naphtha fraction, preferably at least one kerosene and / or gas oil fraction, and a heavy fraction. The heavy fraction generally exhibits an initial boiling point of at least 350°C, preferably above 370°C. This fraction is advantageously recycled to the hydroprocessing unit. It may also be advantageous to recycle a portion of the kerosene to the hydroprocessing unit. The gas oil and kerosene fractions may or may not be recovered separately, and the cut points may be adjusted to produce the desired hydrocarbon products.

[0081] Examples of the present specification will now be described with reference to the accompanying figures.

[0082] In FIG. 1 , a carbon dioxide stream 10, such as a carbon dioxide stream recovered from flue gas, is fed to a reverse water gas shift unit 12. The reverse water gas shift unit includes an autothermal reverse water gas shift vessel containing a bed of reverse water gas shift catalyst positioned below a burner (not shown). Hydrogen, for example, hydrogen produced by an electrolysis unit, is fed to the process via line 14. A portion of the hydrogen is removed from line 14 via line 16 for downstream use, and the remaining portion is fed via line 18 to the reverse water gas shift unit 12, where it is subjected to combustion with oxygen in the autothermal reverse water gas shift vessel and passed through a bed of reverse water gas shift catalyst along with carbon dioxide 10. The reverse water gas shift reaction occurs over the catalyst to form a synthesis gas containing carbon monoxide, hydrogen, carbon dioxide, and water vapor. The reverse water gas shift unit further includes a refrigeration system (not shown) that cools the synthesis gas recovered from the reverse water gas shift vessel below its dew point, and a gas-liquid separator that recovers liquid condensate from the cooled synthesis gas to form a dehydrated synthesis gas. The reverse water gas shift unit further includes a CO2 removal unit (not shown) to which the dehydrated syngas is fed. The CO2 removal unit operates by an amine wash to remove CO2 from the dehydrated syngas, producing a FT syngas consisting essentially of carbon monoxide and hydrogen. The CO2 recovered from the CO2 removal unit may be combined with carbon dioxide fed via line 10 to feed the reverse water gas shift vessel.

[0083] The FT synthesis gas is supplied from the reverse water gas shift unit via line 20 to a hydrocarbon synthesis unit 22, which includes one or more Fischer-Tropsch reactors containing a Fischer-Tropsch catalyst. The Fischer-Tropsch reaction occurs to form liquid hydrocarbon products, co-product water, a tail gas stream containing unreacted carbon monoxide and hydrogen, and gaseous hydrocarbons. The hydrocarbon synthesis unit further includes a refrigeration system and a gas-liquid separator (not shown) that separates the liquid hydrocarbon products from the co-product water and tail gas. A portion of the tail gas is recycled to the one or more Fischer-Tropsch reactors. The remaining portion of the tail gas stream is recovered from the hydrocarbon synthesis unit 22 via line 24 for further processing. The liquid hydrocarbon products are supplied from the hydrocarbon synthesis unit 22 via line 28 to an upgrading unit 30.

[0084] Upgrading unit 30 is also supplied with a portion of hydrogen stream 16 via line 32. The upgrading unit includes a hydrotreater containing a hydrotreating catalyst (not shown) that upgrades liquid hydrocarbons 28 with hydrogen provided via line 32 to form a fuel mixture. Upgrading unit 30 further includes one or more distillation units (not shown) that separate the fuel mixture into various products. The upgrading unit thereby provides a liquid kerosene stream recovered via line 36, a liquid diesel stream recovered via line 38, and a liquid naphtha stream recovered via line 40. A portion of the liquid naphtha stream is recovered from line 40 via line 42 for further processing.

[0085] A portion 24 of the tail gas recovered from the hydrocarbon synthesis unit 22 is supplied to a first de-enrichment vessel 44 containing a de-enrichment catalyst. Steam is supplied to the first de-enrichment vessel via line 46. The de-enrichment catalyst converts C hydrocarbons in the tail gas to methane. The resulting methane-containing gas mixture is supplied from the de-enrichment vessel 44 via line 48 to an autothermal reverse water gas shift vessel of the reverse water gas shift unit 12.

[0086] A portion of the naphtha is supplied via line 42 to a second de-enrichment vessel 50 containing a de-enrichment catalyst. Steam is supplied to the second de-enrichment vessel via line 54. A portion of the hydrogen stream 16 is also supplied to the second de-enrichment vessel via line 56. The de-enrichment catalyst converts C hydrocarbons in the naphtha to methane. The resulting methane-containing gas mixture is supplied from the de-enrichment vessel 50 via line 58 to an autothermal reverse water-gas shift vessel of the reverse water-gas shift unit 12.

[0087] Optionally, in some configurations, hydrocarbon synthesis unit hydrocarbon off-gas, indicated by dashed line 26, may be recovered from hydrocarbon synthesis unit 22 and fed to second de-enrichment vessel 50. Alternatively, or in addition, upgraded hydrocarbon gas, indicated by dashed line 34, may be recovered from upgrading unit 30 and fed to second de-enrichment vessel 50. In this manner, the naphtha feed to the second de-enrichment vessel may optionally be supplemented with a hydrocarbon off-gas stream that may be usefully de-enriched under the same conditions as the naphtha.

[0088] 2 is similar to FIG. 1, except that instead of feeding off-gas streams 26 and 34 along with naphtha stream 42 to second de-enrichment reactor 50 via line 52, off-gas streams 26 and 34 are combined and fed along with tail gas stream 24 via line 52 to first de-enrichment vessel 44. Thus, second de-enrichment vessel 50 is fed only with the naphtha stream via line 42, steam via line 54, and hydrogen via stream 56.

[0089] Figure 3 is similar to Figure 1 except that there are separate tail gas, off-gas, and naphtha de-enrichment vessels. Thus, in Figure 3, a first de-enrichment vessel is supplied with only tail gas via line 24 and steam via line 46, while a second de-enrichment vessel 50 is supplied with only the naphtha stream via line 42, steam via line 54, and hydrogen via stream 56. Off-gas streams 26 and 34 are combined and supplied via line 52 to a third de-enrichment vessel 60 containing a de-enrichment catalyst. Steam is supplied to the third de-enrichment vessel via line 62. A portion of hydrogen stream 56 is optionally supplied to the third de-enrichment vessel, as indicated by dashed line 64. The de-enrichment catalyst converts C2+ hydrocarbons in the off-gas to methane. The resulting methane-containing gas mixture is fed from de-riching vessel 60 via line 66, combined with the methane-containing gas mixture in line 58, and fed via line 68 to the autothermal reverse water gas shift vessel within reverse water gas shift unit 22.

[0090] FIG. 4 is similar to FIG. 1 except that upgrade naphtha stream 42 is omitted and instead hydrocarbon synthesis unit naphtha stream 70 is fed from hydrocarbon synthesis unit 22 to second de-rich vessel 50.

[0091] The invention will now be further illustrated by reference to the following example according to FIG. 1 without the off-gas feeds 26 and 34 to the second de-enrichment reactor 50.

[0092] The flowsheet was modeled to produce 1000 bbl / d of FT crude hydrocarbon product. The operating conditions and compositions of the streams were as follows:

[0093] [Table 1]

[0094] The present invention provides the following advantages: 1. The process maximizes the hydrogen and carbon efficiency of the flowsheet by recycling naphtha (and off-gas) in addition to the Fischer-Tropsch tail gas. 2. Industry demand for sustainable aviation fuel results in a preference for a high jet fuel / kerosene product list. However, schemes with higher kerosene yields produce a larger proportion of naphtha than schemes with higher diesel yields. If the naphtha is not valuable, it may be economically preferable to recycle the naphtha and maximize the carbon input to the kerosene product. 3. The tail gas / off gas / naphtha stream requires de-riching before being fed to the reverse water gas shift unit to prevent carbon contamination of the reactor.

Claims

1. 1. A process for synthesizing hydrocarbons, the process comprising: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) cooling the crude synthesis gas to condense water and removing water from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; (c) passing the feed stream through a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons; and (d) converting the feed stream into an upgrading unit. upgrading the product stream in a unit to produce an upgraded product stream, wherein a naphtha stream is separated from the product stream or the upgraded product stream; at least a portion of the tail gas stream is supplied with steam to a first de-enrichment vessel containing a de-enrichment catalyst to form a first gas mixture containing methane; at least a portion of the naphtha stream is supplied with hydrogen and steam to a second de-enrichment vessel containing a de-enrichment catalyst to form a second gas mixture containing methane; and the first gas mixture and the second gas mixture containing methane are supplied to the reverse water gas shift unit.

2. 10. The process of claim 1, wherein in step (b), carbon dioxide is also removed from the crude syngas.

3. 3. The process of claim 1 or 2, comprising subjecting the gas mixture comprising hydrogen and carbon dioxide to a catalytic or non-catalytic reverse water gas shift reaction.

4. 4. The process according to any one of claims 1 to 3, wherein the gas mixture comprising hydrogen and carbon dioxide is subjected to an autothermal reverse water gas shift reaction, or an electrically heated reverse water gas shift reaction, or a plasma heated reverse water gas shift reaction.

5. 5. The process of any one of claims 1 to 4, wherein the reverse water gas shift unit comprises an autothermal shift reactor in which hydrogen and carbon dioxide are fed to a burner in a reverse water gas shift vessel where the hydrogen and carbon dioxide are partially combusted with oxygen to produce heated gas comprising hydrogen, water vapor, carbon monoxide, and carbon dioxide, and the heated gas is passed through a bed of reverse water gas shift catalyst disposed downstream of the burner.

6. 6. The process of claim 5, wherein the gas mixture comprising carbon dioxide and hydrogen supplied to the burner comprises 15 to 50% by volume, preferably 25 to 40% by volume, of carbon dioxide.

7. 7. The process of claim 5 or 6, wherein the feed gas to the autothermal shift reactor is preheated to a temperature in the range of 400 to 1000°C, preferably 450 to 800°C.

8. 8. The process of any one of claims 5 to 7, wherein the reverse water gas shift catalyst is a nickel oxide-based catalyst containing 3 to 20 wt. % nickel expressed as NiO.

9. 9. The process of any one of claims 1 to 8, wherein the hydrogen supplied to the reverse water gas shift unit is a non-fossil fuel based hydrogen stream produced by catalytic or non-catalytic partial oxidation of biomass or plastics, or by water electrolysis.

10. 10. The process of any one of claims 1 to 9, wherein the carbon dioxide supplied to the reverse water gas shift unit is a carbon dioxide stream recovered from an upstream synthesis gas production unit, a carbon dioxide stream recovered from an ammonia plant using a hydrocarbon or carbonaceous feed, a carbon dioxide stream recovered from the flue gas of a furnace or boiler, the furnace or boiler being heated by combustion of a carbonaceous fuel, or a carbon dioxide stream separated from air or seawater.

11. 11. The process of any one of claims 1 to 10, wherein the carbon dioxide supplied to the reverse water gas shift unit comprises at least a portion of carbon dioxide recycled from downstream of the reverse water gas shift unit.

12. 12. A process according to any preceding claim, wherein an upgraded hydrocarbon off-gas stream recovered from the upgrading unit is also fed to the first de-enrichment vessel and / or the second de-enrichment vessel.

13. 13. The process of any one of claims 1 to 12, wherein a hydrocarbon synthesis unit hydrocarbon off-gas stream recovered from the hydrocarbon synthesis unit is fed to the first de-enrichment vessel and / or the second de-enrichment vessel.

14. 14. A process according to any one of claims 1 to 13, wherein one or more further de-riching vessels are provided for treating an upgraded hydrocarbon off-gas stream recovered from the upgrading unit and optionally a hydrocarbon synthesis unit hydrocarbon off-gas stream recovered from the hydrocarbon synthesis unit with steam to produce a further gas mixture containing methane which is fed to the reverse water gas shift unit.

15. 15. The process of claim 14, wherein at least a portion of the upgraded hydrocarbon off-gas stream recovered from the upgrading unit, and optionally a portion of the hydrocarbon synthesis unit hydrocarbon off-gas stream recovered from the hydrocarbon synthesis unit, are fed to a third de-enrichment vessel containing a de-enrichment catalyst to produce a further gas mixture containing methane, and wherein the gas mixture is fed to the reverse water gas shift unit.

16. 16. The process of claim 14 or 15, wherein the upgrading unit is configured to produce a light hydrocarbon liquid stream that is recycled to the first de-enrichment vessel, the second de-enrichment vessel, or one or more further de-enrichment vessels.

17. 17. A process according to any one of claims 1 to 16, wherein the first de-riching vessel operates at an inlet temperature in the range of from 250 to 650°C, preferably from 300 to 400°C, a steam to carbon molar ratio in the range of from 0.1:1 to 5:1, and a pressure in the range of from 1.0 to 7.0 MPag, preferably from 1.5 to 6.6 MPag.

18. The second de-riching vessel has an inlet temperature in the range of 400 to 550°C, a steam to carbon molar ratio in the range of 1:1 to 5:1, a pressure in the range of 1.0 to 7.0 MPag, preferably 1.5 to 6.6 MPag, and a concentration of 0.001 kg H per kg of carbon-containing component in the feed. ２ The minimum H ２ The process according to any one of claims 1 to 17, which operates content-wise.

19. The one or more further de-riching vessels may be operated at an inlet temperature in the range of 300 to 500°C, a steam to carbon molar ratio in the range of 1:1 to 5:1, a pressure in the range of 1.0 to 7.0 MPag, preferably 1.5 to 6.6 MPag, and a concentration of 0.001 kg H per kg of carbon-containing component in the feed. ２ The minimum H ２ The process according to any one of claims 14 to 18, which operates content-wise.

20. 20. The process of any one of claims 1 to 19, wherein the upgrading unit comprises a hydrotreating unit and one or more atmospheric distillation columns and optionally one or more vacuum distillation columns that provide C1 to C4 gases, hydrocarbon off-gas, a naphtha fraction, at least one kerosene and / or gas oil fraction, a heavy fraction, and optionally a light hydrocarbon liquid stream.

21. 21. A system for carrying out the process of any one of claims 1 to 20, comprising: (a) a reverse water gas shift unit configured to receive a gas mixture comprising hydrogen and carbon dioxide and to form a crude synthesis gas comprising hydrogen, carbon monoxide, carbon dioxide, and water vapor; (b) a cooling and separation device configured to receive the crude synthesis gas and to cool the crude synthesis gas to condense water and remove water and optionally carbon dioxide from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; (c) a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst and configured to receive the feed stream and to form a product stream comprising a mixture of liquid hydrocarbons, a co-product water stream, and a tail gas stream containing hydrogen, carbon monoxide, and gaseous hydrocarbons; and (d) a hydrocarbon synthesis unit configured to receive the product stream and to form a product stream comprising a Fischer-Tropsch catalyst. and an upgrading unit configured to produce an upgraded product stream, wherein separation equipment is provided for separating a naphtha stream from the product stream or the upgraded product stream, a first de-enrichment vessel containing a de-enrichment catalyst configured to be supplied with at least a portion of the tail gas stream and steam, and a second de-enrichment vessel containing a de-enrichment catalyst configured to be supplied with a portion of the naphtha stream, steam, and hydrogen, in each case to provide a gas mixture containing methane, and the first de-enrichment vessel and the second de-enrichment vessel are coupled to the reverse water gas shift unit, and the methane-containing gas mixture is supplied from the first de-enrichment vessel and the second de-enrichment vessel to the reverse water gas shift unit.

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