Process for the production of hydrogen, carbon dioxide and power

Abstract

A process for the production of hydrogen, carbon dioxide and power is described comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a re

Description

This invention relates to processes for the conversion of hydrocarbons to hydrogen for power generation with minimal carbon dioxide emissions. Processes for generating hydrogen, carbon dioxide and power are known. EP2102101 A1 discloses a process for the production of carbon dioxide in concentrated form and electricity from a hydrocarbon feedstock using an air-fired autothermal reactor unit (ATR), a water-gas shift unit and carbon dioxide separation unit in series to produce hydrogen stream and a concentrated carbon dioxide stream and combusting at least part of the hydrogen stream in a gas turbine, wherein the gas turbine drives an electric generator. EP2233432 A1 discloses a plant for generating carbon dioxide in concentrated form and electricity comprising a decarbonised fuel production unit and an electricity generating unit in which the decarbonised fuel is combusted, wherein the decarbonised fuel production unit employs an ATR fired with either industrial pure oxygen, oxygen-enriched air or normal air, wherein the molar ratio of oxygen contained in the oxidant feed stream to carbon (in hydrocarbons) in the fuel feed stream is from 0.45:1 to 0.85:1 and the decarbonised fuel production unit further comprises a water-gas shift unit and a carbon dioxide separation unit for the separation of a concentrated carbon dioxide stream thereby generating a decarbonised fuel stream comprising hydrogen and nitrogen; and wherein in the electricity production unit electricity is produced from hot exhaust gases generated by combusting the decarbonised fuel stream in a combined cycle gas turbine characterised in that decarbonised fuel production unit and electricity production unit are otherwise isolated from each other in process engineering terms. EP2516326 A1 discloses a process for reducing the carbon dioxide emissions from a combined cycle power generation process utilizing a gaseous hydrocarbon feed, comprising splitting the hydrocarbon feed into two portions; a first smaller portion comprising <45% by volume of the feed and a second larger portion comprising >55% by volume of the feed, feeding the first smaller portion to an autothermal reforming process to generate a hydrogen-containing gas and a carbon dioxide stream, combining the hydrogen-containing stream with the second portion of the gaseous hydrocarbon, combusting the resulting hydrogen-containing fuel stream with an oxygen containing gas in a gas turbine to generate electrical power and passing the exhaust gas mixture from the gas turbine to a heat recovery steam generation system that feeds one or more steam turbines to generate additional electrical power. EP2516327 A1 discloses a process for the conversion of a hydrocarbon to carbon dioxide and electrical power comprising subjecting a gas mixture comprising a hydrocarbon feed stream and steam to an integrated reforming process including stages of steam reforming in a gas-heated reformer and secondary reforming to generate a reformed gas mixture, increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas-shift stages, cooling the resulting hydrogen-enriched reformed gas and separating condensed water therefrom, passing the resulting de-watered hydrogen-enriched reformed gas to one or more stages of carbon dioxide separation to recover carbon dioxide, combusting the remaining hydrogen-containing fuel stream with an oxygen containing gas in a gas turbine to generate electrical power and passing the exhaust gas mixture from the gas turbine to a heat recovery steam generation system that feeds one or more steam turbines to generate additional electrical power. We have developed an improved process where carbon dioxide emissions are reduced. Accordingly, the invention provides a process for the production of hydrogen, carbon dioxide and power is described comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a reforming unit comprising an oxygen-fired autothermal reformer to generate a reformed gas mixture with a nitrogen content below 5 mole% on a dry gas basis; (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas; (iii) passing the hydrogen-enriched reformed gas to a separation unit to provide a hydrogen fuel gas stream, a carbon dioxide gas stream and a by-product gas stream, and (iv) passing at least a portion of the hydrogen fuel gas stream to a gas turbine to generate electrical power, wherein at least a portion of the by-product gas stream is compressed and recycled to the process. The Applicants have found that the combination of oxygen firing the autothermal reformer and by-product gas recycle increase the feedstock efficiency and increase the carbon dioxide capture rate to levels at or above 96%. The present invention uses a gaseous mixture comprising a hydrocarbon. The gaseous mixture may comprise any gaseous or low boiling hydrocarbon, such as natural gas, associated gas, LPG, petroleum distillate, diesel, naphtha or mixtures thereof, or hydrocarbon-containing off-gases from chemical processes, such as a refinery off-gas. The gaseous mixture preferably comprises methane, associated gas or natural gas containing a substantial proportion, e.g. over 50% v / v methane. Natural gas is especially preferred. The hydrocarbon may be compressed to a pressure in the range of 10-100 bar abs. The pressure of the hydrocarbon may usefully govern the pressure throughout the process. Operating pressure is preferably in the range of 15-50 bar abs, more preferably 25-50 bar abs as this provides an enhanced performance from the process. If the hydrocarbon contains sulphur compounds, before, or preferably after, compression it may be subjected to desulphurisation. In some arrangement this includes hydrodesulphurisation using CoMo or NiMo catalysts, and absorption of hydrogen sulphide using a suitable hydrogen sulphide adsorbent, e.g. a zinc oxide adsorbent. An ultra-purification adsorbent may usefully be employed downstream of the hydrogen sulphide adsorbent to further protect the steam reforming or water-gas shift catalyst. Suitable, ultra-purification adsorbents may comprise copper-zinc oxide / alumina materials and copper-nickel-zinc oxide / alumina materials. To facilitate hydrodesulphurisation and / or reduce the risk of carbon laydown in the reforming process, a hydrogen-containing gas may be added to the compressed hydrocarbon. The hydrogen-containing gas may be combined with the hydrocarbon upstream and / or downstream of any hydrodesulphurisation stage. The amount of hydrogen in the resulting mixed gas stream may be in the range of 1-20% vol, but is preferably in the range 1-10% vol, more preferably in the range of 1-5% vol on a dry gas basis, especially if there are no unsaturated compounds and low level of organic sulphur in the compressed hydrocarbons. In a preferred embodiment, during normal operation, because the by-product gas contains some hydrogen, a portion of the by-product gas from the separation unit may be compressed and mixed with the compressed hydrocarbon. In other arrangements, desulphurisation may be achieved by treatment of at least a portion of the hydrocarbon by a bulk sulphur removal step including a washing stage with a liquid absorbent in an acid gas recovery unit. This bulk sulphur removal may, if desired, be performed on a portion of the hydrocarbon feed, which is then mixed with the remaining portion after the bulk sulphur removal and the mixed feed is then subjected to hydrodesulphurisation, hydrogen sulphide removal and optionally ultra-purification as described above. If the hydrocarbon contains unsaturated compounds such as olefins, the hydrodesulphurisation and / or H2S absorption vessels may include a recycle arrangement where a portion of hot outlet stream from these vessels is cooled, compressed, and mixed with fresh hydrocarbon to reduce the total level of unsaturates entering the hydrodesulphurisation vessel thereby controlling the heat generated by the saturation reactions. If the hydrocarbon contains other contaminants, such as chloride or heavy metal contaminants, these may be removed, prior to reforming, upstream ordownstream of any desulphurisation, using conventional adsorbents. Adsorbents suitable for chloride removal are known and include alkalised alumina materials. Similarly, adsorbents for heavy metals such as mercury or arsenic are known and include copper sulphide materials. The hydrocarbon may be pre-heated. It may conveniently be pre-heated after compression and before desulphurisation. Various hot gas sources are provided in the present process that may be used for this duty. However, in a preferred embodiment, the hydrocarbon is heated by passing it through multiple heat exchangers in series whereby the hydrocarbon is heated by hot shifted gas followed by heating steam. The hydrocarbon is mixed with steam. The steam introduction may be performed by direct injection of steam and / or by saturation of the hydrocarbon by contact with a stream of heated water. In some arrangements, a gaseous mixture comprising the hydrocarbon and steam may be formed by directly mixing the hydrocarbon with steam. The steam may be steam generated in one or more fired heaters or boilers by boiling boiler feed water and / or process condensate with a fuel gas. Additionally, or alternatively, the steam may be generated by boiling boiler feed water and / or process condensate in heat exchange with the reformed gas or hydrogen-enriched reformed gas mixture. Additionally, or alternatively, the steam may be a steam stream recovered from a stripping unit that has been used to strip process condensate. In some arrangements, the steam may be at least a portion of the steam generated in a water-cooled reactor, such as an isothermal water-gas shift reactor, or steam generated by cooling a combustion exhaust gas, such as exhaust gas recovered from the gas turbine. In other arrangements, the hydrocarbon may be saturated in a saturator fed with hot water to form a saturated gas mixture. The water fed to the saturator preferably comprises one or more of the condensate streams produced in the process. The steam content of the saturated gas mixture may, if desired, be increased by the direct addition of steam. In the present invention, at least a portion of the by-product gas is compressed and recycled to one or more of the reforming unit, the water-gas-shift unit and the separation unit. Hence, a portion of the compressed by-product gas may be combined with the hydrocarbon feedstock, before and / or after any desulphurisation, or the gaseous mixture of hydrocarbon and steam upstream, of the reforming unit. Additionally, or alternatively, a portion of the compressed by product gas may be combined with a pre-reformed and / or partially reformed gas mixture generated within the reforming unit. Additionally, or alternatively, if desired, a portion of the compressed by-product gas may also be recycled to the process by combining it with the reformed gas upstream of the water-gas shift unit, and / or the hydrogen-enriched reformed gas upstream of the separation unit. If desired, the portion recycled to the separation unit may be fed to one or more stages of product separation within the unit. The reforming unit comprises an autothermal reformer. Autothermal reformers are known and typically may comprise an elongate vessel arranged vertically, having a burner disposed at the top of the reformer, to which a feed gas containing hydrocarbon and an oxygen-rich gas are fed, a combustion zone beneath the burner through which a flame extends, and a fixed bed of particulate steam reforming catalyst disposed below the combustion zone. In autothermal reforming, the heat for the endothermic steam reforming reactions is therefore provided by combustion of a portion of hydrocarbon in the feed gas. The feed gas is typically fed to the top of the autothermal reformer and the oxygen-rich gas is fed to the burner, mixing and combustion occur downstream of the burner generating a heated gas mixture the composition of which is brought to equilibrium as it passes through the steam reforming catalyst. The steam reforming catalyst may comprise nickel supported on a refractory support such as rings or pellets of calcium aluminate, magnesium aluminate, alumina, titania, zirconia and the like. In a preferred embodiment, the autothermal steam reforming catalyst comprises a layer of a catalyst comprising Ni and / or Ru on zirconia over a bed of a Ni on alumina catalyst to reduce catalyst support volatilisation that can result in deterioration in performance of the autothermal reformer. In the present invention the ATR is oxygen-fired, in which the oxygen-rich gas preferably comprises at least 90% vol O2, more preferably at least 95% vol O2, most preferably at least 98% vol O2, or at least 99% vol O2, e.g. a pure oxygen gas stream, which may be obtained using a vacuum pressure swing adsorption (VPSA) unit, an air separation unit (ASU) or by the electrolysis of water. The ASU may be electrically driven and is desirably driven using either renewable electricity to further improve the efficiency of the process and minimise CO2 emissions or decarbonised electricity generated by the process, for example by the gas turbine or steam turbine. An advantage of using the ASU is that nitrogen gas separated in the ASU may be combined with the hydrogen-rich fuel gas stream fed to the gas turbine to provide flexibility in terms of controlling flame temperature, NOx emissions, and power generation. The amount of oxygen-rich gas added to the autothermal reformer is preferably such that 40 to 60 moles of oxygen are added per 100 moles of hydrocarbon carbon in the hydrocarbon fed to the process. Preferably the amount of oxygen added is such that the reformed gas leaves the catalyst in the autothermal reformer at a temperature in the range 800-1100°C, more preferably 900-1100°C, most preferably 970-1070°C. In a preferred embodiment, a small purge of steam may be added to the oxygen-rich gas to protect against reverse flow of hydrocarbons into oxidant line at low plant rates or if the plant trips. Whereas the gaseous mixture of hydrocarbon and steam may be fed directly to the autothermal reformer, preferably the feed gas to the autothermal reformer is a partially reformed gas mixture, in particular a partially reformed gas mixture generated upstream of the autothermal reformer by adiabatic pre-reforming in one or more pre-reformers operated in series or parallel, or by steam reforming the gaseous mixture in a gas-heated reformer comprising catalystcontaining tubes heated by the reformed gas mixture recovered from the autothermal reformer. The one or more pre-reformer or gas-heated reformer and the autothermal reformer are preferably operated in series. The partially reformed gas mixture, comprising methane, hydrogen, steam and carbon oxides, may be fed without any dilution or heat exchange, directly to the autothermal reformer in which it is subjected to autothermal reforming to generate the reformed gas mixture. In arrangements using a gas-heated reformer and autothermal reformer in series, the amount of steam introduced is desirably sufficient to give a steam to carbon ratio (defined as the steam to hydrocarbon carbon ratio at the inlet to reforming unit) of at least 1.0:1, i.e. at least 1.0 mole of steam per mole of hydrocarbon carbon in the gaseous mixture. In a preferred operation, the steam to carbon ratio is at least 1.5:1 and more preferably at least 2.0:1. The steam to carbon ratio can be adjusted in a preferred range of 1.0:1 to 3.5:1 to provide an optimal balance of feedstock efficiency and carbon capture rate, whilst mitigating the risk of carbon laydown on reforming catalysts, and reducing the risk of metal dusting on the external surface of gas heater reformer tubes. In arrangements using an adiabatic pre-reformer and autothermal reformer in series, the amount of steam introduced is desirably sufficient to give a steam to carbon ratio of at least 0.4:1, i.e. at least 0.4 moles of steam per mole of hydrocarbon carbon in the gaseous mixture, with a preferred range of 0.4:1 to 5:1. Where the steam to carbon ratio at the inlet to the reforming unit operations is in the range 0.4:1 to less than 2.4:1, it is possible to add additional steam to the reformed gas upstream of the water-gas shift stage. Operating the reforming section at a steam to carbon ratio in the range of 0.4:1 to less than 2.4:1 has the advantage that the heating requirement and oxygen demand for the reforming stages is reduced and that the front-end equipment (e.g. fired heater, pre-reformer, and autothermal reformer) will be smaller and lower in cost. Where the steam to carbon ratio is in the range of 2.4:1 to 5:1, no further steam addition upstream of the water-gas shift unit is necessary, which may be useful in circumstances where steam addition to the reformed gas is impractical or a higher level of steam export from the process is not preferred. The gaseous mixture comprising hydrocarbon and steam is desirably pre-heated prior to reforming. The pre-heating may be performed using heat generated downstream in the process. In some arrangements, the invention comprises a stage of adiabatic pre-reforming upstream of the autothermal reformer. In these arrangements, the gaseous mixture comprising the hydrocarbon and steam may be pre-heated by passing it through one or more heat exchangers downstream of a reformed gas boiler or water-gas shift unit and / or coils in a fired heater. Desirably, the mixed gaseous mixture is pre-heated to 380-650°C. The pre-heated gas mixture may then be subjected to a step of adiabatic steam reforming in a pre-reformer vessel containing a fixed bed of a pre-reforming catalyst. In such a process, the pre-heated gaseous mixture comprising the hydrocarbon and steam is passed adiabatically through a bed of a steam reforming catalyst, usually a steam reforming catalyst having a high nickel content, for example above 40% by weight. During such an adiabatic pre-reforming step, any hydrocarbons higher than methane react with steam to give a mixture of methane, carbon oxides and hydrogen. The use of such an adiabatic steam reforming step, commonly termed pre-reforming, can be desirable to ensure that the feed to the autothermal reformer contains no hydrocarbons higher than methane and also contains some hydrogen. In other arrangements, the gaseous mixture comprising the hydrocarbon and steam is subjected to steam reforming in a gas-heated reformer. In a preferred embodiment using a gas-heated reformer and autothermal reformer, the gaseous mixture may be pre-heated by passing it through a reformed gas interchanger, where it is heated by the reformed gas mixture. Desirably, the mixed stream is heated to 400-500°C, preferably 420-460°C. Different types of gas-heated reformer may be used. In one type of gas-heated reformer, the catalyst is disposed in tubes extending between a pair of tube sheets through a heat exchange zone. Reactants are fed to a zone above the upper tube sheet and pass through the tubes and into a zone beneath the lower tube sheet. The heating medium is passed through the zone between the two tube sheets. The heating medium is typically a hot reformed gas recovered from the autothermal reformer. Gas-heated reformers of this type are described in GB1578270 and WO97 / 05947. The gaseous mixture comprising the hydrocarbon and steam is passed through the catalyst-filled tubes in the gas-heated reformer. During passage through the reforming catalyst, the endothermic steam reforming reaction takes place with the heat required for the reaction supplied by a hot reformed gas recovered from the autothermal reformer, which flows past the exterior surface of the tubes. The steam reforming catalyst used in the gas-heated reformer may comprise nickel supported on a particulate refractory support such as rings or multi-holed pellets of calcium aluminate, magnesium aluminate, alumina, titania, zirconia and the like. Alternatively, a combination of nickel and a precious metal such as ruthenium, may be used. In place of, or in addition to, the particulate steam reforming catalyst, the steam reforming catalyst may comprise one or more structured catalyst units, which may be in the form of metal or ceramic monoliths or folded metal structures on which a layer of nickel and / or precious metal steam reforming catalyst has been deposited. The temperature of the autothermally reformed gas used to heat the gas-heated reformer is preferably sufficient that the gas undergoing steam reforming leaves the catalyst tubes at a temperature in the range 600-850°C, preferably 650-750°C, more preferably 680-720°C. In arrangements comprising a pre-reformer and autothermal reformer, the autothermally reformed gas may be cooled in heat exchange with water, e.g., in a reformed gas boiler, to generate steam. This steam may be used as process steam added to the hydrocarbon feed to the reforming unit or water-gas shift unit. The steam may also be used for heating and / or for power generation in a steam turbine and / or exported from the process. In arrangements comprising a gas-heated reformer and an autothermal reformer, the reformed gas produced by the autothermal reformer is used to provide the heat required for the steam reforming step by using it as the hot gas flowing past the tubes in the gas-heated reformer. During this heat exchange, the reformed gas cools by transferring heat to the gas undergoing steam reforming. Preferably, the reformed gas cools by several hundred degrees Centigrade but it will leave the gas-heated reformer at a temperature somewhat above the temperature at which the gaseous mixture comprising hydrocarbon and steam mixture is fed to the gas-heated reformer. Preferably the reformed gas leaves the gas-heated reformer at a temperature in the range 450-650°C, more preferably 450-580°C. After leaving the gas-heated reformer, the reformed gas is desirably then further cooled in one or more steps of heat exchange. Heat recovered during this cooling may be employed for reactants pre-heating, for example in a feed / effluent interchanger, and / or for heating water used to provide the steam employed in the steam reforming unit. In some arrangements, the reformed gas mixture exiting the shell side of the gas-heated reformer or feed / effluent interchanger may be used to heat water fed to a saturator. The reformed gas comprises hydrogen, carbon monoxide, carbon dioxide, steam, and a small amount of unreacted methane. Preferably, the hydrogen content of the reformed gas is in the range of 30-50% vol on a wet gas basis and the carbon monoxide content in the range 5-20% vol on a wet gas basis or 5-15% vol on a wet gas basis. In the present invention, the hydrogen content of the reformed gas mixture is increased by subjecting it to one or more water-gas shift stages in a water-gas shift unit thereby producing a hydrogen-enriched reformed gas and at the same time converting carbon monoxide in the reformed gas to carbon dioxide. The reaction may be depicted as follows; CO + H2O^CO2 + H2 Whereas steam is present in the reformed gas, supplemental steam may be added before the one or more water-gas shift stages, e.g. by direct addition to the reformed gas, if desired. The one or more water-gas shift stages may include stages of high-temperature shift, mediumtemperature shift, isothermal shift and low-temperature shift. High-temperature shift is operated adiabatically in a shift vessel with inlet temperature in the range of 300-400°C, preferably 320-360°C, over a bed of an iron catalyst, such as a promoted magnetite. Alternatively, a promoted zinc-aluminate catalyst may be used. Medium-temperature shift and low-temperature shift stages may be performed using shift vessels containing supported copper catalysts, particularly copper / zinc oxide / alumina compositions. In low-temperature shift, a gas containing carbon monoxide (preferably <6% vol CO on a dry basis) and steam (at a steam to total dry gas molar ratio in the range of 0.3 to 1.5) may be passed over the catalyst in an adiabatic fixed bed with an outlet temperature in the range 200 to 300°C. The outlet carbon monoxide content may be in the range of 0.1 to 1.5%, preferably under 0.7% vol or under 0.5% vol on a dry basis . Alternatively, in mediumtemperature shift, the gas containing carbon monoxide and steam may be fed to the catalyst at an inlet temperature in the range of 200 to 240°C although the inlet temperature may be as high as 280°C. The outlet temperature may be up to 300°C but may be as high as 360°C. Whereas one or more adiabatic water-gas shift stages may be employed, such as a high-temperature shift stage, optionally followed by a low-temperature shift stage, the reformed gas may be subjected to a stage of isothermal water-gas shift in a cooled shift vessel, optionally followed by one or more adiabatic medium- or low-temperature water-gas shift stages in uncooled vessels as described above. Using an isothermal shift stage, i.e. with heat exchange in the shift converter such that the exothermic reaction in the catalyst bed occurs in contact with heat exchange surfaces that remove heat, offers the potential to use the reformed gas stream in a very efficient manner. Whereas the term “isothermal” is used to describe a cooled shift converter, there may be a small increase in the temperature of the gas between the inlet and outlet, so that the temperature of the hydrogen-enriched reformed gas stream at the exit of the isothermal shift converter may be between 1 and 25 degrees Celsius higher than the inlet temperature. The coolant conveniently may be water under pressure such that partial, or complete, boiling takes place. The water can be in tubes surrounded by catalyst or vice versa. The resulting steam can be used, for example, for heating, or to drive a steam turbine, or to provide process steam for supply to the process, or to provide steam for export from the process. The hydrogen-enriched reformed gas contains steam. In some arrangements it may be desirable, following the one or more water-gas shift stages, to cool the hydrogen-enriched reformed gas to a temperature below the dew point so that at least a portion of the steam condenses. The liquid water condensate may then be separated using one or more gas-liquid separators, which may have one or more further cooling stages between them, to form a dewatered hydrogen-enriched reformed gas. Any coolant may be used. In some arrangements, the cooling includes heat exchange with one or more of the process streams such as boiler feed water or hydrocarbon feed. Cooling may also be performed in heat exchange with one or more liquids in the separation unit, for example in absorbent regeneration. In some arrangements, the hydrogen-enriched reformed gas may be fed to one or more boilers to generate steam. The steam may be used for heating, or used a as a process stream, or used for electricity generation in a steam turbine, or exported from the process. The hydrogen-enriched reformed gas may contain trace amounts of carbon monoxide. In some arrangements, an oxidation unit may be provided downstream of the water-gas shift unit and upstream of the separation unit to convert carbon monoxide present in the hydrogen-enriched reformed gas to carbon dioxide. The oxidation unit may be included downstream, or upstream of the condensate removal. The oxidation unit may comprise one or more oxidation vessels containing an oxidation catalyst that oxidises the carbon monoxide present in the hydrogen-enriched reformed gas, thereby converting it to carbon dioxide. The oxidation reactions may be depicted as follows; 2 CO + O2 2 CO2 2 H2 + O2 2 H2O An oxygen-rich gas is added to the hydrogen-enriched reformed gas. The oxygen-rich gas may be generated by vacuum pressure swing adsorption (VPSA) unit, an air separation unit and / or by electrolysis of water. Some hydrogen is also oxidised to form water. Accordingly, the oxidation catalyst is preferably a CO-selective oxidation catalyst to minimise hydrogen losses. The oxidation catalyst is preferably a supported precious metal catalyst. For example, the catalyst may comprise one or more of Pt, Pd, Rh, Ir or Ru, desirably on an oxidic support such as alumina, titania, zirconia or silica. The amount of precious metal may be in the range of 0.1 to 5% by weight. The oxidation reaction is exothermic, and the reaction may be performed adiabatically in a fixed bed oxidation vessel. The flow through the bed may be axial and / or radial flow. The inlet temperature in such an arrangement may be in the range of 20 to 200°C, and the exotherm in the bed is desirably kept below 75 degrees Celsius. Lower temperatures in the catalyst bed generally favour greater selectivity to CO-oxidation and are preferred. Therefore, it is preferable to locate an adiabatic oxidation vessel downstream of one or more stages of cooling and condensate recovery. In this way a higher selectivity can be achieved, which limits the temperature rise across the adiabatic catalyst bed and affords a longer catalyst lifetime. The oxidation step may alternatively be operated with cooling of the catalyst bed by passing a gaseous or liquid coolant, such as a suitable process stream, preferably steam or a boiling water-steam mixture, through one or more tubes disposed within the catalyst bed. Alternatively, the catalyst can be in tubes surrounded by boiling water. Where a cooled oxidation reactor is used, it is possible to locate the oxidation unit directly downstream of the water-gas shift unit, especially where the water gas shift unit comprises an isothermal shift vessel, with no or minimal cooling stage in between. In this arrangement, the gas mixture fed to the oxidation unit is the hydrogen-enriched reformed gas containing steam and the inlet temperature for the oxidation unit will be close to the exit temperature from the water-gas shift unit and may be in the range of 200 to 320°C. Where the coolant is water under pressure such that partial, or complete, boiling takes place, the water pressure is preferably the same as in the isothermal shift converter, so that a single steam drum can be shared by the isothermal water-gas shift and oxidation units. Alternatively, the water pressure in the cooled oxidation unit may be different from the water pressure in the isothermal water-gas shift unit, preferably lower. The oxidation unit produces a carbon dioxide-enriched hydrogen-enriched reformed gas mixture. Following the oxidation step, the carbon dioxide-enriched hydrogen-enriched reformed gas mixture is preferably cooled to below the dew point to cause condensation of steam present in the oxidised gas mixture. The resulting liquid water condensate may then be separated using one or more gas-liquid separators, which may have one or more further cooling stages between them, to form a de-watered carbon dioxide-enriched hydrogen-enriched reformed gas. In some arrangements, cooling of the hydrogen-enriched reformed gas or the carbon dioxideenriched hydrogen-enriched reformed gas mixture is carried out in heat exchange with the process condensate. The process condensate may be the condensate recovered from the cooled hydrogen-enriched reformed gas and any other aqueous process condensate recovered from the process, such as process condensate recovered downstream of the oxidation unit and / or process condensate recovered from knock-out pots coupled to compression equipment. As a result, a stream of heated condensate is produced, which may be fed to a saturator or process condensate stripper and used to supply some or all of the steam required for reforming and / or water-gas shift stages. Thus, in some arrangements, condensates recovered from the hydrogen-enriched reformed gas and / or the carbon dioxide-enriched hydrogen-enriched reformed gas mixture may be used to provide at least a portion of steam fed to the reforming unit and / or to supplement the steam present in the reformed gas fed to the water-gas shift unit. Because the condensate may contain ammonia, methanol, hydrogen cyanide and CO2, returning the condensate to form steam offers a useful way of returning hydrogen and carbon atoms to the process. One, two or more stages of cooling and condensate recovery may be included upstream and / or downstream of the water-gas shift unit or oxidation unit. However, in some arrangements, it may not be necessary to recover condensate from the hydrogen-enriched reformed gas mixture. In the present invention, the hydrogen-enriched reformed gas, optionally after treatment in the oxidation unit, and / or cooling and separation of condensate, is fed to a separation unit to separate hydrogen from the other components, The separation unit further provides a carbon dioxide stream and a by-product stream. The separation unit may comprise two distinct arrangements. In a first separation arrangement the separation unit comprises a hydrogen separation unit coupled to a downstream cryogenic carbon dioxide separation unit. Alternatively, in a second separation arrangement the separation unit comprises a carbon dioxide removal unit coupled to a downstream hydrogen purification unit. Each type of separation unit arrangement provides distinct advantages. The first separation arrangement produces a hydrogen fuel gas stream to be used in the gas turbine, a carbon dioxide gas stream, a by-product gas stream, and a separate low-pressure hydrogen-containing waste gas stream that may be used as a fuel in one or more fired heaters. The second separation arrangement produces a hydrogen fuel gas stream, a carbon dioxide gas stream and a by-product gas stream, a portion of which may be used as a waste gas that may be used as a fuel in one or more fired heaters. A portion of the by-product gas stream separated in the separation unit is compressed and recycled to the process. The portion of the by-product gas that is returned to the process may be recycled to one or more of, the reforming unit, the water-gas-shift unit, the optional oxidation unit if present, and the separation unit. Hence the portion of the byproduct gas stream may compressed and fed to the inlet or outlet of one or more of the reforming unit, the water-gas-shift unit and the separation unit. An aqueous process condensate may also be separated in the separation unit and returned to process or sent to an effluent treatment plant. In the first separation arrangement the hydrogen separation unit provides a pure hydrogen stream and a hydrogen depleted gas. The hydrogen separation unit may suitably comprise a membrane system, a temperature swing adsorption system, or a pressure swing adsorption (PSA) system. Such systems are commercially available. The hydrogen separation unit can produce a pure hydrogen stream preferably with a purity greater than 99.5% vol, more preferably greater than 99.9% vol. The pure hydrogen stream preferably has a carbon monoxide content of less than 100 ppmv or 50 ppmv, preferably less than 20 ppmv, more preferably less than 10 ppmv. The hydrogen separation unit may also provide a hydrogen-containing waste gas stream, typically at low pressure, e.g. 1 to 3 bar abs, that may be combusted in one or more fired heaters to generate steam or pre-heat process streams. The waste gas stream may comprise hydrogen and inert gases such as nitrogen and argon, with very low levels of other compounds such as methane, carbon monoxide, carbon dioxide and water. The hydrogen content of the waste gas stream may be in the range of 80-99% vol on a wet gas basis and the inert content in the range of 2-5% vol on a wet gas basis. The hydrogen separation unit also provides a hydrogen-depleted gas stream. The hydrogen-depleted gas stream comprises nitrogen and argon, methane, carbon monoxide, hydrogen and carbon dioxide. The hydrogen-depleted gas stream recovered from the hydrogen separation unit is preferably compressed, e.g. to between 50 and 80 bar abs, and dehydrated, e.g. to below lOOppmv water using a suitable absorbent, before being fed into the cryogenic carbon dioxide separation unit. The condensate generated during dehydration is preferably recycled to the process to return valuable hydrogen and carbon that may be present in the condensate. The cryogenic carbon dioxide separation unit may comprise of a series of cooling or refrigeration units configured to liquefy the hydrogen-depleted gas streams, a fractionation unit to separate carbon dioxide, and desirably ancillary equipment such as a carbon dioxide pump to increase the pressure of separated carbon dioxide, and a closed or open loop refrigeration unit. The separated carbon dioxide stream provided by this arrangement may be recovered from the bottom of the fractionation column and typically comprises carbon dioxide, with low levels of other compounds such as methane, inerts and water. Preferably the amount of carbon dioxide present in the carbon dioxide stream is in excess of 95% mol on a wet basis, preferably in excess of 99% mol on a wet basis, more preferably in excess of 99.5% mol on a wet basis. The carbon dioxide-depleted stream may be recovered from the top of the fractionation column or ancillary equipment such as a reflux drum or a heat exchanger. The carbon dioxide-depleted stream may be processed directly or may be sent to a secondary hydrogen separation unit downstream of the cryogenic carbon dioxide separation unit to increase the recovery of hydrogen. The secondary hydrogen purification unit may suitably comprise a membrane system, a temperature swing adsorption system, or a pressure swing adsorption (PSA) system. Such systems are commercially available. The secondary hydrogen purification unit may produce a pure hydrogen stream preferably with a purity greater than 99.5% vol, more preferably greater than 99.9% vol, that is preferably mixed with pure hydrogen stream recovered from the hydrogen separation unit upstream of the cryogenic carbon dioxide separation unit. The secondary hydrogen separation unit may also generate a carbon dioxide containing recycle stream. In some arrangements, the carbon dioxide containing recycle stream may be combined with the hydrogen-depleted gas recovered from the hydrogen separation unit and the resulting mixture compressed and fed to the dehydration unit or cryogenic carbon dioxide separation unit to increase carbon dioxide and hydrogen recovery. The secondary hydrogen separation unit may also generate the by-product gas stream that is returned as a recycle gas to the process. The by-product gas stream generated by this arrangement typically comprises hydrogen, methane, carbon monoxide, carbon dioxide, inerts such as nitrogen and argon, water and low levels of methanol and ammonia. The composition of the by-product gas, on a wet gas basis, may be 40-85% vol hydrogen, 5-25% vol methane and up to 35% vol carbon monoxide. Preferably the carbon monoxide is as high as possible as this allows all the unreacted carbon monoxide to be accumulated in the recycle gas. The secondary hydrogen separation unit may also generate a secondary hydrogen waste gas stream that may be combusted to generate steam or pre-heat process streams, The secondary hydrogen waste gas typically comprises hydrogen and inert gases with very low levels of other compounds such as methane, carbon monoxide, carbon dioxide and water. Preferably, the hydrogen content of the gas is in the range of 80-99% vol on a wet gas basis and the inert content in the range 2-5% vol on a wet gas basis. In the second separation arrangement, the carbon dioxide removal unit may comprise a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system. The carbon dioxide may be separated by an acid gas recovery (AGR) process. In the AGR process a carbon dioxide-containing gas stream is contacted with a stream of a suitable absorbent liquid, such as an amine, particularly methyl diethanolamine (MDEA) and / or piperazine solution 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. Alternatively, methanol or a glycol may be used to capture the carbon dioxide in a similar manner as the amine. If the carbon dioxide separation step is operated as a single pressure process, i.e. essentially the same pressure is employed in the absorption and regeneration steps, only a little recompression of the recycled carbon dioxide will be required. In some arrangements, the laden absorbent liquid goes through multiple stages of pressure reduction, to facilitate separation of carbon dioxide and reducing any carry over of hydrogen and other compounds into the carbon dioxide product, whilst generating power during the pressure reduction process. The hydrogen-containing gas stream separated in these arrangements may be combined with other fuel streams to generate steam or pre-heat process streams. The recovered carbon dioxide may comprise 90-95% vol carbon dioxide with the balance comprising water, hydrogen, inerts gases and traces of other volatile compounds such as methane, carbon monoxide, methanol and ammonia. The recovered carbon dioxide may be further purified if desired and used for the manufacture of chemicals such as methanol, sent to storage or sequestration, or used in enhanced oil recovery (EOR) processes. In cases where the CO2 is to be compressed for storage, transportation, use in EOR processes or conversion to other chemical products, the CO2 may be dried to prevent liquid water present in trace amounts, from condensing. For example, the CO2 may be dried to a dew point <-10°C by passing it through a bed of a suitable desiccant, such as a zeolite, or contacting it with a glycol in a glycol drying unit. The CO2 may also be subjected to a purification step, for example by washing, to remove contaminants such as methanol and ammonia, depending on the required specification. The washing stage may be carried out before product separation, compression or drying. The CO2 may if desired also be subjected to a liquefaction step using known liquefaction schemes after product separation. Upon the separation of the carbon dioxide, a crude hydrogen gas stream is produced. The crude hydrogen stream may comprise 95-99% vol hydrogen with the balance comprising methane, carbon monoxide, carbon dioxide and inert gases. The methane content may be in the range of 0.2-1.5% vol, preferably 0.25-0.9% vol. The crude hydrogen gas stream is passed to a hydrogen purification unit to provide a pure hydrogen stream and a by-product gas. The hydrogen purification unit may suitably comprise a membrane system, a temperature swing adsorption system, or a pressure swing adsorption (PSA) system. Such systems are commercially available. The hydrogen purification unit can produce a pure hydrogen stream preferably with a purity greater than 99.5% vol, more preferably greater than 99.9% vol. The carbon monoxide content may be less than 100 ppmv or 50 ppmv, preferably less than 20 ppmv, more preferably less than 10 ppmv. The carbon dioxide content may be in the range of 0.01-0.5% vol, preferably 0.01-0.1% vol. The balance may be made up of nitrogen and residual water vapour. The hydrogen purification unit also provides the by-product gas stream that is recycled to the process. The by-product gas stream comprises nitrogen and argon, methane, carbon monoxide, hydrogen and carbon dioxide. Preferably the by-product gas comprises 75-90% vol hydrogen with the balance comprising inert gases, water, carbon oxides, and methane. Whereas all of the by-product gas may be recycled to the process, in some arrangements it is advantageous to divide the by-product gas and consume part as a fuel gas to prevent the buildup of inert gases in the process. In addition, combusting part of the by-product gas instead of natural gas in one or more fired heaters, where these are required for steam generation or preheating process streams, reduces carbon dioxide emissions from the process. Thus, in some arrangements, the by-product gas is divided into a first portion and a second portion, the first portion is recycled to the process and the second portion is fed to one or more fired heaters used to heat feed steams or provide steam for the process. The first portion may be in the range of 15 to 90% by volume of the by-product gas. Alternatively, or in addition, a portion of the by-product gas may be exported from the process. In some arrangements, the second portion may be combined with purified natural gas or other hydrocarbons. This can increase the amount of first portion recycled to the process or exported from the process. Alternatively, this can result in a higher flow of hydrogen fuel from the purification unit. The low pressure of the by-product gas produced in the separation unit means that it is not suitable as a feed for the gas turbine. A portion of the hydrogen, with or without purification in the separation unit, may be compressed if necessary and recycled to the hydrocarbon feed if desired for desulphurisation. In the present invention, the hydrogen fuel gas recovered from the separation unit is used in a downstream power generation process. At least part of the hydrogen fuel gas is mixed with an oxygen-containing gas and combusted in a gas turbine, wherein the gas turbine drives an electric generator thereby producing electricity. Conventional gas turbine operating apparatus and conditions may be used. The oxygen-containing gas may be air, oxygen-enriched air, or oxygen provided by electrolysis or the air separation unit used to provide the oxygen gas to the autothermal reformer. The oxygen-containing gas is preferably air, more preferably air supplemented with nitrogen and / or oxygen from an air separation unit that also provides an oxygen stream to the oxygen-fired autothermal reformer. The turbine injection temperature may, if desired, be controlled by steam addition rather than using excess air. In one embodiment, the gas turbine fuel gas may be saturated using a saturator fed with a stream of heated water under pressure or steam may be directly injected into the gas turbine fuel. Unlike prior art processes, in the present invention a portion of the hydrocarbon feedstock is not fed to the gas turbine in order to minimise carbon dioxide emissions from the process. The gas turbine typically comprises a compressor, combustor and turbine connected to a generator for generating electrical power. The turbine exhaust gas may be used to generate steam, which is fed to one or more steam turbines connected to one or more generators to produce additional electricity. Thus, in addition to electricity generation from the gas turbine, electricity may also be generated by one or more steam turbines fed by a heat recovery steam generator (HRSG) using the heat in the exhaust gas from the gas turbine. Preferably the heat recovery steam generation system generates high-pressure, intermediate-pressure and low-pressure steam fed to high-pressure, intermediate-pressure and low-pressure steam turbines. High and intermediate pressure steam generated by heat exchange of the reformed, shifted, and / or oxidised gas mixtures with water and / or steam under pressure may also be fed to the steam turbines if desired. Furthermore, the exhaust gas from the gas turbine may, if desired, be used to heat one or more process fluid streams including the oxygen gas fed to the autothermal reformer as well as boiler feed water at pressure. The heat recovery unit may include a heat recovery and steam generator unit (HRSG) that generates and superheats additional steam for use in the steam turbine and elsewhere in the process of the present invention. Thus, in addition to superheating steam and heating any process streams such as the oxygen feed stream and high pressure water feed to the waste heat boiler(s), the HRSG is capable of generating high pressure (HP) steam, medium pressure (MP) steam and low pressure (LP) steam and of superheating these steam streams. The HRSG may also be capable of reheating MP steam that is produced as an exhaust stream from the high-pressure stage of a multistage steam turbine. The HRSG will typically comprise a plurality of heating coils through which the various process streams may be passed in heat exchange relationship with the exhaust gas. The exhaust gas preferably enters the HRSG at a temperature in the range 650-800°C, preferably 740-780°C. A conventional HRSG arrangement may be used wherein the exhaust gas contacts the heating coils for the production of and superheating of the HP, MP and LP steam, and for heating boiler feed water. The exhaust gas will be progressively cooled as it is heat exchanged with the various process streams. Typical final exhaust gas temperatures will be about 150°C to avoid any dewing and corrosion associated with sulphur compounds (if present) in the gas, as well as to ensure the exhaust gas has enough buoyance in the stack. Preferably, the superheated HP steam that is produced in the HRSG is at a pressure in the range 80 to 200 barg and a temperature in the range 450 to 600°C. Preferably, the superheated MP steam that is generated in the HRSG is at a pressure in the range 25 to 50 barg and a temperature in the range 300 to 450°C. Preferably, the superheated LP steam that is generated in the HRSG is at a pressure in the range 2 to 10 barg and a temperature in the range 200 to 300°C. The steam from the HRSG, particularly the MP steam, may be recycled to the process by combining it with one or more of the hydrocarbon feed, and / or the reformed gas fed to the water-gas shift unit. In one arrangement, the saturator may be replaced with a process condensate stripper fed with steam generated by the HRSG. The cooled exhaust gas is discharged from the HRSG to the atmosphere through a stack. Preferably, the stack is provided with a continuous emission monitoring system for monitoring, for example, the NOx content of the cooled exhaust gas. The HP steam that is generated and superheated in the HRSG may be mixed with the HP steam from the waste heat boiler(s) (that is superheated in the HRSG) and the combined superheated HP steam passed to the HP stage of the steam turbine. If desired, a first portion of the MP steam exhaust from the high pressure stage of the steam turbine may be fed to the MP reheater coil of the HRSG and the re-heated MP steam then delivered to the medium pressure stage (middle stage) of the steam turbine. If desired, a second portion of the MP steam exhaust from the high pressure stage of the steam turbine may be used as MP steam for the steam reforming and water-gas shift conversion of the fuel feed stream and optionally to strip impurities from the process condensate. Where the carbon dioxide removal unit uses a physical or amine wash solvent as sorbent, a portion of the LP steam generated in the HRSG may, if desired, be used to heat and thereby desorb carbon dioxide out of the absorbent. However, preferably the LP steam is superheated in the HRSG and is delivered to the low pressure stage (final stage) of the steam turbine. The physical or amine wash may then be heated in a re-boiler in exchange with the reformed gas. If desired, for example when the demand for power from the gas turbine is reduced, a portion of the hydrogen fuel gas may be exported from the process. The invention is illustrated by reference to the accompanying drawing in which: Figure 1 depicts a flowsheet of one embodiment of the invention, and Figure 2 depicts of a flowsheet of another embodiment of the invention. It will be understood by those skilled in the art that the drawings are diagrammatic and that further items of equipment such as heat exchangers, reflux drums, pumps, vacuum pumps, compressors, temperature sensors, pressure sensors, pressure relief valves, control valves, flow controllers, level controllers, holding tanks, storage tanks, and the like may be required in a commercial plant. The provision of such ancillary items of equipment forms no part of the present invention and is in accordance with conventional chemical engineering practice. In Figure 1, a natural gas stream 10 is combined with a first portion of a by-product gas stream supplied via line 12, and the resulting mixture heated and passed to a desulphurisation unit 14 comprising a hydrodesulphurisation vessel containing a hydrodesulphurisation catalyst followed by two vessels containing zinc oxide hydrogen sulphide absorbents and ultra-purification adsorbents. Sulphur compounds present in the natural gas are converted to hydrogen sulphide which, along with hydrogen sulphide already present in the natural gas, is removed. The resulting desulphurised hydrocarbon 16 is combined with a second portion of the by-product gas provided by line 18 and the resulting gaseous mixture fed to a saturator 20 where it is saturated with steam. The saturator 20 is fed with a water stream comprising a heated process condensate provided via line 22 and a recirculated water stream recovered from the saturator. The resulting saturated hydrocarbon in line 24 is combined with steam provided from a steam boiler (not shown) and steam provided by line 26 to increase the steam to carbon ratio to the desired level. The resulting mixture is heated and fed via line 28 to a reforming unit 30 comprising a gas-heated reformer (GHR) and autothermal reformer (ATR) in series. The gaseous mixture 28 is subjected to a first step of steam reforming in the gas-heated reformer over a particulate nickel steam reforming catalyst disposed in a plurality of externally heated tubes followed by autothermal reforming with an oxygen gas stream provided by line 32 from an air separation unit (not shown) in an autothermal reformer containing a bed of nickel steam reforming catalyst. Reformed gas recovered from the autothermal reformer is used to heat the tubes of the gas-heated reformer thereby producing a partially cooled reformed gas 34, which, without further steam addition, is fed to a water-gas shift unit 36 comprising an isothermal water-gas shift vessel containing a bed of water-gas shift catalyst cooled by boiling water under pressure, such as demineralised boiler feed water (not shown). Within the water-gas shift unit 36, shifted gas recovered from the isothermal water-gas shift vessel is cooled and fed to an adiabatic low-temperature water-gas shift vessel containing a bed of low-temperature shift catalyst to reduce the carbon monoxide level in the resulting hydrogen-enriched gas. A hydrogen-enriched reformed gas mixture is recovered from the water-gas shift unit 36 and fed via line 38 to a heat recovery unit 40 where it is cooled in heat exchange with one or more coolants, including for example boiler feed water, saturator feed water and process condensate, to below the dew point. Process condensate is recovered in one or more gasliquid separators in series to produce a dewatered hydrogen-enriched reformed gas. A major portion of the process condensate recovered from the one or more gas-liquid separators in the heat recovery unit 40 is passed to the saturator feed 22 via line 42. The dewatered hydrogen-enriched reformed gas is passed from the heat recovery unit 40 via line 44 to a separation unit 46 comprising a carbon dioxide removal unit 48 and a hydrogen purification unit 50. The carbon dioxide removal unit 48 operates by means of reactive absorption with an amine absorbent, which removes carbon dioxide from the gas mixture, thereby producing a carbon dioxide stream 52 which is compressed, preferably dehydrated, and sent for storage or conversion into chemicals. By removing carbon dioxide from the feed gas 44, the carbon dioxide removal unit 48 produces a crude hydrogen gas stream which is recovered from the carbon dioxide removal unit via line 54. The crude hydrogen stream 54 is passed to a hydrogen purification unit 50 comprising a pressure-swing absorption unit that purifies the hydrogen by removing trace amounts of methane and carbon oxides as well as any residual inert gases such as nitrogen and argon to provide a high-purity hydrogen stream that is recovered from the purification unit 50 by line 56. The hydrogen purification unit 50 produces a by-product gas stream recovered via line 58 that contains inert gases, methane and carbon oxides as well as some hydrogen. The by-product gas stream 58 is compressed to about 1 - 3 bar abs and then divided; part is further compressed and recycled to the process via line 60 by dividing it into streams 12 and 18 that are combined with the natural gas fed to the purification and reforming unit, respectively. The remainder is fed vial line 62 to one or more fired heaters where it is used as a fuel to preheat feeds and generate saturated or superheated steam in a steam boiler (not shown), which is fed to the saturated hydrocarbon stream in line 24. The pure hydrogen stream in line 56 is passed as the hydrogen fuel gas to a gas turbine 64 where it combusted with air fed via line 66. The air fed to the gas turbine 64 may be pre-mixed with a nitrogen stream provided via line 68, if desired. The nitrogen stream 68 may be recovered from the air separation unit used to provide the oxygen stream 32 to the autothermal reformer inside the reforming unit 30. If desired, oxygen recovered from the air separation unit can be used to at least partly replace the air in line 66. If desired, a portion of the hydrogen fuel gas stream 56, or a portion of the by-product stream 62 may be exported from the process. The hydrogen fuel is combusted in the gas turbine 64 and the combustion gases passed through a turbine connected to a generator (not shown) to generate electrical power. The exhaust gases from the gas turbine 64 are fed via line 70 to a heat recovery steam generator (HRSG) 72 comprising a plurality of coils fed with boiler feed water and stem so that the HRSG produces a high pressure steam stream, a medium or intermediate pressure steam stream and a low pressure steam stream, each of which are fed a steam turbine unit, which is connected to a generator (not shown) to generate additional electrical power. The spent, cooled exhaust gases from the HRSG, comprising mainly nitrogen and water vapour with some oxygen, are fed to a stack via line 74. If desired, a portion of the medium pressure steam generated in the HRSG may be fed via line 76 to the saturated natural gas recovered from the saturator 20 and / or to the reformed gas fed to the water-gas shift unit 36. In Figure 2, a natural gas stream 10 is combined with a first portion of a by-product gas stream supplied via line 12, and the resulting mixture heated and passed to a desulphurisation unit 14 comprising a hydrodesulphurisation vessel containing a hydrodesulphurisation catalyst followed by two vessels containing zinc oxide hydrogen sulphide absorbents and ultra-purification adsorbents. Sulphur compounds present in the natural gas are converted to hydrogen sulphide which, along with hydrogen sulphide already present in the natural gas, is removed. The resulting desulphurised hydrocarbon 16 is combined with steam fed via line 80 and the resulting gaseous mixture fed to a reforming unit 30 comprising an adiabatic pre-reformer and autothermal reformer in series. The gaseous mixture is passed adiabatically through the prereformer containing a bed of nickel pre-reforming catalyst to convert higher hydrocarbons to methane and form a pre-reformed gas mixture comprising methane, steam, hydrogen and carbon oxides. In this embodiment, a second portion of the by-product gas stream is fed via line 18 to the reforming unit 30 either upstream ordownstream of the pre-reformer. The prereformed gas mixture, or the mixture of pre-reformed gas and by-product gas, is fed to the autothermal reformer containing a bed of nickel steam reforming catalyst, where it is autothermally reformed with an oxygen gas stream provided by an air separation unit (not shown) by line 82. A reformed gas recovered from the autothermal reformer is fed via line 84 to a reformed gas boiler 86. Demineralised boiler feed water fed to the boiler 86 via line 88 is converted to steam, which is recovered from the boiler via line 90, and the reformed gas is cooled. The steam 90 is superheated in a fired heater (not shown) to form a superheated steam stream, and a portion of the superheated steam stream sent for export from the process via line 92. The cooled reformed gas recovered from boiler 86 may be further cooled in one or more additional heat exchangers (not shown). The cooled reformed gas is combined with a portion of the superheated steam stream provided by line 94, and the resulting steam-enriched reformed gas mixture fed to a water-gas shift unit 36 comprising an adiabatic high-temperature shift vessel containing a bed of high-temperature water-gas shift catalyst. A shifted gas recovered from the high-temperature water-gas shift vessel is cooled and fed to an adiabatic low-temperature water-gas shift vessel containing a bed of low-temperature shift catalyst to reduce the carbon monoxide level in the resulting hydrogen-enriched reformed gas. A hydrogen-enriched reformed gas mixture is recovered from the water-gas shift unit 36 and fed via line 38 to a heat recovery unit 40 where it is cooled in heat exchange with one or more coolants, including the hydrocarbon feed, purified feed, pre-reformed feed, and boiler feed water to below the dew point. Process condensate is recovered in one, two or more gas-liquid separators in series to produce a dewatered hydrogen-enriched reformed gas. A major portion of the process condensate recovered from the gas-liquid separators in the heat recovery unit 40 is passed via line 42 to a steam stripping unit 96 fed with a portion of the superheated steam stream via line 98. In the stripping unit 96 the condensate is stripped to form an enriched saturated steam stream containing organic compounds that were dissolved in the condensate. The steam recovered from the stripping unit 96 may be combined with a further portion of superheated steam to provide the desired steam to carbon ratio and fed via line 80 to form the gaseous mixture of hydrocarbon and steam fed to the reforming unit 30. The dewatered hydrogen-enriched reformed gas is passed from the heat recovery unit 40 via line 44 to a separation unit 46 comprising a hydrogen separation unit 100 coupled to a downstream cryogenic carbon dioxide separation unit 102. The hydrogen separation unit 100 operates by pressure-swing adsorption (PSA) to produce a hydrogen stream recovered via line 114 and a hydrogen-depleted gas, which is compressed, dried and passed via line 106 to the cryogenic carbon dioxide separation unit 102. The hydrogen separation unit 100 is operated to also produce a low-pressure hydrogen-containing waste gas stream, which is recovered from the unit 100 via line 120 and used as a fuel in one or more fired heaters, for example to preheat the hydrocarbon feed to the process, The cryogenic carbon dioxide separation unit cools and condenses a liquid carbon dioxide stream, which is recovered from the unit 102 via line 108. The cryogenic carbon dioxide separation also produces a carbon dioxide-depleted gas stream, which is recovered from the unit 102 via line 110. Rather than recycling the carbon-dioxide depleted gas from the cryogenic carbon dioxide separation unit 102 to the process directly, in this arrangement, the carbon dioxide-depleted gas stream 110 is fed to a downstream secondary purification unit 112 to increase hydrogen recovery and make the recycle stream richer in carbon compounds. Hence the separation unit comprises the hydrogen separation unit 100, the cryogenic carbon dioxide separation unit 102 and the secondary purification unit 112. The secondary purification unit may be a further pressure-swing adsorption unit that separates the carbon dioxide-depleted gas 110 into a further hydrogen stream 104, which is combined with the hydrogen stream 114 from the hydrogen separation unit 100 to form a combined hydrogen fuel stream 116. The secondary purification unit 112 also produces a byproduct gas stream, which is recycled to the process via line 118. The by-product stream 118 is compressed, divided into the by-product streams 12 and 18 and recycled to the process. If desired, a portion of the hydrogen fuel gas stream 116, ora portion of the low-pressure waste gas stream 120 may be exported from the process. The pure hydrogen stream in line 116 is passed as the hydrogen fuel gas to a gas turbine 64 where it combusted with air fed via line 66. The air fed to the gas turbine 64 may be pre-mixed with a nitrogen stream provided via line 68, if desired. Oxygen rich oxidant could be also used instead of air in line 66, if desired, sourced preferably from the same air separation unit used to supply oxygen to the autothermal reforming inside the reforming unit via line 82. The hydrogen fuel is combusted in the gas turbine 64 and the combustion gases passed through a turbine connected to a generator (not shown) to generate electrical power. The exhaust gases from the gas turbine 64 are fed via line 70 to a heat recovery steam generator (HRSG) 72 comprising a plurality of coils fed with boiler feed water and stem so that the HRSG produces a high pressure steam stream, a medium or intermediate pressure steam stream and a low pressure steam stream, each of which are fed a steam turbine unit, which is connected to a generator (not shown) to generate additional electrical power. The spent, cooled exhaust gases from the HRSG, comprising mainly nitrogen and water vapour with some oxygen, are fed to a stack via line 74. Steam from the HRSG in line 76 may be used to supply the steam added to the process in lines 94 and 80 or exported from the process. The benefits of the invention are as follows: • Inclusion of the separation unit and by-product gas recycle to the process, lead to increased feedstock efficiency and hence reduced OPEX and equivalent levelised cost of hydrogen for the hydrogen fuel, and a high CO2 capture rate of 96.0% minimum and 5 up to 99.9% . • Use of oxygen-fired ATR (as opposed to air-fired ATR) makes the reforming unit and water-gas shift unit smaller and CO2 partial pressure higher, making the CO2 capture easier and more efficient. • Use of a cryogenic CO2 removal scheme as an alternative to the amine-based CO2 10 schemes, enables a carbon capture rate up to 99.9%. • The ability to remove the steam boiler and reduce the size of fired heater (if present) fuelled by by-product gas, and instead recycle of the by-product gas to the process reduces CO2 in flue gas to a minimum and using steam raised in the downstream Heat Recovery Steam Generators (HRSGs) for either direct steam addition or pre-heating 15 process steam using steam, leading to increase by-product recycle and hence even higher feedstock efficiency, and capture rate.

Claims

1. A process for the production of hydrogen, carbon dioxide and power comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a reforming unit comprising an oxygen-fired autothermal reformer to generate a reformed gas mixture with a nitrogen content below 5 mole% on a dry gas basis; (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas; (iii) passing the hydrogen-enriched reformed gas to a separation unit to provide a hydrogen fuel gas stream, a carbon dioxide gas stream and a by-product gas stream, and (iv) passing at least a portion of the hydrogen fuel stream to a gas turbine to generate electrical power, wherein at least a portion of the by-product gas stream is compressed and recycled to the process.

2. A process according to claim 1, wherein the reforming unit further comprises a gas-heated reformer or adiabatic pre-reformer upstream of the autothermal reformer.

3. A process according to claim 1 or claim 2, wherein the hydrocarbon is a methane-containing gas stream.

4. A process according to any one of claims 1 to 3, wherein the gaseous mixture comprising hydrocarbon and steam has a steam to carbon ratio in the range of 1.0:1 to 3.5:1 where the reforming unit comprises a gas-heater reformer and autothermal reformer in series, or a steam to carbon ratio in the range of 0.4:1 to 5:1 where the reforming unit comprises an adiabatic pre-reformer and autothermal reformer in series.

5. A process according to any one of claims 1 to 4, wherein the gaseous mixture comprising the hydrocarbon and steam is formed by contacting the hydrocarbon with water in a saturator to form a saturated gas mixture, with optional direct addition of steam to the saturated gas mixture.

6. A process according to any one of claims 1 to 5, wherein at least a portion of the steam in the gaseous mixture of hydrocarbon and steam is steam recovered from a water-cooled water-gas shift reactor or steam generated by cooling of an exhaust gas recovered from the gas turbine.

7. A process according to any one of claims 1 to 6, wherein the autothermal reformer is fed with an oxygen-rich gas comprising at least 90% vol O2, preferably at least 95% vol O2, more preferably at least 98% vol O2.

8. A process according to any one of claims 1 to 7, wherein the water-gas shift stage comprises a stage of high-temperature shift and optionally a downstream low-temperature shift stage, or a stage of isothermal shift stage and optionally a downstream low-temperature shift stage.

9. A process according to any one of claims 1 to 8, wherein an oxidation unit is provided downstream of the water-gas shift unit and upstream of the separation unit to convert carbon monoxide present in the hydrogen-enriched reformed gas to carbon dioxide.

10. A process according to any one of claims 1 to 9, wherein upstream of the separation unit the hydrogen-enriched reformed gas mixture is cooled and condensed water separated therefrom.

11. A process according to any one of claims 1 to 10, wherein the separation unit comprises a hydrogen separation unit coupled to a downstream cryogenic carbon dioxide separation unit.

12. A process according to claim 11, wherein the hydrogen separation unit comprises a membrane system, a temperature swing adsorption system, or a pressure swing adsorption (PSA) system.

13. A process according to claim 11 or claim 12, wherein the cryogenic carbon dioxide separation comprises a series of refrigeration and fractionation units configured to liquefy and separate carbon dioxide from a hydrogen-depleted gas mixture recovered from the hydrogen separation unit.

14. A process according to claim any one of claims 11 to 13, wherein the separation unit comprises a secondary hydrogen separation unit downstream of the cryogenic carbon dioxide separation unit.

15. A process according to any one of claims 1 to 10, wherein the separation unit comprises a carbon dioxide removal unit coupled to a downstream hydrogen purification unit.

16. A process according to claim 15, wherein the carbon dioxide removal unit operates using a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system.

17. A process according to claim 15 or claim 16, wherein the hydrogen purification unit comprises a pressure-swing adsorption (PSA) unit.

18. A process according to any one of claims 1 to 17, wherein a portion of the by-product gas is recycled to the process by combining the portion with the hydrocarbon feedstock, before or after any desulphurisation, and / or combining it with the gaseous mixture of hydrocarbon and steam upstream of the reforming unit and / or by combining it with a pre-reformed or partially reformed gas mixture generated within the reforming unit.

19. A process according to any one of claims 1 to 18, wherein a portion of the by-product gas is recycled to the process by combining it with the reformed gas upstream of the water-gas shift unit.

20. A process according to any one of claim 1 to 19, wherein a portion of the by-product gas is recycled to the process by combining it with the hydrogen-enriched gas, or a carbon dioxide enriched hydrogen enriched gas produced by an oxidation unit upstream of the separation unit, or by feeding it to one or more stages of product separation within the separation unit.

21. A process according to any one of claims 1 to 20, wherein the by-product gas is divided into a first portion and a second portion, the first portion is recycled to the process, and the second portion is fed to one or more fired heaters used to heat feed steams or provide steam for the process.

22. A process according to any one of claims 1 to 21, wherein the gas turbine is fed with air, preferably air supplemented with nitrogen and / or oxygen from an air separation unit that also provides an oxygen stream to the oxygen-fired autothermal reformer.

23. A process according to any one of claims 1 to 22, wherein an exhaust gas recovered from the gas turbine is used to generate steam, which is fed to one or more steam turbines connected to one or more generators to produce additional electricity.28A

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