Process for the production of methane-containing gas

Abstract

Methane containing gas production method comprising: (a / b) providing respective hydrogen 14 and carbon dioxide 22 containing gas streams; (c) measuring the flow-rate of the hydrogen stream and adjusti

Description

This invention relates to a process to produce a methane-containing product gas mixture. More particularly the invention relates to a process to produce a methane containing product gas mixture from hydrogen and carbon dioxide feeds, wherein the hydrogen feed is generated from the electrolysis of water. BACKGROUND Processes for producing methane containing gas mixtures by methanation of a synthesis gas comprising carbon dioxide, optionally carbon monoxide and hydrogen are well known. Such processes are described in WO2012 / 001401. In a continuous process to produce a methane-containing gas product, which consistently meets the specification required for such product, the stoichiometry of hydrogen relative to carbon dioxide (and optionally carbon monoxide), in a feed gas for methanation, must be tightly controlled and must remain as constant as possible. WO2015 / 159044 is an example of a process wherein the concentration of hydrogen in a methane-containing gas mixture is controlled. It discloses a process for producing a methane-containing gas mixture comprising the steps of: (i) passing a first feed gas mixture comprising hydrogen and carbon dioxide through a bed of a methanation catalyst to react a portion of the hydrogen with at least a portion of the carbon dioxide and form a methane-containing gas mixture containing residual hydrogen, (ii) adding an oxygen-containing gas to the methane-containing gas mixture containing residual hydrogen to form a second feed gas mixture, and (iii) passing the second feed gas mixture through a bed of an oxidation catalyst to react the residual hydrogen and oxygen to form a hydrogen depleted methane-containing gas mixture. With the ever increasing need to address climate change and pollution, there is a drive to recycle carbon dioxide into fuels by methanation using sustainable hydrogen sources. However, the availability of hydrogen from the sources is variable. For example, while it is known to produce hydrogen and oxygen through the electrolysis of water, by using a source of renewable energy, such as wind farms or solar farms, it will be appreciated, that the renewable sources of energy used to drive the electrolysis of water are dependent upon the elements from which they derive energy, and the abundance, or lack thereof, fluctuate, resulting in a fluctuation of the amount of hydrogen that can be produced by electrolysis. The feed gas mixture to a methanation unit would therefore have an inconsistent stoichiometry of hydrogen and carbon dioxide resulting in one having to continually adjust the conditions of methanation in a methanation unit in response to the fluctuations in the feed. The ramping up and ramping down of a methanation unit impacts upon the quality of product. Hence, the use of electrolytically generated hydrogen has not been exploited commercially at large scale as a source for a feed gas mixture to produce methane-containing gases. This invention provides a process suitable for producing on-specification methane containing product gas mixture while plant capacity is ramping up / down, when deviation from the target stoichiometric ratio of reactants can cause excess hydrogen or carbon dioxide slip into the product gas. OBJECT OF THE INVENTION It is an object of the invention to provide a process to maximise the production of an on-specification, high quality methane containing product gas mixture from hydrogen and carbon dioxide (and optionally carbon monoxide) feeds, particularly where the hydrogen containing gas is generated from sustainable sources, while overcoming the above-mentioned disadvantages SUMMARY OF THE INVENTION According to the present invention there is provided a process for producing a methane containing product gas mixture comprising the steps of: (a) providing a hydrogen containing feed gas stream; (b) providing a carbon oxide containing feed gas stream containing carbon dioxide and optionally carbon monoxide; (c) measuring the flow-rate of the hydrogen containing feed gas stream and adjusting the flowrate of the carbon oxide containing feed gas stream, relative to of the flowrate of the hydrogen in the hydrogen containing feed gas stream to produce a feed gas mixture having a composition [H21 — FC021 with a stoichiometric ratio of reactants having a value M of about 3, where M = 7—7-1— (d) passing the feed gas mixture through one or more beds of methanation catalyst, in a methanation unit, to react a portion of the hydrogen with at least a portion of the carbon dioxide and any carbon monoxide to form a first methane containing product gas mixture including residual hydrogen and residual carbon dioxide; (e) measuring the concentration of residual hydrogen of the first methane containing product gas mixture; and combining the first methane containing product gas mixture with an oxygen containing stream, wherein the flow rate of the oxygen containing stream is adjusted relative to the measured concentration of residual hydrogen in the first methane containing product gas mixture, so as to produce a second methane containing gas mixture which is passed through a bed of an oxidation catalyst in a hydrogen removal unit to form a hydrogen depleted third methane containing product gas mixture; comprising a total of less than 5 mole% hydrogen; wherein the hydrogen containing gas stream is produced by electrolysis of water. The process provides maximises production of an on-specification methane containing product gas mixture while plant capacity is ramping up / down resulting in additional hydrogen (or carbon dioxide) in the product gas caused by deviation from the target stoichiometric ratio. The electrolysis of water may be performed using one or more sources of renewable energy or may be performed using electricity generated by a steam turbine fed with steam generated in the process. Any electrolysis system may be used. In a preferred arrangement, the hydrogen containing gas stream and the oxygen containing stream are both produced by electrolysis of water. This removed the need for an air separation unit to provide the oxygen-containing gas. Whereas air can be used as an oxidant in the hydrogen removal unit, this is less preferred because the nitrogen present may make if more difficult to maintain the desired product specification. The hydrogen containing feed gas stream, produced by electrolysis, may be subject to a purification step to remove catalyst poisons therein prior to combining it with a carbon oxide containing gas stream. The carbon oxide containing feed gas mixture may be any suitable gas comprising or consisting essentially of carbon dioxide and optionally containing some carbon monoxide. In some embodiments there is no carbon monoxide present in the carbon oxide feed gas mixture. The carbon oxide feed gas may be passed through a purification unit upstream of the methanation unit to remove catalyst poisons, such as sulphur compounds. Any source of carbon oxide containing feed gas mixture may be used including CO2 from CO2 storage or from upstream processes that include CO2 recovery. The carbon oxide-containing feed gas may also be usefully recovered from processes that gasify renewable carbonaceous materials. The process includes combining a hydrogen containing feed gas stream and a carbon oxide containing feed gas stream to form a feed gas mixture. The composition of the feed gas mixture is adjusted by adjusting the flowrate of the carbon oxide containing gas stream, relative to the flow of hydrogen so as to produce a feed gas mixture having a stoichiometric ratio of reactants with a value M of about 3, where [H2I—rco2i M = [co]+ C02 • By the term about 3 we mean that the stoichiometric ration will typically be in the range of 2.9 to 3.1. The flowrate of hydrogen may be measured using known flowrate measurement apparatus. The flowrate information may be fed to a capacity management module that calculates the amount of carbon oxide-containing gas to feed to the process to achieve the desired stoichiometry. The composition of the feed gas mixture may be analysed using an online gas composition analyser, such as a Raman device, which feeds information to the capacity management control module to enable fine control of the feed gas composition. The capacity management module may further comprises flow ratio controllers and flow rate controllers, the former being in communication with the capacity management module while the latter are in communication with one or more valves in order to control and adjust the flow of the carbon oxide containing gas stream to be combined with the hydrogen containing gas stream. Accordingly, the flowrate of the hydrogen and the concentration of hydrogen in the feed gas mixture may be determinative of the level of adjustment of the flow rate of the carbon oxide containing gas stream so as to move the composition of the feed gas mixture towards a stoichiometric ratio of reactants [H21 — FC021 having a value M of about 3, where M = [co]+ C02 Hence, by controlling and adjusting the flowrate of the carbon oxide gas stream, in real time, relative to the flowrate of hydrogen and concentration of hydrogen in the feed gas mixture, the ability of the process to obtain an on-specification methane containing gas mixture is enhanced. The product methane containing gas mixture preferably gas a hydrogen content below about 5 mol%, more preferably below about 3 mol%. As M increases above 3, the first methane-containing gas mixture contains an excess of hydrogen potentially resulting in a methane containing gas mixture that would not be on-specification. As M falls below 3, then the methane containing gas mixture product contains increasing amounts of carbon dioxide, that potentially results in a methane containing gas mixture product that would not be on-specification. By an “on-specification” methane containing gas mixture, it is meant that the methane containing gas mixture has at least 95 mol% methane or that the methane containing gas mixture contains less than 5 mol% hydrogen and carbon dioxide assuming there are no inert gasses present. It may be desirable, to prevent the poisoning of the methanation catalyst in the methanation unit, to subject the feed gas mixture to one or more desulphurisation steps prior to passing the feed gas mixture through the methanation unit. The feed gas mixture may be passed over a bed of a particulate zinc oxide desulphurisation material. Suitable inlet temperatures for desulphurisation are in the range 100-300°C. A particularly effective zinc oxide desulphurisation material is PURASPEC™ 2020, available from Johnson Matthey PLC. If desired, the feed gas mixture may also be subjected to a step of hydrodesulphurisation by passing it over a hydrodesulphurisation (HDS) catalyst upstream or downstream of the zinc oxide desulphurisation material. The methanation unit comprises one or more methanation vessels connected in parallel or series that contain a methanation catalyst. The methanation catalyst is desirably a nickel or ruthenium methanation catalyst, preferably a particulate nickel containing methanation catalyst, more preferably a precipitated Ni catalyst with a Ni content above 30% by weight, preferably above 40% by weight. The methanation catalyst may be in the form of pellets or extrudates, but may also be a foam, a monolith or a coating on an inert support. Pelleted methanation catalysts are preferred. Such catalysts are available commercially. Particularly suitable precipitated Ni catalyst are CRG catalysts, available from Johnson Matthey PLC. Typically, the methanation catalyst may be operated at an inlet temperature in the range 200-350°C, preferably 200-300 °C, more preferably 230-280 °C. The methanation step reacts the reactants, hydrogen and carbon dioxide (and optionally carbon monoxide), to form methane. A portion of the hydrogen in the feed remains unreacted, because there is an equilibrium limitation on the extent of conversion such that the resultant first methane containing gas mixture of the invention includes residual hydrogen (and carbon dioxide). The methanation reaction is exothermic and the reaction may be performed adiabatically in a fixed catalyst bed in a methanation vessel. The flow through the bed may be axial and / or radial flow. The methanation step may alternatively be operated with cooling of the catalyst bed, e.g. by using a water-cooled methanation reactor. The process includes passing the first methane-containing product gas mixture through a hydrogen removal unit to adjust the hydrogen content and so bring the product methane containing product gas within specification. This is done through a hydrogen removal unit having a bed of an oxidation catalyst over which the first methane containing product gas mixture and an oxygen containing stream is passed. The reaction is an oxidation reaction which is exothermic. The reaction follows the following two general formulas: 2 H2 + O2 -■> 2 H2O 2 CQ + • 2 CO2 The hydrogen removal unit produces a hydrogen depleted methane containing gas mixture. The oxygen containing gas may be air, enriched air having an O2 content above 25% by volume, or an oxygen gas stream containing at least 80%, or at least 90% or at least 95% vol O2. The oxygen containing gas stream may be an oxygen stream recovered from an air separation unit but preferably the oxygen-containing gas stream is produced by the electrolysis of water. Hence in a preferred arrangement the hydrogen containing gas and the oxygen containing gas are provided by an electrolysis unit. The amount of oxygen to be passed to the hydrogen removal unit is calculated based on the measured hydrogen content of the first methane containing product gas mixture. Ordinarily, to ensure a high conversion of hydrogen by oxidation, over an oxidation catalyst, the oxygen containing stream may be added in stoichiometric excess to a methane containing product gas mixture in order to ensure the oxidation of hydrogen (and any carbon monoxide) takes place as fully as possible. However, in the present invention, wherein the concentration of hydrogen in the first methane-containing product gas mixture fluctuates (due to an upstream fluctuation of hydrogen forming part of the feed gas mixture) it is necessary to control and adjust the flowrate of an oxygen containing stream since too much oxygen passed to the hydrogen removal unit may result in unwanted side reactions and too little oxygen in the hydrogen removal unit may result in a lower conversion of hydrogen and ultimately a methane containing gas mixture product which is not on-specification. The amount of oxygen to be passed to the hydrogen removal unit is calculated based on the measured hydrogen content of the first methane containing product gas mixture. Accordingly, the flowrate of the oxygen containing stream into the hydrogen removal unit is adjusted, prior to combining it with the first methane containing product gas mixture, to form a second methane containing gas mixture, with reference to a measured concentration of hydrogen in the first methane containing product gas mixture. The flowrate of the oxygen containing stream will also have to be controlled and adjusted with reference to the temperature in the hydrogen removal unit as too high a temperature will result in the unwanted oxidation of the methane in the second methane containing gas mixture which is undesirable. The measurement of the concentration of hydrogen upstream of the hydrogen removal unit is performed by an on-line analyser coupled to a management control module comprising analyser controllers, flow ratio controllers and flow controllers. The flow controllers may be in communication with pneumatic valves that control the flow of oxygen. In one embodiment of the invention the hydrogen removal unit comprises a first oxidation reactor and a second oxidation reactor, connected in series, each reactor containing a bed of oxidation catalyst Having two oxidation reactors provides operational flexibility and control to prevent overheating and damage to the oxidation catalyst and reactors. Depending on the measured concentration of hydrogen in the first methane containing product gas, and the predicted exotherm, the flows of the oxygen containing stream into the first oxidation reactor and second oxidation reactor may be adjusted. For example, where the hydrogen content is such that the predicted exotherm in the first oxidation reactor provides an exit temperature below about 400 °C no oxygen gas may need to be fed to the second oxidation reactor. If the hydrogen content is such that the exit temperature is estimated to be above about 400 °C, then the amount of oxygen to the first oxidation reactor may be limited and the remaining oxygen to achieve the desired hydrogen removal fed to the second oxidation reactor. The measurements are conduct in real-time as are the adjustments The oxidation catalyst used in the hydrogen removal unit (and hence the oxidation reactors) is preferably a supported precious metal catalyst. For example, the catalyst may comprise one or more of Pt, Pd, Rh, Ir or Ru at 0.1 to 5% by weight on an oxidic support such as alumina, titania, zirconia or silica. Preferably the catalyst comprises Pt or Pd on alumina, e.g. <5% wt Pt on alumina. The oxidation catalyst may be in the form of a woven, nonwoven or knitted mesh, tablets, pellets or extrudates, a foam, monolith or coating on an inert support. The precious metal oxidation catalyst is preferably a 0.1 to 5% wt platinum on alumina catalyst, such as PURAVOC™ 73, available from Johnson Matthey PLC, but other supported precious metal catalysts may be used. The oxidation catalyst may be operated at an inlet temperature, to the hydrogen removal unit, or each of the oxidation reactors, in the range from 150 to 350°C and an exit temperature therefrom may be between 150 to 400°C. The oxidation reaction is exothermic, and the reaction may be performed adiabatically in a fixed bed selective oxidation vessel. The flow through the bed may be axial and / or radial flow. The selective oxidation step may alternatively be operated with cooling of the catalyst bed. Both the methanation and oxidation catalysts are preferably used in the form of pellets or extrudates with a diameter or width in the range 2-10 mm and an aspect ratio, i.e. length / diameter or width in the range 0.5 to 4. The gas hourly space velocity (GHSV) of the first and / or second methane-containing gas mixtures through the catalyst beds may be in the range 2000 to 20000hr1. The process, including the methanation step and the oxidation step(s), is or are desirably performed at a pressure in the range 5 to 80 bar abs. The third methane-containing product gas mixture recovered from the hydrogen removal unit may be further processed, including drying to remove any water contained therein and / or carbon dioxide removal. The drying may be performed by cooling the third methane-containing product gas mixture to below the dew point and collecting the liquid condensate, optionally with further drying over molecular sieves. Should the carbon dioxide content of the hydrogen depleted third methane containing gas mixture recovered from the hydrogen removal unit be in excess of that desired in the product, it is desirably further processed through a carbon dioxide removal unit. The carbon dioxide removal unit may be used to produce a product methanated gas with a carbon dioxide content below 5 mol%. The carbon dioxide removal in the carbon dioxide removal unit may be accomplished using solvent or amine-wash, or caustic-wash techniques known in the art. Alternatively pressure-swing adsorption may be used. In a preferred form of the invention carbon dioxide removal unit operates by means of chemical absorption using an alkanolamine or alkaline salt carbon dioxide removal process. The carbon dioxide recovered from the carbon dioxide removal unit may be recycled to the first feed gas mixture. According to another aspect of the invention, there is provided a system for producing a methane containing product gas mixture according to the claimed process, comprising: (a) a mixing unit for combining a hydrogen-containing feed gas and a feed gas containing carbon oxides in response to a measured flowrate of the hydrogen-containing feed gas, configured to provide a feed gas mixture having a composition with a stoichiometric ratio of reactants having a value M of about 3, where M =;— ’ [CO] + [CO2] (b) a methanation unit comprising a methanation catalyst configured to methanate the feed gas mixture to form a first methane containing gas mixture, and (c) a hydrogen removal unit comprising an oxidation catalyst configured to combine the first methane containing product gas with an oxygen containing stream to form a second methane containing gas mixture and pass the second methane-containing gas mixture over the oxidation catalyst to oxidise hydrogen and form a hydrogen depleted third methane containing product gas mixture comprising a total of less than 5 mole% hydrogen; wherein the system further comprises an electrolysis unit configured to electrolyse water to produce the hydrogen-containing gas. In a preferred arrangement the electrolysis unit is configured to electrolyse water to produce both the hydrogen-containing gas and the oxygen containing stream. In an embodiment of the system, the electrolysis of the water is performed using one or more sources of renewable energy. A purification unit may be provided to desulphurised the supply of gas containing carbon oxides. The hydrogen removal unit may comprise first and second oxidation reactors in series, each reactor containing a bed of oxidation catalyst and configured to operate each reactor with an exit temperature below about 400 °C. The system may further comprise a drying unit as described above configured to dry the hydrogen depleted third methane containing gas mixture. The system may further comprise a carbon dioxide removal unit as described above configured to remove carbon dioxide and produce a product methanated gas with a carbon dioxide content below 5 mol%. The system may further comprise one or more of the following; (a) a capacity management control system as described above, to regulate the flowrate of the hydrogen containing gas stream and the flowrate of the carbon oxide containing gas stream to achieve the target M-value of 3; (b) analyser controllers, to analyse the concentration of hydrogen in the feed gas mixture, the first methane containing product gas mixture and the third methane containing product gas mixture; and (c) flow ratio controllers, flow controllers, and valves in order to regulate and adjust the flow rate of the carbon oxide containing gas stream and the oxygen containing stream. DETAILED DESCRIPTION OF THE INVENTION The invention is further illustrated by reference to the accompanying figure: FIGURES Figure 1: is a depiction of a flowsheet of one embodiment of the invention. In Figure 1, a feed stream of water, line 10, is fed into an electrolysis unit 12 to produce a hydrogencontaining gas recovered in line 14 and an oxygen containing stream recovered in line 16. The electrolysis unit 12 is powered by a renewable energy source such as solar panels and / or wind farms (not shown). The rate at which the water 10 is electrolysed is dependent upon the amount of power provided by the renewable energy source to the electrolysis unit 12 and the fluctuations in the provision of said power to the electrolysis unit 12. A parallel supply of a carbon dioxide gas stream is fed via line 18 to purification unit 20 comprising a purification vessel containing a sulphur compound adsorbent. Sulphur compounds present in the carbon dioxide are removed and a purified carbon dioxide stream is recovered from the purification unit 20 via line 22. The hydrogen stream 18 and purified carbon dioxide stream 22 are passed to a mixing system 24 where they are combined to form a feed gas. The mixing system includes feed flow control and a capacity management including a hydrogen flowrate measurement device and a flow ratio controller that controls the amount of carbon dioxide gas 18 mixed with the hydrogen stream 22 to achieve a target stoichiometry value M of about 3. The flowrates of carbon dioxide and hydrogen fed to the process are adjusted by means of valves in lines 14 and 22 (not shown). Optionally a gas analyser is provided downstream of the mixing unit 24 to measure the feed gas composition, preferably the hydrogen content, which is communicated to the capacity management control system to fine tune the stoichiometry of the feed gas and achieve target M-value of 3. The feed-gas mixture in line 26 is passed through a methanation unit 28. The inlet temperature of the feed-gas mixture in line 30 is about 250°C to 350°C at an absolute pressure of 5-80 bars. The methanation unit 28 is comprises one, two or more methanation vessels each containing a bed of methanation catalyst, connected in series or parallel. The methanation catalyst is a particulate Ni containing methanation catalyst such as Katalco™ CRG available from Johnson Matthey PLC. The synthesis of methane occurs in the methanation unit 28 to form a first methane containing product gas mixture in line 30, recovered from the methanation unit 28 and comprises methane, residual carbon dioxide and residual hydrogen. The methanation unit 28 is configured to control an exit temperature of the first methane containing product gas mixture in line 38 at in the range of 500 to 650 °C. Immediately down-stream of the methanation unit 28, the hydrogen concentration in the first methane containing gas mixture in line 30 is measured. This measurement is made in real time through an analyser control module 32 coupled to the line 30. The analyser control module 32 comprises a Raman gas analyser to analyse the concentration of hydrogen in the first methane containing gas mixture. The analyser control module 32 is in communication shown via dashed line 34 with an oxygen flow control module 36 comprising a computing device, which may be part of a distributed control system, and a flow ratio controller. The flow ratio controller is in communication with a flow controller which regulates, through a valve (not shown), the flow of the oxygen containing stream 16 via line 38 into a hydrogen removal unit 40. The first methane-containing product gas mixture in line 30 is passed from the analyser control module 32 into the hydrogen removal unit 40. The hydrogen removal unit 40 comprises a first oxidation reactor and a optionally a second oxidation reactor connected in series (not shown). In the hydrogen removal unit 40, the oxygen in line 38 is combined with the first methane containing gas mixture from line 30 to form a second methane containing gas mixture in an oxidation reactor to produce the hydrogen depleted third methane containing gas mixture. Immediately downstream of the oxidation reactor in the hydrogen removal unit 40, the composition of the hydrogen depleted third methane containing product gas mixture is analysed by means of an on-line gas analyser (not shown). If the hydrogen content is above the desired level, e.g. more than 5 mol%, the product gas may be subjected to a further step of hydrogen removal in a second oxidation reactor fed with a further portion of the oxygen from line 16. If the composition contains . 5 mol% H2 or less, the hydrogen depleted third methane containing gas mixture may be recovered from the hydrogen removal unit 40 by line 42. If desired the hydrogen depleted third methane containing product gas mixture recovered in line 42 may be cooled in heat exchange with water and / or air to below the dew point (not shown) and condensate recovered to produce a dewatered product methane gas. If the on-line gas analyser measures a carbon dioxide content in the third methane containing product gas mixture above 5 mol%, it is fed via line 44 to a CO2 removal unit 46, where it is cooled and subjected to treatment with a liquid absorbent to remove CO2. The unit 46 preferably operates by chemical absorption using an alkanolamine or alkaline salt carbon dioxide removal process. The CO2 is recovered from the CO2 removal unit via line 48 and may be recycled to the purified carbon dioxide feed line 22. The CO2 removal unit 46 removes excess CO2 from the third methane containing gas mixture to 5 mol%, or lower, to produce a methane containing product gas mixture comprising a total of less than 5 mole% hydrogen and carbon dioxide., which is recovered from the CO2 removal unit via line 50. It will be understood by those skilled in the art that the figure hereto is diagrammatic and that further items of equipment such as feedstock drums, pumps, vacuum pumps, compressors, gas recycling compressors, pressure sensors, pressure relief valves, control valves, level controllers, holding tanks, storage tanks and the like may be required in a commercial plant. Provision of such ancillary equipment forms no part of the present invention and is in accordance with conventional chemical engineering practice.

Claims

1. A process for producing a methane containing product gas mixture comprising the steps of:(a) providing a hydrogen containing feed gas stream;(b) providing a carbon oxide containing feed gas stream containing carbon dioxide and optionally carbon monoxide;(c) measuring the flow-rate of the hydrogen containing feed gas stream and adjusting the flowrate of the carbon oxide containing feed gas stream, relative to of the flowrate of the hydrogen in the hydrogen containing feed gas stream to produce a feed gas mixture having a composition with a stoichiometric ratio of reactants having a value M of about 3, where M = 7——i;(d) passing the feed gas mixture through one or more beds of methanation catalyst, in a methanation unit, to react a portion of the hydrogen with at least a portion of the carbon dioxide and any carbon monoxide to form a first methane containing product gas mixture including residual hydrogen and residual carbon dioxide;(e) measuring the concentration of residual hydrogen of the first methane containing product gas mixture; and combining the first methane containing product gas mixture with an oxygen containing stream, wherein the flow rate of the oxygen containing stream is adjusted relative to the measured concentration of residual hydrogen in the first methane containing gas mixture, so as to produce a second methane containing gas mixture which is passed through a bed of an oxidation catalyst in a hydrogen removal unit to form a hydrogen depleted third methane containing product gas mixture; comprising a total of less than 5 mole% hydrogen; wherein the hydrogen containing gas stream is produced by electrolysis of water.

2. The process of claim 1, wherein and the hydrogen containing gas stream and the oxygen containing stream are produced by electrolysis of water.

3. The process of claim 1 or claim 2, wherein the electrolysis of water is performed using one or more sources of renewable energy.

4. The process of any one of claims 1 to 3, wherein the carbon oxide containing feed gas stream is a carbon dioxide gas stream recovered from CO2 storage or from upstream processes..

5. The process of any one of claims 1 to 4, wherein, the third methane containing product gas mixture is passed through a carbon dioxide removal unit subsequent to being passed through the hydrogen removal unit.

6. The process of claim 5, wherein the carbon dioxide removal unit operates by means of chemical absorption using an alkanolamine or alkaline salt carbon dioxide removal process.

7. The process of any one of claims 1 to 6, wherein the hydrogen removal unit comprises a first oxidation reactor and a second oxidation reactor connected in series, each containing a bed of oxidation catalyst.

8. The process of any one of claims 1 to 7, wherein the hydrogen containing feed gas stream is subject to a purification step to remove catalyst poisons prior to passing through the methanation unit.

9. The process of any one of claims 1 to 8, wherein the carbon oxide containing feed gas stream is subject to one or more desulphurisation and purification steps prior to passing through the methanation unit.

10. A system for producing a methane containing product gas mixture according to the process of any one of claims 1 to 9, comprising:(a) a mixing unit for combining a hydrogen-containing feed gas and a feed gas containing carbon oxides in response to a measured flowrate of the hydrogen-containing feed gas, configured to provide a feed gas mixture having a composition with a stoichiometric ratio of reactants having a value M of about 3, where M =;———i;;’ [CO] + [CO2]”(b) a methanation unit comprising one or more beds of methanation catalyst configured to methanate the feed gas mixture to form a first methane containing product gas mixture, and(c) a hydrogen removal unit comprising an oxidation catalyst configured to combine the first methane containing product gas with an oxygen containing stream to form a second methane containing gas mixture and pass the second methane-containing gas mixture over the oxidation catalyst to oxidise hydrogen and form a hydrogen depleted third methane containing product gas mixture comprising a total of less than 5 mole% hydrogen;wherein the system further comprises an electrolysis unit configured to electrolyse water to produce the hydrogen-containing gas.

11. The system of claim 10, wherein the electrolysis unit is configured to electrolyse water to produce the hydrogen-containing gas and the oxygen containing stream.

12. The system of claim 10 or claim 11 further comprising a drying unit configured to dry the hydrogen depleted third methane containing product gas mixture.

13. The system of claim 10 or claim 11 further comprising a carbon dioxide removal unit configured to remove carbon dioxide and produce a product methanated gas with a carbon dioxide content below 5 mol%.

14. The system of any one of claims 10 to 13, wherein the hydrogen removal unit comprises first and second oxidation reactors in series,15. The system of any one of claims 10 to 14 further comprising one or more of:(a) a capacity management control system, to regulate the flowrate of the hydrogen containing feed gas stream and the flowrate of the carbon oxide containing feed gas stream;(b) analyser controllers, to analyse the concentration of hydrogen and carbon oxides in the feed gas mixture, the first methane containing product gas mixture and the third methane containing product gas mixture; and(c) computing devices, flow ratio controllers, flow controllers, and valves in order to regulate and adjust the flowrate of the carbon oxide containing gas stream and the oxygen containing stream.

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