Cleaning of co 2 rich feed gas

Abstract

Process and plant for cleaning a CO2 rich gas feed (101). The process comprises the steps of: optionally adding an oxidant gas (103) to the CO2 rich gas feed (101) to form a CO2-rich gas feed / oxidant gas mixture (105), supplying the CO2 rich gas feed / oxidant gas mixture (105) to a catalytic oxidation (CATOX) step (112), and producing a first raw cleaned CO2-rich gas (107); adding a reducing gas (109) to the first raw cleaned CO2-rich gas (107) to form a first raw cleaned CO2-rich gas / reducing gas mixture (111); supplying the first raw cleaned CO2-rich gas / reducing gas mixture (111) to a deoxygenation (DEOXO) step (114), and producing a second raw cleaned CO2-rich gas (113); supplying the second raw cleaned CO2-rich gas (113) to at least one of: a sulfur removal step and an optional nitrogen removal step (116), and producing a cleaned CO2-rich gas (115').

Description

[0001] CLEANING OF CO2RICH FEED GAS

[0002] TECHNICAL FIELD

[0003] The present invention relates to a process and plant for cleaning a CO2rich gas feed, in particular for removing sulfur-containing impurities, carbon / hydrogen / oxygen impurities such as any of hydrocarbons, alcohols and aromatic hydrocarbons, and optionally nitrogencontaining impurities.

[0004] BACKGROUND

[0005] Carbon dioxide (CO2) is commercially available in different grades. Typically, “food grade” or “beverage grade” CO2has a purity of 99.9%. However, for processes involving catalytic conversion of CO2to other chemical products (e.g. power-to-X), impurities such as sulfur- containing compounds in the CO2stream may poison the synthesis catalyst, even when present at concentrations of 0.00001 % (100 ppb) or even lower. Oxygen (O2) will only rarely be an actual poison for the catalyst, but the ability to oxidize the catalyst materials may lead to structural damage to the catalyst leading to mechanical or catalytic degradation if present in higher concentrations, e.g. higher than 100 ppm.

[0006] For the production of renewable fuels or electrofuels (e-fuels), such as renewable natural gas (RNG) or interchangeably e-natural gas (e-NG), in which the CO2rich gas is derived from renewable sources and / or hydrogen utilized in the production of synthesis gas (syngas) is generated from water / steam electrolysis, there is a need to purify the CO2rich feed gas stream such that catalysts utilized in the synthesis of the e-fuel do not suffer from premature deactivation / poisoning.

[0007] The so-called “Northern Light CO2specification” seems to become the "standard" for the CO2to be traded on the market and thus a demanding challenge has emerged in that there is now a need to be able to purify a CO2rich feed gas stream based on that specification. The specification contains sulfur and nitrogen containing impurities along with a large number of different carbon / hydrogen / oxygen containing impurities such as hydrocarbons having at least two carbon atoms as well as aromatic compounds which may be carried as volatile organic compounds (VOC), alcohols, and other compounds, so that it is almost impossible to design a process or system which individually can remove these species. The present application addresses this problem and provides a robust process and plant (system) which oxidizes all these compounds to CO2 and H2O, thus being independent on the actual composition of these impurities, and then deal with the sulfur and / or nitrogen containing impurities downstream the above-mentioned oxidation.

[0008] Related prior art is found EP 0952111 A1 as well as in applicant’s WO 2022 / 318319, WO2024218391 and WO2024218319.

[0009] It has been discovered that significant purification is required to avoid catalyst poisoning or degradation of downstream synthesis catalysts.

[0010] Thus, so far this has been dealt with by removing a single or few impurities at a time, such as a sulfur and / or oxygen impurity, and the process and associated system designed accordingly, but for a specific and highly demanding CO2 specification such as the Northern Light CO2 specification, this is practically impossible.

[0011] SUMMARY

[0012] In a first aspect, the invention relates to a process for cleaning a CCh-rich gas feed, said CC>2-rich gas feed comprising:

[0013] - at least 80 vol.% CO2;

[0014] - one or more sulfur containing impurities;

[0015] - one or more carbon / hydrogen / oxygen containing impurities optionally comprising hydrocarbons having at least two carbon atoms and / or aromatic hydrocarbons;

[0016] - optionally one or more nitrogen containing impurities; wherein said process comprises the steps of: i-1):

[0017] - supplying the CCh-rich gas feed to a catalytic oxidation (CATOX) step and producing a first raw cleaned CO2-rich gas, in which the first raw cleaned CO2-rich gas has a lower content of carbon / hydrogen / oxygen containing impurities than the CO2-rich gas feed; or i-2) - adding an oxidant gas to the CO2 rich gas feed to form a CCh-rich gas feed / oxidant gas mixture, supplying the CO2 rich gas feed / oxidant gas mixture to a catalytic oxidation (CATOX) step, and producing a first raw cleaned CO2-rich gas, in which the first raw cleaned CO2-rich gas has a lower content of carbon / hydrogen / oxygen containing impurities than the CO2-rich gas feed or than the CO2 rich gas feed / oxidant gas mixture; ii-1):

[0018] -adding a reducing gas to the first raw cleaned CO2-rich gas to form a first raw cleaned CO2- rich gas / reducing gas mixture;

[0019] - supplying the first raw cleaned CO2-rich gas / reducing gas mixture to a deoxygenation (DEOXO) step, and producing a second raw cleaned CO2-rich gas, in which the second raw cleaned CO2-rich gas has a lower content of oxygen than the first raw cleaned CO2-rich gas or than the first raw cleaned CO2-rich gas / reducing gas mixture;

[0020] - supplying the second raw cleaned CO2-rich gas to a sulfur removal step and an optional nitrogen removal step, and producing a cleaned CO2-rich gas, in which the cleaned CO2-rich gas has a lower content of sulfur containing impurities and optionally a lower content of nitrogen containing impurities than the second raw cleaned CCh-rich gas; or ii-2):

[0021] - supplying the first raw cleaned CCh-rich gas to a sulfur removal step and an optional nitrogen removal step, and producing a second raw cleaned CO2-rich gas, in which the second raw cleaned CCh-rich gas has a lower content of sulfur containing impurities and optionally a lower content of nitrogen containing impurities than the first raw cleaned CO2- rich gas;

[0022] - adding a reducing gas to the second raw cleaned CCh-rich gas to form a second raw cleaned CCh-rich gas / reducing gas mixture;

[0023] - supplying the second raw cleaned CCh-rich gas / reducing gas mixture to a deoxygenation (DEOXO) step, and producing a cleaned CO2-rich gas, in which the cleaned CO2-rich gas has a lower content of oxygen than the second raw cleaned CO2-rich gas or than the second raw cleaned CO2-rich gas / reducing gas mixture.

[0024] Accordingly, while in step ii-1) a reducing gas, such as hydrogen, is added to the first raw cleaned CO2-rich gas, in step ii-2) the reducing agent is added farther downstream, namely to the second raw cleaned CO2-rich gas. It is understood that the term “supplying the CO2 rich gas feed to a catalytic oxidation (CATOX) step” means directly supplying or indirectly supplying the CO2 rich gas feed to a catalytic oxidation (CATOX) step. The same interpretation applies when a given stream is supplied to a given step.

[0025] The term “directly” means that there are no units or process steps changing the composition of the associated gas, here the CO2 rich gas feed / oxidant gas mixture. Conversely, the term “indirectly” means that there is a unit or process step changing the composition of the associated gas. In connection with a plant (system) embodiment, the term “directly supplied” means that the associated units are in “direct fluid communication”. The term “indirectly supplied” means that the associated units are in “indirect fluid communication”.

[0026] Preferably, all the supplied streams in connection with any of the above or below embodiments, is understood as directly supplied.

[0027] Further, for the purposes of the present application:

[0028] Unless otherwise specified, any given percentages for gas content are % by volume (vol.%). The % by volume is used interchangeably with % by mole. All feeds are preheated as required. Unless specified, the concentrations will be given on dry basis, i.e. without taking any water present into account.

[0029] The term “and / or” means at least one of the associated three options. For instance, the term “methanol and / or ethanol” means: methanol, ethanol, methanol and ethanol. The term “and / or” may be used interchangeably with the term “at least one”,

[0030] The term “present application” or “application” may be used interchangeably with the term “present invention” or “invention”, respectively.

[0031] The term “sulfur-containing impurities” may be used interchangeably with the term “sulfur- containing compounds” or “sulfur compounds”.

[0032] The term “purification” and “cleaning” may be used interchangeably. For instance, the term “purification reactor” which refers to the reactor unit i.e. reactor vessel where the purification takes place, may be used interchangeably with the term “cleaning reactor”. The term “suitably” may be used interchangeably with the term “optionally”, i.e. it refers to an optional embodiment.

[0033] The term “synthesis gas” is used interchangeably with the term “syngas” and means a gas mixture comprising H2, and at least one of: CO2 and CO. For instance, a syngas comprises H2 and CO2; or H2 and CO; or H2, CO2 and CO.

[0034] The term “purification” and “cleaning” may be used interchangeably.

[0035] Other definitions are provided in connection with one or more of above and below embodiments.

[0036] The CATOX step provides a robust "one-fits-all" CO2 cleaning unit, which handles all sorts of impurities found in the CO2-rich feed gas and thus enables streamlining i.e. standardizing the downstream process steps to remove e.g. sulfur and optionally also nitrogen containing impurities.

[0037] By the invention, an oxidant such as oxygen, enriched oxygen or air, is added to the CO2 rich gas feed. The CO2-rich gas feed / oxidant gas mixture is heated to the needed temperature, suitably to 400-500C and supplied to the CATOX step under the presence of a CATOX catalyst to oxidize the many carbon / hydrogen / oxygen impurities to CO2 and H2O. The now well specified semi-purified CO2, herein referred to as first raw cleaned CO2-rich gas, containing residual O2, is then further purified with regard to sulfur and optionally with regard to nitrogen impurities, and the residual O2 is converted to CO2 or H2O by addition of, respectively CO or H2.

[0038] By the invention it is possible to reduce the content of sulfur-containing impurities i.e. sulfur compounds, to well below 1 ppmv, thereby enabling downstream use as syngas for production of e.g. e-fuels. By adding H2 after the CATOX step, O2 is hydrogenated to H2O as explained above, while at the same time SO2 is e.g. converted back to H2S, which is easier captured by retainment materials such as absorbents, than SO2.

[0039] For example, in appended Fig. 1 , in which an embodiment corresponding to step ii-1) is shown, there is a first oxidation in a CATOX step under the presence of a CATOX catalyst after addition of an amount of O2 to the CO2 rich feed gas, and then a removal of the residual O2 by adding an amount of H2 as the reducing gas and supplying the first raw cleaned CCh-rich gas / reducing gas mixture to a DEOXO step under the presence of a hydrogenation catalyst before removing the sulfur impurities.

[0040] Step ii-2) corresponds to an embodiment where the removal of residual O2 in a DEOXO step is conducted after removing the sulfur impurities.

[0041] Sulfur compounds are well-known as catalyst poisons, which react with the active material on the catalysts and render them catalytically inactive. For some catalysts, oxygen (O2) is also a critical substance leading to catalyst degradation and e.g. a downstream Cu-based methanol catalyst is prone to oxidation by oxygen and therefore high concentrations of oxygen present in the CO2 (or H2) feed gases to a methanol plant have to be removed at a position upstream the e.g. methanol catalyst.

[0042] In the production of e-fuels, such as e-NG, or methanol (CH3OH, herein also referred to as MeOH), H2 and CO2 are the most common feed stocks. Both CO2 and H2 feed streams contain impurities, which must be removed before the syngas produced from the H2 and / or CO2 gas is admitted to the downstream synthesis of e-NG in methanation reactor(s) or downstream synthesis of methanol (MeOH) in a methanol synthesis reactor. As recited above, there are many impurities and many ways to purify the feed streams by separating individual components. The present invention describes a simple and effective process and plant layout to cope with this problem.

[0043] A solution would be to purify the H2-rich gas feed and the CO2-rich gas feed individually, and further individual removal of impurities contained in the CO2-rich gas feed and which apart from sulfur containing impurities includes carbon / hydrogen / oxygen containing impurities, and optional nitrogen containing impurities, and then combine the purified streams to a H2+CO2 syngas stream to the green chemicals production plant, such as methanation plant for synthesis of methane, such as e-NG or a MeOH synthesis plant or a Fischer-Tropsch (FT) synthesis plant for production of synthetic fuels. This layout may require a dedicated compressor for each of the feed streams and one for the combined stream. Furthermore, each purification system requires a reactor / absorber and heat exchange system.

[0044] In an embodiment,

[0045] - the oxidant gas is oxygen (O2); and / or

[0046] - the reducing gas is at least one of: hydrogen (H2) and carbon monoxide (CO). The oxidant gas O2 may be sourced from a water / steam electrolysis unit producing hydrogen and oxygen. Suitably the electrolysis is powered by renewable sources such as wind, solar, hydro power, geothermal, thermonuclear energy. The reducing gas H2, which also may be sourced from the water / steam electrolysis, enables to hydrogenate residual O2 to H2O. The reducing gas CO enables to convert residual O2 to CO2. Residual O2 is, in an embodiment, removed by adding H2 and passing the mixture over a hydrogenation catalyst in the DEOXO step either before (step ii-1)) or after (step ii-2)) removing the sulfur impurities.

[0047] In an embodiment,

[0048] - the reducing gas is hydrogen (H2) whereby the cleaned CO2-rich gas produced in step ii-1) or step ii-2) is withdrawn as a first synthesis gas (first syngas).

[0049] As it will also become apparent from one or more of above or below embodiments, sufficient H2 may be provided already in connection with the CO2-cleaning to produce a first syngas having a high volume ratio of H2 to CO2 which is suitable for use downstream as the syngas for at least one of: methanation, methanol synthesis, FT-synthesis.

[0050] The CC>2-rich gas feed provided to the process comprises at least 80 vol.%, such at least 90 vol.% CO2, such as at least 95 vol.% CO2, such as at least 99 vol.% CO2, preferably at least 99.5 vol.% CO2, more preferably at least 99.8 vol.% CO2.

[0051] The CC>2-rich gas feed is thus already of high purity prior to the process of the present invention.

[0052] In an embodiment, in step ii-1) the sulfur removal step comprises: a hydrogenation step to produce at least hydrogenated sulfur impurities such as H2S which are subsequently directly supplied to a sulfur retainment step in a guard material.

[0053] It is understood that in connection with step ii-1), the term “sulfur removal step” is a generic term for sulfur removal which comprises the hydrogenation step and subsequent sulfur retainment step. The sulfur retainment step of step ii-2) is associated with the use of a guard material or vice versa. The guard material is further defined in connection with one or more of below embodiments. In connection with step ii-2), as it will become apparent from one or more of above or below embodiments, the term “sulfur removal step” is provided as a sulfur retainment step conducted in the presence of an activated carbon and / or an alkaline absorbent.

[0054] Hence,

[0055] It is understood that the use of the term “guard material” is associated with step ii-1).

[0056] It is understood that the use of the term “activated carbon and / or an alkaline absorbent” is associated with step ii-2).

[0057] For the purposes of the present application, the term “retainment” or “retaining” or “retained” in connection with step ii-1) or step ii-2), may be used interchangeably with any of the terms: adsorption and / or absorption, or respectively, adsorbed and / or absorbed. The term is also meant to include the chemical binding of a sulfur-containing impurity, such as a sulfur- containing impurity in the guard material, e.g. by forming ZnS, CuS and CU2S.

[0058] In connection with step ii-1), the hydrogenation step is, for instance, conducted in the presence of a hydrogenation catalyst comprising a catalyst capable of converting at least SO2 back to H2S. The H2S, as explained earlier, is then easily removed in the sulfur retainment step in the guard material comprising e.g. ZnO. The sulfur is then removed as ZnS.

[0059] In an embodiment, there is no hydrogenation step prior to the sulfur retainment step in said step ii-1).

[0060] Hence, in step ii-1) the second raw cleaned CCh-rich gas is preferably directly supplied to the sulfur removal step and optional nitrogen removal step.

[0061] Suitably, in step ii-2), there is no hydrogenation step prior to the sulfur removal step, the first raw cleaned CCh-rich gas is preferably directly supplied to the sulfur removal step and optional nitrogen removal step. The reducing gas, preferably H2, is added subsequently.

[0062] Preferably, the optional nitrogen removal step is conducted after the sulfur removal step.

[0063] In an embodiment, - the first raw cleaned CCh-rich gas in step i) comprises 500-3000 ppmv O2, or 500-2000 ppmv O2, or 500-1500 ppmv O2, such as 800-1200 ppmv O2, for instance 900-1100 ppmv O2, or 1000 ppmv O2.

[0064] Thereby, the process is tailored so that the first raw cleaned CO2 rich gas is maintained in the oxidized state, while any addition of the oxidant gas, such as O2, is low enough to avoid high H2 consumption and useless formation of water.

[0065] In an embodiment,

[0066] - the reducing gas is H2, and in step ii-1) the first raw cleaned CCh-rich gas / reducing gas mixture is a raw synthesis gas (raw syngas) having a volume (molar) ratio of H2 to CO2 (H2:CC>2) of at least 2, such as 2-5, for instance 2.5-4.5, or 3-4, such as 3.5-4.

[0067] Thereby, sufficient H2 is added already early in the process to provide the required H2:CO2 ratio for downstream synthesis of e.g. methane or methanol or FT-synthesis. Suitably, all the H2 required for the downstream synthesis is added as said reducing gas. The first raw cleaned CCh-rich gas / reducing gas mixture may thus be regarded as a raw syngas. Later addition of H2 to the cleaned CCh-rich gas i.e. to the first syngas, is thus reduced or eliminated.

[0068] In an embodiment, the process comprises: iii) adding a hydrogen stream to the cleaned CO2-rich gas, such as when the cleaned CO2- rich gas is withdrawn as first syngas, to form a second synthesis gas (second syngas) with a volume (molar) ratio of H2 to CO2 (H2:CO2) of at least 2, such as 2-5, for instance 2.5-4.5, or 3-4, such as 3.5-4.

[0069] This further addition of hydrogen may be utilized, where necessary, to supplement the upstream hydrogen addition as the reducing gas, and / or where the reducing gas upstream is CO.

[0070] This hydrogen is suitably also sourced from water / electrolysis. For instance, a portion of the hydrogen produced from the water / steam electrolysis is supplied as said reducing gas and another portion as the hydrogen stream of step iii).

[0071] Accordingly, in an embodiment the process further comprises: - providing an electrolysis unit being fed with a water / steam feedstock, i.e. water or steam, for producing a hydrogen-rich stream and an oxygen-rich stream;

[0072] - diverting at least a portion of said hydrogen-rich stream, as said reducing gas in step ii-1) or step ii-2); or as said hydrogen stream in step iii); and / or

[0073] - diverting at least a portion of said oxygen-rich stream as said oxidant gas in step i-2).

[0074] Optionally, prior to the addition of the hydrogen stream, a minor stream is diverted from the cleaned CO2-rich gas.

[0075] In an embodiment,

[0076] - any of the raw syngas, the first syngas, and the second syngas comprises: about 25 vol.% CO2 and 75 vol.% H2; or about 20 vol.% CO2 and 80 vol% H2.

[0077] Any of these syngas streams, having about 25 vol.% CO2 and 75 vol.% H2, is suitable for downstream methanol production, preferably as e-methanol, or for downstream production of synthetic fuels by FT synthesis.

[0078] Any of these syngas streams having about 20 vol.% CO2 and 80 vol.% H2, is suitable for downstream methane production, preferably as e-NG.

[0079] For instance, the syngas from which the impurities have been removed, comprises 20 vol.% CO2 and 80 vol% H2. Thereby, the syngas is advantageously conditioned for producing e.g. e-NG via the methanation reaction: CO2 + 4 H2 -> CH4 + 2 H2O. The upstream removal of impurities from the CO2 rich feed gas enables safe operation of the downstream methanation without risking the poisoning of the associated catalysts, i.e. a methanation catalyst.

[0080] Accordingly, in an embodiment, the process further comprises:

[0081] - supplying the first or second syngas to a methanation step and producing a methane (CH4) product comprising at least 90 vol.% CH4, such as at least 95 vol.% CH4 or at least 97 vol.% CH4; preferably, the methanation step comprises supplying the first or second syngas to one or more methanation reactors in the presence of a methanation catalyst, preferably a plurality of methanation reactors arranged in series. More preferably, five methanation reactors are provided with intermediate heat recovery, optionally with removal of water as process condensate from at least one of the fourth and fifth methanation reactors.

[0082] For the purposes of the present invention, the use of the term “one or more”, “at least one” and the use of the indefinite article “a” or “an”, means the singular and plural form. For instance, the term “one or more methanation reactors” may be used interchangeably with the term “a methanation reactor”.

[0083] For the methanation, a nickel-based catalysts is suitably utilized due to its high activity and selectivity towards methane formation. The nickel (Ni)-based catalyst is typically supported on a high-surface-area material, such as alumina (AI2O3) or silica (SiCh), to enhance its stability and dispersion. The methanation reaction is exothermic, thus releasing heat. This heat can cause temperature gradients within the catalyst bed, leading to hot spots and potential catalyst deactivation. To mitigate this issue, catalyst promoters like cerium (Ce), zirconium (Zr), or ruthenium (Ru) may be added to enhance the thermal stability of the catalyst and resistance to carbon deposition.

[0084] The syngas may also be advantageously conditioned for methanol synthesis or for Fischer- Tropsch (FT) synthesis.

[0085] Accordingly,

[0086] In an embodiment, the process further comprises:

[0087] - optionally, supplying the first or second syngas to a reverse water gas shift (RWGS) step in the presence of a catalyst active in RWGS, preferably in an electrically heated reactor for RWGS (e-RWGS), to provide: a modified methanol syngas;

[0088] - supplying the first or second syngas, or the modified methanol syngas to a methanol synthesis step, and producing: a raw methanol product, further optionally removing water from the raw methanol product.

[0089] In an embodiment, the process further comprises:

[0090] - supplying the first or second syngas to a reverse water gas shift (RWGS) step in the presence of a catalyst active in RWGS, preferably in an electrically heated reactor for RWGS (e-RWGS), to provide: a Fischer-Tropsch (FT)-syngas having a H2:CO molar ratio of 1.9-2.1 , preferably 2;

[0091] - supplying the FT-syngas to a FT-synthesis step, and producing a synthetic fuel which is at least one of: aviation fuel, kerosene, gasoline and diesel fuel.

[0092] In an embodiment, a recycle stream from the FT-process, such as FT-tail gas or hydrogenated FT-tail gas, is supplied upstream the RWGS, e.g. upstream the e-RWGS.

[0093] RWGS, methanol synthesis and methanation are well known in the art. For details on e- RWGS, which is a more recent technology, reference is given to e.g. applicant’s WO 2022079098.

[0094] The RWGS increases the CO content in the syngas and further serves to e.g. adjust, the module “M” of the syngas (M=(H2-CO2) / (CO+CO2)) on molar basis, for e.g. downstream methanol synthesis in a methanol converter, or to adjust the H2:CO molar ratio of the FT- syngas. For downstream methanol synthesis, M is preferably 2.0-2.1. For FT-synthesis, the molar ratio of H2to CO in the FT-syngas is about 2.

[0095] For methanol synthesis, a copper-based catalyst is suitably utilized due to its high activity and selectivity towards methanol production. The copper (Cu)-based catalyst is often supported on a high surface area material, such as zinc oxide (ZnO) or alumina (AI2O3), to enhance its stability and dispersion. The support material helps to increase the surface area available for catalytic reactions and provides mechanical strength to the catalyst bed. In addition to copper, catalyst promoters such as zinc (Zn), chromium (Cr), or aluminum (Al) may be added to enhance the catalyst's performance. These promoters can improve the catalytic activity, selectivity, and resistance to deactivation.

[0096] The methanol synthesis reaction is typically carried out under high-pressure conditions, often in the range of 50-100 bar, and at elevated temperatures, typically around 200-300°C. The reaction involves the hydrogenation of carbon monoxide (CO) and carbon dioxide (CO2) to produce methanol (CH3OH).

[0097] For details on FT synthesis, reference is for instance given to Steynberg A. and Dry M.

[0098] “Fischer-Tropsch Technology”, Studies in Surface Sciences and Catalysts, vol. 152. It is understood that the term “synthetic fuel” is at least one of: aviation fuel, kerosone, gasoline and diesel. The aviation fuel may also be sustainable aviation fuel (SAF), i.e. aviation fuel which is produced based on sustainable resources.

[0099] For the purposes of the present application, the term “aviation fuel” is regarded as a different synthetic fuel than “kerosene”. The term “aviation fuel” may be used interchangeably with the term “jet fuel” and includes SAF, in compliance with specific standards for use in jet fuel engines. The term “kerosene” is broader and refers to a flammable hydrocarbon liquid often used as a fuel or solvent.

[0100] In another embodiment, the process comprises converting at least a portion of the methanol to a synthetic fuel via a TIGAS process, which produces gasoline as the synthetic fuel stream. In yet another embodiment, the process comprises converting at least a portion of the methanol to a synthetic fuel via a methanol-to-jet fuel (MTJ) process, which provides at least an aviation fuel, suitably SAF, as the synthetic fuel stream.

[0101] Accordingly, in an embodiment, the process comprises converting at least a portion of the methanol to: gasoline, e.g. via a TIGAS process, or aviation fuel e.g. via a methanol-to-jet fuel (MTJ) process.

[0102] The FT, TIGAS and MTJ processes are well-known in the art.

[0103] In an embodiment, the CO2 rich gas feed is derived from a renewable source by, prior to step i), providing a step selected from:

[0104] - combustion or gasification of a lignocellulosic biomass such as wood products, algae, grass, forestry waste and / or agricultural residue;

[0105] - combustion or gasification of municipal waste, in particular the organic portion thereof, where the municipal waste is defined as a feedstock containing materials of items discarded by the public, such as mixed municipal waste given in Ell Directive 2018 / 2001 (RED II), Annex IX, part A;

[0106] - microbial conversion of nitrogen-rich renewable feedstock such as manure or sewage sludge;

[0107] - fermentation of hydrocarbon(sugar) rich feed streams such as corn, sugar cane and beets;

[0108] - Direct Air Capture (DAC). A biogenic feed comprising the CO2 is thus provided, thus enabling the downstream production of e.g. natural gas renewable natural gas (RNG). The term “green natural gas” may then also be associated with the produced NG. Similarly, where the product downstream is for instance methanol, it may be regarded as “green methanol”.

[0109] For the purposes of the present application, as at least hydrogen utilized in the process can be produced from water / steam electrolysis powered by renewable sources, the term “e-fuel” such as e-NG may be used interchangeably with the term “renewable fuel” or “green fuel” such as RNG.

[0110] In an embodiment, the CO2-rich gas feed can also be obtained from said direct air capture (DAC) processes, metallurgical processes, cement production or fossil fuel combustion. The CO2 concentration in most of the above-mentioned gas streams may typically be too low for further chemical processing and a concentration step is required to increase the CO2 concentration to the desired value as mentioned above.

[0111] This concentration step is often called a carbon capture process, and the process can take several forms. The most commonly used process includes an absorption step in which the CO2 is absorbed into an alkaline liquid and the CO2 loaded liquid is passed to a desorbing step in which the CO2 is desorbed from the alkaline liquid, producing a concentrated CO2 stream and a CO2 depleted alkaline liquid, which is then returned to the absorption step.

[0112] In e.g. combustion processes, the flue gas from a furnace / boiler will, besides CO2, SO2, N2, H2O, O2, also contain relatively low concentrations of NOx, originating from fuel-bound nitrogen and / or from N2 in the atmosphere. Depending on the cleaning steps of the flue gas and the degree of carryover and retainment in the carbon capture process (concentration step), the CO2 rich stream can contain both O2, SO2 and NOx.

[0113] NOx typically describes both NO, NO2 and N2O, which are the species normally found in combustion processes. NO is typically the dominant species in the combustion process but may not be it in the CO2-rich gas stream as NO is poorly soluble in the aqueous solutions of the carbon capture process, whereas NO2 is much more soluble and thus easier transported to the CO2 rich gas stream.

[0114] The guard material as further described in the present invention is capable of hydrogenating O2 and reducing SO2 to H2S by means of reaction with H2 and thus NOx may also become hydrogenated / reduced on the guard material. Those reactions are: NO + 2.5 H2 -> NH3 + H2O; NO2+ 3.5 H2-> NH3+ 2 H2O; N2O + 4 H2-> 2 NH3+ H2O.

[0115] From these chemical reactions, it is observed that both water and ammonia may be formed on the guard material. Neither water nor ammonia are retained on the guard material and therefore they may become part of the cleaned H2-and-CO2 rich gas stream. The NH3can under certain conditions become an issue as CO2, H2O and NH3can react and form ammonium bicarbonate (NF HCCh) and / or ammonium carbamate (NH4COONH2), or methyl amines, which can solidify and result in (local) plugging, corrosion and fouling. This typically takes place at high pressure and low temperature.

[0116] If deemed necessary, the NH3can be removed from the CO2 rich feed gas stream by means of e.g. a water washing or a water condensation step, where the readily soluble NH3is transferred from the gas phase to the liquid phase and will leave the process via the aqueous stream i.e. condensate stream.

[0117] As already described, the H2 used in the process, e.g in the hydrogenation and / or when forming the syngas downstream, is preferably derived from a renewable source, such as electrolysis of water / steam powered by any of: wind, solar, hydro power, geothermal, thermonuclear energy. For instance, in connection with appended Fig. 2, the hydrogen added as streams 109, 109’ and 109” may be derived from the same source, preferably hydrogen produced from water / steam electrolysis.

[0118] In another embodiment, at least part of the H2 used in the process is derived from a reforming unit after further hydrogen enrichment such as after water-gas shift (WGS) and hydrogen purification e.g. in a pressure swing adsorption (PSA) unit and / or a membrane unit. The reforming unit is supplied with a hydrocarbon gas feed or a pre-reformed hydrocarbon gas feed. The hydrocarbon gas feed is for instance natural gas.

[0119] For the purposes of the present application, the term “at least part” or interchangeably “at least a portion” of a given item, such as a given process stream, or a conduit carrying the process stream, means a portion of the item or the entire item.

[0120] In an embodiment,

[0121] - the CO2 rich gas feed comprises: at least 97 vol.% CO2, such as at least 99 vol.% CO2; - the sulfur containing impurities in the CO2 rich gas feed are less than 30 ppmv, such as less than 20 ppmv;

[0122] - the carbon / hydrogen / oxygen containing impurities comprise alcohols such as methanol and / or ethanol;

[0123] - the carbon / hydrogen / oxygen containing impurities in the CO2 rich gas feed are less than 2000 ppmv, such as less than 1000 ppmv.

[0124] In an embodiment,

[0125] - the CO2 rich gas feed comprises:

[0126] - at least 99 vol.% CO2;

[0127] - no more than 30 ppm-mol (ppmv) water (H2O);

[0128] - no more than 10 ppmv oxygen (O2);

[0129] - no more than 50 ppmv hydrogen (H2);

[0130] - no more than 100 ppmv carbon monoxide (CO);

[0131] - the sulfur containing impurities are sulfur oxides (SOx) and hydrogen sulfide (H2S), and the CO2 rich gas feed comprises:

[0132] - no more than 10 ppmv SOX;

[0133] - no more than 9 ppmv H2S;

[0134] - the nitrogen containing impurities are nitrogen oxides (NOX), ammonia (NH3), optionally amines, optionally nitrogen (N2), and the CO2 rich gas feed comprises:

[0135] - no more than 1 .5 ppmv NOX;

[0136] - no more than 10 ppmv NH3;

[0137] - optionally, no more than 10 ppmv amines;

[0138] - optionally, no more than 50 ppmv N2.

[0139] This is in compliance with the so-called Northern Light CO2 specification, discussed farther above.

[0140] In an embodiment,

[0141] - the sulfur-containing impurities are one or more compounds selected from: SO2, COS, CS2, DMS and H2S.

[0142] In an embodiment,

[0143] - the hydrocarbons having at least two carbon atoms are selected from: C2-C6 alkanes, C2- Ce alkenes, C2-C6 alkynes, and combinations thereof; and / or

[0144] - the aromatic hydrocarbons are selected from: Ce-Cs aromatic hydrocarbons, C9-C12 aromatics hydrocarbons, and combinations thereof.

[0145] Combinations of the above embodiments are also envisaged.

[0146] For instance, in an embodiment:

[0147] - the sulfur-containing impurities are one or more compounds selected from SO2, COS, CS2, DMS and H2S, for instance H2S;

[0148] - the hydrocarbons having at least two carbon atoms are selected from: C2-C6 alkanes, C2- Ce alkenes, C2-C6 alkynes, and combinations thereof;

[0149] - the aromatic hydrocarbons are selected from: Ce-Cs aromatic hydrocarbons, C9-C12 aromatics hydrocarbons, and combinations thereof.

[0150] By the invention, the cleaned CO2-rich gas has a content of said impurities which is significantly lower than in the CO2 rich gas feed, as well as more CO2 molecules in the cleaned CCh-rich gas than in the CO2 rich gas feed by virtue of oxidation of the hydrocarbons having at least two carbon atoms i.e. higher hydrocarbons.

[0151] The term “the cleaned CCh-rich gas has a content of said impurities which is significantly lower than in the CO2 rich feed gas” means that the impurities are substantially removed so that in the cleaned (purified) CO2 rich gas, i.e. the outlet stream from the CO2 cleaning process, at least 95% of the combined sulfur containing impurities, nitrogen containing impurities and carbon / hydrogen / oxygen containing impurities in the CO2 rich gas feed, are removed; or the sum of sulfur containing impurities, optional nitrogen containing impurities and carbon / hydrogen / oxygen containing impurities in the cleaned CO2 rich gas, is lower than 200 ppm, or lower than 100 ppm.

[0152] In an embodiment, the cleaned CCh-rich gas comprises less than 100 ppbv (parts per billion by volume) sulfur, or less than 50 ppbv sulfur, or less than 10 ppbv sulfur, preferably less than 5 ppbv sulfur, most preferably less than 1 ppbv sulfur.

[0153] The sum of sulfur containing impurities should be understood as sulfur equivalents, i.e. 10 ppbv SO2 correspond to 10 ppbv sulfur and 10 ppbv CS2 correspond to 20 ppbv sulfur.

[0154] The same interpretation applies to the optional nitrogen containing impurities. In an embodiment, the cleaned CCh-rich gas comprises less than 100 ppm, preferably less than 50 ppm, more preferably less than 10 ppm hydrocarbons having at least two carbon atoms i.e. higher hydrocarbons.

[0155] In an embodiment, the cleaned CCh-rich gas comprises less than 10 ppm, preferably less than 5 ppm and most preferably less than 1 ppm aromatic hydrocarbons.

[0156] In an embodiment, the cleaned CCh-rich gas comprises less than 10 ppm, preferably less than 1 ppm and most preferably less than 0.1 ppm alcohols.

[0157] Preferably the alcohols are methanol and / or ethanol.

[0158] Combinations of the above embodiments is also envisaged.

[0159] For instance, in an embodiment:

[0160] -the cleaned CCh-rich gas comprises less than 50 ppbv, preferably less than 10 ppbv and most preferably less than 5 ppbv sulfur;

[0161] - the cleaned CCh-rich gas comprises less than 100 ppm, preferably less than 50 ppm, more preferably less than 10 ppm hydrocarbons having at least two carbon atoms i.e. higher hydrocarbons;

[0162] - the cleaned CCh-rich gas comprises less than 10 ppm, preferably less than 5 ppm and most preferably less than 1 ppm aromatic hydrocarbons;

[0163] - the cleaned CCh-rich gas comprises less than 10 ppm, preferably less than 1 ppm and most preferably less than 0.1 ppm alcohols.

[0164] In an embodiment,

[0165] - the CATOX step is conducted in a reactor unit i.e. reactor vessel comprising a catalyst, in which the catalyst is selected from: tungsten, vanadium, molybdenum, platinum and palladium in metallic and / or in metal oxide form supported on a carrier; or from vanadium, tungsten, chromium, copper, manganese, molybdenum, platinum, palladium, rhodium or ruthenium in metallic and / or metal oxide form supported on a carrier selected from alumina, titania, silica and ceria and combinations thereof;

[0166] - the DEOXO step is conducted in an 02-hydrogenation reaction zone comprising a hydrogenation catalyst; - wherein the hydrogenation catalyst comprises an alumina and / or silica carrier impregnated with a metal, such as: Cu, Mn, Pt, Pd, or combinations thereof; or

[0167] - wherein the hydrogenation catalyst comprises a Cu / Zn / AI based material; or

[0168] - wherein the Ch-hydrogenation reaction zone is arranged as a fixed bed of hydrogenation catalyst pellets or as one or more layers of monolithic type hydrogenation catalyst, and the hydrogenation catalyst comprises an alumina and / or silica carrier impregnated with Pt and / or Pd.

[0169] In an embodiment, the CATOX step and the DEOXO step are conducted separately in the presence of the same catalyst, such as a Pt and / or Pd based catalyst supported on alumina and / or silica carrier, and preferably within the temperature interval 300-600°C, preferably 400-500°C.

[0170] For the purposes of the present application, a temperature range in a given process step or associated process unit such as reactor thus comprising a reaction zone, means the inlet temperature in an adiabatic step, or the reaction temperature in an isothermal step.

[0171] For CATOX, the adiabatic temperature increase is e.g. less than 10°C. For DEOXO, the adiabatic temperature increase is e.g. higher than CATOX but less than 30°C, such as 20- 30°C. The outlet stream from the DEOXO, e.g. the second raw cleaned CO2-rich gas, is preferably cooled in a feed effluent heat exchanger in which said feed is the CO2-rich feed gas.

[0172] In an embodiment,

[0173] - at least one of: the CATOX step (step i)) and DEOXO step in step ii-1), is conducted within the temperature interval 250-600°C;

[0174] - in step ii-2) the DEOXO step is conducted within the temperature interval 50-600°C, suitably at a lower temperature than the DEOXO step of step ii-1).

[0175] In step ii-1), the DEOXO operates with sulfur in the gas and therefore the DEOXO step needs to be operated at 250-600°C to avoid sulfur poisoning. The DEOXO step in step ii-1) also serves to protect a downstream hydrogenation catalyst in connection with a sulfur removal comprising a hydrogenation step uitlizing a NiMo and / or CoMo based catalyst upstream the sulfur retainment step. In step ii-2) the DEOXO operates with a sulfur-free gas which enables operation at a much larger temperature interval, namely 50-600°C, thereby also increasing the flexibility of operation. In other words, it is easier to operate the DEOXO in a sulfur-free environment, for instance by operation at 50-100°C or 50-200°C or 50-225°C.

[0176] For instance, in step ii-1) the DEOXO may be regarded as operating at high temperatures “HT-DEOXO”, whereas in step ii-2) the DEOXO may be regarded as operating at low temperatures “LT-DEOXO”. Low temperature in connection with this embodiment is lower than 250°C; while high temperature is a temperature of 250°C or higher, up to said 600°C.

[0177] For instance, in step ii-1) the DEOXO operates at temperatures of 250, 275, 300, 325, 350, 375, 400, 425, 450, 475, 500, 525, 550, 575 or 600°C.

[0178] For instance, in step ii-2) the DEOXO operates at temperatures of 50, 75, 100, 125, 150, 175, 200, 225°C.

[0179] In an embodiment,

[0180] - in step ii-1) the DEOXO step and the sulfur removal step, suitably where the sulfur removal step is provided as a sulfur retainment step without upstream hydrogenation associated thereto, are conducted in the presence of the same guard material, suitably in the same unit i.e. in a DEOXO / sulfur removal unit, and wherein the guard material is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al.

[0181] It has been found that it is possible to merge the DEOXO and the sulfur removal step into the same catalyst bed i.e. with the same guard material, thereby providing simplicity as well as saving capital expenditures (CAPEX) and operating expenditures (OPEX).

[0182] In an embodiment,

[0183] - in step ii-1) the hydrogenation step and the sulfur retainment step are conducted in the presence of the same guard material, wherein the guard material is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al; or

[0184] - in step ii-1) the hydrogenation step is conducted in the presence of a hydrogenation catalyst, the catalyst being a NiMo and / or CoMo based catalyst, whereby at least SO2 is converted to H2S: and the sulfur retainment step is conducted in a guard material, wherein the guard material is any of ZnO, a Cu-promoted ZnO and a Cu-Zn-AI type.

[0185] In an embodiment,

[0186] - in step ii-2) the sulfur removal is provided as a sulfur retainment step conducted in the presence of: an activated carbon such as promoted or unpromoted activated carbon and / or an alkaline absorbent; preferably arranged as a one or more fixed beds; more preferably, activated carbon arranged as one or more fixed beds, and downstream an alkaline absorbent arranged as one or more fixed beds.

[0187] Since the hydrogenation can only take place after H2 addition, in connection with step ii-2) the alkaline absorbent and / or activated carbon provide the best results for the sulfur retainment step.

[0188] In an embodiment,

[0189] - the activated carbon is provided as a promoted activated carbon, and the promoted activated carbon is an alkaline agent-promoted activated carbon, such as KOH-promoted activated carbon.

[0190] This enhances the sulfur retainment capacity, as the sulfur impurity, e.g. at least SO2, reacts with the basic agent now also being provided as part of the activated carbon, particularly within the pores therein.

[0191] In connection with this embodiment, thus in step ii-2), the sulfur retainment step is conducted at 20-150°C, such as 30-80°C; and at 1-90 barg, such as 20-40 barg.

[0192] In an embodiment, in step ii-2) the sulfur (S) retainment is conducted in a S-scavenger reaction zone, preferably a SCh-scavenger reaction zone, comprising said activated carbon; wherein the process further comprises: supplying a water stream to the S-scavenger reaction zone and forming a sulfuric acid product; and wherein:

[0193] - said sulfuric acid product is continuously withdrawn from the S-scavenger reaction zone; or

[0194] - said sulfuric acid product is collected in the pores of said activated carbon and semi- continuously withdrawn from the S-scavenger reaction zone. For the purposes of the present application, the term “S-scavenger reaction zone”, such as “SC>2-scavenger reaction zone” is utilized where a reaction of water with SO2 to produce sulfuric acid takes place in a fixed bed, in particular in activated carbon.

[0195] For the purposes of the present application, the term “S-absorption zone” is utilized where an absorbent, in particular an alkaline absorbent, is provided in step ii-2).

[0196] In an embodiment, in step ii-2) the S-scavenger zone is a SCh-scavenger reaction zone, which is arranged to receive a liquid or gaseous water stream e.g. water vapor and provide a sulfuric acid stream. A SCh-scavenger reaction zone may thus for instance be a SO2- removal unit.

[0197] It has been found that without water addition, there is a much lower SO2 conversion efficiency. The activated carbon is most effective when some water, e.g. water vapor, is present.

[0198] The term “continuously” means “continuous operation”, which as is well known in the art means that the incoming stream during a given production cycle is constant, as also is the stream being withdrawn as the outcoming product, here the sulfuric acid product. This contrasts with the term “semi-continuously” i.e. “semi-continuous operation”, as is also well known in the art, in which the outcoming product is withdrawn after a certain period of time, here after the sulfuric acid product is collected in the pores of the activated carbon.

[0199] Where the SO2 removal step is conducted in an activated carbon bed, the catalytic activity of the activated carbon enables reaction of the SO2 with the O2 in the CO2 of the feed gas and thus strongly binds the formed SO3 to the activated carbon. The activated carbon is suitably washed with water to remove the SO3 and sulfuric acid, H2SO4, thus making e.g. a continuous system and thus significantly reducing the use for absorbents which must be replaced over time. To increase catalytic activity of the activated carbon, an amount of water is present and preferably there is a relative humidity in the 20-70% range.

[0200] A continuous system to remove SO2 from the CCh-rich feed gas is thus suitably achieved, utilizing the existing O2 in the CCh-rich gas feed to form SO3 over an activated carbon bed, thus providing a substantially SCh-free CCh-rich stream as said S-depleted gas for the downstream Ch-hydrogenation. Water may also be present in the feed gas, which normally is undesirable, as high concentrations of water can limit or inhibit the uptake of S-compounds in typical guard (absorbent) materials. Hence, typically it would be assumed that limiting the water concentration provides for a more efficient operation of the guard material and thereby the SC>2-scavenger absorption zone. Suitably, therefore, in such systems, the total content of H2O entering the SCh-scavenger absorption zone, is no more than 2 vol%, such as no more than 1.0 vol%, or no more than 0.5 vol%, e.g. approximately 0.2 vol%. Now, and in contrast thereto, the present invention takes advantage of any water present, for producing sulfuric acid.

[0201] While there are many traditional processes for removal of SO2 from a gas stream, each with their own advantages and disadvantages, it is a paramount challenge to remove SO2 when present in low concentrations in an almost pure CCh-rich feed gas. Hence, traditionally, for flue gases, which contain CO2 albeit in much lower concentration, alkaline scrubbers are typically used to capture and neutralize the acidic SO2 in the flue gas with reagents such as aqueous solutions of NaOH, CaCCh, NH3, KOH etc. Gas / liquid scrubbers are best suited to remove large amounts of SO2 and it is difficult to obtain very low SO2 emissions.

[0202] Gas / solid contactors can be made with the same alkaline species as above, now just found as a solid on a porous carrier system. Such systems will have a higher removal efficiency, but typically with the cost of a lower removal capacity as the amount of active reagent gets depleted as the reaction proceeds.

[0203] In particular, it has been found that the recited activated carbon and alkaline absorbent are suitable for removal of low concentrations of SO2, each with its own advantages and which combine synergistically for enabling the removal of S-impurities such as SO2. The two embodiments (activated carbon and alkaline absorbent) can be used individually or be combined to take advantage of both.

[0204] Activated carbon is known to be able to remove SO2 from off-gases from e.g. sulfuric acid plants and flue gases from combustion processes. The process was developed in the 1960’s and is known as the Sulfacid process. The SO2 is absorbed into the pores of the activated carbon and in the presence of O2 it is oxidized to SO3 which then can react with water to form sulfuric acid, H2SO4. The sulfuric acid can then be washed out of the pores by liquid water and the SO2 removal capability is regained. The Sulfacid process typically operates at 30-60°C in process gases with up to 10 vol% O2, up to 1 ,000 ppm SO2 around 5-15 vol% H2O and up to 15 vol% CO2. No references about purification of CCh-rich feed gases with much lower concentrations of SO2, O2 and H2O have been reported.

[0205] Alkaline based absorbents are well known for their ability to capture acidic compounds and for SO2 purification in CO2, yet there is a competition between the more acidic SO2 against the less acidic CO2, and with a molar CO2 to SO2 ratio in the typical range of 100,000 to 1 ,000,000.

[0206] Potassium (K) based absorbents have been shown to be effective in SO2 removal. The potassium will typically be applied on a porous carrier in the form of KOH, KHCO3 or K2CO3. When put in operation in a CO2-rich feed gas, the origin of the K precursor is insignificant as the potassium compound will equilibrate with the CO2 and form a mixture of KHCO3 and K2CO3, the ratio depending on the CO2 and H2O partial pressures and the temperature. The more acidic SO2 replaces the CO2 in the potassium carbonate and form a SOs2' or HSOs' compound. If they can react with the O2 also present in the CO2 gas, SO42' or HSO4' is formed and these ions are much more stable than the sulfites and will have less tendency to be desorbed from the absorbent.

[0207] In an embodiment, in step ii-2) an oxygen stream is added to the sulfur removal step, e.g. to the feed gas thereto, which in step ii-2) is the first raw cleaned CCh-rich gas. Accordingly, an oxygen stream is added for increasing the oxygen content in the first raw cleaned CCh-rich gas, which is beneficial for situations where there are significant fluctuations in the composition of the feed gas.

[0208] In particular for such alkaline absorption solutions, it may even be beneficial to add an amount of O2 to the first raw cleaned CCh-rich gas, should the O2 concentration be constantly low or too low or experience periods where the O2 concentration for some reason decreases or drops to zero. This O2 addition increases the stability and removal efficiency of alkaline and activated carbon solutions, by e.g. making stable sulfates, yet it is also limited as the O2 must be hydrogenated in a downstream step (DEOXO step) and thus increases the H2 consumption therein and thereby operating costs.

[0209] A S-removal unit, such as a SO2 removal unit, could either be designed as a single unit, i.e. a single vessel, of either an activated carbon bed or an alkaline absorbent bed or a combination of an activated carbon bed followed by an alkaline absorbent bed. For ease of replacement of activated carbon or absorbent and optimization of operating temperature, two separate units, i.e. two separate vessels, can be used. Between the two vessels, auxiliary equipment can be placed, such as a compressor, heat exchanger, liquid separator or other equipment.

[0210] For simplicity, the two beds can be placed in the same unit, the beds preferably separated with e.g. different bed support structures.

[0211] In an embodiment,

[0212] - in step ii-1) the guard material in the sulfur retainment step is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al; and the sulfur retainment step takes place at a temperature in the interval 120-250°C, such as 140- 200°C or 150-180°C, and a pressure in the interval 1-120 bar, such as 20-40 bar.

[0213] For instance, the content of Al is 2-20 wt% Al e.g. 2-10 wt% Al or 2-15 wt% Al. The guard material may comprise minor amounts of at least one of K, Cs and C. The elements will either be found in a reduced or oxidised state.

[0214] In a particular embodiment, the guard material is coprecipitated Cu / ZnO / alumina-based guard material, in which Cu is ~ 40 wt%, ZnO is ~30 wt% and alumina ~10 wt%.

[0215] For the purposes of the present application, the sign ~ means + / -10% . For instance, Cu can be 40, 36 or 44 wt% i.e. within 10%; or 42, 38 wt% i.e. within 5%.

[0216] On the Cu / Zn / AI based guard material, the following purification reactions take place: kJ hydrogenation hydrogenation

[0217] H2S + ZnO <- H2O + ZnS retainment on guard material

[0218] Further, the cleaning process in the guard bed material of step ii-1) is preferably operated in the pressure range 1-120 bar, such as 1-100 bar or 1-90 bar, preferably 1-50 bar, depending on the pressure of feed gas(es), as well as the pressure of the downstream conversion process. Suitably, the pressure is in the range of 20-40 bar, such as 20-30 bar, corresponding to the operation pressure of methanation reactor(s) arranged downstream.

[0219] Further, to provide the best compromise between high catalytic / adsorption efficiency and low tendency for carbonate formation and evolution of undesired side reactions, such as water and methanol formation, the cleaning process in the guard bed material in step ii-1) is suitably operated in the interval 120-250°C.

[0220] For instance, the pressure is 10, 20, 30, 40, 50, 60, 70, 80, 90, 100 or 110 bar.

[0221] For instance, the temperature is 130, 140, 150, 160, 170, 180, 190, 200, 210, 220, 230, or 240°C.

[0222] In an embodiment, the temperature of the guard material is in the range 140-200°C, preferably 150-180°C. Within these and including these values, it has been found that the temperature is sufficiently high to ensure optimal purification while at the same time being sufficiently low to keep methanol formation, which is an undesired byproduct, under control.

[0223] The above temperature range is, in an embodiment, achieved by said step of withdrawing a portion of the cleaned CCh-rich gas stream and recycling at least a portion thereof to any position upstream the reactor vessel comprising the guard material. Thereby, not only is the temperature sufficiently high to ensure optimal purification and at the same time sufficiently low to keep the methanol formation under control, but at the same time it is possible to ensure a constant inlet flow to the unit i.e. reactor vessel, thereby maintaining the residence time therein at the design value despite any intermittent operation upstream, such as water / steam electrolysis, for providing hydrogen.

[0224] As recited, the temperature is understood as reaction temperature in an isothermal reactor, or inlet temperature in an adiabatic reactor.

[0225] In a second aspect of the invention, there is also provided a plant (system) for carrying out the process according to any one of the preceding process embodiments.

[0226] Any of the embodiments and associated benefits of the first aspect (process) of the invention may be used in connection with the second aspect (plant) of the invention, or vice versa. BRIEF DESCRIPTION OF THE FIGURES

[0227] Fig. 1 shows an embodiment of the invention for producing a cleaned CO2-rich gas.

[0228] Fig 2 shows another embodiment of the invention for producing a cleaned CO2-rich gas and further syngas for downstream production of e-NG.

[0229] DETAILED DESCRIPTION

[0230] Fig. 1 shows an embodiment according to the invention. CO2 rich gas feed 1 comprises: at least 80 vol.% CO2, one or more sulfur containing impurities, optionally one or more nitrogen containing impurities, and one or more carbon / hydrogen / oxygen containing impurities, in which the carbon / hydrogen / oxygen containing impurities optionally comprise hydrocarbons having at least two carbon atoms and / or aromatic hydrocarbons. An oxidant stream 3, here an O2 stream, is added to the to the CO2 rich gas feed 1 to form a CO2-rich gas feed / oxidant gas mixture 5, which is supplied to a catalytic oxidation (CATOX) step in CATOX unit 12 under the presence of a CATOX catalyst 12’, thereby producing a first raw cleaned CO2-rich gas 7. The CO2-rich gas feed / oxidant gas mixture 5 is optionally pressurized and preheated prior to being supplied to the CAT OX unit 12. A reducing gas 9, here a H2 stream, is added to the first raw cleaned CO2-rich gas 7 to form a first raw cleaned CO2-rich gas / reducing gas mixture 11 , which is then supplied to a deoxygenation (DEOXO) step in a DEOXO unit 14 under the presence of a DEOXO catalyst 14’ e.g. a hydrogenation catalyst, thereby producing a second raw cleaned CO2-rich gas 13 having a lower content of oxygen than: the first raw cleaned CO2-rich gas 7 or the first raw cleaned CO2-rich gas / reducing gas mixture 11 . The second raw cleaned CO2-rich gas 13 is suitably cooled in a feed effluent heat exchanger (not shown) in which said feed is the CO2-rich gas feed 1 , and supplied to a sulfur removal step in a sulfur retainment unit 16 comprising a guard material 16’, thereby producing a cleaned CO2-rich gas 15.

[0231] In another embodiment (not shown), the order of DEOXO unit 14 and sulfur retainment unit 16 is reversed, so that the sequential order is CATOX unit 12, then sulfur retainment unit 16, and then DEOXO unit 14. The hydrogen stream 9 is then added to the effluent stream from the sulfur retainment unit 16. Fig. 2 shows an embodiment according to the invention in which the sulfur removal step comprises: a hydrogenation step in a hydrogenation unit (not shown) upstream the sulfur retainment unit. So, now with reference to Fig. 2, CO2 rich feed gas 101 from a biogenic origine comprises: at least 80 vol.% CO2, one or more sulfur containing impurities, optionally one or more nitrogen containing impurities, and one or more carbon / hydrogen / oxygen containing impurities, in which the carbon / hydrogen / oxygen containing impurities optionally comprise hydrocarbons having at least two carbon atoms and / or aromatic hydrocarbons. An oxidant stream 103, here an O2 stream, is added to the CCh-rich gas feed 101 to form a CC>2-rich gas feed / oxidant gas mixture 105, which is supplied to a catalytic oxidation (CATOX) step in CATOX unit 112 under the presence of a CATOX catalyst 112’, thereby producing a first raw cleaned CO2-rich gas 107. A reducing gas 109 is added, for instance a H2 stream, to form a first raw cleaned CO2-rich gas / reducing gas mixture 111 , which is then supplied to a deoxygenation (DEOXO) step in a DEOXO unit 114 under the presence of a DEOXO catalyst 114’ e.g. a hydrogenation catalyst, thereby producing a second raw cleaned CO2-rich gas 113 having a lower content of oxygen than: the first raw cleaned CO2- rich gas 107 or the first raw cleaned CO2-rich gas / reducing gas mixture 111. The second raw cleaned CO2-rich gas 113 is supplied to a sulfur removal step which comprises: a hydrogenation unit 116” under the presence of hydrogenation catalyst 16’” and directly downstream the sulfur retainment unit 116 comprising a guard material 116’, thereby producing a cleaned CO2-rich gas 115’. To the hydrogenation unit 116” an optional hydrogen stream 109’ may be added, for instance where the reducing gas 109 added is CO rather than H2. Further, hydrogen 109” is optionally also added to the cleaned CO2-rich gas 115’ to form synthesis gas (syngas) 117, which is then supplied to a downstream methanation reactor to produce methane, suitably as e-NG. The cleaned CO2-rich gas 115 of Fig. 1 or cleaned CO2-rich gas 115’ in Fig. 2 may also be converted to methanol or to synthetic fuels via FT-synthesis (not shown).

Claims

29CLAIMS1 . A process for cleaning a CCh-rich gas feed, said CCh-rich gas feed comprising:- at least 80 vol.% CO2;- one or more sulfur containing impurities;- one or more carbon / hydrogen / oxygen containing impurities optionally comprising hydrocarbons having at least two carbon atoms and / or aromatic hydrocarbons;- optionally one or more nitrogen containing impurities; wherein said process comprises the steps of: i-1):- supplying the CCh-rich gas feed to a catalytic oxidation (CATOX) step and producing a first raw cleaned CO2-rich gas, in which the first raw cleaned CO2-rich gas has a lower content of carbon / hydrogen / oxygen containing impurities than the CO2-rich gas feed; or i-2)- adding an oxidant gas to the CO2-rich gas feed to form a CO2-rich gas feed / oxidant gas mixture, supplying the CO2-rich gas feed / oxidant gas mixture to a catalytic oxidation (CATOX) step, and producing a first raw cleaned CO2-rich gas, in which the first raw cleaned CO2-rich gas has a lower content of carbon / hydrogen / oxygen containing impurities than the CO2-rich gas feed or than the CO2-rich gas feed / oxidant gas mixture; ii-1):-adding a reducing gas to the first raw cleaned CO2-rich gas to form a first raw cleaned CO2- rich gas / reducing gas mixture;- supplying the first raw cleaned CO2-rich gas / reducing gas mixture to a deoxygenation (DEOXO) step, and producing a second raw cleaned CO2-rich gas, in which the second raw cleaned CO2-rich gas has a lower content of oxygen than the first raw cleaned CO2-rich gas or than the first raw cleaned CO2-rich gas / reducing gas mixture;- supplying the second raw cleaned CO2-rich gas to a sulfur removal step and an optional nitrogen removal step, and producing a cleaned CO2-rich gas, in which the cleaned CO2-rich gas has a lower content of sulfur containing impurities and optionally a lower content of nitrogen containing impurities than the second raw cleaned CCh-rich gas;30 or ii-2):- supplying the first raw cleaned CCh-rich gas to a sulfur removal step and an optional nitrogen removal step, and producing a second raw cleaned CO2-rich gas, in which the second raw cleaned CCh-rich gas has a lower content of sulfur containing impurities and optionally a lower content of nitrogen containing impurities than the first raw cleaned CO2- rich gas;- adding a reducing gas to the second raw cleaned CCh-rich gas to form a second raw cleaned CCh-rich gas / reducing gas mixture;- supplying the second raw cleaned CCh-rich gas / reducing gas mixture to a deoxygenation (DEOXO) step, and producing a cleaned CO2-rich gas, in which the cleaned CO2-rich gas has a lower content of oxygen than the second raw cleaned CO2-rich gas or than the second raw cleaned CO2-rich gas / reducing gas mixture.

2. The process according to claim 1 , wherein:- the oxidant gas is oxygen (O2); and / or- the reducing gas is at least one of: hydrogen (H2) and carbon monoxide (CO).

3. The process according to any one of the preceding claims, wherein:- the reducing gas is hydrogen (H2) whereby the cleaned CO2-rich gas produced in step ii-1) or step ii-2) is withdrawn as a first synthesis gas (first syngas).

4. The process according to any one of the preceding claims, wherein the CO2-rich gas feed comprises at least 90 vol.% CO2, such as at least 95 vol.% CO2, such as at least 99 vol.% CO2, preferably at least 99.5 vol.% CO2, more preferably at least 99.8 vol.% CO2.

5. The process according to any one of the preceding claims, wherein: in step ii-1) the sulfur removal step comprises: a hydrogenation step to produce at least hydrogenated sulfur impurities such as H2S which are subsequently directly supplied to a sulfur retainment step in a guard material.

6. The process according to any one of the preceding claims, wherein:- the first raw cleaned CCh-rich gas in step i) comprises 500-3000 ppmv O2, or 500-2000 ppmv O2, or 500-1500 ppmv O2, such as 800-1200 ppmv O2, for instance 900-1100 ppmv O2, or 1000 ppmv O2.

7. The process according to any one of claims 3-6, wherein:- the reducing gas is H2, and in step ii-1) the first raw cleaned CCh-rich gas / reducing gas mixture is a raw synthesis gas (raw syngas) having a volume (molar) ratio of H2 to CO2 (H2:CC>2) of at least 2, such as 2-5, for instance 2.5-4.5, or 3-4, such as 3.5-4.

8. The process according to any one of the preceding claims, where the process comprises: iii) adding a hydrogen stream to the cleaned CCh-rich gas, such as when the cleaned CO2- rich gas is withdrawn as first syngas, to form a second synthesis gas (second syngas) with a volume (molar) ratio of H2 to CO2 (H2:CO2) of at least 2, such as 2-5, for instance 2.5-4.5, or 3-4, such as 3.5-4.

9. The process according to any one of the preceding claims, wherein the process further comprises:- providing an electrolysis unit being fed with a water / steam feedstock, i.e. water or steam, for producing a hydrogen-rich stream and an oxygen-rich stream;- diverting at least a portion of said hydrogen-rich stream, as said reducing gas in step ii-1) or step ii-2); or as said hydrogen stream in step iii); and / or- diverting at least a portion of said oxygen-rich stream as said oxidant gas in step i-2).

10. The process according to any one of claims 3-9, wherein the process further comprises:- supplying the first or second syngas to a methanation step and producing a methane (CH4) product comprising at least 90 vol.% CH4, such as at least 95 vol.% CH4 or at least 97 vol.% CH4; preferably, the methanation step comprises supplying the first or second syngas to one or more methanation reactors in the presence of a methanation catalyst, preferably a plurality of methanation reactors arranged in series.

11. The process according to any one of claims 3-9, wherein the process further comprises:- optionally, supplying the first or second syngas to a reverse water gas shift (RWGS) step in the presence of a catalyst active in RWGS, preferably in an electrically heated reactor for RWGS (e-RWGS), to provide: a modified methanol syngas;- supplying the first or second syngas, or the modified methanol syngas to a methanol synthesis step, and producing: a raw methanol product, further optionally removing water from the raw methanol product.

12. The process according to any one of claims 3-9, wherein the process further comprises:- supplying the first or second syngas to a reverse water gas shift (RWGS) step in the presence of a catalyst active in RWGS, preferably in an electrically heated reactor for RWGS (e-RWGS), to provide: a Fischer-Tropsch (FT)-syngas having a H2:CO molar ratio of 1.9-2.1 , preferably 2;- supplying the FT-syngas to a FT-synthesis step, and producing a synthetic fuel which is at least one of: aviation fuel, kerosene, gasoline and diesel fuel.

13. The process according to any one of the preceding claims, wherein the CO2-rich gas feed is derived from a renewable source by, prior to step i), providing a step selected from:- combustion or gasification of a lignocellulosic biomass such as wood products, algae, grass, forestry waste and / or agricultural residue;- combustion or gasification of municipal waste, in particular the organic portion thereof, where the municipal waste is defined as a feedstock containing materials of items discarded by the public, such as mixed municipal waste given in Ell Directive 2018 / 2001 (RED II), Annex IX, part A;- microbial conversion of nitrogen-rich renewable feedstock such as manure or sewage sludge;- fermentation of hydrocarbon(sugar) rich feed streams such as corn, sugar cane and beets;- Direct Air Capture (DAC).

14. The process according to any one of the preceding claims, wherein:- the CO2-rich gas feed comprises: at least 97 vol.% CO2, such as at least 99 vol.% CO2;- the sulfur containing impurities in the CO2-rich gas feed are less than 30 ppmv, such as less than 20 ppmv;- the carbon / hydrogen / oxygen containing impurities comprise alcohols such as methanol and / or ethanol;-the carbon / hydrogen / oxygen containing impurities in the CO2-rich gas feed are less than 2000 ppmv, such as less than 1000 ppmv.

15. The process according to any one of the preceding claims, wherein:- the CO2-rich gas feed comprises:- at least 99 vol.% CO2;- no more than 30 ppm-mol (ppmv) water (H2O);33- no more than 10 ppmv oxygen (O2);- no more than 50 ppmv hydrogen (H2);- no more than 100 ppmv carbon monoxide (CO);- the sulfur containing impurities are sulfur oxides (SOx) and hydrogen sulfide (H2S), and the CO2-rich gas feed comprises:- no more than 10 ppmv SOX;- no more than 9 ppmv H2S;- the nitrogen containing impurities are nitrogen oxides (NOX), ammonia (NH3), optionally amines, optionally nitrogen (N2), and the CO2-rich gas feed comprises:- no more than 1 .5 ppmv NOX;- no more than 10 ppmv NH3;- optionally, no more than 10 ppmv amines;- optionally, no more than 50 ppmv N2.

16. The process according to any one of the preceding claims, wherein:- the sulfur containing impurities are one or more compounds selected from: SO2, COS, CS2, DMS and H2S.

17. The process according to any one of the preceding claims, wherein:- the hydrocarbons having at least two carbon atoms are selected from: C2-C6 alkanes, C2- Ce alkenes, C2-C6 alkynes, and combinations thereof; and / or- the aromatic hydrocarbons are selected from: Ce-Cs aromatic hydrocarbons, C9-C12 aromatics hydrocarbons, and combinations thereof.

18. The process according to any one of the preceding claims, wherein:- the CATOX step is conducted in a reactor unit i.e. a reactor vessel comprising a catalyst, in which the catalyst is selected from: tungsten, vanadium, molybdenum, platinum and palladium in metallic and / or in metal oxide form supported on a carrier; or from vanadium, tungsten, chromium, copper, manganese, molybdenum, platinum, palladium, rhodium or ruthenium in metallic and / or metal oxide form supported on a carrier selected from alumina, titania, silica and ceria and combinations thereof;34- the DEOXO step is conducted in an 02-hydrogenation reaction zone comprising a hydrogenation catalyst;- wherein the hydrogenation catalyst comprises an alumina and / or silica carrier impregnated with a metal, such as: Cu, Mn, Pt, Pd, or combinations thereof; or- wherein the hydrogenation catalyst comprises a Cu / Zn / AI based material; or- wherein the 02-hydrogenation reaction zone is arranged as a fixed bed of hydrogenation catalyst pellets or as one or more layers of monolithic type hydrogenation catalyst, and the hydrogenation catalyst comprises an alumina and / or silica carrier impregnated with Pt and / or Pd.

19. The process according to any one of the preceding claims, wherein the CATOX step and the DEOXO step are conducted separately in the presence of the same catalyst, such as a Pt and / or Pd based catalyst supported on alumina and / or silica carrier, and preferably within the temperature interval 300-600°C, preferably 400-500°C.

20. The process according to any one of the preceding claims, wherein:- at least one of: the CATOX step in step i) and DEOXO step in step ii-1), is conducted within the temperature interval 250-600°C;- in step ii-2) the DEOXO step is conducted within the temperature interval 50-600°C, suitably at a lower temperature than the DEOXO step of step ii-1).

21. The process according to any one of the preceding claims, wherein:- in step ii-1) the DEOXO step and the sulfur removal step, suitably where the sulfur removal step is provided as a sulfur retainment step without upstream hydrogenation associated thereto, are conducted in the presence of the same guard material, suitably in the same unit i.e. in a DEOXO / sulfur removal unit, and wherein the guard material is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al.

22. The process according to any one of claims 5-20, wherein:- in step ii-1) the hydrogenation step and the sulfur retainment step are conducted in the presence of the same guard material, wherein the guard material is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al; or35- in step ii-1) the hydrogenation step is conducted in the presence of a hydrogenation catalyst, the catalyst being a NiMo and / or CoMo based catalyst, whereby at least SO2 is converted to H2S; and the sulfur retainment step is conducted in a guard material, wherein the guard material is any of ZnO, a Cu-promoted ZnO and a Cu-Zn-AI type.

23. The process according to any one of the preceding claims, wherein:- in step ii-2) the sulfur removal is provided as a sulfur retainment step conducted in the presence of an activated carbon such as promoted or unpromoted activated carbon and / or an alkaline absorbent; preferably arranged as a one or more fixed beds; more preferably, activated carbon arranged as one or more fixed beds, and downstream an alkaline absorbent arranged as one or more fixed beds.

24. The process according to claim 23, wherein:- the activated carbon is provided as a promoted activated carbon, and the promoted activated carbon is an alkaline agent-promoted activated carbon, such as KOH-promoted activated carbon.

25. The process according to any one of claims 5-22, wherein:- in step ii-1) the guard material in the sulfur retainment step is a Cu-Zn-AI guard material having a chemical composition of 25-60 wt% Cu, 15-70 wt% Zn, and 1-20 wt% Al; and the sulfur retainment step takes place at a temperature in the interval 120-250°C, such as 140- 200°C or 150-180°C, and a pressure in the interval 1-120 bar, such as 20-40 bar.

26. Plant for carrying out the process according to any one of the preceding claims.

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