Process for synthesis of hydrocarbons

Abstract

A process for synthesizing hydrocarbons is described, 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 steam, (b) cooling the crude syngas to condensate water and removing water and optionally carbon dioxide from the crude syngas to produce a feed stream comprising hydrogen and carbon monoxide, (c) passing the feed stream through a hydrocarbon synthesis unit comprising a reactor comprising a Fischer-Tropsch catalyst to form a product stream comprising a mixture of liquid hydrocarbons, a co-produced water stream, and a tail gas stream comprising 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, feeding at least a portion of the tail gas stream together with steam to a first depletion vessel containing a depletion catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is fed together with hydrogen and steam to a second depletion vessel containing a depletion catalyst to form a second gas mixture containing methane, and the first gas mixture containing methane and the second gas mixture are fed to the reverse water gas shift unit. A system for performing the method is also provided.

Description

Technical Field

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

[0002] Methods for synthesizing hydrocarbons from synthesis gas containing hydrogen and carbon monoxide prepared by using the reverse water gas shift reaction are known. For example, WO2022 / 079407 A1 discloses a method for synthesizing hydrocarbons, in which at least a part of a carbon dioxide stream recovered from a carbon dioxide removal unit and a part 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 part 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 depletion step to form a depleted tail gas. The depleted 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] We have recognized that the method efficiency can be improved by adding at least a part of the tail gas recovered from the hydrocarbon synthesis unit or the upgrading unit and a part of the naphtha stream to the depletion stage to produce a methane-containing gas for the reverse water gas shift unit, thereby producing additional synthesis gas. We have also recognized that different depletion vessels and conditions are required for the effective utilization of the tail gas and the naphtha fraction.

[0004] Therefore, the present invention provides a method for synthesizing hydrocarbons, the method comprising the steps of: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a raw syngas comprising hydrogen, carbon monoxide, carbon dioxide and steam, (b) cooling the raw syngas to condense water and removing water (and optionally also carbon dioxide) from the raw syngas 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-produced 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 fed together with steam to a first depletion vessel containing a depletion catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is fed together with hydrogen and steam to a second depletion vessel containing a depletion catalyst to form a second gas mixture containing methane, and the first gas mixture containing methane and the second gas mixture containing methane are fed to the reverse water gas shift unit.

[0005] The present invention also provides a system for performing the method, the system comprising: (a) a reverse water gas shift unit configured to feed a gas mixture comprising hydrogen and carbon dioxide, the gas mixture forming a raw syngas comprising hydrogen, carbon monoxide, carbon dioxide and steam, (b) cooling and separation equipment configured to feed the raw syngas, the cooling and separation equipment cooling the raw syngas to condense water and removing water (and optionally also carbon dioxide) from the raw syngas to produce a feed stream comprising hydrogen and carbon monoxide, (c) a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst, the hydrocarbon synthesis unit being configured to feed the feed stream to form a product stream comprising a mixture of liquid hydrocarbons, a co-produced water stream, and a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons, and (d) an upgrading unit configured to feed the product stream to produce an upgraded product stream, wherein separation equipment is provided to separate a naphtha stream from the product stream or the upgraded product stream; a first depletion vessel containing a depletion catalyst is configured to feed at least a portion of the tail gas stream and steam; a second depletion vessel containing a depletion catalyst is configured to feed a portion of the naphtha stream, steam and hydrogen, in each case providing a gas mixture containing methane; and wherein the first depletion vessel and the second depletion vessel are coupled to the reverse water gas shift unit to feed the gas mixture containing methane from the first depletion vessel and the second depletion 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 raw syngas. After cooling, water and optional carbon dioxide are removed, and optional hydrogen is added to produce a feed gas for a hydrocarbon synthesis unit. The hydrocarbon synthesis unit feeds a hydrocarbon product mixture to a 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-produced 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 fed together with steam to two or more depleted vessels containing a depleted catalyst, which converts C2+ hydrocarbons therein into a gas mixture containing methane, and the gas mixture is fed to the reverse water gas shift unit. The conditions in the depleted vessels are different, and hydrogen is additionally supplied to the depleted vessel fed with naphtha. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The present invention is illustrated by reference to the accompanying drawings, in which:

[0008] Figure 1 A flowchart depicting one embodiment of the present invention with separate tail gas depletion vessels and upgraded naphtha depletion vessels;

[0009] Figure 2 A flowchart depicting another embodiment of the present invention with separate tail gas depletion vessels and upgraded naphtha depletion vessels;

[0010] Figure 3 A flowchart depicting another embodiment of the present invention with separate tail gas depletion vessels, hydrocarbon off-gas depletion vessels and upgraded naphtha depletion vessels; and

[0011] Figure 4 A flowchart depicting another embodiment of the present invention with separate tail gas depletion vessels and naphtha depletion vessels of the hydrocarbon synthesis unit.

[0012] Those skilled in the art should understand that the drawings are illustrative, and other equipment items may be required in a commercial plant, such as reflux drums, compressors, pumps, vacuum pumps, towers, heat exchangers, temperature sensors, pressure sensors, pressure reducing valves, control valves, flow controllers, level controllers, etc. The provision of such auxiliary equipment items does not form part of the present invention and conforms to conventional chemical engineering practices. DETAILED DESCRIPTION

[0013] As described in the Summary of the Invention section, this specification provides a method for synthesizing hydrocarbons, the method comprising the following steps: (a) feeding a gas mixture comprising hydrogen and carbon dioxide to a reverse water gas shift unit to form a raw syngas comprising hydrogen, carbon monoxide, carbon dioxide and steam, (b) cooling the raw syngas to condense water and removing water (and optionally carbon dioxide) from the raw syngas 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-produced 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 fed together with steam to a first depletion vessel containing a depleted catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is fed together with hydrogen and steam to a second depletion vessel containing a depleted catalyst to form a second gas mixture containing methane, and the first gas mixture containing methane and the second gas mixture containing methane are fed to the reverse water gas shift unit.

[0014] This specification also provides a system for performing the method, the system comprising: (a) a reverse water gas shift unit configured to feed a gas mixture comprising hydrogen and carbon dioxide, the gas mixture forming a raw syngas comprising hydrogen, carbon monoxide, carbon dioxide and steam, (b) a cooling and separation device configured to feed the raw syngas, the cooling and separation device cooling the raw syngas to condense water and removing water (and optionally carbon dioxide) from the raw syngas to produce a feed stream comprising hydrogen and carbon monoxide, (c) a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst, the hydrocarbon synthesis unit being configured to feed the feed stream to form a product stream comprising a mixture of liquid hydrocarbons, a co-produced water stream, and a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons, and (d) an upgrading unit configured to feed the product stream to produce an upgraded product stream, wherein separation means are provided to separate a naphtha stream from the product stream or the upgraded product stream; a first depletion vessel containing a depleted catalyst is configured to feed at least a portion of the tail gas stream and steam; a second depletion vessel containing a depleted catalyst is configured to feed a portion of the naphtha stream, steam and hydrogen, in each case providing a gas mixture containing methane; and wherein the first depletion vessel and the second depletion vessel are connected to the reverse water gas shift unit to feed the gas mixture containing methane from the first depletion vessel and the second depletion vessel to the reverse water gas shift unit.

[0015] The reverse water gas shift unit may include any suitable reactor or combination of reactors for performing 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 method may include subjecting a gas mixture containing hydrogen and carbon dioxide to a catalytic or non-catalytic reverse water gas shift reaction. The reverse water gas shift reaction can be described as follows:

[0016]

[0017] Thus, the reverse water gas shift process is 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 undergo 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 undergo an autothermal reverse water gas shift reaction. A particularly preferred reverse water gas shift unit includes an autothermal reforming reactor in which hydrogen and carbon dioxide are fed as a mixture or separately to a burner within a reverse water gas shift vessel where the hydrogen and carbon dioxide are partially burned with oxygen to produce a heated gas containing hydrogen, steam, carbon monoxide and carbon dioxide, and the heated gas passes through a bed of reverse water gas shift catalyst disposed downstream of the burner. Such an arrangement is described in WO2022 / 079408A1. Hydrogen is burned in the reverse water gas shift vessel to generate heat for the reverse water gas shift reaction. Thus, in this arrangement, hydrogen in excess of carbon dioxide should be provided such that sufficient hydrogen remains after combustion to drive the reaction forward through the reverse water gas shift catalyst. Excess hydrogen is also desirable in view of the potential end use of the carbon monoxide-containing gas in the Fischer-Tropsch synthesis of hydrocarbons where the H2:CO ratio is ideally about 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 conversion of carbon dioxide achieved in the reverse water gas shift unit and the hydrogen to carbon monoxide ratio required by the downstream process.

[0018] The gas mixture containing carbon dioxide and hydrogen fed to the burner may contain 15 vol% to 50 vol%, preferably 25 vol% to 40 vol% of carbon dioxide. The gas mixture containing carbon dioxide and hydrogen fed to the burner preferably contains in total less than 10 vol% of other gases such as steam, nitrogen, carbon monoxide and methane.

[0019] Any suitable hydrogen source may be used. More than one hydrogen source may be used. The method preferably uses hydrogen based on non-fossil fuels. Thus, hydrogen may be generated by catalytic or non-catalytic partial oxidation of biomass or plastics, optionally followed by steam reforming of the partially oxidized product gas. Alternatively, hydrogen may be provided by water splitting. Preferably, the hydrogen is electrolytic hydrogen, such as hydrogen formed by electrolysis of water. Intermediate storage of hydrogen may be used to reduce any variability in the production of hydrogen by electrolysis. In some embodiments, co-produced water from a hydrocarbon synthesis unit may undergo electrolysis to produce an electrolytic hydrogen stream for use in the method. Such water electrolysis may conveniently use electricity from renewable sources such as solar, wind or tidal energy. By using renewable electricity, the overall carbon intensity of the process may be negative, resulting in overall negative carbon dioxide emissions.

[0020] 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 the carbon dioxide stream may be a stream recovered from a furnace or boiler flue gas, where the furnace or boiler is heated by combustion of a carbonaceous fuel (such as natural gas or coal), biomass or a carbonaceous waste (such as plastic). Alternatively, the carbon dioxide may be a CO2 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, for example, after treating the raw syngas in a carbon dioxide removal unit and / or a downstream process that generates carbon dioxide as a by-product (such as a Fischer-Tropsch hydrocarbon synthesis unit).

[0021] In some arrangements, carbon dioxide may be at least partially recovered from the syngas stream generated by a syngas generation unit upstream of the reverse water gas shift unit. This has the advantage that the syngas generation unit provides additional hydrogen and carbon monoxide for use in the hydrocarbon synthesis unit.

[0022] The syngas generation unit can be any unit that converts a feedstock into syngas comprising hydrogen, carbon monoxide and carbon dioxide. Depending on the nature of the feedstock, various syngas generation technologies can be preferred. For example, in the case where the feedstock is natural gas, the syngas generation unit preferably comprises a catalytic partial oxidation unit, a non-catalytic partial oxidation unit or an autothermal reformer. Alternatively, in the case where the feedstock is coal, biomass or municipal solid waste or an equivalent containing abiogenic carbon, the syngas generation unit preferably comprises a gasifier. Any known gasification technology can be used. Preferably, the gasification is carried out by partial oxidation, which comprises burning the feedstock together with air or oxygen at high temperature (generally between 800 °C and 1600 °C) under sub-stoichiometric conditions in order to obtain crude syngas. When nitrogen-free syngas is desired, oxygen is used in this process. The gasification produces syngas and a residual fraction containing tar. Generally speaking, syngas is a gas mixture comprising carbon monoxide, hydrogen, water vapor and carbon dioxide. In addition, it will also typically contain sulfur-, nitrogen- and halogen-containing impurities. Common sulfur-containing impurities are carbonyl sulfide (COS) and hydrogen sulfide (H2S). These impurities (if present) are advantageously removed upstream of the Fischer-Tropsch hydrocarbon synthesis unit using one or more pollutant removal stages, by scrubbing (absorption), by passing the crude syngas through one or more beds of a suitable adsorbent, or by a combination of these means. Syngas purification can be carried out in one or more stages before and / or after the carbon dioxide removal unit.

[0023] The reverse water gas shift unit and the syngas generation unit (if present) can use oxygen. An air separation unit (ASU) can be used to recover oxygen from air, and the air separation unit can be driven by a renewable power source or steam generated in a reformer gas boiler or other sources (including from downstream processes). Preferably, the oxygen used in this process comprises electrolytic oxygen, such as oxygen formed by electrolysis of water in an electrolysis unit. If desired, this has the beneficial effect of reducing the capital investment of the air separation equipment and / or reducing the power consumption of the air separation equipment.

[0024] Therefore, both the hydrogen and oxygen used for this process are preferably generated using an electrolysis unit into which a water source is fed. The water can include condensate recovered from the crude gas mixture generated in the reverse water gas shift unit or in the upstream syngas generation unit, and / or can contain water recovered from downstream conversion units such as the Fischer-Tropsch hydrocarbon synthesis unit. If desired, the water can be treated to remove contaminants such as organic compounds or salts, which would adversely affect the electrolysis unit.

[0025] The power for the electrolysis unit is ideally not obtained from the combustion of fossil fuels. The power for electrolysis can be provided by nuclear energy or preferably by renewable power sources such as photovoltaic solar energy, wind energy, tidal energy, hydro or hydroelectric, ocean energy, geothermal energy, and / or biomass. The electricity for electrolysis can also be provided using turbines driven by steam generated using heat recovered from product gas streams produced by partial oxidation of biomass or waste plastics. The power can be stored in intermediate facilities such as pumped hydrogen storage or battery storage to provide a more constant power supply to the electrolysis unit.

[0026] If desired, the carbon dioxide and hydrogen streams or the gas mixture containing carbon dioxide and hydrogen can be compressed to a pressure in the range of 0.8 MPa to 6.5 MPa, preferably 1.2 MPag to 5.5 MPag.

[0027] Before compression, but preferably after compression, the gas stream fed to the reverse water gas shift unit can be preheated. The preheating temperature of the feed gas to the autothermal reverse water gas shift vessel is preferably in the range of 400 °C to 1000 °C, preferably 450 °C to 800 °C to sustain combustion and minimize carbon formation. The hydrogen and carbon dioxide streams can be premixed before preheating or preheated and mixed. The feed can be preheated to its preheating temperature by exchange with the raw synthesis gas mixture, and / or by steam heating, or by using a calciner heater or by electric heating or by a combination of two or more of these. Preferably, the feed gas mixture containing carbon dioxide and hydrogen is heated by exchange with the raw synthesis gas mixture (optionally supplemented with electric heating).

[0028] 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 that includes a reverse water gas shift vessel containing a reverse water gas shift catalyst.

[0029] A preferred reverse water gas shift unit includes an autothermal reverse water gas shift vessel that contains a burner and a fixed bed of reverse water gas shift catalyst. The burner is fed with a gas stream containing carbon dioxide and an oxygen stream and burns a portion of the hydrogen and any hydrocarbons present in the carbon dioxide-containing gas to generate the heat for the endothermic reverse water gas shift reaction.

[0030] Oxygen and a gas mixture comprising carbon dioxide and hydrogen are fed to a burner disposed in a reverse water gas shift vessel. Any burner design can be used, such as the burners used in autothermal reformers. Combustion generates a flame in a combustion zone upstream of the catalyst within the reverse water gas shift vessel. The local conditions in the combustion section, particularly in the pre-flame region, can be controlled by managing the momentum of the oxidant and gas streams. The water gas shift vessel can be oriented such that the combustion zone is above the bed of the reverse water gas shift catalyst. Such an arrangement is used in autothermal reformer vessels and can be used in this process, which can be referred to as autothermal reverse water gas shift. However, other arrangements of the burner and catalyst can also be used.

[0031] The gas mixture is heated to a temperature typically in the range of 800 °C to 1300 °C by combustion. Oxygen is consumed. The heated gas mixture comprising carbon monoxide, carbon dioxide, steam and unreacted hydrogen is then passed through a reverse water gas shift catalyst bed within the reverse water gas shift vessel downstream of the burner.

[0032] The reverse water gas shift catalyst can be any suitable transition metal oxide catalyst, such as a catalyst based on nickel oxide, iron oxide or chromium oxide, but other catalysts used as reverse water gas shift catalysts can be used. Preferably, the catalyst is a nickel oxide-based catalyst. Such a catalyst is active for the reverse water gas shift catalyst but also advantageously reform steam methane provided by the depletion vessel and present in the gas mixture comprising hydrogen and carbon dioxide. Thus, the catalyst preferably comprises nickel oxide on a suitable refractory metal oxide support. The refractory metal oxide support can include zirconia, alumina, calcium aluminate, magnesium aluminate, titanium dioxide 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 can range from 3 wt% to 20 wt%, expressed as NiO.

[0033] The reverse water gas shift catalyst can be granular, for example in the form of shaped units such as pellets, rings or extrudates, which can be leaf-shaped or grooved. The catalytically active metal (e.g., nickel) can be dispersed throughout the granular catalyst or present only in an eggshell layer with a thickness of 200 μm to 1000 μm on the surface of the refractory support. Alternatively, the catalyst can comprise one or more monolithic supports such as metal or ceramic foams or honeycombs carrying the catalytically active metal. Preferably, the catalyst is a granular catalyst, more preferably a 4-hole cylinder, particularly a leaf-shaped or grooved cylinder, to provide a higher geometric surface area (GSA) than a solid cylinder of similar size. A catalyst with a GSA in the range of 400 m 2 to 550 m 2 is preferred.

[0034] If desired, a layer of zirconia balls, pellets or sheets may be placed on top of the reverse water gas shift catalyst to protect the surface of the catalyst from irregularities in the combustion gas stream. The benefit of providing this layer is to prevent disruption of the surface of the catalyst bed.

[0035] By controlling the preheat temperature and the amount of oxygen fed to the burner, the outlet temperature of the reverse water gas shift vessel can be controlled. The outlet temperature can be in the range of 700 °C to 1050 °C, preferably 750 °C to 950 °C.

[0036] 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 also used to convert methane generated from waste material streams from downstream processes into carbon monoxide. Accordingly, a methane-containing gas stream from a first depletion vessel and a second depletion vessel is fed to the reverse water gas shift vessel. At least a portion of the tail gas recovered from the Fischer-Tropsch hydrocarbon synthesis unit is fed to the first depletion vessel. A portion of the naphtha recovered from the hydrocarbon synthesis unit or a upgrading unit coupled to the hydrocarbon synthesis unit is fed to the second depletion vessel.

[0037] The depletion vessels operate by adiabatically steam reforming the hydrocarbons in the tail gas stream and the naphtha stream. Accordingly, steam also needs to be supplied to the depletion vessels. In addition, a hydrogen source is also provided to the second depletion vessel in order to satisfactorily steam reform the naphtha without deactivating the catalyst by carbon formation.

[0038] In the present invention, at least a portion of the tail gas stream is fed together with steam to a first depletion vessel containing a depletion catalyst to form a gas mixture containing methane, and at least a portion of the naphtha stream is fed together with hydrogen and steam to a second depletion vessel containing a depletion catalyst to form a second gas mixture containing methane. The steam introduction can be achieved by directly injecting steam and / or by saturating the feed gas by contact with a stream of heated water. The heated water may include condensate from a downstream process, which contains soluble organic compounds. Alternatively, the steam for direct injection may have been used to strip organic compounds from the condensate from a downstream process. In this way, the organic compounds can be converted into hydrogen and carbon oxides in the depletion vessels, and the burden of wastewater treatment in the downstream process can be reduced.

[0039] The amount of steam introduced can be such that the molar ratio of steam to carbon in the feed to the depletion vessel is from 0.1:1 to 5:1. The so-called molar ratio of steam to carbon refers to the molar ratio of steam to the total amount of carbon-containing components in the feed, and the carbon-containing components include hydrocarbons, CO and CO2.

[0040] The feed gas to the depletion vessel typically has an inlet temperature in the range of 250 °C to 650 °C. The feed gas can adiabatically pass through a bed of depletion catalyst, such as a particulate nickel catalyst having a high nickel content (e.g., higher than 40 wt%). Such catalysts are commercially available. The same or different catalysts can be used in the first depletion vessel and the second depletion vessel.

[0041] A hydrogen stream is fed together with naphtha into the second depletion vessel to reliably convert naphtha to methane. The hydrogen can be a pure hydrogen stream or can contain a suitably high hydrogen content to provide the hydrogen for depletion. In some embodiments, the pure hydrogen stream can be supplemented with hydrogen-containing off-gas from a hydrocarbon synthesis unit and / or a upgrading unit.

[0042] During the depletion step, any hydrocarbon higher than methane reacts with steam to give a mixture of methane, carbon oxides, and hydrogen.

[0043] In some arrangements, the first depletion vessel operates at an inlet temperature in the range of 250 °C to 650 °C, preferably 300 °C to 400 °C; and a steam to carbon molar ratio of 0.1:1 to 5:1.

[0044] If desired, the first depletion vessel can operate at a pressure in the range of 1.0 Mpa to 7.0 MPag, preferably 1.5 Mpa to 6.6 MPag.

[0045] In some arrangements, the second depletion vessel operates at an inlet temperature in the range of 400 °C to 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.

[0046] If desired, the second depletion vessel can operate at a pressure in the range of 1.0 Mpa to 7.0 MPag, preferably 1.5 Mpa to 6.6 MPag. The operating pressures of the first depletion vessel and the second depletion vessel can be the same or different.

[0047] Producing a gas mixture containing methane is preferred over directly feeding the tail gas stream, hydrocarbon off-gas stream, and naphtha stream to a reverse water gas shift unit because it reduces the risk of forming unwanted carbon in the reverse water gas shift vessel or on the reverse water gas shift catalyst.

[0048] In the present invention, the methane-containing gas mixture recovered from the depletion vessel is fed to a reverse water gas shift unit. The methane-containing gas mixture can be fed from the depletion vessel to the reverse water gas shift unit alone, or mixed with one or both of a hydrogen feed stream and a carbon dioxide feed stream. The methane-containing gas mixture can optionally be preheated. The methane-containing gas mixture can be preheated alone or after being combined with the hydrogen and carbon dioxide feed streams. 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°C to 1000°C, preferably 450°C to 800°C, to sustain combustion and minimize carbon formation.

[0049] The hydrocarbon synthesis unit produces a product stream that is upgraded in an upgrading unit. The product stream comprises a mixture of gaseous and liquid hydrocarbons. In some arrangements, a hydrocarbon synthesis unit naphtha stream 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 having an approximate end boiling point of less than 240°C.

[0050] In addition, the hydrocarbon synthesis unit can be operated to produce a hydrocarbon synthesis unit hydrocarbon offgas stream by physically separating light gaseous hydrocarbons (such as C1, C2, C3, and C4 hydrocarbons) from heavier liquid hydrocarbons and co-produced water fed to one or more gas-liquid separators in the FT unit.

[0051] The upgrading unit can be configured to produce an upgraded naphtha stream from the product stream. The upgraded naphtha stream can be recovered in the upgrading unit from one or more distillation towers 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 comprises saturated hydrocarbons, typically C5 to C11, with a boiling point range of 30°C to 220°C.

[0052] Typically, naphtha from the hydrocarbon synthesis unit or naphtha from the upgrading unit will be fed to a second depletion vessel. Thus, the naphtha stream from the hydrocarbon synthesis unit or the upgrading unit can be compressed, vaporized, mixed with steam and hydrogen, and fed to the second depletion vessel.

[0053] The upgrading unit can be configured to additionally produce an upgraded hydrocarbon offgas stream. The upgraded hydrocarbon offgas stream can be recovered in the upgrading unit from an emission vessel in which a reduction in the pressure of the mixed hydrocarbon feed results in the flashing or volatilization of light hydrocarbons, or from one or more distillation towers in which the feed is heated and the hydrocarbons are separated based on their boiling points. The emission vessel and one or more distillation towers can be downstream of the hydrotreating unit. The upgraded offgas will typically comprise saturated hydrocarbons, hydrogen, methane, carbon monoxide, carbon dioxide, and inert contaminants such as nitrogen.

[0054] One or both of the hydrocarbon offgas streams can usefully be recycled into the process to further improve the carbon efficiency of the process and minimize the carbonaceous streams sent to fuel, where they would ultimately result in carbon dioxide emissions. Since the offgas streams can be produced at similar pressures, it may be advantageous to compress them together rather than separately before feeding them to the depletion vessel.

[0055] Accordingly, the upgraded hydrocarbon offgas and optionally the hydrocarbon synthesis unit offgas can also be fed to the first depletion vessel and / or the second depletion vessel. Alternatively, one or more additional depletion vessels can be provided for treating one or both of the hydrocarbon offgas streams. The destination of the offgas stream will depend on the proportion of C2, C3, and C4 hydrocarbons present when the stream is combined with the tail gas or the naphtha stream. Feeding the offgas to the third depletion vessel may be advantageous for operating flexibility and optimized operating conditions. Thus, in some arrangements, at least a portion of the upgraded hydrocarbon offgas, steam, and optionally a portion of the hydrocarbon synthesis unit offgas are fed to a third depletion vessel containing a depletion catalyst to produce an additional gas mixture containing methane that is fed to the reverse water gas shift unit. If desired, a hydrogen stream can also be provided to one or more additional depletion vessels to improve the depletion of the offgas stream.

[0056] In some arrangements, one or more additional depletion vessels can be configured to operate at an inlet temperature in the range of 300 °C to 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 carbonaceous components in the feed.

[0057] If desired, one or more additional depletion vessels can operate at a pressure in the range of 1.0 Mpa to 7.0 MPag, preferably 1.5 Mpa to 6.6 MPag. The pressure of one or more additional depletion vessels can be the same as or different from that of the first and second depletion vessels.

[0058] The upgrading unit can also be operated to additionally produce a light hydrocarbon liquid stream, which, if desired, can be recycled to the first depletion vessel, the second depletion vessel, or one or more additional depletion vessels. The light hydrocarbon liquid stream will mainly contain C3 and C4 saturated hydrocarbons. If used, the light hydrocarbon liquid will need to be compressed and vaporized before being fed to one or more additional depletion vessels.

[0059] The proportions of the naphtha, tail gas, offgas, and light hydrocarbon streams fed to the depletion vessels will vary depending on the product makeup produced by the upgrading unit and the recycle ratio of the tail gas within the hydrocarbon synthesis unit. It is expected that the mass proportion of the tail gas will be greater than that of the offgas stream, and the tail gas contains sufficient hydrogen such that if fed together with the offgas, no further addition of hydrogen to the first depletion vessel is required.

[0060] If sulfur contaminants are present in the naphtha feed stream and the upgraded hydrocarbon off-gas stream in the upgrading unit, then preferably after compression, these sulfur contaminants can be removed by subjecting the naphtha and upgraded off-gas streams to a desulfurization step upstream of the depletion step. This can be achieved using any suitable desulfurization method, such as including absorbing sulfur compounds by passing the stream through a bed of zinc oxide absorbent.

[0061] The upgraded hydrocarbon off-gas can be recovered at a pressure in the range of 0.1 Mpa to 1.0 MPag. The hydrocarbon synthesis unit hydrocarbon off-gas can be recovered at a pressure in the range of 0.1 Mpa to 1.0 MPag. If desired, the upgraded hydrocarbon off-gas and the hydrocarbon synthesis unit hydrocarbon off-gas can be compressed to a pressure in the range of 1.0 Mpa to 7.0 MPag. The off-gases can be compressed separately or preferably combined and compressed.

[0062] The gas mixture containing methane from the first depletion vessel, the second depletion vessel, and one or more additional depletion vessels will contain unreacted steam. This is not usually necessary, but if desired, the depleted gas mixture can be cooled below the dew point to condense the steam and recover the condensate to produce a dehydrated depleted gas feed to the reverse water gas shift unit. Removing the steam can improve the reverse water gas shift equilibrium. The recovered condensate can be usefully used to generate steam for the process or to generate hydrogen by electrolysis of water.

[0063] If desired, the gas mixture containing methane can be compressed before entering the inlet of the reverse water gas shift unit. The compression can be carried out before or preferably after any dehydration step.

[0064] The gas mixture feed containing hydrogen and carbon dioxide to the reverse water gas shift unit can be preheated and combined with the methane-containing gas stream from the depletion vessel. Alternatively, the methane-containing gas stream can optionally be preheated and fed separately to the reverse water gas shift reactor.

[0065] The reverse water gas shift unit converts carbon dioxide to carbon monoxide and consumes some hydrogen by the reverse water gas shift reaction described above. The reverse water gas shift unit produces a raw synthesis gas mixture.

[0066] The raw synthesis gas mixture from the reverse water gas shift vessel contains steam formed by the reverse water gas shift reaction and optionally steam added together with the methane-containing gas mixture. Water is recovered from the raw synthesis gas mixture by cooling the product gas mixture below the dew point and separating the condensate, for example using one or more conventional gas-liquid separators. Removal of the water condensate from the raw synthesis gas mixture produces a dehydrated product gas. The cooling can be carried out by raising the steam and / or by preheating one or more of a hydrogen stream, a carbon dioxide stream, a mixed gas stream containing hydrogen and carbon dioxide, and optionally the depleted vessel feed gas. Further cooling can also be carried out with cold water and / or air. The process steam generated by the cooling can be used for the depletion step or downstream processes and / or for power generation.

[0067] If desired, the condensed water can be at least partially recycled to the process. If desired, the condensate can be used as boiler feed water after treatment. Additionally or alternatively, the condensate, optionally after treatment with contaminants, can be fed to an electrolysis unit for generating hydrogen for the process. Thus, in some embodiments, a water stream recovered from the raw synthesis gas mixture can be fed to the electrolysis unit. If desired, the condensate can also be used again as boiler feed water after treatment.

[0068] The crude synthesis gas mixture contains carbon dioxide, which is removed from the dehydrated product gas using a carbon dioxide removal unit. Most of the carbon dioxide can be separated by a membrane, a solid absorbent, or preferably a scrubbing system, such as a system operating by countercurrent contact of the crude synthesis gas mixture or the dehydrated product gas with an absorbent liquid filled in a column. The absorbent liquid can be a physical solvent such as potassium carbonate (sold under the Benfield process), methanol (sold under the Rectisol process), or glycol (sold under the Selexol process) or a chemical solvent such as an amine. Thus, the carbon dioxide removal unit can include one or more vessels providing a physical scrubbing system or a reactive scrubbing system, preferably a reactive scrubbing system, especially an amine scrubbing system. Carbon dioxide can be removed by a conventional acid gas recovery unit (AGRU). In a conventional AGRU, a dehydrated gas stream is contacted with a stream of a suitable absorbent liquid (such as an amine, for example an aqueous solution containing monoethanolamine (MEA), methyldiethanolamine (MDEA), or dimethylethanolamine (DMEA), especially methyldiethanolamine (MDEA)), such that the carbon dioxide is absorbed by the liquid to produce a loaded absorbent liquid and a gas stream with a reduced carbon dioxide content. The loaded absorbent liquid is then regenerated by heating and / or reducing the pressure to desorb the carbon dioxide and obtain a regenerated absorbent liquid, which is then recycled to the carbon dioxide absorption stage. The heat of regeneration from the loaded absorbent can be recovered from the process. For example, a portion of the crude synthesis gas mixture or the steam generated by cooling the crude synthesis gas mixture can be used to heat the loaded absorbent.

[0069] Alternatively, instead of scrubbing with an amine, cold methanol or glycol can be used in a manner similar to an amine to remove carbon dioxide.

[0070] The recovered carbon dioxide obtained from the carbon dioxide removal unit is preferably recompressed as needed and returned to the reverse water gas shift vessel to increase the overall conversion to carbon monoxide.

[0071] The recovered carbon dioxide can be combined with the carbon dioxide feed, the hydrogen feed, or a gas mixture containing hydrogen and carbon monoxide before preheating. It is preferably combined with the carbon dioxide feed stream before compression.

[0072] Removing carbon dioxide from the dehydrated 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 hydrogen fed into 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 gas stream containing carbon monoxide.

[0073] A gas stream containing carbon monoxide contains carbon monoxide and hydrogen. The molar ratio of hydrogen to carbon monoxide can be in the range of 1.0 to 2.5:1, preferably 1.2 to 2.5:1, more preferably 1.6 to 2.2, which is particularly suitable for hydrocarbon synthesis by the Fischer-Tropsch reaction.

[0074] In the present invention, the product gas is fed to a Fischer-Tropsch hydrocarbon synthesis unit for synthesizing a hydrocarbon product mixture.

[0075] The Fischer-Tropsch hydrocarbon synthesis unit may include one or more Fischer-Tropsch reaction vessels containing a Fischer-Tropsch catalyst. The Fischer-Tropsch conversion stage can be carried out according to any known method using any known catalyst, but is advantageously applied to a method using a cobalt catalyst.

[0076] The Fischer-Tropsch process involves a series of chemical reactions that produce various hydrocarbons, ideally having the formula (C n H 2n+2 ). The more useful reactions produce alkanes as follows:

[0077] (2n + 1)H2 + n CO → C n H 2n+2 + n H2O

[0078] where n is typically from 5 to 100 or higher, and the preferred products have an n in the range of 10 to 20.

[0079] The Fischer-Tropsch reaction can be carried out using one or more reactors (such as a fixed-bed reactor, a slurry-phase reactor, a bubble column reactor, a loop reactor or a fluidized bed reactor). The process can be operated at a pressure in the range of 0.1 Mpa to 10 MPa and at a temperature in the range of 170 °C to 350 °C. The gas hourly space velocity (GHSV) for continuous operation is in the range of 1000 hr -1 to 25000 hr -1within the range. Preferably, Fischer-Tropsch synthesis is carried out using one or more fixed-bed reactors, i.e., reaction vessels, in which the catalyst bed is fixed within the vessel and the purified syngas passes through the vessel. Any Fischer-Tropsch catalyst can be used, but cobalt-based Fischer-Tropsch catalysts are preferred over iron-based catalysts due to their lower carbon dioxide selectivity. Suitable cobalt Fischer-Tropsch catalysts are known, but the preferred catalyst in this process comprises 9 wt% to 20 wt% Co supported on a suitable carrier material. Thus, suitable catalysts comprise agglomerates, pellets or extrudates which comprise metal oxides such as alumina, zinc oxide, titanium dioxide or silica or mixtures thereof, on which the catalytically active metal, preferably cobalt, is deposited. In a particularly preferred arrangement, the Fischer-Tropsch catalyst is used in combination with a catalyst support suitable for a tubular Fischer-Tropsch reactor, where the catalyst support containing the catalyst is disposed within one or more tubes which are cooled by a circulating coolant such as pressurized water. The so-called "catalyst support" refers to, for example, a catalyst container in the form of a cup or a can, which is configured to allow gases and / or liquids to flow into and out of the support and to flow through a bed of catalyst or catalyst precursor disposed within the support. Any suitable catalyst support can be used. In one arrangement, the catalyst support is the catalyst support described in WO2011 / 048361, the content of which is incorporated herein by reference. In an alternative arrangement, the catalyst support can comprise the monolithic catalyst disclosed in WO2012 / 136971, the content of which is also incorporated herein by reference. In another alternative arrangement, the catalyst support can be the catalyst support disclosed in WO2016 / 050520, the content of which is also incorporated herein by reference. In a preferred embodiment, the Fischer-Tropsch hydrocarbon synthesis unit comprises a tubular reactor, where the catalyst support containing the Fischer-Tropsch catalyst is disposed within one or more tubes cooled by a cooling medium.

[0080] Typically, a portion of the carbon monoxide is converted in one or more Fischer-Tropsch reactors to produce a liquid hydrocarbon product, co-produced water, and a gaseous mixture containing unreacted hydrogen and carbon monoxide, plus carbon dioxide and gaseous light hydrocarbons (including methane, ethane, propane, and butane). The reaction product mixture can be cooled, and one or more gas-liquid separators can be used to separate an aqueous stream and a liquid hydrocarbon stream from the gas mixture. The co-produced water can be separated using known hydrocarbon-water separators. The separated gas mixture (which can be referred to as the "tail gas") can be used in a variety 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 recycle fraction that forms the loop can be set to control the accumulation of inert gases such as methane in the Fischer-Tropsch hydrocarbon synthesis unit to an acceptable level. The remaining portion still contains valuable carbon sources. Thus, in the present invention, a portion of the tail gas is recycled via a first depletion vessel containing a depleted catalyst to a reverse water gas shift unit 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 depletion step. The portion that is not recycled to the reverse water gas shift unit (which can be referred to as the "purge gas") is removed from the process to prevent the accumulation of inert gases. The purge gas can be output as fuel or used in the process in a calcination heater or thermal oxidizer to heat the feed to the reverse water gas shift vessel or superheat steam.

[0081] The liquid hydrocarbons recovered from the hydrocarbon synthesis unit are upgraded in an upgrading unit to provide more valuable hydrocarbon products. One or more liquid hydrocarbon streams produced by the hydrocarbon synthesis unit can be fed to the upgrading unit, including but not limited to molten hydrocarbon waxes and light hydrocarbon condensates that are liquid at ambient temperature.

[0082] Advantageously, the hydrocarbon synthesis unit is operated to produce a molten hydrocarbon wax liquid that is upgraded in a hydrotreating unit to produce liquid fuels. Thus, in some embodiments, at least a portion and preferably all of the liquid hydrocarbon mixture produced by hydrocarbon synthesis is fed as a feedstock in the presence of hydrogen to an upgrading unit that includes a hydrotreating unit. The hydrotreating unit can perform various conversions, such as hydroisomerization, hydrogenation, hydrodeoxygenation, and / or hydrocracking, using one or more vessels containing a suitable catalyst. The hydrotreating unit requires hydrogen. This can be provided by various sources, but advantageously is 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 fed to the hydrotreating unit.

[0083] The hydrotreating unit can be operated under the following conditions: generally between 200 °C and 450 °C, preferably between 250 °C and 450 °C, more preferably between 300 °C and 450 °C, and most preferably between 320 °C - 420 °C; at a pressure between 0.2 MPag and 15 MPag, preferably between 0.5 MPag and 10 MPag, and more preferably between 1 MPag and 9 MPag; at a liquid hourly space velocity between 0.1 h-1 and 10 h-1, preferably between 0.2 h-1 and 7 h-1, and more preferably between 0.5 h-1 and 5.0 h-1, and the hydrogen content can be between 100 liters of H2 and 2000 liters of H2 per liter of feedstock, and preferably between 150 liters of H2 and 1500 liters of H2 per liter of feedstock.

[0084] The hydrotreating stage can be suitably carried out under conditions such that the single-pass conversion of the product with a boiling point greater than or equal to 370 °C to the product with a boiling point less than 370 °C is greater than 40 wt% and more preferably at least 50 wt%, in order to obtain middle distillates (gas oil and kerosene) with sufficiently good low-temperature characteristics (pour point, freezing point) to meet the current specifications of this type of fuel.

[0085] The catalysts used for this stage are known. For example, hydroisomerization and hydrocracking can be carried out according to any of the known methods using any of the known catalysts, and it is not limited to a specific method or catalyst. Most of the catalysts suitable for hydroisomerization / hydrocracking are bifunctional types that combine an acid functional group with a hydrogenation functional group. The acid functional group is generally provided via a support with a high specific surface area (generally between 150 m2 / g and 800 m2 / g) that exhibits surface acidity, such as halogenated (specifically, chlorinated or fluorinated) alumina, phosphorylated alumina, a combination of boron and aluminum oxides, or silica / alumina. Generally, the hydrogenation function is provided by one or more metals of 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 Group VI metal (such as chromium, molybdenum, and tungsten) and at least one Group VIII metal. Most conventional hydrocracking catalysts are composed of a weakly acidic support (such as silica / alumina). These systems are usually used to produce middle distillates of very good quality. Many catalysts in the hydrocracking market are based on the combination of silica / alumina and Group VIII metals. These systems have very good selectivity for middle distillates and the products formed have good quality. According to a preferred embodiment, the hydroisomerization / hydrocracking catalyst comprises at least one hydrogenation-dehydrogenation element selected from the noble metals of Group VIII, preferably platinum and / or palladium, and at least one amorphous refractory oxide support, preferably silica / alumina.

[0086] The hydrocarbon product recovered from the hydrotreating unit can be fed to a separation device to recover valuable hydrocarbon products. The separation device may include one or more atmospheric distillation towers and optionally one or more vacuum distillation towers, which separate the upgraded hydrocarbon offgas, the naphtha fraction, and preferably at least one kerosene and / or gasoil fraction and the heavy fraction. Generally, the heavy fraction exhibits an initial boiling point of at least 350 °C, preferably greater than 370 °C. Advantageously, this fraction is recycled to the hydrotreating unit. A portion of the kerosene can also be advantageously recycled to the hydrotreating unit. The gasoil and kerosene fractions may or may not be recovered separately, and the fractionation points can be adjusted to produce the desired hydrocarbon products.

[0087] Embodiments of the present specification are now described with reference to the accompanying drawings.

[0088] In Figure 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 disposed below a burner (not shown). Hydrogen, such as hydrogen produced by an electrolysis unit, is fed into the process via line 14. A portion of the hydrogen is withdrawn from line 14 via line 16 for downstream use, and the remainder is fed via line 18 to the reverse water gas shift unit 12, where in the autothermal reverse water gas shift vessel, the remainder undergoes combustion with oxygen and passes through the bed of reverse water gas shift catalyst together with carbon dioxide 10. The reverse water gas shift reaction occurs on the catalyst to form a syngas comprising carbon monoxide, hydrogen, carbon dioxide, and steam. The reverse water gas shift unit also includes cooling equipment (not shown) for cooling the syngas recovered from the reverse water gas shift vessel below the dew point, and a gas-liquid separator for recovering liquid condensate from the cooled syngas to form a water-free syngas. The reverse water gas shift unit also includes a CO2 removal unit (not shown), and the water-free syngas is fed to this CO2 removal unit. The CO2 removal unit operates by amine scrubbing, which removes CO2 from the water-free syngas to produce an FT syngas consisting essentially of carbon monoxide and hydrogen. The recovered CO2 from the CO2 removal unit can be mixed with the carbon dioxide fed via line 10, which is fed to the reverse water gas shift vessel.

[0089] FT synthesis gas is fed from the reverse water gas shift unit to the hydrocarbon synthesis unit 22 via line 20. The hydrocarbon synthesis unit includes one or more Fischer-Tropsch reactors containing a Fischer-Tropsch catalyst. The Fischer-Tropsch reaction occurs to form a liquid hydrocarbon product, co-produced water, and a tail gas stream containing unreacted carbon monoxide and hydrogen, as well as gaseous hydrocarbons. The hydrocarbon synthesis unit also includes cooling equipment and a gas-liquid separator (not shown) that separates the liquid hydrocarbon product from the co-produced water and the tail gas. A portion of the tail gas is recycled to one or more of the Fischer-Tropsch reactors. The remaining portion of the tail gas stream is recovered from the hydrocarbon production unit 22 via line 24 for further processing. The liquid hydrocarbon product is fed from the hydrocarbon synthesis unit 22 to the upgrading unit 30 via line 28.

[0090] A portion of the hydrogen stream 16 is also fed to the upgrading unit 30 via line 32. The upgrading unit includes a hydrotreating unit containing a hydrotreating catalyst (not shown) that upgrades the liquid hydrocarbon 28 with the hydrogen fed via line 32 to form a fuel mixture. The upgrading unit 30 also includes one or more distillation units (not shown) that separate the fuel mixture into various products. Thus, the upgrading unit 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.

[0091] A portion 24 of the tail gas recovered from the hydrocarbon synthesis unit 22 is fed to a first depletion vessel 44 containing a depleted catalyst. Steam is fed to the first depletion vessel via line 46. The depleted catalyst converts C2+ hydrocarbons in the tail gas to methane. The resulting gas mixture containing methane is fed from the depletion vessel 44 to the autothermal reverse water gas shift vessel in the reverse water gas shift unit 12 via line 48.

[0092] A portion of the naphtha from line 42 is fed to a second depletion vessel 50 containing a depleted catalyst. Steam is fed to the second depletion vessel via line 54. A portion of the hydrogen stream 16 is also fed to the second depletion vessel via line 56. The depleted catalyst converts C2+ hydrocarbons in the naphtha to methane. The resulting gas mixture containing methane is fed from the depletion vessel 50 to the autothermal reverse water gas shift vessel in the reverse water gas shift unit 12 via line 58.

[0093] Optionally, in some arrangements, hydrocarbon synthesis unit hydrocarbon waste gas shown by the dashed line 26 can be recovered from the hydrocarbon synthesis unit 22 and fed to the second depletion vessel 50. Alternatively or in addition, upgraded hydrocarbon waste gas shown by the dashed line 34 can be recovered from the upgrading unit 30 and fed to the second depletion vessel 50. In this way, the naphtha fed to the second depletion vessel can optionally be supplemented with a hydrocarbon waste gas stream that can be effectively depleted under the same conditions as the naphtha.

[0094] Figure 2 Similar to Figure 1 , instead of feeding the waste gas streams 26 and 34 together with the naphtha stream 42 to the second depletion reactor 50 via line 52, the waste gas streams 26 and 34 are combined and fed together with the tail gas stream 24 to the first depletion vessel 44 via line 52. Thus, the second depletion vessel 50 is fed only the naphtha stream via line 42, steam via line 54, and hydrogen via stream 56.

[0095] Figure 3 Similar to Figure 1 , except that there are separate tail gas, waste gas, and naphtha depletion vessels. Thus, in Figure 3 , the first depletion vessel is fed only the tail gas via line 24 and steam via line 46, and the second depletion vessel 50 is fed only the naphtha stream via line 42, steam via line 54, and hydrogen via stream 56. The waste gas streams 26 and 34 are combined and fed via line 52 to a third depletion vessel 60 containing a depletion catalyst. Steam is fed via line 62 to the third depletion vessel. Optionally, a portion of the hydrogen stream 56 is fed to the third depletion vessel as shown by the dashed line 64. The depletion catalyst converts C2+ hydrocarbons in the waste gas to methane. The resulting methane-containing gas mixture is fed from the depletion 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 in the reverse water gas shift unit 22.

[0096] Figure 4 Similar to Figure 1 , except that the upgraded naphtha stream 42 is omitted, and instead the hydrocarbon synthesis unit naphtha stream 70 is fed from the hydrocarbon synthesis unit 22 to the second depletion vessel 50.

[0097] The present invention will now be further described with reference to the following example according to Figure 1 , in which there is no waste gas feed 26 and 34 to the second depletion reactor 50.

[0098] A simulation flow diagram to produce 1000 bbl / d of FT crude hydrocarbon product. The operating conditions and composition of the streams are as follows:

[0099] Material flow 10 18 42 54 56 58 20 24 46 28 Temperature (°C) 25 25 480 250 25 525 40 300 250 515 Pressure (bara) 30 30 30 40 30 25 35 27 40 25 Flow rate (te / h) 10.3 2.1 2.1 3.7 0.01 5.8 15.7 2.9 1.0 3.9 Composition (mol%) Water 5.0 0.3 - 100 0.3 43.4 0.4 0.5 100 23.9 Hydrogen - 99.5 - - 99.5 10.1 65.1 17.7 - 7.9 Carbon monoxide - - - - - 0.6 29.6 11.2 - 0.7 Carbon dioxide 95.0 - - - - 11.4 0.5 4.4 - 9.5 Methane - - - - - 34.5 3.3 51.9 - 50.3 Nitrogen - - - - - - 1.1 10.3 - 7.7 Oxygen - 0.2 - - 0.2 - - - - - Ethane - - - - - - - 1.4 - - Propane - - 0.3 - - - - 1.2 - - Butane - - 2.5 - - - - 0.7 - - Pentane - - 21.9 - - - - 0.4 - - Hexane - - 29.1 - - - - 0.2 - - Heptane - - 27.6 - - - - 0.1 - - Octane - - 17.6 - - - - - - - Nonane - - 1.0 - - - - - - -

[0100] The present invention provides the following advantages:

[0101] 1. The process maximizes the hydrogen and carbon efficiency of the flow sheet by recycling naphtha (and off-gas) as well as Fischer-Tropsch tail gas.

[0102] 2. The industrial demand for sustainable aviation fuel has led to a preference for the composition of high jet fuel / kerosene products. However, higher kerosene yield scenarios produce a greater proportion of naphtha compared to higher diesel yield scenarios. If naphtha is not important, it is economically preferred to recycle the naphtha and maximize the carbon in the input kerosene product.

[0103] 3. The tail gas / off-gas / naphtha feed streams need to be depleted before being fed to the reverse water gas shift unit to prevent carbon fouling of the reactor.

Claims

1. A method for synthesizing hydrocarbons, the method comprising the following steps: (a) Feed a gas mixture containing hydrogen and carbon dioxide to a reverse water gas shift unit to form a raw syngas containing hydrogen, carbon monoxide, carbon dioxide and steam, (b) cool the raw syngas to condense water and remove water from the raw syngas to produce a feed stream containing hydrogen and carbon monoxide, (c) pass 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-produced water stream and a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons, and (d) upgrade 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 fed together with steam to a first depletion vessel containing a depleted catalyst to form a first gas mixture containing methane, at least a portion of the naphtha stream is fed together with hydrogen and steam to a second depletion vessel containing a depleted catalyst to form a second gas mixture containing methane, and the first gas mixture containing methane and the second gas mixture containing methane are fed to the reverse water gas shift unit.

2. The method according to claim 1, wherein in step (b), the method further removes carbon dioxide from the raw syngas.

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

4. The method according to any one of claims 1 to 3, wherein the gas mixture containing hydrogen and carbon dioxide undergoes 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. The method according to any one of claims 1 to 4, wherein the reverse water gas shift unit comprises an autothermal reforming reactor in which hydrogen and carbon dioxide are fed to a burner within a reverse water gas shift vessel where the hydrogen and the carbon dioxide are partially combusted with oxygen to generate a heated gas containing hydrogen, steam, carbon monoxide and carbon dioxide, and the heated gas passes through a bed of reverse water gas shift catalyst disposed downstream of the burner.

6. The method according to claim 5, wherein the gas mixture containing carbon dioxide and hydrogen fed to the burner contains 15 vol% to 50 vol%, preferably 25 vol% to 40 vol% of carbon dioxide.

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

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

9. The method according to any one of claims 1 to 8, wherein the hydrogen fed to the reverse water gas shift unit is a non-fossil fuel-based hydrogen stream generated by catalytic or non-catalytic partial oxidation of biomass or plastic or by electrolysis of water.

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

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

12. The method according to any one of claims 1 to 11, wherein the upgraded hydrocarbon offgas stream recovered from the upgrading unit is also fed to the first depletion vessel and / or the second depletion vessel.

13. The method according to any one of claims 1 to 12, wherein the hydrocarbon synthesis unit hydrocarbon offgas stream recovered from the hydrocarbon synthesis unit is fed to the first depletion vessel and / or the second depletion vessel.

14. The method according to any one of claims 1 to 13, wherein one or more additional depletion vessels are provided for treating the upgraded hydrocarbon offgas stream recovered from the upgrading unit and optionally the hydrocarbon synthesis unit hydrocarbon offgas stream recovered from the hydrocarbon synthesis unit with steam to produce an additional gas mixture containing methane, and the additional gas mixture is fed to the reverse water gas shift unit.

15. The method according to claim 14, wherein at least a portion of the upgraded hydrocarbon offgas stream recovered from the upgrading unit and optionally a portion of the hydrocarbon synthesis unit hydrocarbon offgas stream recovered from the hydrocarbon synthesis unit are fed to a third depletion vessel containing a depleted catalyst to produce an additional gas mixture containing methane that is fed to the reverse water gas shift unit.

16. The method according to claim 14 or claim 15, wherein, The upgrading unit is configured to produce a light hydrocarbon liquid stream that is recycled to the first depletion vessel, the second depletion vessel, or the one or more additional depletion vessels.

17. The method according to any one of claims 1 to 16, wherein the first depletion vessel is operated under the following conditions: an inlet temperature in the range of 250 °C to 650 °C, preferably 300 °C to 400 °C; a steam-to-carbon molar ratio in the range of 0.1:1 to 5:1; and a pressure in the range of 1.0 MPag to 7.0 MPag, preferably 1.5 MPag to 6.6 MPag.

18. The method according to any one of claims 1 to 17, wherein the second depletion vessel is operated under the following conditions: an inlet temperature in the range of 400 °C 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 MPag to 7.0 MPag, preferably 1.5 MPag to 6.6 MPag; and a minimum H2 content of 0.001 kg H2 per kg of the carbonaceous component in the feed.

19. The method according to any one of claims 14 to 18, wherein the one or more additional depletion vessels are operated under the following conditions: an inlet temperature in the range of 300 °C 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 MPag to 7.0 MPag, preferably 1.5 MPag to 6.6 MPag; and a minimum H2 content of 0.001 kg H2 per kg of the carbonaceous component in the feed.

20. The method according to 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, and the hydrotreating unit and the one or more atmospheric distillation columns and the optionally one or more vacuum distillation columns provide a C1-C4 gas, a 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. A system for performing the method according to any one of the preceding claims, the system comprising: (a) A reverse water-gas shift unit configured to feed a gas mixture comprising hydrogen and carbon dioxide, the gas mixture forming a raw syngas comprising hydrogen, carbon monoxide, carbon dioxide, and steam, (b) a cooling and separation device configured to feed the raw syngas, the cooling and separation device cooling the raw syngas to condense water and removing water and optionally carbon dioxide from the raw syngas to produce a feed stream comprising hydrogen and carbon monoxide, (c) a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst, the hydrocarbon synthesis unit being configured to feed the feed stream to form a product stream comprising a mixture of liquid hydrocarbons, a co-produced water stream, and a tail gas stream comprising hydrogen, carbon monoxide, and gaseous hydrocarbons, and (d) an upgrading unit configured to feed the product stream to produce an upgraded product stream, wherein a separation device is provided to separate a naphtha stream from the product stream or the upgraded product stream; a first depletion vessel containing a depletion catalyst is configured to feed at least a portion of the tail gas stream and steam; a second depletion vessel containing a depletion catalyst is configured to feed a portion of the naphtha stream, steam, and hydrogen, in each case providing a gas mixture comprising methane; and wherein the first depletion vessel and the second depletion vessel are connected to the reverse water-gas shift unit to feed the gas mixture comprising methane from the first depletion vessel and the second depletion vessel to the reverse water-gas shift unit.

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