A method and system for synthesising hydrocarbons

Abstract

A method for synthesising hydrocarbons, the method comprising:(a) feeding hydrogen and carbon dioxide to a reverse water-gas shift unit to form synthesis gas comprising hydrogen and carbon monoxide; (

Description

Field This specification relates to a method and system for synthesising hydrocarbons from synthesis gas comprising hydrogen and carbon monoxide prepared using reverse water-gas shift and steam methane reforming. Background Processes for synthesis hydrocarbons from synthesis gas comprising hydrogen and carbon monoxide prepared using a reverse water-gas shift reaction are known. For example, WO2022 / 079407 discloses a process for synthesising hydrocarbons wherein a carbon dioxide stream and a hydrogen stream are fed to a reverse water-gas shift unit to produce synthesis gas which is fed to a Fischer-Tropsch hydrocarbon synthesis unit to produce hydrocarbons. A tail gas comprising one or more of methane, ethane, propane, butane and C5-C10 hydrocarbons may be recovered from the Fischer-Tropsch hydrocarbon synthesis unit and subjected to a derichment step, to form a deriched tail gas. The deriched tail gas may be fed to the Fischer-Tropsch hydrocarbon synthesis unit and / or to the reverse water-gas shift unit. In this regard, it is to be noted that derichment of a mixture of hydrocarbons is a known process in which C2+ hydrocarbons are converted into gas mixtures containing methane. This is generally achieved by passing a mixture of hydrocarbons through a derichment reactor containing derichment catalyst to convert longer chain hydrocarbons to methane. One potential problem with prior art methods of synthesis hydrocarbons from synthesis gas prepared using a reverse water-gas shift reaction is that the supply of feed gas, particularly hydrogen, required for the reverse water-gas shift reaction may be variable and / or unreliable. For example, it may be desirable from an environmental perspective to supply hydrogen using a water electrolyser powered by renewable energy (so-called green hydrogen). However, if the supply of renewable energy to the electrolyser is variable and / or limited, then this can lead to variable and / or limited supply of hydrogen for the reverse water-gas shift reaction. One potential solution to this problem is to provide a back-up hydrogen storage vessel so that when supply of hydrogen is insufficient, hydrogen can be provided from the back-up storage vessel. However, hydrogen can be expensive to store due to its low density and can lead to safety issues. Hydrogen gas storage also requires large amounts of space and expensive equipment (e.g., compressors and high pressure rated equipment). Liquid hydrogen storage requires less space, but also requires expensive liquefication equipment. It is an aim of the present specification to address this issue. Summary The present specification provides a method for synthesising hydrocarbons, the method comprising: (a) feeding hydrogen and carbon dioxide (e.g., as a gas mixture) to a reverse water-gas shift unit to form synthesis gas comprising hydrogen and carbon monoxide; (b) passing the synthesis gas though a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to form a product stream comprising a mixture of hydrocarbons; (c) separating and storing a portion of the mixture of hydrocarbons in a storage vessel; (d) feeding a portion of the stored hydrocarbons from the storage vessel to a derichment reactor containing a derichment catalyst generating a methane containing feed gas; and (e) feeding the methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. This method is advantageous in that rather than requiring a large storage of hydrogen for the reverse water-gas shift unit, a portion of the hydrocarbon product stream from the hydrocarbon synthesis unit is separated and stored in a storage vessel. When required, a portion of the stored hydrocarbons from the storage vessel can be used to generate a methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. As such, the present specification provides a method for synthesising hydrocarbons using both a reverse water-gas shift reaction and a steam methane reforming reaction within the reverse water-gas shift reactor. The methane containing feed gas for the steam methane reforming reaction is generated from a storage of hydrocarbons which is built up by separating and storing a portion of hydrocarbons generated by the Fisher-Tropsch reactor. This avoids, or at least reduces, the requirements for large scale hydrogen storage vessels while still being robust to variations in supply of feed gases and / or power supply and / or product demand. Such a system is desirable for operation using renewable sources of energy while being robust to variations in availability, particularly during the ongoing global energy transition when supply of such renewable energy sources may not be reliable and / or sufficient. Advantageously, the hydrocarbons are stored in the storage vessel in liquid form in step (c) and the stored hydrocarbons are converted to gas form in step (d) when feeding the stored hydrocarbons from the storage vessel to the derichment reactor. In this regard, when compared to hydrogen, hydrocarbons from the product stream of the hydrocarbon synthesis unit are easier, cheaper, and safer to reliably store in liquid form with reduced energy demand and / or need for complex equipment. Furthermore, the hydrocarbons which are separated from the product stream and stored for re-use in the system when required can be those which are not high value desirable hydrocarbon products. For example, the hydrocarbons stored in the storage vessel may comprise or consist of naphtha which is separated from the product stream of the hydrocarbon synthesis unit. Naphtha is not typically a high value desired product and recycling it back into the process increases the yield of more desirable longer chain hydrocarbons. One or both of steam and hydrogen can also be fed to the derichment reactor with the portion of stored hydrocarbons in step (d) to form the methane containing feed gas for the reverse water-gas shift unit. Typically, steam is used in a derichment reactor along with a hydrocarbon input stream to generate a methane containing gas. Addition of hydrogen to the derichment reactor with the hydrocarbon stream from the storage vessel is also advantageous to reduce or eliminate carbon formation within the derichment reactor. The quantity of stored hydrocarbon which is fed from the storage vessel to the derichment reactor during operation can be varied according to the quantity of the methane containing feed gas required by the reverse water-gas shift unit at any particular time during operation. In this regard, the quantity of the methane containing feed gas required by the reverse water-gas shift unit can be dependent on the quantity / availability of hydrogen and / or carbon dioxide for the gas mixture fed to the reverse water-gas shift unit in step (a) and / or the quantity of the product stream required from the hydrocarbon synthesis unit in step (b). For example, if there is insufficient renewable energy to generate the required quantities of hydrogen for the reverse water-gas shift unit, any short-fall can be compensated by generating methane containing feed gas for the reverse water-gas shift unit from the store of hydrocarbons separated from the product stream of the hydrocarbon synthesis unit. As such, the relative amounts of H2 / CO2 feed gas and methane feed gas to the reverse water-gas shift unit can be varied while still generating the required amount of syngas from the reverse water-gas shift unit to the Fischer-Tropsch unit. It will also be appreciated that while both reverse water gas shift and steam methane reforming reactions occur within the same reverse water-gas shift unit to generate syngas, the relative amounts of these reactions within the reverse water-gas shift unit will vary according to the relative amounts of H2 / CO2 feed gas and methane feed gas introduced to the reverse water-gas shift unit. It should also be noted that the H2 / CO2 feed gas and the methane feed gas can be mixed prior to entering the reverse water-gas shift unit or they can enter the reverse water-gas shift unit as separate feeds which mix within the reverse water-gas shift unit. The hydrogen and carbon dioxide of the H2 / CO2 feed gas can also be mixed prior to entering the reverse water-gas shift unit or enter the reverse water-gas shift unit as separate feeds which mix within the reverse water-gas shift unit. Furthermore, in addition to separating and storing a portion of the hydrocarbons from the product stream of the hydrocarbon synthesis unit, a portion of the mixture of hydrocarbons from the product stream can also be separated and fed directly to the derichment reactor without being stored in the storage vessel. That is, at least a portion of the hydrocarbon product stream can be used to continuously provide a portion of the feed gas to the reverse water-gas shift unit while in parallel a portion of the hydrocarbon product stream can be stored for future use when needed. This configuration efficiently and continuously recycles unwanted portions of the hydrocarbon product stream back into the system while simultaneously providing a storage of hydrocarbon such that the system is robust and flexible to account for future increases in product demand or shortfalls in supply of reactants. In this case, the proportion of hydrocarbons fed to the storage vessel relative to the proportion of hydrocarbons fed directly to the derichment reactor without being stored can be varied according to the quantity of the feed gas required by the reverse water-gas shift unit. As indicated previously, the quantity of the feed gas required by the reverse water-gas shift unit can be dependent on the quantity of hydrogen and / or carbon dioxide available for the reverse water-gas shift unit and / or the quantity of the product stream required from the hydrocarbon synthesis unit. In addition to the above, the hydrocarbon synthesis unit generates a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons in addition to the product stream, and at least a portion of the tail gas, optionally mixed with steam, can also be fed to either the same derichment reactor as previously described or to a second, separate, derichment reactor to generate a feed gas to the reverse water-gas shift unit. Since the tail gas stream has a different composition to the stored hydrocarbons, the optimal conditions for operating the derichment reactor for the tail gas will tend to be different to those for the stored hydrocarbons. As such, the tail gas stream can be fed to a second, separate derichment reactor which has different operating conditions to those of the derichment reactor which receives hydrocarbons from the storage vessel. In this way, optimal conditions can be provided for derichment of both the tail gas stream and the stream of hydrocarbons from the storage vessel. The hydrocarbon synthesis unit also generates a water stream in addition to the hydrocarbon product stream, and advantageously at least a portion of the water stream is electrolysed or thermochemically split to produce hydrogen which is fed to the reverse water-gas shift unit and / or the derichment reactor. This configuration provides an additional degree of flexibility to feed the reverse water-gas-shift unit while minimizing losses and emissions from the system. The reverse water-gas shift reactor will typically produce a crude synthesis gas which requires conditioning prior to being input to the hydrocarbon synthesis unit. As such, the synthesis gas generated by the reverse water-gas shift reactor is typically passed to a conditioning unit (which may comprise a plurality of sub-units) to remove water, and optionally carbon dioxide, prior to passing the synthesis gas to the hydrocarbon synthesis unit. Such synthesis gas conditioning units are known in the art. Advantageously, at least a portion of the water removed in the conditioning unit is electrolysed or thermochemically split to produce hydrogen which is fed to the reverse water-gas shift unit and / or the derichment reactor. Furthermore, advantageously at least a portion of the carbon dioxide removed in the conditioning unit is recycling to the reverse water-gas shift unit. Again, this configuration provides an additional degree of flexibility to feed the reverse water-gas-shift unit while minimizing losses and emissions from the system. The present specification also provides a system for synthesising hydrocarbons according to the method of any preceding claim. The system comprises: a reverse water-gas shift unit configured to receive hydrogen and carbon dioxide and form a synthesis gas comprising hydrogen and carbon monoxide; a hydrocarbon synthesis unit configured to receive the synthesis gas and form a product stream comprising a mixture of hydrocarbons; a separation unit configured to separate a portion of the mixture of hydrocarbons from the product stream; a storage vessel for storing the portion of hydrocarbons separated from the product stream; and a derichment reactor configured to receiving a portion of the stored hydrocarbons from the storage vessel and generate a methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. Additional features of the system are as described in relation to the method and are not repeated here for reasons of conciseness. However, it will be understood that features described in relation to the method can be combined with features of the aforementioned system. Brief Description of the Drawings Figure 1 shows a flow sheet for a method of synthesising hydrocarbons according to the present specification using reverse water-gas shift and hydrocarbons separated and stored from a Fischer-Tropsch hydrocarbon synthesis section. Figure 2 shows a flow sheet for a method of synthesising hydrocarbons according to the present specification with some additional features to those illustrated in Figure 1 including water electrolysers to recycle water and generate hydrogen for the reverse water-gas shift reaction. Figure 3 shows an example of a flow sheet for the synthesis gas generating section of the system using reverse water-gas shift and hydrocarbons separated and stored from the Fischer-Tropsch hydrocarbon synthesis section. Figure 4 shows another example of a flow sheet for the synthesis gas generating section of the system using reverse water-gas shift and hydrocarbons separated and stored from the Fischer-Tropsch hydrocarbon synthesis section. Figure 5 shows another example of a flow sheet for the synthesis gas generating section of the system using reverse water-gas shift and hydrocarbons separated and stored from the Fischer-Tropsch hydrocarbon synthesis section. A summary of the reference numerals used in the figures is set out in the table below. Reference Item 100 Hydrogen stream 102 Carbon dioxide stream 104 Reverse water-gas shift reactor 106 Hydrocarbon synthesis unit 108 Hydrocarbon (naphtha) separation unit 110 Hydrocarbon product processing unit 112 Recycled hydrocarbon (naphtha) storage unit 114 Hydrocarbon derichment reactor 116 Tail gas derichment reactor 200 Synthesis gas conditioning unit 202 Water electrolyser / thermolysis 204 Water electrolyser / thermolysis 1 High pressure steam 2 High pressure steam 3 High pressure steam 4 High pressure steam 5 Mixer 6 Stream of steam and oxygen 7 Oxygen stream 8 Hydrogen stream 9 Hydrogen stream 10 Hydrogen stream 11 Mixer 12 Stream of hydrogen and carbon dioxide (and optionally methane) 13 Feed interchanger 14 Carbon dioxide stream (optionally also including hydrogen and / or methane) 15 Heater 16 Heated carbon dioxide stream 17 Mixer 18 Feed stream for reverse water-gas shift reactor 19 Tails gas recycled from Fischer-Tropsch 20 Mixer 21 Mixture of steam and tails gas 22 Tails gas interchanger 23 Steam and tails gas stream 24 Tails gas derichment reactor 25 Stream from tails gas derichment reactor 26 Naphtha stream T1 Naphtha interchanger 28 Heated naphtha stream 29 Mixer 30 Naphtha and steam mixture 31 Naphtha heater 32 Heated naphtha / steam mix 33 Mixer 34 Naphtha / steam / hydrogen mix 35 Naphtha derichment reactor 36 Naphtha derichment reactor exit stream 37 Stream exiting the naphtha derichment reactor 38 Stream to the second carbon dioxide recovery unit 39 Second carbon dioxide recovery unit 40 Stream comprising methane and hydrogen 41 Carbon dioxide stream to storage 42 Reverse water-gas shift reactor 43 Crude synthesis gas stream 44 Synthesis gas boiler 45 Hot synthesis gas stream 46 Synthesis gas stream 47 Synthesis gas stream 48 Synthesis gas stream 49 Cooler(s) 50 Synthesis gas stream 51 Carbon dioxide recovery unit 52 Synthesis gas stream 53 Recycled carbon dioxide 54 Synthesis gas purifier / conditioner 55 Synthesis gas stream 56 Carbon dioxide stream 57 Carbon dioxide to storage Detailed Description As described in the summary section, the present specification provides a method for synthesising hydrocarbons, the method comprising: (a) feeding hydrogen and carbon dioxide (e.g., as a gas mixture) to a reverse water-gas shift unit to form a synthesis gas comprising hydrogen and carbon monoxide; (b) passing the synthesis gas though a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to form a product stream comprising a mixture of hydrocarbons; (c) separating and storing a portion of the mixture of hydrocarbons in a storage vessel; (d) feeding a portion of the stored hydrocarbons from the storage vessel to a derichment reactor containing a derichment catalyst generating a methane containing feed gas; and (e) feeding the methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. As also described in the summary section and illustrated in Figure 1, the present specification provides a system for implementing the aforementioned method. The system comprises: a reverse water-gas shift unit 104 configured to receive hydrogen 100 and carbon dioxide 102 and form a synthesis gas comprising hydrogen and carbon monoxide; a hydrocarbon synthesis unit 106 configured to receive the synthesis gas and form a product stream comprising a mixture of hydrocarbons; a separation unit 108 configured to separate a portion of the mixture of hydrocarbons from the product stream; a storage vessel 112 for storing (advantageously in liquid form) the portion of hydrocarbons separated from the product stream; and a derichment rector 114 configured to receiving a portion of the stored hydrocarbons from the storage vessel 112 and generate a methane containing feed gas to the reverse water-gas shift unit 104 where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. The main hydrocarbon product stream from the hydrocarbon synthesis unit 108 (containing desired hydrocarbon products which are not recycled back into the system) is further processed in product processing unit 110. This method is advantageous in that rather than requiring a large storage of hydrogen for the reverse water-gas shift unit, a portion of the hydrocarbon product stream from the hydrocarbon synthesis unit is separated and stored in a storage vessel. When required, a portion of the stored hydrocarbons from the storage vessel can be used to generate a methane containing feed gas to the reverse water-gas shift unit. As such, the present specification provides a method for synthesising hydrocarbons using a reverse water-gas shift unit which avoids, or at least reduces, the requirements for large scale hydrogen storage vessels while still being robust to variations in supply of feed gases and / or power supply and / or product demand. Such a system is desirable for operation using renewable sources of energy while being robust to variations in availability, particularly during the ongoing global energy transition when supply of such renewable energy sources may not be reliable and / or sufficient. Advantageously, the hydrocarbons are stored in the storage vessel 112 in liquid form and the stored hydrocarbons are converted to gas when feeding the stored hydrocarbons from the storage vessel 112 to the derichment reactor 114. In this regard, when compared to hydrogen, hydrocarbons from the product stream of the hydrocarbon synthesis unit are easier, cheaper, and safer to reliably store in liquid form with reduced energy demand and / or need for complex equipment. Furthermore, the hydrocarbons which are separated from the product stream and stored for re-use in the system when required can be those which are not high value desirable hydrocarbon products. For example, the hydrocarbons stored in the storage vessel may comprise or consist of naphtha which is separated from the product stream of the hydrocarbon synthesis unit 106. Naphtha is not typically a high value desired product and recycling it back into the process increases the yield of more desirable longer chain hydrocarbons. One or both of steam and hydrogen can also be fed to the derichment reactor 114 with the portion of stored hydrocarbons from the storage vessel 112 to form the methane containing feed gas for the reverse water-gas shift unit / reactor 104. Typically, steam is used in a derichment reactor 114 along with a hydrocarbon input stream to generate a methane containing gas. Addition of hydrogen to the derichment reactor 114 with the hydrocarbon stream from the storage vessel 112 is also advantageous to reduce or eliminate carbon formation within the derichment reactor 114. The quantity of stored hydrocarbon which is fed from the storage vessel 112 to the derichment reactor 114 during operation can be varied according to the quantity of the methane containing feed gas required by the reverse water-gas shift unit 104 at any particular time during operation. In this regard, the quantity of the methane containing feed gas required by the reverse water-gas shift unit 104 can be dependent on the quantity / availability of hydrogen 100 and / or carbon dioxide 102 for the gas fed to the reverse water-gas shift unit 104 and / or the quantity of the product stream required from the hydrocarbon synthesis unit 106. For example, if there is insufficient renewable energy to generate the required quantities of hydrogen 100 for the reverse water-gas shift reaction, any short-fall can be compensated by generating methane containing feed gas for steam methane reforming within the reverse water-gas shift unit from the store of hydrocarbons 112 separated from the product stream of the hydrocarbon synthesis unit 106. Furthermore, in addition to separating and storing a portion of the hydrocarbons from the product stream of the hydrocarbon synthesis unit, a portion of the mixture of hydrocarbons from the product stream can also be separated and fed directly to the derichment reactor 114 without being stored in the storage vessel 112 (see dashed line in Figure 1). That is, at least a portion of the hydrocarbon product stream can be used to continuously provide a portion of the feed gas to the reverse water-gas shift unit while in parallel a portion of the hydrocarbon product stream can be stored for future use when needed. This configuration efficiently and continuously recycles unwanted portions of the hydrocarbon product stream back into the system while simultaneously providing storage of hydrocarbon such that the system is robust and flexible to account for future increases in product demand or shortfalls in supply of reactants. In this case, the proportion of hydrocarbons fed to the storage vessel 112 relative to the proportion of hydrocarbons fed directly to the derichment reactor 114 without being stored can be varied according to the quantity of the feed gas required by the reverse water-gas shift unit 104. As indicated previously, the quantity of the feed gas required by the reverse water-gas shift unit 104 can be dependent on the quantity of hydrogen and / or carbon dioxide available for the gas mixture fed to the reverse water-gas shift unit and / or the quantity of the product stream required from the hydrocarbon synthesis unit 106. In addition to the above, the hydrocarbon synthesis unit 106 generates a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons in addition to the product stream, and at least a portion of the tail gas, optionally mixed with steam, can also be fed to either the same derichment reactor as previously described or to a second, separate, derichment reactor 116 to generate a methane containing feed gas to the reverse water-gas shift unit. Since the tail gas stream has a different composition to the stored hydrocarbons, the optimal conditions for operating the derichment reactor for the tail gas will tend to be different to those for the stored hydrocarbons. As such, the tail gas stream can be fed to a second, separate derichment reactor 116 which has different operating conditions to those of the derichment reactor 114 which receives hydrocarbons from the storage vessel 112. In this way, optimal conditions can be provided for derichment of both the tail gas stream and the stream of hydrocarbons from the storage vessel 112. The reverse water-gas shift reactor will typically produce a crude synthesis gas which requires conditioning prior to being input to the hydrocarbon synthesis unit. Figure 2 shows a similar configuration to the system of Figure 1 with a synthesis gas conditioning unit 200. The synthesis gas generated by the reverse water-gas shift reactor 104 is passed to the conditioning unit 200 to remove water, and optionally carbon dioxide, prior to passing the synthesis gas to the hydrocarbon synthesis unit 106. Such synthesis gas conditioning units are known in the art. Advantageously, at least a portion of the water removed in the conditioning unit 200 is electrolysed or thermochemically splitin unit 202 to produce hydrogen which is fed to the reverse water-gas shift unit 104 (and / or to the derichment reactor(s) 114 / 116). Furthermore, advantageously at least a portion of the carbon dioxide removed in the conditioning unit 200 is also recycling to the reverse water-gas shift unit 104. This configuration provides an additional degree of flexibility to feed the reverse water-gas-shift unit while minimizing losses and emissions from the system. It may be noted that while electrolysers may be utilized during normal operation, there may be insufficient power to operate electrolysers during turndown. As such, electrolysers may be operated during normal operation but not operated during turndown. As also illustrated in Figure 2, the hydrocarbon synthesis unit 106 also generates a water stream in addition to the hydrocarbon product stream, and advantageously at least a portion of the water stream is electrolysed or thermochemically split in unit 204 (which may be the same or different to unit 202) to produce hydrogen which is fed to the reverse water-gas shift unit 104 (and / or to the derichment reactor(s) 114 / 116). This configuration also provides an additional degree of flexibility to feed the reverse water-gas-shift unit while minimizing losses and emissions from the system. In other respects, the system shown in Figure 2 is the same as that shown in Figure 1. Further features of components and operating parameters for these systems are discussed below. The reverse water-gas shift unit may comprise any suitable reactor or combination of reactors that conduct the reverse water-gas shift reaction. The reverse water-gas shift unit may comprise a reactor containing a reverse water-gas shift catalyst. Alternatively, the reverse water-gas shift reactor unit may operate non-catalytically, i.e., without a catalyst. The process may therefore comprise subjecting the 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 depicted as follows: CO2 + H2 # CO + H2O AH = +9.8 kcal / mole The reverse water-gas shift process therefore is favoured at high temperatures. The reverse water-gas shift reactor may be plasma-heated or electrically-heated. The gas mixture comprising hydrogen and carbon dioxide may therefore be subjected to an electrically heated reverse water-gas shift reaction or a plasma-heated reverse-water-gas-shift reaction. The gas mixture comprising hydrogen and carbon dioxide may be subjected to an autothermal reverse water-gas shift reaction. A particularly preferred reverse water-gas shift unit comprises an autothermal shift reactor in which hydrogen and carbon dioxide are fed as a mixture or separately to a burner inside a reverse water-gas shift vessel where they are partially combusted with oxygen to generate a heated gas comprising hydrogen, steam, carbon monoxide and carbon dioxide that passes through a bed of reverse water gas shift catalyst disposed downstream of the burner. Such an arrangement is described in WO2022 / 079408. Hydrogen is combusted in the reverse water-gas shift vessel to generate heat for the reverse water-gas shift reaction. Accordingly, in this arrangement hydrogen should be provided in excess of the carbon dioxide so that sufficient hydrogen remains after combustion to drive the reaction forward over 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 desirably about 2:1. The molar ratio of hydrogen to carbon dioxide in the gas mixture fed to the burner may be in the range of 1:1 to 5:1. The ratio may vary depending on the conversion of the carbon dioxide achieved in the reverse water-gas shift unit and the desired hydrogen to carbon monoxide ratio for the downstream process. The gas mixture comprising carbon dioxide and hydrogen fed to the burner may comprise 15 to 50% by volume, preferably 25 to 40% by volume, of carbon dioxide. The gas mixture comprising carbon dioxide and hydrogen fed to the burner preferably comprises less than 10% vol in total of other gases, such as steam, nitrogen, carbon monoxide and methane. Any suitable source of hydrogen may be used. More than one source of hydrogen may be used. The process preferably utilises non-fossil fuel based hydrogen. Accordingly, the hydrogen may be generated by catalytic or non-catalytic partial oxidation of biomass or plastics, optionally followed by steam reforming of the partial oxidation product gases. Alternatively, the hydrogen may be provided by splitting water. Preferably, the hydrogen is electrolytic hydrogen, for example hydrogen formed by electrolysis of water. While intermediate storage of the hydrogen may be used to reduce any variability in production of hydrogen from the electrolysis, as described previously, the present specification can reduce or eliminate this requirement via storage of a proportion of hydrocarbon product from the system which can be used to generate a feed gas for the reverse water-gas shift unit. In some embodiments the co-produced water from the hydrocarbon synthesis unit may also be subjected to electrolysis to produce an electrolysis hydrogen stream used in the process. Such water electrolysis may conveniently use electricity from renewable sources such as solar, wind or tidal power. By using renewable electricity, the overall carbon intensity of the process can be negative, resulting in overall negative carbon dioxide emissions. Any suitable source of carbon dioxide may be used. Thus, the carbon dioxide stream may be a stream recovered from a conventional ammonia plant that uses a hydrocarbon or carbonaceous feed, or the carbon dioxide stream may be one recovered from a furnace or boiler flue gas, wherein the furnace or boiler is heated by combustion of a carbonaceous fuel, such as natural gas or coal, biomass, or carbonaceous wastes, such as plastics. 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 from downstream of the reverse water-gas shift unit, for example following treatment of the crude synthesis gas 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. In some arrangements, the carbon dioxide may at least in part be recovered from a synthesis gas stream generated by a synthesis gas generation unit upstream of the reverse water-gas shift unit. This has the advantage that the synthesis gas generation unit provides additional hydrogen and carbon monoxide for use in the hydrocarbon synthesis unit. While the systems as described herein can use a reverse water-gas shift unit as the primary, or only, source of synthesis gas for the hydrocarbon synthesis unit, it is also possible to provide a system in which synthesis gas is provided from alternate sources, in which case the reverse water-gas shift configuration can be utilized as a secondary source of synthesis gas for the hydrocarbon synthesis unit. In that case, the alternative source of synthesis gas may be provided by a synthesis gas generation unit which may be any unit that converts a feedstock into a synthesis gas comprising hydrogen, carbon monoxide and carbon dioxide. Depending on the nature of the feedstock various syngas generation technologies may be preferred. For example, where the feedstock is natural gas, the synthesis gas generation unit preferably comprises a catalytic partial oxidation unit, a non-catalytic partial oxidation unit or an autothermal reformer. Alternatively, where the feedstock is coal, biomass or municipal solid waste or equivalent containing non-biogenic carbon, the synthesis gas generation unit preferably comprises a gasifier. Any known gasification technology may be used. Preferably, the gasification is carried out by partial oxidation, which comprises combusting the feedstock under sub-stoichiometric conditions at high temperature, generally between 800°C and 1600°C, with air or oxygen in order to obtain a crude synthesis gas. When a nitrogen-free synthesis gas is desired, this process uses oxygen. Gasification produces synthesis gas and a residual fraction comprising tar oils. The synthesis gas is generally a gas mixture comprising carbon monoxide, hydrogen, water vapour and carbon dioxide. In addition, it typically will comprise sulphur-comprising, nitrogen-comprising and halogen-comprising impurities. Common sulphur-containing impurities are carbonyl sulphide (COS) and hydrogen sulphide (H2S). These impurities, where present, are desirably removed upstream of the Fischer-Tropsch hydrocarbon synthesis unit using one or more contaminant removal stages by washing (absorption), by passing the crude synthesis gas through one or beds of a suitable adsorbent, or by a mixture of these. Synthesis gas purification may be performed in one or more stages before and / or after the carbon dioxide removal unit. The reverse water-gas shift unit and synthesis gas generation unit, if present, may use oxygen. Oxygen may be recovered from air using an air separation unit (ASU), which may be driven by renewable power sources or steam raised in the reformed gas boiler or other sources, including from downstream processes. Preferably, the oxygen used in the process comprises electrolytic oxygen, for example oxygen formed by the electrolysis of water in an electrolysis unit. This has the benefit of reducing the capital investment in an air separation plant and / or reduces the power consumption by an air separation plant, if required. Hydrogen and oxygen for the process are therefore both preferably generated using an electrolysis unit to which a source of water is fed. The water may include condensate recovered from the crude synthesis gas mixture produced by the reverse water-gas shift unit, or in an upstream syngas generation unit, and / or may comprise the water recovered from a downstream conversion unit such as a Fischer-Tropsch hydrocarbon synthesis unit. If required, the water may be treated to remove contaminants, such as organic compounds or salts, that would adversely affect the electrolysis unit. The electricity for the electrolysis unit is desirably not obtained from the combustion of fossil fuels. The electrical power for the electrolysis may be provided by nuclear power or preferably, by renewable power sources, such as photovoltaic solar energy, wind energy, tidal energy, waterpower or hydroelectricity, marine energy sources, geothermal energy and / or biomass. The electricity for the electrolysis may also be provided using a turbine driven by steam generated using heat recovered from product gas streams created by the partial oxidation of biomass or plastic waste. Electrical power may be stored in an intermediate facility such pumped hydro- or battery-storage to provide a more constant supply of electrical power to the electrolysis unit. The carbon dioxide and hydrogen streams or the gas mixture comprising the carbon dioxide and hydrogen may, if required, be compressed to a pressure in the range of 0.8 to 6.5 MPag, preferably 1.2 to 5.5 MPag. Before, but preferably after compression, the gas streams fed to the reverse water-gas shift unit may be preheated. The pre-heat temperature of the feed gases to an autothermal reverse water-gas shift vessel are preferably in the range of 400 to 1200°C, 400 to 1000°C, or 450 to 800°C to sustain combustion and minimise carbon formation. The hydrogen and carbon dioxide streams may be premixed before preheating or preheated and mixed. Preheating of the feeds to their pre-heat temperatures may be done by interchange with the crude synthesis gas mixture, and / or by steam heating, or by using a fired heater or by electrical heating or by a combination of two or more these. Preferably, the feed gas mixture comprising carbon dioxide and hydrogen is heated by interchange with the crude synthesis gas mixture, optionally supplemented by electrical heating. In the present specification, carbon dioxide is converted to carbon monoxide by subjecting it to the 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. A preferred reverse water-gas shift unit comprises an autothermal reverse water-gas shift vessel containing a burner and a fixed bed of the reverse water-gas shift catalyst. The burner is fed with the carbon dioxide containing gas and an oxygen stream and combusts a portion of the hydrogen and any hydrocarbons present in the carbon dioxidecontaining gas, thereby generating heat for the endothermic reverse water-gas shift reaction. Methane feed gas generated from stored hydrocarbons via a derichment reactor is also combusted in the reverse water-gas shift unit and undergoes steam methane reforming within the unit to generate syngas. Further still, methane feed gas generated from Fischer-Tropsch tails gas via a derichment reactor is also combusted in the reverse water-gas shift unit and undergoes steam methane reforming within the unit to generate syngas. The oxygen, carbon dioxide, hydrogen, and methane are fed to a burner disposed in a reverse water-gas shift unit which sustains both reverse water-gas shift and steam methane reforming reactions. Any burner design may be used, such as burners used in autothermal reformers. Combustion generates a flame in a combustion zone upstream of the catalyst within the reverse water-gas shift unit. The localized conditions in the combustion section, especially in the flame front region, may be controlled by managing the momentum of the oxidant and gas streams. The water-gas shift unit may be orientated such that the combustion zone is above the bed of reverse water-gas shift catalyst. Such arrangements are used in autothermal reforming vessels and may be used in the present process, which may be termed autothermal reverse water-gas shift. Other arrangements of the burner and catalyst may however also be used. The gas mixture is heated by the combustion to a temperature typically in the range of 800 to 1300°C. Oxygen is consumed. The heated gas mixture comprising carbon monoxide, carbon dioxide, steam, and unreacted hydrogen is then passed through a bed of reverse water-gas shift catalyst disposed within the reverse water-gas shift vessel downstream of the burner. The reverse water-gas shift catalyst may be any suitable transition metal oxide catalyst, for example a catalyst based on nickel oxide, iron oxide or on chromium oxide, but other catalysts used as reverse water-gas shift catalysts may be used. Preferably the catalyst is a nickel-oxide based catalyst. Such catalysts are active for the reverse water-gas shift catalyst but advantageously will also steam reform methane provided by the derichment reactors and present in the gas mixture comprising hydrogen and carbon dioxide. The catalyst therefore preferably comprises nickel oxide on a suitable refractory metal oxide support. The refractory metal oxide support may comprise zirconia, alumina, calcium aluminate, magnesium aluminate, titania magnesia, or mixtures thereof. More preferably, the catalyst comprises nickel oxide on zirconia, nickel oxide on alpha-alumina, nickel oxide on calcium aluminate or nickel oxide on magnesium aluminate. The nickel content may be in the range of from 3 to 20% by weight, expressed as NiO. The reverse water-gas shift catalyst may be particulate, for example in the form of shaped units such as pellets, rings or extrudates, which may be lobed or fluted. The catalytically active metal, e.g., nickel, may be dispersed throughout the particulate catalyst or present only within an eggshell layer of thickness 200 to 1000 micrometres on the surface of the refractory support. Alternatively, catalyst may comprise one or more monolithic supports such as a metal or ceramic foam or honeycomb supporting the catalytically active metal. Preferably, the catalyst is a particulate catalyst, more preferably 4-hole cylinder, particularly one that is a lobed or fluted to provide a higher geometric surface area (GSA) than a similarly sized solid cylinder. Catalysts having a GSA in the range 400-550 m2 per cubic metre are preferred. 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 surface of the catalyst from irregularities in the combusting gas flow. A benefit of providing this layer is to prevent disturbance of the surface of the catalyst bed. By controlling the pre-heat temperature and the amount of oxygen fed to the burner, it is possible to control the exit temperature of the reverse water-gas shift vessel. The exit temperature may be in the range 700 to 1050°C, preferably 750 to 950°C. In addition to producing the carbon monoxide gas stream by the reverse water-gas shift reaction, the reverse water-gas shift vessel is used to convert methane generated from waste streams from downstream processes into carbon monoxide. The reverse water-gas shift vessel is therefore fed with a methane-containing gas stream from a derichment reactor which is fed by a hydrocarbon stream from a storage vessel containing hydrocarbons separated from the product stream of the hydrocarbon synthesis unit. Advantageously, two derichment reactors are provided, a first derichment reactor being fed with at least a portion of a tail gas recovered from the Fischer Tropsch hydrocarbon synthesis unit and a second derichment reactor which is fed with a portion of the stored naphtha recovered from the hydrocarbon synthesis unit or an upgrading unit coupled to the hydrocarbon synthesis unit. The derichment reactors operate by adiabatically steam reforming hydrocarbons in the tail gas and naphtha streams. Accordingly, a supply of steam to the derichment reactors is also required. Furthermore, in order to satisfactorily steam reform the naphtha without deactivation of the catalyst by carbon formation, a source of hydrogen is also provided to the second derichment reactor. In the aforementioned configuration, at least a portion of the tail gas stream is fed with steam to a first derichment reactor containing a derichment catalyst to form a gas mixture containing methane, and at least a portion of the stored naphtha is fed with hydrogen and steam to a second derichment reactor containing a derichment catalyst to form a second gas mixture containing methane. The steam introduction may be achieved by direct injection of steam and / or by saturation of the feed gas by contact with a stream of heated water. The heated water may comprise condensed water from a downstream process that contains soluble organic compounds. Alternatively, the steam used for direct injection may have been used to strip organic compounds from condensed water from a downstream process. In this way, the organic compounds may be converted to hydrogen and carbon oxides in the derichment reactor and the burden of wastewater treatment for the downstream process may be reduced. The amount of steam introduced may be such as to give a steam to carbon molar ratio in the feeds to the derichment reactors of 0.1:1 to 5:1. The steam to carbon molar ratio is defined as the molar ratio of steam to the sum of the carbon-containing components in the feed, including hydrocarbons, CO and CO2. The derichment reactor feed gases, typically have inlet temperatures in the range of 250-650°C. The feed gases may be passed adiabatically through a bed of a derichment catalyst, such as a particulate nickel catalyst having a high nickel content, for example above 40% by weight. Such catalysts are available commercially. The same or a different catalyst may be used in the first and second derichment reactors. A stream of hydrogen is fed with the naphtha to the second derichment reactor to reliably convert naphtha to methane. The hydrogen may be a pure hydrogen stream or may comprise a suitably high hydrogen content to provide the hydrogen for the derichment. In some embodiments a pure hydrogen stream may be supplemented with hydrogen-containing off gas from the hydrocarbon synthesis unit and / or the upgrading unit. During the derichment step, any hydrocarbons higher than methane react with steam to give a mixture of methane, carbon oxides and hydrogen. In some arrangements the first derichment reactor operates with an inlet temperature in the range of 250 to 650°C, preferably 300 to 400°C and a steam to carbon molar ratio of 0.1:1 to 5:1. If desired, the first derichment reactor may be operated at a pressure in the range of 1.0 to 7.0 MPag, preferably 1.5 to 6.6 MPag. In some arrangements the second derichment reactor operates with an inlet temperature in the range 400 to 550°C, a steam to carbon molar ratio of 1:1 to 5:1 and a minimum Hz content of 0.001 kg H? per kg of carbon-containing components in the feed. If desired, the second derichment reactor may be operated at a pressure in the range of 1.0 to 7.0 MPag, preferably 1.5 to 6.6 MPag. The operating pressure of the first and second derichment reactors may be the same or different. Generating methane-containing gas mixtures is preferred over feeding the tail gas, hydrocarbon offgas and naphtha streams directly to the reverse water-gas shift unit because it reduces the risk of unwanted carbon formation in the reverse water-gas shift vessel or on the reverse water-gas shift catalyst. The gas mixtures containing methane recovered from the derichment reactors are fed to the reverse water-gas shift unit. The gas mixtures containing methane may be fed separately from the derichment reactors to the reverse water-gas shift unit or mixed with one or both of the hydrogen and carbon dioxide feed streams. The gas mixtures containing methane may optionally be preheated. The gas mixtures containing methane may be preheated separately or once combined with the hydrogen and carbon dioxide stream feeds. When using an autothermal reverse water-gas shift reactor, the gas mixtures containing methane may be pre-heated to a temperature in the range of 400 to 1200°C, 400 to 1000°C, or 450 to 800°C to sustain combustion and minimise carbon formation. 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 arrangements, it is possible to separate a hydrocarbon synthesis unit naphtha stream from the product stream upstream of the upgrading unit. The naphtha stream may be recovered by cooling the product stream and separating it using one or more vapour-liquid separators. The naphtha stream recovered from the hydrocarbon synthesis unit typically comprises of a mixture of C3 to C9 hydrocarbons with an approximate final boiling point of less than 240°C. In addition, the hydrocarbon synthesis unit may be operated to produce a hydrocarbon synthesis unit hydrocarbon off-gas stream by physical separation of light gaseous hydrocarbons, e.g., Cl, C2, C3 and C4 hydrocarbons, from heavier liquid hydrocarbons and co-produced water fed to one or more vapour-liquid separators in the FT unit. The upgrading unit may be configured to produce an upgrader naphtha stream from the product stream. The upgrader naphtha stream may be recovered in the upgrading unit from one or more distillation columns in which feeds are heated and hydrocarbons separated based on their boiling points. The naphtha product stream recovered from the upgrading unit typically comprises saturated hydrocarbons typically C5 to Cll with a boiling point in the range 30 to 220°C. Generally, it will be either the naphtha from the hydrocarbon synthesis unit or the naphtha from the upgrading unit that will be fed to the storage vessel and optionally directly to the derichment reactor. Hence, the naphtha stream from the hydrocarbon synthesis unit or the upgrading unit may be compressed, vapourised, mixed with steam and hydrogen and fed to the derichment reactor. The upgrading unit may be configured to additionally produce an upgrader hydrocarbon off-gas stream. The upgrader hydrocarbon off-gas stream may be recovered in the upgrading unit from a letdown vessel in which pressure of a mixed hydrocarbon feed is reduced causing light hydrocarbons to flash or volatilise, or from one or more distillation columns in which feeds are heated and hydrocarbons separated based on their boiling points. The let-down vessel and one or more distillation columns may be downstream of a hydrotreating unit. The upgrader off-gas will typically comprise saturated hydrocarbons, hydrogen, methane, carbon monoxide, carbon dioxide and inert contaminants such as nitrogen. One or both of the hydrocarbon off-gas streams may usefully be recycled to the process to further improve carbon efficiency of the process and minimise carbon-containing streams sent to fuel where they would ultimately lead to carbon dioxide emissions. As the off-gas streams may be produced at similar pressures it may be advantageous to compress them together rather than individually prior to being fed to the derichment reactor. Accordingly, the upgrader hydrocarbon off-gas and optionally the hydrocarbon synthesis unit hydrocarbon off-gas may also be fed to the first derichment reactor and / or the second derichment reactor. Alternatively, one or more further derichment reactors may be provided for treatment of one or both of the hydrocarbon off-gas streams. The destination of the off-gas streams will depend on the proportion of C2, C3 and C4 hydrocarbons present when combining the streams with the tail gas or the naphtha stream. It may be advantageous for operational flexibility and optimised operating conditions to feed the off-gas to a third derichment reactor. Thus, in some arrangements, a third derichment reactor containing a derichment catalyst is fed with at least a portion of the upgrader hydrocarbon off gas, steam and optionally a portion of the hydrocarbon synthesis unit hydrocarbon off-gas, to produce a further gas mixture containing methane that is fed to the reverse water gas shift unit. If desired a hydrogen stream may also be provided to the one or more further derichment reactors to improve derichment of the off-gas stream. In some arrangements, the one or more further derichment reactors may be configured to operate with an inlet temperature in the range 300 to 500°C, a steam to carbon molar ratio of 1:1 to 5:1 and a minimum Hz content of 0.001 kg H? per kg of carbon-containing components in the feed. If desired, the one or more further derichment reactors may be operated at a pressure in the range of 1.0 to 7.0 MPag, preferably 1.5 to 6.6 MPag. The pressure of the one or more further derichment reactors may be the same or different from the first and second derichment reactors. The upgrading unit may also be operated to additionally produce a light hydrocarbon liquid stream that, if desired, may be recycled to the first, second or one or more further derichment reactors. The light hydrocarbon liquid stream will primarily comprise of C3 and C4 saturated hydrocarbons. If used, the light hydrocarbon liquid will require compression and vaporisation prior to being fed to one or more further derichment reactors. The proportions of the naphtha, tails gas, off-gas and light hydrocarbon streams fed to the derichment reactors will vary depending on the product slate produced from the upgrading unit and on the recycle ratio of tail gas within the hydrocarbon synthesis unit. It is expected that the proportion of tail gas by mass will be greater than the off-gas streams, with sufficient hydrogen contained in the tail gas to require no further hydrogen addition to the first derichment reactor if fed also with the off-gas. If sulphur contaminants are present in the naphtha and upgrader hydrocarbon off-gas streams in the upgrading unit, these may be removed, preferably after compression, by subjecting the naphtha and upgrader off-gas stream to a step of desulphurisation upstream of the derichment step. This may be accomplished using any suitable desulphurisation method, such as including absorbing the sulphur compounds by passing the streams through beds of zinc oxide absorbents. The upgrader hydrocarbon off-gas may be recovered at a pressure in the range 0.1 to 1.0 MPag. The hydrocarbon synthesis unit hydrocarbon off-gas may be recovered at a pressure in the range 0.1 to 1.0 MPag. If desired, the upgrader hydrocarbon off-gas and the hydrocarbon synthesis unit hydrocarbon off-gas may be compressed to a pressure in the range 1.0 to 7.0 MPag. The offgases may be compressed separately or preferably combined and compressed. The gas mixtures containing methane from the first, second and one or more further derichment reactors will contain unreacted steam. It is usually not necessary to do so, but if desired the steam may be condensed by cooling the deriched gas mixtures to below the dew point and recovering condensate to produce de-watered deriched gas feed to the reverse water gas shift unit. Removing the steam may improve the reverse water-gas shift equilibrium. The recovered condensate may usefully be used to generate steam for the process or used to generate hydrogen by electrolysis of water. The gas mixtures containing methane may be compressed, if desired before feeding to the inlet of the reverse water-gas shift unit. Compression may be performed before or preferably after any dewatering step. 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 streams from the derichment reactors. Alternatively, methane-containing gas streams may be optionally preheated and fed separately to the reverse water gas shift reactor. 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 generates a crude synthesis gas mixture. The crude synthesis gas mixture from the reverse water-gas shift vessel comprises steam formed by the reverse water-gas shift reaction and possibly steam added with the gas mixtures containing methane. Water is recovered from the crude synthesis gas mixture by cooling the product gas mixture to below the dew point and separating condensate, e.g., using one or more conventional gas-liquid separators. Removing water condensate from the crude synthesis gas mixture produces a dewatered product gas. The cooling may be performed by raising steam and / or by preheating one or more of the hydrogen stream, the carbon dioxide stream, the mixed gas stream comprising hydrogen and carbon dioxide, and optionally the derichment reactor feed gases. Further cooling with cold water and / or air may also be performed. Process steam generated by the cooling may be used in the derichment step or in downstream processes and / or for power generation. The condensed water may, if desired, be recycled at least in part to the process. The condensate may be used, after treatment if desired, be used as boiler feed water. In addition, or alternatively, the condensate, optionally after treatment to use contaminants, may be fed to an electrolysis unit used to generate hydrogen for the process. Accordingly, in some embodiments, a water stream recovered from the crude synthesis gas mixture may be fed to an electrolysis unit. Condensate may also be used, again after treatment if desired, as a boiler feed water. The crude synthesis gas mixture contains carbon dioxide, which is removed from the dewatered product gas using a carbon dioxide removal unit. The majority of the carbon dioxide may be separated by membrane, solid absorbent, adsorbent or, preferably, a wash system, such as a system operating by counter current contact of the crude synthesis gas mixture or dewatered product gas with absorbent liquid over packing in a tower. The absorbent liquid can be a physical solvent such as potassium carbonate (sold as the Benfield process), methanol (sold as the Rectisol process) or glycols (sold as the Selexol process) or chemical solvents such as amines. The carbon dioxide removal unit may therefore include one or more vessels providing a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system. The carbon dioxide may be removed by a conventional acid gas recovery unit (AGRU). In a conventional AGRU, a de-watered gas stream is contacted with a stream of a suitable absorbent liquid, such as an amine, for example an aqueous solution comprising monoethanolamine (MEA), methyldiethanolamine (MDEA) or dimethylethanolamine (DMEA), particularly methyl diethanolamine (MDEA), so that the carbon dioxide is absorbed by the liquid to give a laden absorbent liquid and a gas stream having a decreased content of carbon dioxide. The laden absorbent liquid is then regenerated by heating and / or reducing the pressure to desorb the carbon dioxide and to give a regenerated absorbent liquid, which is then recycled to the carbon dioxide absorption stage. Heat from the regeneration of the laden absorbent may be recovered from within the process. For example, a portion of the crude synthesis gas mixture or steam generated by cooling the crude synthesis gas mixture may be used to heat the laden absorbent. Alternatively, in place of the washing with amines, cold methanol or a glycol may be used in a similar manner as the amine to remove the carbon dioxide. The recovered carbon dioxide obtained from the carbon dioxide removal unit is preferably recompressed as required and returned to the reverse water-gas shift unit to increase the overall conversion to carbon monoxide. The recovered carbon dioxide may be combined with the carbon dioxide feed, the hydrogen gas feed or the gas mixture containing hydrogen and carbon monoxide before pre-heating. It is preferably combined with the carbon dioxide feed stream before compression thereof. The removal of carbon dioxide from the dewatered product gas produces a gas stream comprising carbon monoxide. Hydrogen will also be present in the product gas with the amount depending on the excess of hydrogen fed to the reverse water-gas shift vessel. If desired, one or more purification units may be provided downstream of the carbon dioxide removal unit to remove contaminants from the gas stream comprising carbon monoxide. The gas stream comprising carbon monoxide comprises carbon monoxide and hydrogen. The hydrogen to carbon monoxide molar ratio may be in the range 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. In the present specification, the product syngas is fed to a Fischer-Tropsch hydrocarbon synthesis unit that synthesises a mixture of hydrocarbon products. The Fischer-Tropsch hydrocarbon synthesis unit may comprise one or more Fischer-Tropsch reaction vessels containing a Fischer-Tropsch catalyst. The Fischer-Tropsch conversion stage can be carried out according to any one of the known processes, using any one of the known catalysts, but is advantageously applied to processes using cobalt catalysts. The Fischer-Tropsch process involves a series of chemical reactions that produce a variety of hydrocarbons, ideally having the formula (CnH2n+2). The more useful reactions produce alkanes as follows: (2n + 1) H2 + n CO -> CnH2n+2 + n H2O, where n is typically 5-100 or higher, with preferred products having n in the range 10-20. The Fischer-Tropsch reaction may be performed using one or more reactors such as fixed-bed reactors, slurry-phase reactors, bubble-column reactors, loop reactors or fluidised bed reactors. The process may be operated at pressures in the range 0.1 to 10 MPag and temperatures in the range 170 to 350°C. The gas-hourly-space velocity (GHSV) for continuous operation is in the range 1000 to 25000 hr1. Preferably the Fischer-Tropsch synthesis is carried out using one or more fixed bed reactors, i.e. a reaction vessel with a bed of catalyst fixed within the vessel through which the purified synthesis gas is passed. Any Fischer-Tropsch catalyst may 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 preferred catalysts in the process comprise 9 to 20% wt Co supported on a suitable support material. Suitable catalysts therefore include agglomerates, pellets or extrudates comprising metal oxides such as alumina, zinc oxide, titania 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 carrier suitable for use in a tubular Fischer-Tropsch reactor where the catalyst carrier containing the catalyst is disposed within one or more tubes that are cooled by circulating coolant, such as water under pressure. By "catalyst carrier" we mean a catalyst container, for example in the form of a cup or can, configured to allow a gas and / or liquid to flow into and out of the carrier and through a bed of the catalyst or catalyst precursor disposed within the carrier. Any suitable catalyst carrier may be used. In one arrangement, the catalyst carrier is that described in WO2011 / 048361, the contents of which are incorporated herein by reference. In an alternative arrangement, the catalyst carrier may include a catalyst monolith as disclosed in WO2012 / 136971, the contents of which are also incorporated herein by reference In yet another alternative arrangement, the catalyst carrier may be that disclosed in WO2016 / 050520, the contents of which are also incorporated herein by reference. In preferred embodiments, the Fischer-Tropsch hydrocarbon synthesis unit comprises a tubular reactor in which catalyst carriers containing a Fischer-Tropsch catalyst are disposed within one or more tubes cooled by a cooling medium. Typically, a portion of the carbon monoxide is converted in the one or more Fischer-Tropsch reactors to produce a mixture of liquid hydrocarbon products, co-produced water, and a gaseous mixture containing unreacted hydrogen and carbon monoxide, plus carbon dioxide and gaseous light hydrocarbons including methane, ethane, propanes and butanes. The reaction product mixture may be cooled, and the aqueous and liquid hydrocarbon streams separated from the gas mixture using one or more gas-liquid separators. The co-produced water may be separated using known hydrocarbon-water separators. The separated gas mixture, which may be termed "tail gas", may be used in a number of ways. Preferably a first portion of the tail gas is recycled to the one or more Fischer-Tropsch reactors in a synthesis loop to increase the overall conversion of carbon monoxide to hydrocarbons. The fraction that is recycled to form the loop may be set to control the build-up of inert gases, such as methane, in the Fischer-Tropsch hydrocarbon synthesis unit to an acceptable level. The remaining portion still contains a valuable source of carbon. Accordingly, a portion of the tail gas is recycled to the reverse water-gas shift unit via the first derichment reactor containing a derichment catalyst that converts any C2+ higher hydrocarbons present in the 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 derichment step. The portion that is not recycled to the reverse water-gas shift unit, which may be termed "purge gas", may be removed from the process to prevent the build-up of inert gases. The purge gas may be exported as fuel or used within the process in a fired heater or thermal oxidiser to heat feed to the reverse water-gas shift vessel or superheat steam. 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 a molten hydrocarbon wax and a light hydrocarbon condensate, which is liquid at ambient temperature. Desirably, the hydrocarbon synthesis unit is operated to produce a molten hydrocarbon wax liquid, which is subjected to upgrading treatments in a hydrotreating unit to generate liquid fuels. Accordingly, in some embodiments, at least a portion and preferably all of the liquid hydrocarbon mixture resulting from the hydrocarbon synthesis is fed as a feedstock, in the presence of hydrogen, to an upgrading unit comprising a hydrotreating unit. The hydrotreating unit may perform various conversions such as hydroisomerization, hydrogenation, hydrodeoxygenation, and / or hydrocracking using one or more vessels containing suitable catalysts. Hydrogen is required by the hydrotreating unit. This may be provided by various sources but is desirably provided by an electrolysis unit to minimise carbon dioxide emissions from the process. Accordingly, in some embodiments, a portion of the hydrogen stream from an electrolysis unit is fed to the hydrotreating unit. The hydrotreating unit may be operated at a temperature generally of between 200 and 450°C, preferably from 250 to 450°C, more preferably from 300 to 450°C and most preferably between 320 to 420°C; a pressure of between 0.2 and 15 MPag, preferably between 0.5 and 10 MPag and more preferably from 1 to 9 MPag; a liquid hourly space velocity of between 0.1 and 10 h'1, preferably between 0.2 and 7 h-1 and more preferably between 0.5 and 5.0 h'1, and the hydrogen content may be between 100 and 2000 litres Hz per litre of feedstock and preferably between 150 and 1500 litres Hz per litre of feedstock. The hydrotreating stage may suitably be carried out under conditions such that the conversion per pass of products with a boiling point of greater than or equal to 370° C into products having boiling points of less than 370° C is greater than 40% by weight and more preferably at least 50% by weight, so as to obtain middle distillates (gas oil and kerosene) having sufficiently good cold properties (pour point, freezing point) to satisfy the specifications in force for this type of fuel. The catalysts used in this stage are known. For example, hydroisomerization and hydrocracking can be carried out according to any one of the known processes, using any one of the known catalysts, and it is not limited to a specific process or catalyst. The majority of the catalysts suitable for hydroisomerization / hydro-cracking are of the bifunctional type combining an acid function with a hydrogenating function. The acid function is generally provided via supports of high specific surface area (150 to 800 m2 / g generally) exhibiting a surface acidity, such as halogenated (in particular chlorinated or fluorinated) aluminas, phosphorated aluminas, combinations of boron and aluminium oxides, or silicas / aluminas. The hydrogenating function is generally provided either by one or more metals from Group VIII of the Periodic Table of the Elements, 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, and at least one metal from Group VIII. Most conventional hydrocracking catalysts are composed of weakly acidic supports, such as silicas / aluminas. These systems are typically used to produce middle distillates of very good quality. Many catalysts of the hydrocracking market are based on silica / alumina in combination with a metal from Group VIII. These systems have a very good selectivity for middle distillates and the products formed are of good quality. According to one preferred embodiment, the hydroisomerization / hydrocracking catalyst comprises at least one hydro-dehydrogenating element chosen from the noble metals of Group VIII, preferably platinum and / or palladium, and at least one amorphous refractory oxide support, preferably silica / alumina. The hydrocarbon products recovered from the hydrotreatment unit may be fed to separation apparatus to recover the valuable hydrocarbon products. The separation apparatus may comprise one or more atmospheric distillation columns and optionally one or more vacuum distillation columns that separate the upgrader hydrocarbon off-gas, the naphtha fraction, and 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 of greater than 370° C. This fraction is advantageously recycled to hydrotreatment unit. It may also be advantageous to recycle a portion of the kerosene to the hydrotreatment 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 product. The methodology and systems of the present specification are advantageous during periods when the availability of electrical power is low, and thus, insufficient to operate an electrolyser to supply hydrogen feed stock to the RWGS reactor. Naphtha is separated from the hydrocarbon product stream and stored. This stored naphtha can then be deriched to produce a feed stream for the RWGS reactor when required. This reduces the amount of hydrogen storage that would otherwise be required to maintain plant operation. As previously described, when compared to storage of feed gases for the reverse water-gas shift reactor (carbon dioxide, hydrogen, oxygen, steam), naphtha storage and subsequent derichment and use as a feed stream allows for reduced hydrogen storage by generating hydrogen, carbon monoxide, carbon dioxide, and methane that are fed to the RWGS reactor. Benefits of the present methodology are the reduction of hydrogen storage and the ability to continue plant operation during low power periods. During power down times where the power supply is not 100% available, the plant will need to operate at variable loads. This leads to the requirement of feed storage vessels. Hydrogen, in particular, can be expensive to store due to its low density. Hydrogen gas storage requires large amounts of plot space and expensive equipment (compressors and high pressure rated equipment). Liquid hydrogen storage requires less space but expensive liquefication equipment. Thus, by using naphtha to generate a portion of the RWGS feed, the cost of hydrogen storage can be reduced. Furthermore, reduced pressurised hydrogen storage is inherently safer. Further still, since naphtha is not typically a desired product, recycling the naphtha back into process increases the yield of more desirable longer chain hydrocarbons. In relation to the above, it should be noted that naphtha, which typically falls in the C4 - C9 hydrocarbon chain length range, is heated and dosed with steam and hydrogen before it is fed to the derichment reactor where it undergoes reforming reactions, water gas shift reaction, and methanation reactions. These reactions are set out below. Reforming Reactions: CnHm + nH20 -> nCO + (0.5m + n)H2 CH4 + H20 o CO + 3H2 CH4 + CO2 o 2CO + 2H2 Water Gas Shift Reaction: CO +H2O o CO2 +h2 Methanation Reactions: CO + 3H2 o CH4 + H20 C02 + 4W2 o CH4 + 2H2O Depending on the configuration of carbon dioxide removal, the deriched naphtha is either added upstream of a feed interchanger or downstream of a feed heater. If a second carbon dioxide recovery unit is used downstream of the naphtha derichment reactor, the deriched naphtha will require cooling. Hence, the deriched naphtha leaving such a second carbon dioxide recovery unit is added upstream of the feed heater so it can be heated to the required temperature prior to being fed to the RWGS reactor. If the deriched naphtha does not require heating it is added downstream of the feed heater and into the RWGS reactor. The hydrogen to carbon monoxide ratio is controlled via the amount of carbon dioxide removed and stored and also via hydrogen dosing. According to certain configurations, the system can be operated in different modes as defined in the following clauses: 1. A method for synthesising hydrocarbons, the method comprising: (a) providing a reactant gas formed of a hydrogen stream having a variable hydrogen stream flow rate and a carbon dioxide stream, the variable hydrogen stream flow rate in a first operating mode being a flow rate equal to or above a pre-determined acceptable flow rate and in a second operating mode being a flow rate below the pre-determined acceptable flow rate; (b) feeding the reactant gas to a reverse water-gas shift unit to form a crude synthesis gas comprising hydrogen, carbon monoxide, steam and carbon dioxide, wherein the reverse water-gas shift unit comprises a reverse water-gas shift reactor (optionally an autothermal reverse water-gas shift reactor in which the reactant gas is fed to a burner inside a reverse water-gas shift vessel where reactant gas is partially combusted with oxygen to generate a heated gas comprising hydrogen, steam and carbon dioxide that passes through a bed of reverse water gas shift catalyst disposed downstream of the burner to form the crude syngas); (c) cooling the crude synthesis gas to condense water and removing carbon dioxide and water from the crude synthesis gas to produce a feed stream comprising hydrogen and carbon monoxide; (d) passing the feed stream though 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; (e) upgrading the product stream in an upgrading unit to produce an upgraded product stream; and (f) separating a naphtha stream from the product stream or the upgraded product stream; wherein, when in the first operating mode the variable hydrogen stream flow rate is equal to or greater than the pre-determined acceptable flow rate, and at least a portion of the naphtha stream is passed to a naphtha reservoir (storage vessel); and in the second operating mode when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate, feeding naphtha from the naphtha reservoir (storage vessel) with steam and hydrogen to a derichment reactor containing a derichment catalyst to form a gas mixture containing methane which is fed to the reverse water-gas shift unit. 2. The method of clause 1, wherein when the variable hydrogen stream flow rate is equal to or greater than the pre-determined acceptable flow rate, substantially all of the naphtha stream is passed to the naphtha reservoir; and / or when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate, substantially none of the naphtha stream is passed to the naphtha reservoir. 3. The method of clause 1, wherein when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate, at least a portion of the naphtha stream is passed to the naphtha reservoir (storage vessel), and the portion of the naphtha stream passed to the naphtha reservoir is greater when the variable hydrogen stream flow rate is equal to or greater than the pre-determined acceptable flow rate in comparison to when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate. 4. The method of clause 1, wherein the portion of the naphtha stream passed to the derichment reactor is greater when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate in comparison to when the variable hydrogen stream flow rate is equal to or greater than the pre-determined acceptable flow rate. 5. The method according to any preceding clause, wherein the pre-determined acceptable flow rate results in the reactant gas having a hydrogen to carbon dioxide molar ratio of from 2:1 to 10:1. 6. The method according to clause 1, wherein when the flow rate of the hydrogen stream drops below the predetermined flow rate, the method further comprises reducing the flow rate of the carbon dioxide stream. 7. The method of any preceding clause, wherein if the hydrogen stream flow rate drops below the predetermined flow rate, the stored naphtha stream and steam are fed with hydrogen to the derichment reactor. 8. The method of any preceding clause, wherein when the variable hydrogen stream flow rate changes from a flow rate below the pre-determined acceptable flow rate to a flow rate equal to or above the pre-determined acceptable flow rate, the feeding of the stored naphtha stream, hydrogen and steam to the derichment reactor is halted. Alternatively, the naphtha from storage is not stopped completely. For example, there can be a small continuous flow of naphtha, H2 and steam to keep the naphtha derichment hot so that it is readily available. 9. The method according to any preceding clause, wherein in the first operating mode, subjecting the gas mixture comprising hydrogen and carbon dioxide to a catalytic or non-catalytic reverse-water-gas-shift reaction. 10. The method according to any preceding clause, wherein in the first operating mode, the gas mixture comprising carbon dioxide and hydrogen fed to the burner comprises 10 to 50% by volume, preferably 25 to 40% by volume, of carbon dioxide. 11. The method according to any preceding clause, wherein the reactant gas fed to the autothermal reverse water-gas shift reactor is preheated to a temperature in the range of 400 to 1200°C, 400 to 1000°C, or 450 to 800°C. 12. The method according to any preceding clause, wherein the reverse water-gas shift catalyst is a nickel-oxide based catalyst containing 3-20% by weight nickel, expressed as NiO. 13. The method according to any preceding clause, wherein in the first operating mode, 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 plastics, or by electrolysis or thermolysis of water. 14. The method according to any preceding clause, wherein in the first operating mode, the carbon dioxide fed to the reverse water-gas shift unit is a carbon dioxide stream recovered from an upstream synthesis gas generation unit, a carbon dioxide stream recovered from an ammonia plant that uses a hydrocarbon or carbonaceous feed, a carbon dioxide stream recovered from a furnace or boiler flue gas, wherein the furnace or boiler is heated by combustion of a carbonaceous fuel, or a carbon dioxide stream separated from air or seawater. 15. The method according to any preceding clause, further comprising introducing at least a portion of the carbon dioxide removed from the crude synthesis gas into the reactant gas fed to the reverse water-gas shift unit. 16. The method according to clause 15, wherein when the variable hydrogen stream flow rate is less than the pre-determined acceptable flow rate, the method further comprises removing carbon dioxide from the reactant gas prior to passing the reactant gas to the reverse water-gas shift unit. 17. The method according to any preceding clause, wherein the derichment reactor operates with 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 with a minimum H2 content of 0.001 kg H2 per kg of carbon-containing components in the feed. 18. The method according to any preceding clause, further comprising: feeding at least a portion of the tail gas stream with steam to a second derichment reactor containing a derichment catalyst to form a second gas mixture containing methane; and feeding the second gas mixture containing methane to the reverse water gas shift unit. 19. The method according to clause 19, wherein the second derichment reactor operates with an inlet temperature in the range of 250 to 650°C, preferably 300 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 to 7.0 MPag, preferably 1.5 to 6.6 MPag. 20. The method according to any preceding clause, wherein an upgrader hydrocarbon off-gas stream recovered from the upgrading unit is also fed to the derichment reactor and / or the second derichment reactor. 21. The method according to any preceding clause, wherein a hydrocarbon synthesis unit hydrocarbon off-gas stream recovered from the hydrocarbon synthesis unit is fed to the derichment reactor and / or the second derichment reactor. 22. The method according to any preceding clause, wherein one or more further derichment reactors are provided for treatment of an upgrader 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 that is fed to the reverse water gas shift unit. 23. The method according to clause 22, wherein the one or more further derichment reactors operates with 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 with a minimum H2 content of 0.001 kg H2 per kg of carbon-containing components in the feed. 24. The method according to any preceding clause, 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-C4 gases, 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. 25. A system for performing the method according to any one of the preceding clauses comprising: (a) a reverse water-gas shift unit configured to be fed with a reactant gas, that forms a crude synthesis gas comprising hydrogen, carbon monoxide carbon dioxide and steam, (b) cooling and separation apparatus configured to be fed with the crude synthesis gas that cools the crude synthesis gas to condense water and remove carbon dioxide and water 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 configured to be fed with 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, (d) an upgrading unit configured to be fed with 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, (e) a derichment reactor containing a derichment catalyst is configured to be fed with naphtha, hydrogen and steam, to provide a gas mixture containing methane, and wherein the derichment reactor is coupled to the reverse water-gas shift unit to feed the gas mixture containing methane from the derichment reactors to the reverse water gas shift unit, (f) a naphtha reservoir (storage vessel) for storing naphtha from the naphtha stream, and (g) a valve system for switching the system between a first configuration and a second configuration, wherein in the first configuration, the system is configured to pass at least a portion of the naphtha stream to the naphtha storage vessel, and in the second configuration the system is configured to pass naphtha from the naphtha storage vessel to the derichment reactor. Further details of embodiments of the present methodology are provided in the following examples. Example 1 In Figure 3, high pressure steam 1, 4 and oxygen 7 are combined at mixer 5 to form stream 6 which is fed to the reverse water-gas shift (RWGS) reactor 42. Hydrogen from stream 8, 9 is combined with recycled carbon dioxide stream 53 at mixer 11 to form stream 12 which is fed to the feed interchanger 13 where it is heated by syngas stream 46. The combined hydrogen and carbon dioxide stream 14 exiting the feed interchanger 13 is further heated using feed heater 15 to form stream 16 to mixer 17. Tails gas stream 19 recycled from Fischer-Tropsch is combined with high pressure steam 2 at mixer 20 to make stream 21 which is heated using hot syngas stream 45 via tails gas interchanger 22. The heated tails gas and steam stream 23 is fed to the tails gas derichment reactor 24 where it is converted to stream 25. Stream 25 primarily consists of methane and steam as well as low concentration of hydrogen and carbon dioxide. The naphtha stream 26 (from a naphtha storage vessel according to embodiments of the present specification) is passed to the naphtha interchanger 27, where it is heated by the syngas stream 47 coming out of the feed interchanger 13. The heated naphtha stream 28 is mixed with high pressure steam 3 at mixer 29 to form stream 30, which is heated in the naphtha heater 31 and then dosed with hydrogen 10 at mixer 33 to form stream 34 which is fed to the naphtha derichment reactor 35. Stream 37 exiting the naphtha derichment reactor is combined with stream 16 and 25 at mixer 17 to form a feed stream 18 for the reverse water-gas shift (RWGS) reactor 42. The RWGS reactor 42 generates hot, crude syngas stream 43, which is passed to syngas boiler 44 to generate syngas stream 45. Syngas stream 45 exiting the syngas boiler 44 is fed to the hot inlet of the tails gas interchangers 22, 13 and 27 where it is partially cooled by feed streams. The syngas stream 48 exiting the naphtha interchanger 27 is further cooled via a series of coolers in block 49 before being fed to a carbon dioxide recovery unit 51, where the carbon dioxide is separated and compressed to generate a carbon dioxide stream 56 and a syngas stream 52. Syngas stream 52 is then compressed and further purified in block 54 to form syngas stream 55 which is sent to the Fischer-Tropsch section. The compressed carbon dioxide stream 56 is split: a portion is recycled via 53 as feed stream for the RWGS Reactor and the rest is sent to storage via stream 57. Parameters for the various gas streams in Example 1 are set out in the following tables. Stream 1 2 3 4 6 7 8 9 10 12 14 Temperature (°C) 265 265 265 265 247 40 40 40 40 45 405 Pressure (bar a) 51 51 51 51 21 27 28 28 28 23 23 Mass Flow (kg / h) 15402 477 9354 100 5946 5846 93 7 86 2643 2643 Composition (mol%) Water 100 100 100 100 3.3 0.3 0.3 0.3 0.3 0.3 0.3 Hydrogen 0 0 0 0 0.1 0.1 99.6 99.6 99.6 5.6 5.6 CO 0 0 0 0 0 0 0 0 0 0.2 0.2 CO2 0 0 0 0 0 0 0 0 0 93.9 93.9 Nitrogen 0 0 0 0 0 0 0 0 0 0 Oxygen 0 0 0 96.6 99.6 0.1 0.1 0.1 0 0 C1-C3 Alkanes 0 0 0 0 0 0 0 0 0 0 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 Stream 1 2 3 4 6 7 8 9 10 12 14 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 Stream 16 18 19 21 23 25 26 28 30 32 34 Temperature (°C) 550 522 30 159 300 379 40 41 286 497 482 Pressure (bar a) 22 22 35 24 24 22 5 29 29 28 28 Mass Flow (kg / h) 2643 18676 918 1395 1395 1395 5198 5198 14552 14552 14638 Composition (mol%) Water 0.3 38.8 0.1 33.7 33.7 29 0.1 0.1 89.9 89.9 83.9 Hydrogen 5.6 10.7 5.8 3.8 3.8 2.9 0 0 0 0 6.6 CO 0.2 0.7 3.7 2.5 2.5 0 0 0 0 0 0 CO2 93.9 15.6 0.7 0.4 0.4 3.7 0 0 0 0 0 Nitrogen 0 0.1 2.1 1.4 1.4 1.4 0 0 0 0 0 Oxygen 0 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 0 34 86.3 57.3 57.3 63 0.6 0.6 0.1 0.1 0.1 C4-C6 Alkanes 0 0 1.1 0.8 0.8 0 60.6 60.6 6.2 6.2 5.7 C7-C10 Alkanes 0 0 0.1 0.1 0.1 0 38.7 38.7 3.9 3.9 3.7 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 Stream 37 43 45 46 47 48 50 52 53 55 56 57 Temp (°C) 535 900 450 435 416 304 30 40 48 133 48 48 Pressure (bar a) 22 21 20 20 19 19 17 16 23 35 23 23 Mass Flow (kg / h) 14638 24622 24622 24622 24622 24622 24622 10025 2636 10054 6760 4123 Composition (mol%) Water 42.9 28.2 28.2 28.2 28.2 28.2 28.2 0 0.3 0.1 0.3 0.3 Hydrogen 11.9 41 41 41 41 41 41 66.2 0.5 66.1 0.5 0.5 CO 0.8 19.2 19.2 19.2 19.2 19.2 19.2 31.1 0.2 31 0.2 0.2 CO2 10.6 9.9 9.9 9.9 9.9 9.9 9.9 0 99 0 99 99 Nitrogen 0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0 0.1 0 0 Oxygen 0 0 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 33.8 1.6 1.6 1.6 1.6 1.6 1.6 2.6 0 2.6 0 0 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 0 0 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 0 Example 2 Figure 4 differs from Figure 1 in that there is a second carbon dioxide recovery unit 39. Most of the naphtha derichment reactor exit stream 36 is sent to the carbon dioxide recovery unit 39 via stream 38, and a small portion is sent to mixer 17 via stream 37. From the carbon dioxide separation unit 39, the separated carbon dioxide stream 41 is sent to storage, and stream 40 which mainly consists of methane and hydrogen is combined with stream 9 and 53 at mixer 11. In addition, there is no carbon dioxide being sent to storage downstream of the carbon dioxide separation and compression block 51. The carbon dioxide separated at block 51 is entirely recycled via stream 53. Parameters for the various gas streams in Example 2 are set out in the following table. Stream 1 2 3 4 6 7 8 9 10 12 14 16 Temperature (°C) 265 265 265 265 247 40 40 40 40 32 381 550 Pressure (bar a) 51 51 51 51 21 27 28 28 28 23 23 22 Mass Flow (kg / h) 8682 979 8153 100 5197 5097 180 104 75 7088 7088 7088 Composition (mol%) Water 100 100 100 100 3.7 0.3 0.3 0.3 0.3 6.2 6.2 6.2 Hydrogen 0 0 0 0.1 0.1 99.6 99.6 99.6 28.9 28.9 28.9 CO 0 0 0 0 0 0 0 0 1.2 1.2 1.2 CO2 0 0 0 0 0 0 0 0 14.7 14.7 14.7 Nitrogen 0 0 0 0 0 0 0 0 0 0 0 Oxygen 0 0 0 96.2 99.6 0.1 0.1 0.1 0 0 0 C1-C3 Alkanes 0 0 0 0 0 0 0 0 49 49 49 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 0 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 Stream 18 19 21 23 25 26 28 30 32 34 36 37 Temperature (°C) 503 30 158 300 369 40 41 226 497 482 535 535 Pressure (bar a) 22 35 24 24 22 5 29 29 28 28 22 22 Mass Flow (kg / h) 11195 1852 2831 2831 2831 4531 4531 12684 12684 12759 12759 1276 Composition (mol%) Water 15.9 0.1 33.3 33.3 30 0.1 0.1 89.9 89.9 83.9 42.9 42.9 Hydrogen 20.7 5.7 3.8 3.8 2.8 0 0 0 0 6.6 11.9 11.9 CO 0.9 3.5 2.4 2.4 0 0 0 0 0 0 0.8 0.8 CO2 11.3 0.3 0.2 0.2 2.9 0 0 0 0 0 10.6 10.6 Nitrogen 0.2 1.3 0.9 0.9 0.9 0 0 0 0 0 0 0 Oxygen 0 0 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 51 88 58.8 58.8 63.4 0.6 0.6 0.1 0.1 0.1 33.8 33.8 C4-C6 Alkanes 0 0.9 0.6 0.6 0 60.6 60.6 6.2 6.2 5.7 0 0 C7-C10 Alkanes 0 0.1 0.1 0.1 0 38.7 38.7 3.9 3.9 3.7 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 0 Stream 38 40 41 43 45 46 47 48 50 52 53 55 Temperature (°C) 535 30 28 900 450 411 226 178 30 40 48 130 Pressure (bar a) 22 23 2 21 20 20 19 19 17 16 23 35 Mass Flow (kg / h) 11483 4171 7312 16392 16392 16392 16392 16392 16392 10344 2813 10374 Composition (mol%) Water 42.9 8.4 78.3 15 15 15 15 15 15 0 0.3 0.1 Hydrogen 11.9 23.5 0 49.7 49.7 49.7 49.7 49.7 49.7 62.4 1.1 62.3 CO 0.8 1.5 0 23.4 23.4 23.4 23.4 23.4 23.4 29.3 0.4 29.3 CO2 10.6 0 21.5 5.3 5.3 5.3 5.3 5.3 5.3 0 97.9 0 Nitrogen 0 0 0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0 0.1 Oxygen 0 0 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 33.8 66.6 0.1 6.5 6.5 6.5 6.5 6.5 6.5 8.1 0.3 8.1 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 0 0 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 0 Example 3 Figure 5 differs from Figure 2 with all of the stream exiting the naphtha derichment reactor 35 being sent to the carbon dioxide separation vessel 39 via stream 38. Parameters for the various gas streams in Example 3 are set out in the following table. Stream 1 2 3 4 6 7 8 9 10 12 14 16 Temperature (°C) 265 265 265 265 247 40 40 40 40 32 374 550 Pressure (bar a) 51 51 51 51 21 27 28 28 28 23 23 22 Mass Flow (kg / h) 8240 1114 8232 100 5200 5100 128 52 76 7095 7095 7095 Composition (mol%) Water 100 100 100 100 3.7 0.3 0.3 0.3 0.3 6.9 6.9 6.9 Hydrogen 0 0 0 0.1 0.1 99.6 99.6 99.6 25 25 25 CO 0 0 0 0 0 0 0 0 1.3 1.3 1.3 CO2 0 0 0 0 0 0 0 0 12.2 12.2 12.2 Nitrogen 0 0 0 0 0 0 0 0 0 0 0 Oxygen 0 0 0 96.2 99.6 0.1 0.1 0.1 0 0 0 C1-C3 Alkanes 0 0 0 0 0 0 0 0 54.5 54.5 54.5 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 0 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 Stream 18 19 21 23 25 26 28 30 32 34 38 40 Temperature (°C) 495 30 158 300 368 40 41 225 497 482 535 30 Pressure (bar a) 22 35 24 24 22 5 29 29 28 28 22 23 Mass Flow (kg / h) 10307 2099 3213 3213 3213 4574 4574 12806 12806 12882 12882 4679 Composition (mol%) Water 13.9 0.1 33.2 33.2 30.2 0.1 0.1 89.9 89.9 83.9 42.9 8.4 Hydrogen 18.3 5.8 3.9 3.9 2.8 0 0 0 0 6.6 11.9 23.5 CO 0.9 3.5 2.3 2.3 0 0 0 0 0 0 0.8 1.5 CO2 9.4 0.3 0.2 0.2 2.7 0 0 0 0 0 10.6 0 Nitrogen 0.2 1.1 0.8 0.8 0.8 0 0 0 0 0 0 0 Oxygen 0 0 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 57.2 88.2 59 59 63.5 0.6 0.6 0.1 0.1 0.1 33.8 66.6 C4-C6 Alkanes 0 0.9 0.6 0.6 0 60.6 60.6 6.2 6.2 5.7 0 0 C7-C10 Alkanes 0 0.1 0.1 0.1 0 38.7 38.7 3.9 3.9 3.7 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 0 0 Stream 41 43 45 46 47 48 50 52 53 55 Temperature (°C) 28 900 450 404 209 165 30 40 48 130 Pressure (bar a) 2 21 20 20 19 19 17 16 23 35 Mass Flow (kg / h) 8203 15507 15507 15507 15507 15507 15507 10426 2364 10456 Composition (mol%) Water 78.3 13 13 13 13 13 13 0 0.3 0.1 Hydrogen 0 50.6 50.6 50.6 50.6 50.6 50.6 61.4 1.3 61.3 CO 0 23.8 23.8 23.8 23.8 23.8 23.8 28.9 0.5 28.8 CO2 21.5 4.6 4.6 4.6 4.6 4.6 4.6 0 97.5 0 Nitrogen 0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0 0.1 Oxygen 0 0 0 0 0 0 0 0 0 0 C1-C3 Alkanes 0.1 7.9 7.9 7.9 7.9 7.9 7.9 9.6 0.4 9.6 C4-C6 Alkanes 0 0 0 0 0 0 0 0 0 0 C7-C10 Alkanes 0 0 0 0 0 0 0 0 0 0 C2-C4 Olefins 0 0 0 0 0 0 0 0 0 0 C5-C7 Olefins 0 0 0 0 0 0 0 0 0 0 C1-C4 Alcohols 0 0 0 0 0 0 0 0 0 0 While this invention has been particularly shown and described with reference to certain examples, it will be understood to those skilled in the art that various changes in form and detail may be made without departing from the scope of the invention as defined by the appended claims. Claims 1. A method for synthesising hydrocarbons, the method comprising: (a) feeding hydrogen and carbon dioxide to a reverse water-gas shift unit to form synthesis gas comprising hydrogen and carbon monoxide; (b) passing the synthesis gas though a hydrocarbon synthesis unit comprising a reactor containing a Fischer-Tropsch catalyst to form a product stream comprising a mixture of hydrocarbons; (c) separating and storing a portion of the mixture of hydrocarbons in a storage vessel; (d) feeding a portion of the stored hydrocarbons from the storage vessel to a derichment reactor containing a derichment catalyst generating a methane containing feed gas; and (e) feeding the methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide. 2. A method according to claim 1, wherein the hydrocarbons are stored in the storage vessel in liquid form in step (c) and the stored hydrocarbons are converted to gas form in step (d) when feeding the stored hydrocarbons from the storage vessel to the derichment reactor. 3. A method according to claim 1 or 2, wherein the hydrocarbons stored in the storage vessel comprise or consist of naphtha which is separated from the product stream of the hydrocarbon synthesis unit. 4. A method according to any preceding claim, wherein one or both of steam and hydrogen are fed to the derichment reactor with the portion of stored hydrocarbons in step (d). 5. A method according to any preceding claim, wherein the quantity of stored hydrocarbon which is fed from the storage vessel to the derichment reactor is varied according to the quantity of the methane containing feed gas required by the reverse water-gas shift unit. 6. A method according to claim 5, wherein the quantity of the methane containing feed gas required by the reverse water-gas shift unit is dependent on the quantity of hydrogen and / or carbon dioxide fed to the reverse water-gas shift unit in step (a) and / or the quantity of the product stream required from the hydrocarbon synthesis unit in step (b). 7. A method according to any preceding claim, wherein, in addition to separating and storing the portion of the mixture of hydrocarbons from the product stream in the storage vessel, a portion of the mixture of hydrocarbons from the product stream is separated and fed to the derichment reactor without being stored in the storage vessel. 8. A method according to claim 7, wherein the proportion of hydrocarbons fed to the storage vessel relative to the proportion of hydrocarbons fed to the derichment reactor without being stored is varied according to the quantity of the methane containing feed gas required by the reverse water-gas shift unit. 9. A method according to any preceding claims, wherein the hydrocarbon synthesis unit generates a tail gas stream containing hydrogen, carbon monoxide and gaseous hydrocarbons in addition to the product stream, and at least a portion of the tail gas, optionally mixed with steam, is fed to either the derichment reactor or a second, separate, derichment reactor to generate a feed gas to the reverse water-gas shift unit. 10. A method according to claim 9, wherein the tail gas stream is fed to the second, separate derichment reactor which has different operating conditions to those of the derichment reactor which receives hydrocarbons from the storage vessel. 11. A method according to any preceding claim, wherein the hydrocarbon synthesis unit generates a water stream in addition to the product stream, and at least a portion of the water stream is electrolysed or thermochemically split to produce hydrogen which is fed to the reverse water-gas shift unit and / or the derichment reactor. 12. A method according to any preceding claim, wherein the synthesis gas generated by the reverse water-gas shift reactor in step (a) is passed to a conditioning unit to remove water, and optionally carbon dioxide, prior to passing the synthesis gas to the hydrocarbon synthesis unit in step (b). 13. A method according to claim 12, wherein at least a portion of the water removed in the conditioning unit is electrolysed or thermochemically split to produce hydrogen which is fed to the reverse water-gas shift unit and / or the derichment reactor. 14. A method according to claim 12 or claim 13, wherein at least a portion of the carbon dioxide removed in the conditioning unit is recycling to the reverse water-gas shift unit. 15. A system for synthesising hydrocarbons according to the method of any preceding claim, the system comprising: a reverse water-gas shift unit configured to receive hydrogen and carbon dioxide and form synthesis gas comprising hydrogen and carbon monoxide; a hydrocarbon synthesis unit configured to receive the synthesis gas and form a product stream comprising a mixture of hydrocarbons; a separation unit configured to separate a portion of the mixture of hydrocarbons from the product stream; a storage vessel for storing the portion of hydrocarbons separated from the product stream; and a derichment reactor configured to receiving a portion of the stored hydrocarbons from the storage vessel and generate a methane containing feed gas to the reverse water-gas shift unit where the methane undergoes a steam methane reforming reaction to form synthesis gas comprising hydrogen and carbon monoxide.

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