Process for the production of hydrogen and carbon dioxide

Abstract

A process for the production of hydrogen and carbon dioxide is described comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a steam reforming unit comprising an oxygen-fired autothermal reformer to generate a reformed gas mixture; (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in the presence of steam, in a water-gas shift unit to provide a hydrogen-enriched reformed gas; (iii) passing the hydrogen-enriched reformed gas to a separation unit heated with steam to provide a hydrogen product stream, a carbon dioxide product stream and a by-product gas stream; and (iv) recycling at least a portion of the by-product gas stream to the process, wherein electrical heating is used to (a) generate at least a portion of the steam used in one or more of the steam reforming unit, the water-gas shift unit and the separation unit and / or (b) directly or indirectly heat a process gas fed to one or more of the reforming unit, the water-gas shift unit and the separation unit.

Description

[0001] P102247

[0002] 1

[0003] Process for the production of hydrogen and carbon dioxide

[0004] This invention relates to processes for the conversion of hydrocarbons to hydrogen and carbon dioxide. The invention provides higher feedstock efficiency and lower direct and indirect carbon 5 dioxide and nitrogen oxide (NOx) emissions than prior art, with significant control and operability improvements.

[0005] Processes for generating hydrogen and carbon dioxide are known.

[0006] WO2024134157 A1 and WO2024134158 A1 disclose processes for the production of hydrogen comprising the steps of: hydrodesulphurisation, reforming in a reforming section comprising a an autothermal reformer, water-gas shift, carbon dioxide separation and recovery, and hydrogen purification. The hydrogen purification step produces a hydrocarbon- containing offgas stream which is split: a portion is used as a fuel gas stream which is fed to one or more 15 fired heaters used to heat one or more process streams within the process, the remainder is compressed and split into a hydrodesulphurisation recycle stream which is used in the hydrodesulphurisation unit, and a process recycle stream which is returned to the process.

[0007] We have developed an improved process where the feedstock efficiency can be significantly 20 increased vs prior art, especially at lower plant rates resulting in greater control and operability.

[0008] The improved process also allows the direct and indirect carbon dioxide and nitrogen oxide emissions to be significantly reduced.

[0009] Accordingly, the invention provides a process for the production of hydrogen and carbon 25 dioxide comprising the steps of:

[0010] (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a steam reforming unit comprising an oxygen-fired autothermal reformer to generate a reformed gas mixture;

[0011] (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in the presence of steam, in a water-gas shift unit to provide a hydrogen-enriched reformed gas;

[0012] (iii) passing the hydrogen-enriched reformed gas to a separation unit heated with steam to provide a hydrogen product stream, a carbon dioxide product stream and a by-product gas stream; and

[0013] 35 (iv) recycling at least a portion of the by-product gas stream to the process, wherein electrical heating is used to (a) generate at least a portion of the steam used in one or more of the steam reforming unit, the water-gas shift unit and the separation unit and / or (b)P102247

[0014] 2

[0015] directly or indirectly heat a process gas fed to one or more of the reforming unit, the water-gas shift unit and the separation unit.

[0016] The Applicants have found that the combination of a standalone electric steam boiler and / or 5 electric process heater to replace part of the combusting of by-product gas and further recycling of by-product gas to the process front-end can lead to an increase in the feedstock efficiency and an increase in direct carbon dioxide capture rate to levels at or above 98%. This can also lead to a reduction in total (direct and indirect) carbon dioxide emissions as defined by Scope 1+2+3 given that the majority of emissions are associated with fugitive emissions from feedstocks, meaning the emissions reduced as a result of increased feedstock efficiency offsets any increase in emissions associated with increased electricity supply to the process. The invention also allows a reduction in direct nitrogen oxides (NOX) emissions as a result of a reduction in the amount of hydrogen-containing by-product gas that is combusted which is associated with high flame temperature and hence NOXformation.

[0017] 15

[0018] In the process, electrical heating is used to (a) generate at least a portion of the steam used in one or more of the steam reforming unit, the water-gas shift unit and the separation unit and / or (b) directly or indirectly heat a process gas fed to one or more of the reforming unit, the water- gas shift unit and the separation unit. Any suitable electrical heating device may be used such 20 as an electrical steam boiler, a resistance heater, an inductive heater or a firebrick heater.

[0019] Preferably, the electrical heating is used to produce saturated or superheated steam and / or directly or indirectly heat one or more of the process gas streams. Steam generated by electric heating may be fed to one or more of the reforming unit, water-gas shift unit and the separation unit to be either used directly as steam for reforming and / or water-gas shift reactions, or to heat 25 one or more process gas streams indirectly. Hence, steam generated by the electrical heating may be used to directly or indirectly heat one or more process gas streams used in the process. In some arrangements, the electrical heating may be used to directly or indirectly heat, for example via heating medium, one or more process gas streams fed to or within the reforming unit, water-gas shift unit and the separation unit. Process gas streams that may be heated electrically include feed gas to the reforming unit, partially reformed gas within the reforming unit, recycle streams, purified gas, saturator water, saturated gas streams, oxygen gas streams, feed to an oxidation unit, where present, and feeds to the separation unit including absorbent regeneration streams in the carbon dioxide removal unit. In a preferred arrangement, an electrical heater is used to heat a feed gas, such as pre-reformed gas, to the 35 autothermal reformer in the steam reforming unit. If desired, a portion of the steam raised in an electric steam boiler may also be exported from the process.

[0020] The present invention uses a gaseous mixture comprising a hydrocarbon.P102247

[0021] 3

[0022] 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 5 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.

[0023] If the hydrocarbon contains sulphur compounds, before, or preferably after, compression it may be subjected to desulphurisation. In some arrangements, 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 15 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 20 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, 25 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. Alternatively, the compression of a portion of the by-product gas and the hydrocarbon can take place in a single compressor.

[0024] 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 35 sulphide removal and optionally ultra-purification as described above.

[0025] 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 the hotP102247

[0026] 4

[0027] 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.

[0028] 5 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.

[0029] 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 15 shifted gas followed by heating steam.

[0030] 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.

[0031] 20

[0032] 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. In the present invention, at least a portion of steam may be generated in an electricsteam boiler. The extent of electric steam boiling duty is flexible and can be adjusted as a function of (1) the required increase in

[0033] 25 feedstock efficiency, (2) the required reduction in direct and indirect carbon dioxide and nitrogen oxides emissions, (3) and other constraints such as the availability of large-scale electric steam boilers or very low plant turndown ratio requirements.

[0034] 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, 35 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 inP102247

[0035] 5

[0036] the process. The steam content of the saturated gas mixture may, if desired, be increased by the direct addition of steam.

[0037] In the present invention, at least a portion of the by-product gas is compressed and recycled to 5 one or more of the reforming unit, the water-gas shift unit and the separation unit. Hence, a portion of the 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 by-product gas may be combined with a pre-reformed and / or partially reformed gas mixture generated within the reforming unit.

[0038] 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 15 separation within the unit.

[0039] 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 20 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 the combustion of a portion of hydrocarbon in the feed gas. The feed gas is typically fed to the top of the reformer, and the oxygen-rich gas is fed to the burner, mixing and combustion occur 25 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.

[0040] 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 35 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 CO2P102247

[0041] 6

[0042] emissions or decarbonised electricity generated by the process, for example by the gas turbine or steam turbine.

[0043] The amount of oxygen-rich gas added to the autothermal reformer is preferably such that 40 to 5 90 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 at low plant rates or if the plant trips.

[0044] 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 one arrangement the partially reformed gas mixture is generated upstream of the 15 autothermal reformer by adiabatic pre-reforming in one or more pre-reformers operated in series or parallel. In another arrangement the partially reformed gas mixture is generated by steam reforming the gaseous mixture in one or more gas-heated reformers comprising catalystcontaining tubes heated by the reformed gas mixture recovered from the autothermal reformer. If desired, two or more gas-heated reformers may be coupled to a single ATR. The one or 20 more pre-reformer or gas-heated reformers and the autothermal reformer are preferably operated in series.

[0045] 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 25 it is subjected to autothermal reforming to generate the reformed gas mixture.

[0046] 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.

[0047] 35

[0048] 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,P102247

[0049] 7

[0050] 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 5 that the heating requirement and oxygen demand for the reforming stages is reduced and that the front-end equipment (e.g. fired heater and / or electric process 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 preferred.

[0051] 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.

[0052] 15

[0053] In the present invention, at least a portion of pre-heating may be carried out using an electric process heater. The extent of electric pre-heating duty is flexible and can be adjusted as a function of (1) the required increase in feedstock efficiency, (2) the required reduction in direct and indirect carbon dioxide and nitrogen oxides emissions, (3) and other constraints such as 20 the availability of large-scale electric process heaters or very low plant turndown ratio requirements.

[0054] 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

[0055] 25 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 and / or electric process 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 35 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.P102247

[0056] 8

[0057] 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.

[0058] 5 Desirably, the mixed stream is heated to 400-500°C, preferably 420-460°C. Different types of gas-heated reformers 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 15 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 20 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 25 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.

[0059] 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.

[0060] In arrangements comprising a gas-heated reformer and an autothermal reformer, the reformed 35 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 CentigradeP102247

[0061] 9

[0062] 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 5 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.

[0063] 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 is in the range of 5- 15 20% vol on a wet gas basis.

[0064] 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 20 reformed gas to carbon dioxide. The reaction may be depicted as follows;

[0065] CO + H2O ^ CO2+ H2

[0066] Whereas steam is present in the reformed gas, supplemental steam may be added before the 25 one or more water-gas shift stages, e.g. by direct addition to the reformed gas, if desired.

[0067] The one or more water-gas shift stages may include stages of high-temperature shift, mediumtemperature shift, isothermal shift and low-temperature shift.

[0068] 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.

[0069] Medium-temperature shift and low-temperature shift stages may be performed using shift 35 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 0.1 to 1.5) may be passed over the catalyst in an adiabatic fixed bed with an outlet temperature in theP102247

[0070] 10

[0071] range 185 to 300°C. The outlet carbon monoxide content may be in the range of 0.1 to 1.5%, preferably under 0.5% vol on a dry basis. Alternatively, in medium-temperature shift, the gas containing carbon monoxide and steam may be fed to the catalyst at an inlet temperature in the range of 185 to 240°C although the inlet temperature may be as high as 280°C. The outlet 5 temperature may be up to 300°C but may be as high as 360°C.

[0072] 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 15 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.

[0073] 20 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, optionally after being superheated elsewhere in the process.

[0074] The hydrogen-enriched reformed gas contains steam. In some arrangements it may be 25 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 as a process stream, or used for 35 electricity generation in a steam turbine, or exported from the process, optionally after being superheated elsewhere in the process.P102247

[0075] 11

[0076] 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 5 of the condensate removal. The oxidation unit may also be included within the separation unit.

[0077] 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;

[0078] 2 CO + O2-► 2 CO2

[0079] 2 H2+ O22 H2O

[0080] An oxygen-rich gas may be added to the hydrogen-enriched reformed gas. The oxygen-rich gas may be generated by a vacuum pressure swing adsorption (VPSA) unit, an air separation 15 unit and / or by electrolysis of water. Some hydrogen is also oxidised to form water.

[0081] Accordingly, the oxidation catalyst is preferably a CO-selective oxidation catalyst to minimise hydrogen losses.

[0082] The oxidation catalyst is preferably a supported precious metal catalyst. For example, the 20 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, 25 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.

[0083] Therefore, it is preferable to locate an adiabatic oxidation vessel downstream of one or more stages of cooling and condensate recovery or compression. 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 35 of the water-gas shift unit, especially where the water-gas shift unit comprises an isothermal shift vessel or a low-temperature 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 exitP102247

[0084] 12

[0085] 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, and the water-gas shift unit comprises an isothermal shift vessel, the water pressure is preferably the same as in the isothermal shift converter so that a single steam drum can be shared by the 5 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.

[0086] Where included downstream of the water-gas shift unit and upstream of the separation unit, 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 15 them, to form a de-watered carbon dioxide-enriched hydrogen-enriched reformed gas.

[0087] In some arrangements, cooling of the hydrogen-enriched reformed gas or the carbon dioxide- enriched 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 20 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 25 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 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.

[0088] However, in some arrangements, it may not be necessary to recover condensate from the 35 hydrogen-enriched reformed gas mixture.

[0089] 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 toP102247

[0090] 13

[0091] separate hydrogen from the other components, The separation unit further provides a carbon dioxide stream and a by-product stream.

[0092] The separation unit may comprise different arrangements. In a first separation arrangement, 5 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 product stream, a carbon dioxide product stream, a by-product gas stream, and a hydrogen-containing waste gas stream that may be used as fuel in one or more fired heaters. The second separation arrangement produces a hydrogen product stream, a carbon dioxide product 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.

[0093] 15

[0094] 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 a portion of the by-product gas stream may be 20 compressed and fed to the inlet or outlet of one or more of the reforming unit, the water-gas shift unit, the optional oxidation unit if present and the separation unit.

[0095] An aqueous process condensate may also be separated in the separation unit and returned to the process or sent to an effluent treatment plant.

[0096] 25

[0097] 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.

[0098] 35 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 in addition to electric steam boilers or process heaters that may be present to provide the residual steam or pre-heating requirement.P102247

[0099] 14

[0100] 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.

[0101] 5

[0102] 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.

[0103] In some arrangements, an oxidation unit may be provided downstream of the compression or 15 dehydration units and upstream of the cryogenic carbon dioxide separation unit to convert carbon monoxide present in the hydrogen-depleted gas stream to carbon dioxide. The oxidation unit may comprise one or more oxidation vessels containing any suitable oxidation catalyst, such as a supported platinum group metal catalyst, that oxidises the carbon monoxide present in the hydrogen-enriched reformed gas, thereby converting it to carbon dioxide. The 20 oxidation reactions may be depicted as follows;

[0104] 2 CO + O2-► 2 CO2

[0105] 2 H2+ O22 H2O

[0106] 25 An oxygen-rich gas may be added to the hydrogen- depleted gas. The oxygen-rich gas may be generated by a vacuum pressure swing adsorption (VPSA) unit, an air separation unit and / or by electrolysis of water.

[0107] The cryogenic carbon dioxide separation unit may comprise 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.

[0108] The separated carbon dioxide stream provided by this arrangement may be recovered from the 35 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, and more preferably in excess of 99.5% mol on a wet basis.P102247

[0109] 15

[0110] 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.

[0111] The carbon dioxide-depleted stream may be processed directly or sent to a secondary 5 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. In preferred arrangements, the secondary hydrogen separation system comprises a PSA system and optionally a membrane system in series. 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 a pure hydrogen stream recovered from the hydrogen separation unit upstream of the cryogenic carbon dioxide separation unit.

[0112] 15 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.

[0113] 20

[0114] 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 25 of the by-product gas, on a wet gas basis, may be 15-85% 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 is in the range of 2-5% vol on a wet gas basis.

[0115] 35 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 aP102247

[0116] 16

[0117] 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 5 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.

[0118] In some arrangements, the laden absorbent liquid goes through multiple stages of pressure reduction, to facilitate the separation of carbon dioxide and reduce any carryover of hydrogen and other compounds into the carbon dioxide product, whilst generating power during the 15 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.

[0119] The recovered carbon dioxide may comprise 90-95% vol carbon dioxide with the balance 20 comprising water, hydrogen, inerts gases and traces of other volatile compounds such as methane, carbon monoxide, methanol and ammonia.

[0120] 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 25 recovery (EOR) processes. In cases where the CO2 is to be compressed or pumped 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, pumping or drying. The CC>2may if desired also be subjected to a liquefaction step using known liquefaction schemes after product separation.

[0121] 35

[0122] 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 comprisingP102247

[0123] 17

[0124] 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.

[0125] The crude hydrogen gas stream is passed to a hydrogen purification unit to provide a pure 5 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.

[0126] The hydrogen purification unit also provides the by-product gas stream that is recycled to the 15 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.

[0127] Whereas all of the by-product gas may be recycled to the process, for example when all of the 20 steam generation or process heating requirements are provided by a combination of heat available in the process and electric steam boiler and process heater, in some arrangements it is advantageous to divide the by-product gas and consume part as a fuel gas to prevent the build-up of inert gases in the process. In addition, combusting part of the by-product gas instead of hydrocarbon fuel in one or more fired heaters, where these are required for steam 25 generation or pre-heating 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.

[0128] The hydrogen product gas may be compressed and used in downstream power or heating processes, for example, by using it as fuel in a gas turbine (GT) or by injection into a domestic or industrial networked gas piping system. The hydrogen product, optionally after further 35 purification, may also be used in a downstream chemical synthesis process. Thus, the hydrogen product may be purified and used to produce ammonia by reaction with nitrogen in an ammonia synthesis unit. Alternatively, the hydrogen product may optionally be purified and used with a carbon dioxide-containing gas to manufacture methanol in a methanol productionP102247

[0129] 18

[0130] unit. Alternatively, the hydrogen product may be purified and used with a carbon-monoxide containing gas to synthesise hydrocarbons in a Fischer-Tropsch production unit. Any known ammonia, methanol or Fischer-Tropsch production technology may be used. Alternatively, the hydrogen may be used to upgrade hydrocarbons, e.g. by hydro-treating or hydro-cracking 5 hydrocarbons in a hydrocarbon refinery, or in any other process where pure hydrogen may be used. Compression may again be accomplished using an electrically driven compressor powered by renewable electricity.

[0131] A portion of the hydrogen product, with or without purification, may be compressed if necessary and recycled to the hydrocarbon feed if desired for desulphurisation and to reduce the potential for carbon formation in the pre-reformer or gas-heated reformer.

[0132] In some arrangements, the hydrogen may be combusted directly, without the need for recompression, in a gas turbine. The turbine exhaust gas may be used to raise process steam 15 and cater for the heating needs of the process.

[0133] If an application for hydrogen is for producing electricity, the majority of the product hydrogen can be sent to the gas turbine, and the excess heat is used to produce further electricity by raising high-pressure steam and expanding it through a steam turbine, for example as practised 20 in conventional combined cycle power plants. Medium-pressure steam can be extracted from the appropriate stages of the steam turbine and sent to the process, thus enhancing the heat integration in the hydrogen plant and the power plant for better energy utilization. The heat recovery exercise can be also completed at low temperatures from both the hydrogen and the power plants by district heating.

[0134] 25

[0135] The invention is illustrated by reference to the accompanying drawing in which:

[0136] Figure 1 depicts a flowsheet of one embodiment of the invention, and

[0137] Figure 2 depicts a flowsheet of another embodiment of the invention.

[0138] 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 35 present invention and is in accordance with conventional chemical engineering practice.

[0139] 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 is heated and passed to a desulphurisation unitP102247

[0140] 19

[0141] 14 comprising a hydrodesulphurisation vessel containing a hydrodesulphurisation catalyst followed by two vessels containing zinc oxide hydrogen sulphide absorbents and ultrapurification 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 5 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 is fed to a saturator 20 where it is saturated with steam. The saturator 20 is fed with a water stream 22 comprising a heated process condensate provided via line 42, make-up water and a recirculated water stream recovered from the saturator. The resulting saturated hydrocarbon in line 24 is combined with steam provided by 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 15 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 20 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). At least a portion of the steam generated in the isothermal water-gas shift vessel is provided as stream 26 to the reforming unit. Within the water-gas shift unit 36, shifted gas recovered from the isothermal water-gas shift vessel is cooled and fed to an 25 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 20 via line 22.

[0142] 35 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,P102247

[0143] 20

[0144] thereby producing a carbon dioxide stream 52 which is compressed, preferably dehydrated, and then sent for storage or conversion into chemicals in either a gaseous or dense phase form. 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 5 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 product stream in line 56 is then compressed to provide a compressed purified hydrogen stream for export.

[0145] 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 to 3 bar abs and then divided; part is further

[0146] 15 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 desulphurisation unit 14 and reforming unit 20, respectively. The remainder is fed via line 62 to a steam boiler 64 to generate steam and superheat the steam. The steam may be fed to the saturated hydrocarbon stream in line 24 along with the steam provided in line 26. Flue gas generated in the steam boiler 64 is emitted to 20 the atmosphere via line 66.

[0147] In the present invention, additional steam is generated in electric steam boiler 70 which is then mixed with steam generated in steam boiler 64 and is then used in the process for heating purposes via line 72. For example, the stream 72 may be used to heat one or more of the feed 25 gas 10, the recycle streams 12, 18, the purified gas 16, the saturator water stream 22, the saturated gas stream 24, the oxygen gas stream 32, or the absorbent regeneration stream in the carbon dioxide removal unit. If desired, a portion of the by-product stream 62, or a portion of the steam raised in steam boiler 64 or electric steam boiler 70 may be exported from the process.

[0148] 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 is 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 ultra35 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 a reforming unit 74 comprising an adiabatic pre-reformerP102247

[0149] 21

[0150] 75, an electric process heater 76 and an autothermal reformer 77 in series. The gaseous mixture is first heated using heat recovered in the heat recovery unit 40 (not shown), passed adiabatically through the pre-reformer 75 containing a bed of nickel pre-reforming catalyst to convert higher hydrocarbons to methane and form a pre-reformed gas mixture comprising 5 methane, steam, hydrogen and carbon oxides. In this embodiment, a second portion of the byproduct gas stream is fed via line 18 to the reforming unit 74 downstream of the pre-reformer 75, although in other embodiments it may be added upstream of the pre-reformer. The prereformed gas mixture, or the mixture of pre-reformed gas and by-product gas, is further heated in an electric process heater 76 and then fed via line 78 to the autothermal reformer 77 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.

[0151] 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

[0152] 15 superheated in a fired heater (not shown) to form a superheated steam stream, and a portion of the superheated steam stream is 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 20 mixture is 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 25 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 the hydrocarbon feed, purified 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.

[0153] 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 steam stripping unit 96, the condensate from line 42 is stripped to form an enriched saturated steam stream containing organic compounds that 35 were dissolved in the condensate, and an organic-lean condensate stream that may be sent to effluent treatment or returned to process via a deaerator (not shown). The steam containing organic compounds recovered from the stripping unit 96 may be combined with a furtherP102247

[0154] 22

[0155] portion of saturated or 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.

[0156] The dewatered hydrogen-enriched reformed gas is passed from the heat recovery unit 40 via 5 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. In the embodiment depicted in Figure 2, 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 pre-reformer 75 or autothermal reformer 77. Other arrangements for the units 100 and 102 may be used. The cryogenic carbon dioxide separation unit cools and condenses a liquid carbon dioxide stream, 15 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. In the embodiment depicted in Figure 2, rather than recycling the carbon-dioxide depleted gas from the cryogenic carbon dioxide separation unit 102 to the process directly, the carbon dioxide-depleted gas stream 110 is fed to a downstream secondary purification unit 112 to 20 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 25 from the hydrogen separation unit 100 to form a combined hydrogen product stream 116. The secondary purification unit 112 also produces a by-product 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. Other secondary purification configurations may be used, for example, hydrogen stream 104 can be omitted in which case the recycle stream 118 will contain more H2, or a membrane unit can be placed downstream of the pressure swing absorption.

[0157] If desired, a portion of the hydrogen product gas stream 116, or a portion of the low-pressure waste gas stream 120 may be exported from the process.

[0158] 35

[0159] The invention is further illustrated by the following calculated example of a process in accordance with the flowsheet depicted in Figure 1.P102247

[0160] 23

[0161]

[0162]

[0163] P102247

[0164] 24

[0165]

[0166] The benefits of the invention are as follows:

[0167] • Inclusion of the electric steam boiler and / or electric process heater leads to a 5 reduction in direct CO2 emissions (equivalent to an increase in Scope 1 carbon capture by about 1 percentage point at normal full rate) from the process, as less carbon (and hydrogen) containing fuel need to be combusted to meet process requirements, resulting in a carbon capture rate of 98 to 99.9% dependent on the type of carbon dioxide removal system employed.

[0168] 10 • As a result of reduced fuel gas combustion resulting in high flame temperature, the direct NOx emissions from the process are reduced, eliminating the need for NOx abatement subject to the level of electric heating and the permitted NOx emissions in the proposed plant location.

[0169] • Improvement in plant operability and control arrangement by inclusion of an

[0170] 15 alternative heating and / or steam generation mechanism, for example by reducing the delay between any plant rate change and the process fuel availability for further rate change.

[0171] • Improvement in feedstock efficiency by up to 3 percentage points as a result of reduced carbon (and hydrogen) containing gas combustion, resulting in a higherP102247

[0172] 25

[0173] proportion of the by-product gas being recycled, reducing operating cost and equivalent levelised cost of hydrogen.

[0174] • Extending the lowest rate the plant can operate without external firing of either hydrogen product or natural gas by about 50%.

[0175] 5 • Reduction in total (direct and indirect) emissions as defined by Scope 1+2+3 at normal full rate as a result of improvement in feedstock efficiency, hence reducing scope 3 emissions i.e. fugitive emissions associated with hydrocarbon feedstock production and transport, that offsets the increase in scope 2 emissions associated with an increase in electricity supply (subject to the carbon intensity of imported electricity).

Claims

P10224726Claims1. A process for the production of hydrogen and carbon dioxide comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam to steam reforming in a steam reforming unit comprising an oxygen-fired autothermal reformer to generate a reformed gas mixture; (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in the presence of steam, in a water- gas shift unit to provide a hydrogen-enriched reformed gas; (iii) passing the hydrogen- enriched reformed gas to a separation unit heated with steam to provide a hydrogen product stream, a carbon dioxide product stream and a by-product gas stream; and (iv) recycling at least a portion of the by-product gas stream to the process, wherein electrical heating is used to (a) generate at least a portion of the steam used in one or more of the steam reforming unit, the water-gas shift unit and the separation unit and / or (b) directly or indirectly heat a process gas fed to one or more of the reforming unit, the water-gas shift unit and the separation unit.

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 mixture6. 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.P102247277. 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, upstream of the separation unit, or within 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 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.P1022472817. 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 claims 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 electrical heating is used to produce saturated or superheated steam and / or heat one or more of the process gas streams.

23. A process according to the claims 1 to 22, wherein steam generated by electric heating is fed to one or more of the reforming unit, water-gas shift unit and the separation unit to be either used directly as steam for reforming and / or water-gas shift reactions, or to heat one or more process gas streams indirectly.

24. A process according to claims 1 to 22 wherein electrical heating is used to directly or indirectly heat one or more process gas streams fed to or within the reforming unit, water- gas shift unit and the separation unit.

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