Plant and process for producing a synthesis gas with low carbon intensity (CI)

Abstract

A plant and process for producing a synthesis gas, the synthesis gas being at least one of a raw synthesis gas and a shifted synthesis gas, the plant comprising: a reforming section comprising a reforming unit arranged to convert a hydrocarbon feed gas to a first raw synthesis gas; a splitting point arranged to split the first raw synthesis gas into at least: a second raw synthesis gas and a third raw synthesis gas; a first high temperature hydrogen separation unit (first HT H2-separation unit) arranged to receive the second raw synthesis gas and provide: a first hydrogen-rich gas (first HT H2-rich gas) and a first hydrogen-lean gas (first HT H2-lean stream); a conduit arranged to supply at least a portion of the first HT H2-rich gas as fuel to the reforming section; a mixing point arranged to combine at least a portion of the third raw synthesis gas with at least a portion of the first HT H2-lean gas into a fourth raw synthesis gas as said raw synthesis gas. Optionally, a water gas shift (WGS) section comprising one or more WGS conversion units is arranged to receive the raw synthesis gas and provide said shifted synthesis gas. Optionally, the synthesis gas is further converted to a hydrogen product and a CO2-product.

Description

[0001] Plant and process for producing a synthesis gas with low carbon intensity (Cl)

[0002] FIELD OF THE INVENTION

[0003] The present invention relates to a plant and process for producing synthesis gas; optionally further for producing hydrogen.

[0004] BACKGROUND

[0005] In the production of a synthesis gas from a hydrocarbon feed gas, such as - natural gas, a typical process comprises steam reforming of the said hydrocarbon feed gas for producing the synthesis gas. The synthesis gas may be further conditioned into a synthesis gas suitable for hydrogen production, an ammonia synthesis gas suitable for downstream ammonia synthesis optionally also urea synthesis, a Fischer-Tropsch (FT) synthesis gas suitable for downstream FT synthesis into transportation range hydrocarbon fuels, or a methanol synthesis gas suitable for downstream methanol synthesis.

[0006] For instance, in the production of hydrogen, a typical process comprises the steam reforming of natural gas for producing a raw synthesis gas (syngas), water gas shift (WGS) of the raw syngas to increase the hydrogen content, optionally CO2-removal from the syngas and finally, a hydrogen purification in usually a Pressure Swing Adsorption unit (PSA unit) thereby forming a hydrogen product and a PSA off-gas. The PSA off-gas is typically recycled to the steam reforming as fuel.

[0007] A typical “Blue Hydrogen plant / process” is a plant / process for producing hydrogen where most of the CO2 produced in the process is captured and not emitted to the atmosphere by using a CO2 removal section downstream of the WGS and upstream of the hydrogen purification section. Additionally, use of carbon containing fuel is minimized and the entire plant / process is designed for higher flow in order to accommodate the need for excess H2 to be used as fuel in the plant / process, for thereby reducing the CO2 emissions and correspondingly the carbon intensity (Cl) of the plant / process. Additional hydrocarbon feed gas is then needed to meet hydrogen fuel demand and overall additional feed flows are required from start to end, as excess H2 from the PSA unit is used as fuel. Related prior art is found in e.g. applicant’s WO 2022038090 and WO 2020221642.

[0008] WO 2012173483 A1 discloses a method for hydrogen production comprising the provision of a hydrogen separation module arranged in between a conventional steam methane reformer (SMR) and WGS reactor. The separated hydrogen is withdrawn as a low-pressure hydrogen product or is directed to a hydrogen compressor. The compressed hydrogen is delivered as hydrogen product or further purified in a pressure swing adsorption arranged downstream the WGS reactor.

[0009] It would be desirable to provide a plant / process for converting a hydrocarbon feed gas to synthesis gas, optionally further to hydrogen, with reduced carbon intensity (Cl).

[0010] It would be desirable to provide a plant / process for producing synthesis gas, optionally further to hydrogen, with lower installation cost, operating cost and reduced plot space.

[0011] It would be desirable to provide a plant / process for producing synthesis gas, optionally further to hydrogen, with lower installation cost, operating cost and reduced plot space.

[0012] It would be desirable to provide a plant / process for producing synthesis gas, optionally further to hydrogen, with improved CO2 removal with relatively low energy consumption.

[0013] SUMMARY

[0014] Accordingly, in a first aspect of the invention, there is provided a plant 100, 100’, 100” for producing a synthesis gas 21 , 23, 25, the synthesis gas being at least one of a raw synthesis gas 21 and a shifted synthesis gas 23, 25, the plant comprising:

[0015] - a reforming section comprising a reforming unit 14 arranged to convert a hydrocarbon feed gas 1 , 3, 7 to a first raw synthesis gas 15;

[0016] - a splitting point 30 arranged to split the first raw synthesis gas 15 into at least: a second 15’ raw synthesis gas and a third 15” raw synthesis gas;

[0017] - a first high temperature hydrogen separation unit (first HT ^-separation unit, 18) arranged to receive the second 15’ raw synthesis gas and provide: a first 19 hydrogen-rich gas (first HT H2-rich gas, 19), preferably a first 19 HT H2-rich low-pressure gas (first HT H2-rich LP gas, 19); and a first 17 hydrogen-lean gas (first HT H2-lean stream, 17), preferably a first 17 HT H2-lean high-pressure gas (first HT H2-lean HP gas, 17);

[0018] - a conduit arranged to supply at least a portion of the first HT H2-rich gas 19 as fuel to the reforming section;

[0019] - a mixing point 32 arranged to combine at least a portion of the third 15” raw synthesis gas with at least a portion of the first 17 HT H2-lean gas into a fourth 21 raw synthesis gas as said raw synthesis gas 21.

[0020] Thereby, high temperature (HT) hydrogen-rich gas from first HT ^-separation unit is not taken out from the plant but used internally as fuel in the reforming section. This ensures more efficient use of the HT H2 being withdrawn rather than cooling it down. The first HT H2-rich gas is preferably withdrawn at low pressure, e.g. 1-10 barg and thus it is advantageously supplied as fuel to the reforming section. The utilization of low pressure (LP) and high temperature (HT) hydrogen is ideal for fuel, thereby significantly reducing the need of externally sourcing a fuel gas such as natural gas which attendant CC>2-emissions. The carbon intensity (Cl) of the plant is thereby significantly reduced.

[0021] Furthermore, since the first HT ^-separation unit is arranged immediately downstream the reforming section, thus upstream e.g. a water gas shift section, and the first HT H2- separation unit is arranged to receive a portion, thus a by-pass stream, of the first raw synthesis gas from the reforming section, the process gas flow to the first HT ^-separation unit and thus the size of this separation unit is significantly reduced, as so is the process gas flow to any other unit(s) downstream, thereby also reducing the size of these units and accordingly the plant size. Hence, there are lower installation costs, operating costs and reduced plot space. Where the first HT ^-separation unit is provided as a Pd-based membrane unit, significant cost reductions are further achieved by processing a smaller flow, as Pd-based membranes are highly expensive.

[0022] In an embodiment, as recited above, the first hydrogen-rich gas (first HT H2-rich gas) is a first HT H2-rich low-pressure gas (first HT H2-rich LP gas). In an embodiment, as recited above, the first HT hydrogen-lean gas (first HT H2-lean stream) is a first HT H2-lean high-pressure gas (first HT H2-lean HP gas).

[0023] In an embodiment, the hydrocarbon feed gas is selected from: natural gas, naphtha, LPG, biogas, industrial gas, and combinations thereof. All these hydrocarbon feed gases are well-known in the art. These are also defined below.

[0024] For the purposes of the present application:

[0025] The term “present invention” or simply “invention” may be used interchangeably with the terms “present application” or simply “application”, respectively.

[0026] The term “first aspect of the invention” refers to the plant (system) according to the invention. The term “second aspect of the invention” refers to the process according to the invention.

[0027] The term “plant / process” means plant and / or process.

[0028] The term “section” and “unit” may be used interchangeably. A section may comprise one or more subsections. A subsection may be a unit. A unit may comprise one or more subunits. For instance, the reforming section may comprise a reforming unit. For instance, the reforming section may comprise a hydrocarbon feed gas purification section, the hydrogen purification section comprising a hydrogenator and a sulfur absorber (i.e. hydrogenation unit and sulfur absorption unit). For instance, a water gas shift (WGS) section may comprise one or more WGS conversion units.

[0029] The term “synthesis gas”, also normally referred to “syngas”, means a fuel gas mixture rich in carbon oxide(s) and hydrogen.

[0030] The term “high temperature hydrogen separation unit (HT ^-separation unit)” means a unit capable of separating a significant portion of the hydrogen contained in the gas fed thereto, for instance here the first raw synthesis gas, and which operates in the temperature range of 200-500°C. For instance, the HT ^-separation unit is a membrane unit, such as a Pd-based membrane unit.

[0031] The term “hydrocarbon feed gas” means a gas stream comprising hydrocarbons, in which the hydrocarbons may be as simple as e.g. methane (CH4) and may also comprise more complex molecules.

[0032] The term “natural gas” means a mixture of hydrocarbons having methane as the major constituent. The methane content can be 85 vol% or higher, and other higher hydrocarbons (C2+) may also be present such as ethane and propane. The term “naphtha” means a mixture of hydrocarbons in the range of C5-C10, preferably as paraffins and olefins. More specifically, the naphtha fraction contains hydrocarbons in the C5-C10 range i.e. with IBP = 30°C, 50% BP = 115°C and FBP = 160°C according to characterization by ASTM D86.

[0033] The term “LPG” means liquified petroleum gas or liquid petroleum gas and is a gas mixture of hydrocarbons comprising predominantly propane and butane.

[0034] The term “biogas” means a gas produced by the fermentation of organic matter, consisting mainly of methane and carbon dioxide. The methane content can be in the range 40-70 vol.% and the carbon dioxide content in the range 30-60 vol%.

[0035] The term “industrial gas” means a hydrocarbon containing off-gas having a heating value which is sufficient for burning the gas. An example is refinery off-gas, which often comprises components such as diolefins, olefins, CO2, CO, hydrocarbons, H2S, and various organic sulfur species.

[0036] The term “X-rich” or “X-lean” in which X is H2 or CO2, means that the associated process stream comprises more than 50 vol.% of CO2 or H2, or less than 50 vol.% of CO2 or H2, respectively. For instance, the term “H2-rich gas” means more than 50 vol.% H2, such as at least 60 vol.%, or at least 70 vol.%, or at least 80 vol.%, or at least 90 vol.% H2, or at least 95 vol.%, or at least 99 vol.% H2. For instance, the term “H2-lean gas” means less than 50 vol.% H2, such as less than 40 vol.%, or less than 30 vol.%, or less than 20 vol.%, or less than 10 vol.%, or less than 5 vol.%, or less than 1 vol.% H2.

[0037] The term “conduit” means a process line, such as a pipe, carrying a given process stream.

[0038] The term “mixing point” means a mixing unit or a juncture.

[0039] The term “and / or” means in connection with a given embodiment any of three options. The term “and / or” may be used interchangeably with the term “at least one of” the three options.

[0040] The term “comprising” includes “comprising only” i.e. “consisting of”.

[0041] The term “suitably” means “optionally”, i.e. an optional embodiment.

[0042] The use of the article “a” or “an” means at least one. For instance, the term “a reforming unit” means “at least one reforming unit”, or interchangeably “one or more reforming units”.

[0043] The term “at least a portion” of a certain item means the entire item or a portion thereof. For instance, at least a portion of a given process stream, means the entire stream or a portion thereof. The term “arranged” and “configured” may be used interchangeably.

[0044] Other definitions are provided in connection with one or more of above or below embodiments.

[0045] The raw synthesis gas is for instance conditioned to a Fischer-Tropsch (FT) synthesis gas for downstream FT synthesis into transportation range hydrocarbon fuels; or a methanol synthesis gas for downstream methanol synthesis, or an ammonia synthesis gas for downstream ammonia synthesis, optionally further for urea production, or a synthesis gas for downstream hydrogen production.

[0046] Where the raw synthesis gas is for instance envisaged for ammonia production optionally further for urea production, or for hydrogen production, a WGS section is suitably provided.

[0047] Accordingly, in an embodiment, the plant comprises:

[0048] - a water gas shift (WGS) section comprising one or more WGS conversion units 20, 22 arranged to receive the raw synthesis gas 21 and provide said shifted synthesis gas 23, 25; and wherein the first HT H2-separation unit 18 is arranged to operate at a temperature corresponding to the inlet temperature of the first 20 of the one or more of the WGS conversion units 20, 22 of the WGS section.

[0049] The shifted synthesis gas 23 from the first WGS conversion unit 20, for instance a high temperature shift (HTS) unit, may be regarded as a partly shifted synthesis gas. The shifted synthesis gas 25 from the last WGS conversion unit 22, for instance a medium temperature shift (MTS) unit or a low temperature shift (LTS) unit, may be regarded as a fully shifted synthesis gas.

[0050] In an embodiment, the first HT ^-separation unit 18 is arranged to operate in the temperature range 200-500°C, such as 300-475°C, or such as 300-400°C.

[0051] Thereby, since a significant portion of the hydrogen in the raw syngas has been removed, there is a higher conversion in the WGS section and at the same time a high flexibility in the operation of the plant is achieved, as the operation of the first HT H2- separation unit is tailored to correspond to the inlet temperature of the first WGS conversion unit.

[0052] The one or more WGS units means at least one of: a high temperature shift unit (HTS- unit); a medium temperature shift (MTS-unit), and a low temperature shift unit (LTS- unit). In an embodiment, the one or more WGS conversion units are: a HTS-unit and a downstream MTS-unit. In an embodiment, the one or more WGS conversion units are: HTS-unit and a downstream LTS-unit. In another embodiment, the one or more WGS conversion units are: a HTS-unit and a downstream MTS and LTS-unit. WGS enables the enrichment of the syngas in hydrogen, as is well-known in the art.

[0053] In an embodiment, the plant comprises a heat exchanging unit such as a waste heat boiler (WHB) arranged to receive the first raw synthesis gas 15 and provide a cooled first raw synthesis gas upstream said splitting point 30, preferably at said temperature of 200-500°C, and the second 15’ raw synthesis gas is less than 80 vol.%, such as IQ- 50 vol.% of the first raw synthesis gas 15, for instance: 15 or 20 or 25 or 30 or 35 or 40 or 45 vol.% of the first raw synthesis gas.

[0054] The present invention, therefore, only uses a relatively smaller stream, for instance ca. 50 vol.% of the first raw synthesis gas, to the first HT ^-separation and the H2 product from such unit, being withdrawn at low pressure, is used preferably in its entirety as fuel in the reforming section. Further, as recited above, where the first HT ^-separation unit is provided as a Pd-membrane unit, there is also at least a reduction in the associated costs of the Pd-membrane unit, as this unit is configured to receive a smaller process flow, namely the second raw synthesis gas.

[0055] In an embodiment, the reforming unit 14 is at least one of: a steam methane reformer (SMR), an electrically heated steam methane reformer (e-SMR), a convection reformer i.e. a heat exchange reformer (HER), and an autothermal reformer (ATR).

[0056] These reforming units are well-known in the art. Details of SMR (also known as tubular reforming) and ATR can be found in the art such as “Studies in Surface Science and Catalysis, Vol. 152, ’’Synthesis gas production for FT synthesis”; Chapter 4, p.258-352, 2004”, as well as in: lb Dybkjaer, Fuel Processing Technology 42 (1995) 85-107. A convection reformer is herein referred to as heat exchange reformer (HER). A specific HER is the so-called convection reformer HTCR (Haldor TOPSOE™ Convection Reformer™) utilizing bayonet tubes as described in e.g. EP 0535505. The HTCR is a vertical, refractory-lined vessel with a bundle of bayonet tubes inside. Each bayonet tube is surrounded by another tube that guides the hot flue gas around the bundle of tubes containing the feedstock. Below the vertical section there is an adjacent combustion chamber, such as a horizontal combustion chamber containing one or more burners, utilizing a hydrocarbon fuel gas such as natural gas, as fuel. The heat is transferred to the feedstock by convection, resulting in more effective exploitation of the thermal inputs, lower fuel consumption and no steam export. An arrangement of HER and ATR in series is described in WO 2012 / 084135. An arrangement of HER and ATR in parallel is described in WO 2015 / 128456. For a description of e-SMR which is a more recent technology, reference is given to in particular WO 2019 / 228797 A1.

[0057] In an embodiment, the plant further comprises:

[0058] - a synthesis gas cooling section 24 arranged to receive the synthesis gas 23, 25, preferably the synthesis gas 25 from the last WGS conversion unit 22 of the WGS section, and provide a cooled synthesis gas 27;

[0059] - optionally, a process condensate separator (PC-separator) arranged to receive the cooled synthesis gas 27 and provide: a process condensate stream and a water-depleted synthesis gas;

[0060] - a 002-removal section 26 arranged to receive the cooled synthesis gas 27 or the optional water-depleted synthesis gas, and provide: a CO2-rich gas 31 and a CO2-de- pleted synthesis gas 29.

[0061] In a typical 'Blue-H2' plant / process i.e. a plant / process for producing hydrogen where the CO2 produced is captured and not emitted to the atmosphere, the entire plant / process is designed for higher flow to accommodate the need for excess hydrogen to be used as fuel in the plant / process. In contrast thereto, in the present invention, by utilizing the first HT ^-separation unit, a part of the plant including WGS section, CO2-re- moval section, optionally hydrogen purification unit e.g. PSA, does not need to be designed for such excess hydrogen flow. In an embodiment, the CCh-removal section 26 is arranged as a CCh-absorption / de- sorption unit 26 which further provides a high-pressure flash gas (HP flash gas); and wherein the plant is arranged according to at least one of the following configurations:

[0062] - the reforming unit 14 is a convection reformer i.e. a heat exchange reformer (HER) arranged in series or in parallel with an autothermal reformer (ATR); and the convection reformer is further arranged to receive at least a portion of at least one of: the CCh-de- pleted synthesis gas 29 and the HP flash gas;

[0063] - the reforming section comprises a hydrocarbon feed gas purification section 10 arranged upstream the reforming unit 14 and arranged to receive the hydrocarbon feed gas 1 , the hydrocarbon feed gas purification section 10 preferably comprises a hydro- genator and sulfur absorber, and the hydrocarbon feed gas purification section 10 is further arranged to receive at least a portion of the CCh-depleted synthesis gas 29, optionally at least a portion of the HP flash gas;

[0064] - the CC>2-absorption / desorption unit 26 is further arranged to receive at least a portion of the HP flash gas as an internal recycle stream;

[0065] - at least a portion of the HP flash gas is provided as fuel to one or more burners of the reforming unit 14, the reforming unit being arranged as a steam methane reformer (SMR) or a convection reformer i.e. a heat exchanger reformer (HER);

[0066] - the plant comprises a fired heater providing heat to at least the reforming unit 14; and at least a portion of the HP flash gas is provided as fuel to one or more burners of the fired heater, the reforming unit being arranged as an ATR.

[0067] Accordingly, in an embodiment, the reforming unit comprises a convection reformer i.e. heat exchange reformer (HER) arranged in series or in parallel with an autothermal reformer (ATR); wherein the CCh-removal section is arranged as a CCh-absorption / de- sorption unit, i.e. an amine wash unit, and which is further arranged to provide a high- pressure flash gas (HP flash gas); and wherein the convection reformer is further arranged to receive at least a portion of at least one of: the CCh-depleted synthesis gas and the HP flash gas. While typically, e.g. in a Blue-H2 plant / process, additional hydrocarbon feed gas is needed to meet hydrogen fuel demand and overall additional feed flows are required from start to end, as excess H2 from the PSA unit is used as fuel, the present embodiment enables lower hydrocarbon feed gas consumption e.g. lower natural gas consumption, while at the same time reducing the oxygen consumption in the ATR. Additionally, as further recited below, there is a reduction in size of the HER. This effect is even more significant where the HER is arranged in series with the ATR.

[0068] It is understood that for the purposes of the present application, the term “reforming section” means the section of the plant comprising at least a reforming unit. The reforming section may also comprise a hydrocarbon feed gas purification section. The hydrocarbon feed gas purification section may comprise a hydrogenator and a sulfur absorber downstream the hydrogenator. The reforming section may also comprise a pre-reformer. A pre-reformer is arranged in between the hydrocarbon feed gas purification section and the reforming unit. The term “pre-reformer” and “pre-reforming unit” are used interchangeably.

[0069] The term “CCh-absorption / desorption unit” means an amine wash unit which comprises a CC>2-absorber and a CCh-stripper. According to the present embodiment, the unit also comprises a high-pressure flash drum and low-pressure flash drum, thereby separating said CC>2-rich stream, said CCh-depleted synthesis gas as a H2-rich stream, and said HP flash gas.

[0070] The term “high pressure flash gas stream (HP flash gas)” means a stream derived from the CC>2-absorption / desorption unit having a pressure significantly above atmospheric pressure, such as 3-10 barg and having a significant content of hydrogen, such as 20- 40 vol.% as well as a significant CO2 content, such as 60-80 vol.%.

[0071] More specifically, the amine wash unit comprises a CCh-absorber and a CCh-stripper as well as a high-pressure flash drum and low-pressure flash drum, thereby separating the CC>2-rich gas containing more than 99 vol.% CO2 such as 99.5 vol.% CO2 or 99.8 vol.% CO2, the CC>2-depleted synthesis gas which is H2-rich e.g. containing 98 vol.% hydrogen, as well as the HP flash gas containing e.g. about 60 vol.% CO2 and 40 vol.% H2. In the amine wash unit, in the first high pressure flash step via said high-pressure drum, the bulk part of the impurities is released together with some CO2 to the gas phase as a high-pressure flash gas. In the low-pressure flash step via said low-pressure flash drum, mainly CO2 is released to a final product as the CCh-rich gas. A fired heater is conventionally associated with at least the ATR to provide the required heat of feed streams to the ATR. A fired heater is conventionally also utilized to preheat any hydrocarbon feed gas upstream the ATR, for instance hydrocarbon feed gas to a pre-reformer, and / or pre-reformed hydrocarbon feed gas to the ATR. A fired heater comprises one or more burners conventionally utilizing a fossil-based hydrocarbon fuel gas such as natural gas for the burning. The associated flue gas exiting the fired heater contains CO2 which is emitted to the atmosphere.

[0072] The invention enables a significant reduction of hydrocarbon-based fuel required for the burning, such as natural gas, thereby significantly reducing CO2 emissions, as the CC>2-depleted synthesis gas and the HP flash gas now being used as fuel gas to the burners have a significant content of hydrogen. The provision of the HP flash gas as fuel, thus further enables to decarbonize the hydrocarbon feed e.g. natural gas, whereby at least 95% of the carbon is captured. The high-pressure flash gas stream is thereby advantageously integrated into the plant / process for further improving carbon capture. The CCh-depleted synthesis gas is H2-rich and can be provided as fuel gas at a high pressure to the convection reformer, thereby enabling higher performance of the convection reformer along with a significant reduction of its size, as mentioned earlier. Up to 40% size reduction is achieved. The carbon intensity (Cl) of the plant / process, being a direct consequence of reduced CCh-emissions, is thus further reduced.

[0073] In a particular embodiment, as it also will become apparent from one or more of embodiments recited in the present application, there is no hydrogen purification unit, such as Pressure Swing Adsorption (PSA) unit arranged downstream the CCh-absortion / de- sorption unit, thus further reducing at least plant size. CAPEX is accordingly, further reduced.

[0074] In an embodiment, the CCh-removal section 26 is arranged as a membrane unit and provides: said CCh-rich gas 31 as a CCh-product 31 , and said CCh-depleted synthesis gas 29 as a hydrogen product 29; optionally, the plant comprises at least one of: a CCh-product booster compressor arranged to receive the CCh-product 31 and to supply the CCh-product 31 at the required pressure for use downstream; and a H2-product booster compressor arranged to receive the hydrogen product 29 and to supply the hydrogen product 29 at the required pressure for use downstream.

[0075] A H2 compressor is not strictly required, since in producing fuel grade H2, there may be no need to pressurize the H2. So, the compressors are optional depending on the specific needs.

[0076] The separated CCh-rich gas being withdrawn as the CCh-product may be disposed by e.g. sequestration in geological structures or used as industrial gas for various purposes.

[0077] The membrane unit is for instance a hollow fiber membrane comprising one or more modules, such as membrane as disclosed in e.g. WO 2024121590 A1.

[0078] Energy consumption in the CO2-product booster compressor is reduced while the byproduct booster compressor duty is increased, yet the total duty from both booster compressors is overall significantly reduced. Further, the methane slip from the reforming unit and the CO slip from the WGS section can be tailored so that the CO2-rich gas from the membrane unit is sent directly to e.g. sequestration without a CO2 removal unit. Furthermore, the need for a CO2-absorption / desorption unit i.e. an amine wash unit as well as a pressure swing adsorption (PSA) unit is eliminated. Accordingly, in a particular embodiment, there is no hydrogen purification unit, such as Pressure Swing Adsorption (PSA) unit arranged downstream the membrane unit, thus further reducing at least plant size. CAPEX is thereby further reduced.

[0079] In an embodiment

[0080] - the CO2-removal section 26 is arranged as a membrane unit in series with: a CO2-ab- sorption / desorption unit or a cryogenic separation unit;

[0081] - wherein the membrane unit is arranged to provide: a first CCh-rich gas, and said CO2- depleted synthesis gas 29 as a hydrogen product 29;

[0082] - wherein the CCh-absorption / desorption unit or the cryogenic separation unit is arranged to receive said first CCh-rich gas and provide said CCh-rich gas 31 as a CO2- product, the CCh-product having a higher purity than the first CCh-rich gas; - optionally, the plant comprises at least one of: a CCh-product booster compressor arranged to receive the CCh-product 31 and to supply the CCh-product 31 at the required pressure for use downstream; and a H2-product booster compressor arranged to receive the hydrogen product 29 and to supply the hydrogen product 29 at the required pressure for use downstream.

[0083] Preferably, the plant is absent of a hydrogen purification unit 28, such as a pressure swing adsorption (PSA) unit, arranged downstream the CCh-removal section 26.

[0084] The CC>2-absorption / desorption unit is an amine wash unit.

[0085] The membrane unit is for instance a hollow fiber membrane comprising one or more modules, as disclosed in e.g. WO 2024121590 A1.

[0086] Hence, in the CO2-removal section according to this embodiment, hydrogen is removed in a membrane unit upstream the CO2 removal unit arranged as a CO2-absorption / de- sorption unit i.e. amine wash unit or a cryogenic separation unit.

[0087] Conventionally, synthesis gas containing 70-75 vol.% H2 is sent to a CO2-removal unit where CO2 is captured at low pressure. The large hydrogen content in the synthesis gas increases equipment size and energy cost. Removing hydrogen upstream the CO2 removal unit reduces its size and associated costs. The associated plot size of the CC>2-removal unit arranged as a CCh-absorption / desorption unit i.e. amine wash unit or a cryogenic separation unit is consequently significantly reduced. Further, a PSA unit, typically used in a hydrogen plant and typically also arranged downstream the CCh-re- moval unit, is not required, while energy consumption is also reduced due to the smaller process gas flow. Downside is that the hydrogen product comes out at low pressure and additional compression cost may be expected.

[0088] While the total booster compressor duty may be increased, there is a higher CO2 content in the process gas to the CO2 removal unit, which increases its efficiency. The amine wash unit suitably produces a high pressure (HP flash gas) and, which as recited, can be recycled back to reforming section as feed or fuel gas with only a small booster compressor. In either of the above embodiments where hydrogen is removed from the synthesis gas via a membrane unit, either the membrane unit being arranged alone or with a serially arranged downstream CCh-removal unit, there is a much smaller plot space. H2 purity may be reduced compared to where a PSA unit is provided, yet fuel grade H2 can still be produced. Some impurities (CH4, CO, H2) remain in the CO2-rich gas from the membrane unit. The H2 purity may be increased by providing a two-step membrane unit, such as two membrane modules arranged in the membrane unit, or a PSA unit on the H2 permeate stream from the membrane unit.

[0089] In an embodiment, the CO2-removal section 26 is arranged as a CO2-absorption / de- sorption unit or a cryogenic separation unit; and the plant further comprises:

[0090] - a hydrogen purification unit 28 arranged to receive the CO2-depleted synthesis gas 29 and provide: a hydrogen purification unit H2-rich gas 33 as a hydrogen product 33, and a hydrogen purification unit off-gas 13;

[0091] - a conduit arranged to supply at least a portion of the hydrogen purification unit off-gas 13 as fuel 13” or as additional hydrocarbon feed 13’ to at least one of: the reforming section and the WGS section.

[0092] The at least a part of the the hydrogen purification unit off-gas can be compressed in a hydrogen purification unit off-gas recycle compressor 16, heated as required and supplied to the reforming section and / or the WGS section. For instance, the compressed portion 13’ of the hydrogen purification unit off-gas 13 is supplied to a pre-reformer 12 arranged upstream the reforming unit 14 and / or to the raw synthesis gas 21 or partly shifted synthesis gas 23 in the WGS section. Upstream the hydrogen purification unit off-gas recycle compressor 16 a portion is withdrawn as fuel 13” supplied to e.g burners of a SMR or of a HER arranged as a HTCR, or to a fired heater associated with an ATR.

[0093] Thereby, higher integration of streams for not only use as fuel gas but as part of hydrocarbon feed, is achieved. There are reduced CO2 emissions. The carbon intensity (Cl) is thus further reduced. For the purposes of the present application, a CCh-removal section and a hydrogen purification unit are regarded as separate and distinct units. Although in both the CCh-re- moval section and the hydrogen purification unit there is an enrichment in hydrogen, the purpose of each section / unit differs. In a CCh-removal section, for instance a CO2- absorption / desorption unit or a cryogenic separation unit, the purpose is to remove and thereby produce a CCh-rich gas stream as a CCh-product being e.g. at least 99 vol.% CO2, such as at least 99.5 vol.% CO2. In a hydrogen purification unit, for instance a PSA unit or a membrane unit, the purpose is to remove and thereby produce a H2-rich gas stream as a hydrogen product being e.g. at least 99 vol.% H2, such as at least 99.5 vol.% H2.

[0094] For the purposes of the present application, the CCh-removal section may also be arranged as a membrane unit, which provides a CCh-rich gas and a CCh-depleted synthesis gas as the hydrogen product.

[0095] For the purposes of the present application, the CCh-removal section may also be arranged as a membrane unit in series with a CCh-absorption / desorption unit or in series with a cryogenic separation unit, the CCh-removal section providing a CCh-depleted synthesis gas as a hydrogen product and a CCh-rich gas as the CCh-product.

[0096] As it will also become apparent from one or more embodiments, for the purposes of the present application, the CCh-removal section, this being any of: a CCh-absorption / de- sorption unit, a cryogenic separation unit, a membrane unit, and combinations thereof, may also be arranged in the off-gas stream from the hydrogen purification unit, the hydrogen purification unit being any of: a PSA unit, a membrane unit, a cryogenic separation unit, and combinations thereof.

[0097] Accordingly, in an embodiment, the plant 100’ further comprises:

[0098] - optionally, a synthesis gas cooling section 24 arranged to receive the synthesis gas 23, 25 and provide a cooled synthesis gas 27;

[0099] - optionally, a process condensate separator (PC-separator) arranged to receive the cooled synthesis gas 27 and provide: a process condensate stream and a water-depleted synthesis gas; - a hydrogen purification unit 28 arranged to receive the synthesis gas 23, 25 or the optional cooled synthesis gas 27 or the optional water-depleted synthesis gas, and provide: a hydrogen purification unit H2-rich gas 33 as a hydrogen product 33, and a hydrogen purification unit off-gas 13; preferably, the hydrogen purification unit (28) is arranged to directly receive: the synthesis gas (23, 25) or the optional cooled synthesis gas (27) or the optional water-depleted synthesis gas;

[0100] - a hydrogen purification unit off-gas compressor 16 and an optional drying unit, arranged to receive the hydrogen purification unit off-gas 13 and provide a compressed- and-optionally dried hydrogen purification unit off-gas 13’;

[0101] - an off-gas CCh-removal section 44 arranged to receive at least a portion of the com- pressed-and-optionally dried hydrogen purification unit off-gas 13’, and provide: a CO2- rich gas 47 as a CCh-product 47 and a CCh-depleted hydrogen purification unit off-gas 45;

[0102] - a conduit arranged to supply at least a portion 45’, 45” of the CCh-depleted hydrogen purification unit off-gas 45 as fuel 45” or as additional hydrocarbon feed 45’ to at least one of: the reforming section and the WGS section.

[0103] As recited above, the hydrogen purification unit 28 is preferably arranged to directly receive the synthesis gas 23, 25, or to directly receive the optional cooled synthesis gas 27 or to directly receive the optional water-depleted synthesis gas. There is no CCh-re- moval section in between the WGS section and the hydrogen purification unit.

[0104] More generally, for the purposes of the present application, the term “to directly receive” or “to directly supply” means that there are no units changing the composition of a process stream. Accordingly, there is direct fluid communication in between the associated units. For instance, in the present embodiment, the hydrogen purification unit is preferably: in direct fluid communication with the WGS section providing the synthesis gas, or in direct fluid communication with the synthesis gas cooling section providing the cooled synthesis gas, or in direct fluid communication with the PC-separator providing the water-depleted synthesis gas.

[0105] Thereby, the off-gas 002-removal section is smaller, enabling lower in capital and operating expenditures (CAPEX and OPEX) compared to when provided in the larger synthesis gas stream e.g. upstream the hydrogen purification unit. In an embodiment, the plant 100” further comprises:

[0106] - optionally, a synthesis gas cooling section 24 arranged to receive the synthesis gas 23, 25 and provide a cooled synthesis gas 27;

[0107] - optionally, a process condensate separator (PC-separator) arranged to receive the synthesis gas 23, 25 or the optional cooled synthesis gas 27, and provide: a process condensate stream and a water-depleted synthesis gas;

[0108] - a second 34 high temperature hydrogen separation unit (second HT ^-separation unit, 34) arranged to receive at least a portion of the synthesis gas 23, 25 or at least a portion of the optional cooled synthesis gas 27 or at least a portion of the optional water-depleted synthesis gas, and provide: a second 35 HT hydrogen-rich gas (second HT H2-rich gas, 35), preferably a second 35 HT H2-rich low-pressure gas (second HT H2-rich LP gas, 35); and a second 37 HT hydrogen-lean gas (second HT H2-lean gas, 37), preferably a second 3) HT H2-lean high-pressure gas (second HT H2-lean HP gas, 37); wherein the plant further comprises:

[0109] - a CC>2-rich gas cooling section 36 arranged to receive the second 37 HT H2-lean gas and provide: a cooled H2-lean gas 39 as a CCh-product 39;

[0110] - optionally, a CCh-removal section arranged to receive the CCh-product 39 and provide a further purified CCh-product;

[0111] - a H2-rich gas cooling section 40 arranged to receive: at least a portion of the second HT H2-rich LP gas 35, optionally together with a portion 19’ of the first HT H2-rich gas 19, via mixing point 38, as a combined H2-rich gas 41 , and provide: a hydrogen product 43;

[0112] - a H2-product booster compressor 42 arranged to receive the hydrogen product 43 and to supply the hydrogen product 43’ at the required pressure for use downstream.

[0113] Thereby, the CCh-product is withdrawn at high pressure and readily available for e.g. sequestration, suitably also without extensive CO2 removal, which is advantageous, despite the provision of the second HT ^-separation unit and the H2-product booster compressor. Since the process flow through the WGS section has been reduced via the provision upstream of the first HT ^-separation unit, the provision of the second HT H2-separation unit may be provided at lower costs. For instance, the first HT H2- separation unit may be provided as a Pd-based membrane unit, while the second HT H2-separation unit may be provided without the need of Pd, e.g. as a hollow fiber membrane comprising one or more modules, as disclosed in e.g. WO 2024121590 A1.

[0114] In an embodiment, the plant further comprises a conduit arranged to supply a portion of the second HT H2-rich gas 35 as fuel to the reforming section, optionally together with the at least a portion of the first HT H2-rich gas 19.

[0115] This enables further reduction of the carbon footprint (CO2 emissions) and thereby further reduction of Cl in the plant / process.

[0116] In an embodiment, the plant is arranged to supply the at least a portion of the first HT H2-rich gas 19 and / or said portion of the second HT H2-rich gas 35:

[0117] - as fuel to one or more burners of the reforming unit 14, the reforming unit being arranged as a steam methane reformer (SMR) or a convection reformer i.e. a heat exchanger reformer (HER); and / or

[0118] - as fuel to one or more burners of a fired heater arranged in the plant for providing heat to at least the reforming unit 14 i.e. the plant comprises a fired heater providing heat to at least the reforming unit 14, the reforming unit being arranged as an ATR.

[0119] As already explained, the carbon intensity (Cl) of the plant is thereby significantly reduced.

[0120] The HER is suitably arranged as a HTCR, as described above, where a burner is arranged to provide the heat for the bayonet tubes arranged within the HTCR. In an SMR, also referred in the art as tubular reformer, a number of burners are arranged to provide the heat for the catalyst tubes arranged within the SMR. The burners typically also utilize an externally sourced fuel gas such as natural gas, thereby causing significant CC>2-emissions in the produced flue gas. The invention enables at least significant reduction of the natural gas, as a hydrogen-rich gas is utilized as fuel gas, while at the same time the flue gas is outputted as a CCh-depleted flue gas, i.e. flue gas with a low content of CO2. The term “flue gas” means a gas obtained from burning hydrocarbon streams and / or hydrogen, the flue gas containing mainly CO2, N2 and H2O with traces of CO, Ar and other impurities, plus a little surplus of O2.

[0121] In an embodiment,

[0122] - the reforming section comprises a pre-reforming unit 12, preferably an adiabatic prereforming unit 12, arranged upstream the reforming unit 14;

[0123] - the plant comprises: a hydrogen purification unit off-gas compressor 16 arranged to receive the at least a portion of the hydrogen purification unit off-gas 13, and provide a high-pressure off-gas (HP off-gas 13’); a low-pressure off-gas (LP off-gas 13”) diverted upstream said hydrogen purification unit off-gas compressor 1) as a portion of the hydrogen purification unit off-gas 13;

[0124] - wherein:

[0125] - the pre-reforming unit 12 is arranged to receive, preferably to directly receive, at least a portion of the HP off-gas 13’; and / or

[0126] - the plant is further arranged to supply, preferably to directly supply, at least a portion of the LP off-gas 13”: as fuel to one or more burners of the reforming unit 14, the reforming unit 14 being arranged as an SMR or a convection reformer i.e. heat exchange reformer (HER); or as fuel to one or more burners of a fired heater providing heat to the reforming unit 14, the reforming unit being arranged as an ATR.

[0127] This enables further integration in the plant / process, with the hydrogen purification unit off-gas, which contains some methane and lower hydrocarbons as well as hydrogen, advantageously being incorporated into the hydrocarbon feed to the pre-reforming unit, or for use as fuel in burners, e.g. in a fired heater.

[0128] The hydrogen-purification unit off-gas may also be used for providing energy in other units, such as any units where natural gas is normally used, for instance auxiliary boilers for steam generation.

[0129] In a pre-reforming unit, all higher hydrocarbons can be converted to carbon oxides and methane, but the pre-reforming unit is also advantageous for light hydrocarbons. Providing the pre-reforming unit, hence pre-reforming step, may have several advantages including, for instance where the reforming unit immediately downstream the pre-reforming unit is an ATR, by reducing the required O2 consumption in the ATR and allowing higher inlet temperatures to the ATR since cracking risk by preheating is minimized. Furthermore, the pre-reforming unit may provide an efficient sulfur guard resulting in a practically sulfur free feed gas entering the ATR and the downstream system. The pre-reforming step may be carried out at temperatures between 300-650°C, preferably 390-480°C.

[0130] A pre-reforming unit may be arranged upstream the reforming unit, in which the reforming unit is a HER arranged in series or in parallel with the ATR.

[0131] As already described, the reforming section may further comprise a hydrocarbon feed gas purification section, suitably a hydrogenation unit and a sulfur absorption unit which are arranged upstream said pre-reformer unit or upstream said reforming unit. Suitably, a portion of a H2-rich gas produced in the plant is sent via hydrogen-recycle compressor to the hydrocarbon feed gas before being fed to the feed side of the hydrogenator unit. Thereby, sulfur in the hydrocarbon feed gas which is detrimental for downstream catalysts is removed while at the same time the energy consumption is further reduced, as hydrogen produced is used in the main hydrocarbon feed gas prior to it entering the hydrogenator instead of using external hydrogen sources.

[0132] The term “feed side” means inlet side or simply inlet. For instance, the feed side of the hydrogenator unit means the inlet side of the hydrogenator unit.

[0133] It is understood that the reforming section is the section of the plant comprising units up to and including the reforming unit, such as the ATR. The reforming section may thus comprise: the hydrocarbon feed gas purification section which comprises a hydrogenation and a sulfur absorption unit, a pre-reformer unit and a reforming unit. The pre-re- former unit may be arranged as a plurality of pre-reforming units, such as an adiabatic pre-reforming unit or a plurality of adiabatic pre-reforming units. The reforming unit may be arranged as a single reforming unit arranged immediately downstream the pre-re- forming unit, such as an ATR arranged immediately downstream the pre-reforming unit. The reforming unit may be arranged as a plurality of reforming units, such as a convection heated reformer arranged in series with an ATR. The reforming section may be arranged to being absent of a pre-reforming unit, with the reforming unit being arranged e.g. as a convection heated reformer along with an ATR.

[0134] As recited, the plant is suitably arranged to combine any of: the first HT H2-rich gas, the second HT H2-rich gas and the LP off-gas, before being supplied as fuel.

[0135] In an embodiment,

[0136] - any of the first high temperature hydrogen separation unit (first HT ^-separation unit, 18) and second high temperature hydrogen separation unit (second HT ^-separation unit, 34) is arranged as a membrane unit, preferably as a Pd-based membrane unit; and / or

[0137] - the hydrogen purification unit 28 is at least one of: a membrane unit, preferably a Pd- based membrane unit, a pressure swing adsorption (PSA) unit and a cryogenic separation unit.

[0138] Membrane units, such as Pd-based membrane units, PSA and cryogenic separation units are well-known in the art.

[0139] In a second aspect of the invention, there is provided a process 100, 100’, 100” for producing a synthesis gas 21 , 23, 25, the synthesis gas being at least one of a raw synthesis gas 21 and a shifted synthesis gas 23, 25, the process comprising:

[0140] - converting a hydrocarbon feed gas 1 , 3, 7 to a first raw synthesis gas 15 in a reforming section comprising a reforming unit 14;

[0141] - splitting the first raw synthesis gas 15 into at least: a second 15’ raw synthesis gas and a third 15” raw synthesis gas;

[0142] - supplying the second 15’ raw synthesis gas to a first high temperature hydrogen separation unit (first HT ^-separation unit, 18) and withdrawing therefrom: a first 19 hydrogen-rich gas (first HT H2-rich gas, 19), preferably a first 19 HT H2-rich low-pressure gas (first HT H2-rich LP gas, 19); and a first 17 hydrogen-lean gas (first HT H2-lean stream, 17), preferably a first 17 HT H2-lean high-pressure gas (first HT H2-lean HP gas, 17); - supplying at least a portion of the first 19 HT H2-rich gas as fuel to the reforming section;

[0143] - combining at least a portion of the third 15” raw synthesis gas with at least a portion of the first 17 HT H2-lean gas into a fourth 21 raw synthesis gas as said raw synthesis gas 21 ;

[0144] - optionally supplying the raw synthesis gas 21 to a water gas shift (WGS) section comprising one or more WGS conversion units 20, 22 and withdrawing therefrom a shifted synthesis gas 23, 25.

[0145] Any of the embodiments and associated benefits of the first aspect (plant) of the invention may be used in connection with the second aspect (process) of the invention, or vice versa.

[0146] For instance:

[0147] In an embodiment, the process comprises:

[0148] - said optional step of supplying the raw synthesis gas to a water gas shift (WGS) section comprising one or more WGS conversion units and withdrawing therefrom a shifted synthesis gas as said synthesis gas;

[0149] - operating the first HT ^-separation unit at a temperature corresponding to the inlet temperature of the first of the one or more of the WGS conversion units of the WGS section.

[0150] In an embodiment, the process comprises operating the first HT ^-separation unit in the temperature range 200-500°C such as 300-475°C, or such as 300-400°C.

[0151] In an embodiment, the process comprises:

[0152] - suppling the first raw synthesis gas to a heat exchanging unit such as a waste heat boiler (WHB) and withdrawing therefrom a cooled first raw synthesis gas prior to said splitting of the raw synthesis gas, preferably at said temperature of 200-500°C, and in which the second raw synthesis gas is less than 80 vol%, such as 10-50% vol. of the first raw synthesis gas, for instance: 15 or 20 or 25 or 30 or 35 or 40 or 45 vol.% of the first raw synthesis gas. In an embodiment, the process comprises:

[0153] - supplying the synthesis gas to a synthesis gas cooling section and withdrawing therefrom a cooled synthesis gas;

[0154] - optionally, supplying the cooled synthesis gas to a process condensate separator (PC-separator) and withdrawing therefrom: a process condensate stream and a water- depleted synthesis gas;

[0155] - supplying the cooled synthesis gas or the optional water-depleted synthesis gas to a CC>2-removal section and withdrawing therefrom: a CCh-rich gas, and a CCh-depleted synthesis gas.

[0156] In a third aspect, the invention relates to a method of modifying an existing plant for producing a synthesis gas. The synthesis gas being at least one of a raw synthesis gas and a shifted synthesis gas. The existing plant comprising a reforming section comprising a reforming unit arranged to convert a hydrocarbon feed gas to a first raw synthesis gas.

[0157] The method of modifying the plant comprising the steps of:

[0158] Providing a splitting point downstream of the reforming unit. The splitting point being arranged to split the first raw synthesis gas into at least a second raw synthesis gas and a third raw synthesis gas.

[0159] Providing a first high temperature hydrogen separation unit and arranging said first high temperature hydrogen separation unit to receive the second raw synthesis gas.

[0160] The first high temperature hydrogen separation unit being configured to provide a first hydrogen-rich gas (first HT H2-rich gas), preferably a first HT H2-rich low-pressure gas (first HT H2-rich LP gas, 19); and a first hydrogen-lean gas (first HT H2-lean stream), preferably a first HT H2-lean high-pressure gas (first HT H2-lean HP gas).

[0161] Providing a conduit and arranging said conduit to supply at least a portion of the first HT H2-rich gas as fuel to the reforming section.

[0162] Providing a mixing point and arranging said mixing point to combine at least a portion of the third raw synthesis gas with at least a portion of the first HT H2-lean gas into a fourth raw synthesis gas as said raw synthesis gas.

[0163] In one embodiment the method of modifying the existing plant further comprises the step of providing a temperature controlling means upstream of the splitting point and configuring the temperature controlling means to adjust the temperature of the first raw synthesis gas. The temperature controlling means may be a heat exchanging unit such as a waste heat boiler (WHB) arranged to receive the first raw synthesis gas and provide a cooled first raw synthesis gas upstream said splitting point. Preferably the temperature controlling means is configured to provide a cooled first raw synthesis gas at a temperature of 200-500°C.

[0164] In one or more embodiments the method of modifying the existing plant further comprises the step of providing a second temperature controlling means downstream of the mixing point, such as upstream of a water gas shift (WGS) section and / or integrated with a water gas shift section. The second temperature controlling means may be a steam addition point and / or a heat exchanger.

[0165] The water gas shift reactions are dependent on the amount of hydrogen in the raw synthesis gas. As the hydrogen concentration is lowered the temperature development in a water gas shift unit increase. Depending on the specification of an existing water gas shift unit(s) it may therefore be necessary to provide the second temperature controlling means to one or more water gas shift unit.

[0166] The invention provides at least the following advantages:

[0167] - Significant reduction in the carbon intensity (Cl) due to lower CO2 emissions.

[0168] - Utilization of low-pressure (LP) and high temperature (HT) hydrogen suitably as fuel for the reforming section.

[0169] - Reduction of process flow through the WGS section, optionally where the plant is arranged for producing hydrogen-rich syngas, such as for hydrogen or ammonia production, also reduction of process flow through CO2 removal section and hydrogen purification unit e.g. PSA, resulting in smaller equipment in these sections or units.

[0170] - Removal of a portion of H2 from the WGS inlet stream enhances conversion of CO to H2 in the WGS section, resulting in a more efficient process.

[0171] - Relatively higher CO2 concentration in the synthesis gas and therefore, improved CO2 removal in the CO2-removal section, i.e. relatively less energy consumption.

[0172] BRIEF DESCRIPTION OF THE FIGURES

[0173] Fig. 1 shows a plant / process layout according to an embodiment of the invention for the conversion of a hydrocarbon feed gas into a CO2-product and a H2-product. Fig. 2 shows a plant / process layout according to another embodiment of the invention for the conversion of a hydrocarbon feed gas into a CCh-product and a F^-product, in which the CCh-removal section is provided in the off-gas from the hydrogen purification unit.

[0174] Fig. 3 shows a plant / process layout according to another embodiment of the invention for the conversion of a hydrocarbon feed gas into a CCh-product and a H2-product.

[0175] DETAILED DESCRIPTION

[0176] With reference to Fig.1 , a plant / process 100 is shown according to an embodiment of the invention, in which a hydrocarbon feed gas 1 such as natural gas is converted to a first raw synthesis gas 15 in a reforming section. The reforming section comprises a hydrocarbon feed gas purification section 10, suitably a hydrogenation unit and a sulfur absorption unit (not shown), being arranged upstream a pre-reforming unit 12, e.g. one or more adiabatic pre-reforming unit(s). Steam 5 is added to the pre-reforming unit 12, more specifically to the purified hydrocarbon feed gas 3 being supplied to the pre-re- forming unit. A conduit 13’ is arranged to supply, via a hydrogen purification unit off-gas compressor 16, at least a portion of an off-gas 13 (conduit 13) from a hydrogen purification unit 28 arranged downstream as additional hydrocarbon feed 13’ to the reforming section, for instance to the pre-reforming unit 12, e.g. to the purified hydrocarbon feed gas 3 being supplied to the pre-reforming unit 12. The hydrogen purification unit 28 is for instance a PSA unit. The pre-reformed hydrocarbon feed gas 7 is supplied to a reforming unit 14 of the reforming section. The reforming unit 14 is for instance provided as a convection reformer i.e. a heat exchange reformer (HER) arranged together, e.g. in series, with an autothermal reformer (ATR) (not shown). Air 11 is supplied to burners of e.g. the HER and / or a fired heater associated with at least the ATR. A conduit 13” is arranged to supply, from upstream the hydrogen purification unit off-gas compressor 16, at least a portion of the hydrogen purification unit off-gas 13 as low- pressure fuel 13” to the burners. A conduit 19 is arranged to supply at least a portion of a first HT H2-rich gas 19 as fuel to the reforming section, in particular to the burners of the reforming unit 14, from which a CCh-depleted flue gas 9 is withdrawn. A splitting point 30 is arranged downstream the reforming unit 14 to split the first raw synthesis gas 15 into at least: a second 15’ raw synthesis gas and a third 15” raw synthesis gas. A first high temperature hydrogen separation unit (first HT ^-separation unit, 18) is arranged to receive the second 15’ raw synthesis gas and provide: the first 19 hydrogenrich gas (first HT H2-rich gas 19), and a first 17 hydrogen-lean gas (first HT H2-lean stream 17). A mixing point 32 is arranged to combine at least a portion of the third 15” raw synthesis gas with at least a portion of the first 17 HT H2-lean gas into a fourth 21 raw synthesis gas, herein also referred to as raw synthesis gas 21. The process flow is for instance controlled via valves, as shown in the figure.

[0177] The plant 100 may further comprise a water gas shift (WGS) section comprising one or more WGS conversion units 20, 22, such as a high temperatures shift (HTS) unit 20 and low temperature shift (LTS) unit 22. The WGS section is arranged to receive the raw synthesis gas 21 and provide a first shifted (partly) synthesis gas 23 and after the final WGS conversion unit, here the LTS unit 22, a fully shifted synthesis gas 25, herein both shifted synthesis gas streams referred to as “synthesis gas” 23, 25. A synthesis gas cooling section 24 is arranged to receive the synthesis gas 23, 25, preferably synthesis gas 25, and provide a cooled synthesis gas 27; optionally, a process condensate separator (PC-separator, not shown) is arranged to receive the cooled synthesis gas 27 and provide: a process condensate stream and a water-depleted synthesis gas. A 002-removal section 26 is arranged to receive the cooled synthesis gas 27 or the optional water-depleted synthesis gas, and provide: a CO2-rich gas 31 which e.g. is withdrawn for sequestration, as well as a CO2-depleted synthesis gas 29.

[0178] In the embodiment of Fig. 1 the 002-removal section 26 is arranged as a CO2-absorp- tion / desorption unit i.e. amine wash unit, or a cryogenic separation unit, and the plant / process further comprises: the above mentioned hydrogen purification unit 28 which is arranged to receive the CO2-depleted synthesis gas 29 and provide: a hydrogen purification unit H2-rich gas 33 as a hydrogen product 33, and the hydrogen purification unit off-gas 13 of which at least a portion is supplied as fuel 13” or as additional hydrocarbon feed 13’ to the reforming section.

[0179] Fig. 2 is as in Fig. 1 but describes a plant / process 100’ where a 002-removal section 44 is provided in the hydrogen purification unit off-gas 13 from the hydrogen purification unit 28. As in connection with the plant 100 of Fig. 1 , the plant 100’ comprises: optionally, a synthesis gas cooling section 24 arranged to receive the synthesis gas 25 and provide a cooled synthesis gas 27; optionally, a process condensate separator (PC- separator, not shown) arranged to receive the cooled synthesis gas 27 and provide: a process condensate stream and a water-depleted synthesis gas; hydrogen purification unit 28 arranged to directly receive the synthesis gas 25 or the optional cooled synthesis gas 27 or the optional water-depleted synthesis gas, and provide: a hydrogen purification unit H2-rich gas 33 as a hydrogen product 33, and a hydrogen purification unit off-gas 13; a hydrogen purification unit off-gas compressor 16 and an optional drying unit (not shown), arranged to receive the hydrogen purification unit off-gas 13 and provide a compressed-and-optionally dried hydrogen purification unit off-gas 13’. The offgas CC>2-removal section 44 is arranged to receive at least a portion of the com- pressed-and-optionally dried hydrogen purification unit off-gas 13’, and provide: CO2- rich gas 47 as CCh-product 47 and a CCh-depleted hydrogen purification unit off-gas 45; a conduit is arranged to supply at least a portion 45’, 45” of the CCh-depleted hydrogen purification unit off-gas 45 as fuel 45” or as additional hydrocarbon feed 45’ to at least one of: the reforming section as show in the figure and the WGS section (not shown).

[0180] With reference to Fig. 3, the same units and process streams of Fig. 1 are provided up to and including the MTS or LTS shift unit 22 of the WGS section. In the plant / process 100”, The synthesis gas 25 is now converted to a H2-procduct 43’ and a CO2-rich gas 39 by arranging a second 34 high temperature hydrogen separation unit (second HT H2-separation unit 34), which receives the synthesis gas 25 and provides: a second 35 HT hydrogen-rich gas (second HT H2-rich gas 35), and a second 37 HT hydrogen-lean gas (second HT H2-lean gas 37). A CO2-rich gas cooling section 36 is arranged to receive the second 37 HT H2-lean gas 37, which is CO2-rich and at high pressure, and provide: a cooled H2-lean gas 39 as a CO2-product 39. This CO2-product 39 is at high pressure and thus suitable for e.g. sequestration without extensive CO2 removal. A H2- rich gas cooling section 40 is arranged to receive: at least a portion of the second HT H2-rich LP gas 35, optionally together with a portion 19’ of the first HT H2-rich gas 19, via mixing point 38, as a combined H2-rich gas 41 , and provide: a hydrogen product 43. A H2-product booster compressor 42 is arranged to receive the hydrogen product 43 and to supply the hydrogen product 43’ at the required pressure for use downstream. EXAMPLES

[0181] Utilization of low pressure (LP) and high temperature (HT) hydrogen as fuel from high temperature (HT)-H2 separation has a synergistic effect in synthesis gas generation process / plant with higher focus on less carbon dioxide emissions, such as - Blue-H2 process / plant. In Table 1 below, the key parameters from a simulation as per the invention according to the embodiment of Fig. 1 is compared to that from the prior art.

[0182] Table 1

[0183] UoM: units of measure

[0184] In Table 1 , C1 represents prior art, where LP and HT H2 from HT-H2 separation section is cooled and compressed as a part of the product. The hydrogen purification unit offgas is entirely used as fuel. Additional energy requirement is supplied by burning fossil fuel, such as natural gas.

[0185] On the other hand, C2 represents a process / plant in accordance with the present invention, where LP and HT H2 from HT-H2 separation section in its entirety is used as fuel. Only a fraction of hydrogen purification unit off-gas is used as fuel, which also functions as the purge of inerts entering the process via hydrocarbon feed. The inerts exit the plant via the flue gas. Unlike the prior art (C1), only a 49% of the first raw syngas exiting the reforming section is directed to HT-H2 separation.

[0186] The hydrocarbon feed gas + fuel consumption increases in 02 by 3%-point. This increase caters lower LHV (Lower Heating Value) of H2 fuel compared to that of hydrocarbon fuel. Yet, the provision of LP and HT-H2 as fuel allows better utilization of the off-gas from downstream hydrogen purification unit in view of carbon capture. Consequently, carbon intensity (Cl), a proxy of which is expressed herein as unit of CO2 emission per unit of product, the product here being hydrogen, is reduced by 75% by adopting principles as per present invention. Above 90% carbon capture is achieved in the process. Even higher carbon capture is achieved where the requirement of off-gas purge by using it as fuel is reduced. This is linked to inert content in the feed. Relatively higher portion of first raw syngas flow needs to be directed to the HT-H2 separation section.

Claims

CLAIMS1. Plant (100, 100’, 100”) for producing a synthesis gas (21 , 23, 25), the synthesis gas being at least one of a raw synthesis gas (21) and a shifted synthesis gas (23, 25), the plant comprising:- a reforming section comprising a reforming unit (14) arranged to convert a hydrocarbon feed gas (1 , 3, 7) to a first raw synthesis gas (15);- a splitting point (30) arranged to split the first raw synthesis gas (15) into at least: a second (15’) raw synthesis gas and a third (15”) raw synthesis gas;- a first high temperature hydrogen separation unit (first HT ^-separation unit, 18) arranged to receive the second (15’) raw synthesis gas and provide: a first (19) hydrogen-rich gas (first HT H2-rich gas, 19), preferably a first (19) HT H2-rich low-pressure gas (first HT H2-rich LP gas, 19); and a first (17) hydrogen-lean gas (first HT H2-lean stream, 17), preferably a first (17) HT H2-lean high-pressure gas (first HT H2-lean HP gas, 17);- a conduit arranged to supply at least a portion of the first HT H2-rich gas (19) as fuel to the reforming section;- a mixing point (32) arranged to combine at least a portion of the third (15”) raw synthesis gas with at least a portion of the first (17) HT H2-lean gas into a fourth (21) raw synthesis gas as said raw synthesis gas (21).

2. Plant according to claim 1 , wherein the plant comprises:- a water gas shift (WGS) section comprising one or more WGS conversion units (20, 22) arranged to receive the raw synthesis gas (21) and provide said shifted synthesis gas (23, 25); and wherein the first HT ^-separation unit (18) is arranged to operate at a temperature corresponding to the inlet temperature of the first (20) of the one or more of the WGS conversion units (20, 22) of the WGS section.

3. Plant according to anyone of the preceding claims, wherein the first HT ^-separation unit (18) is arranged to operate in the temperature range 200-500°C, such as 300- 475°C, or such as 300-400°C.

4. Plant according to anyone of the preceding claims, wherein the plant comprises a heat exchanging unit such as a waste heat boiler (WHB) arranged to receive the firstraw synthesis gas (15) and provide a cooled first raw synthesis gas upstream said splitting point (30), preferably at said temperature of 200-500°C, and wherein the second (15’) raw synthesis gas is less than 80 vol.%, such as 10-50 vol.% of the first raw synthesis gas (15).

5. Plant according to anyone of the preceding claims, wherein the reforming unit (14) is at least one of: a steam methane reformer (SMR), an electrically heated steam methane reformer (e-SMR), a convection reformer i.e. a heat exchange reformer (HER), and an autothermal reformer (ATR).

6. Plant according to anyone of the preceding claims, wherein the plant (100) further comprises:- a synthesis gas cooling section (24) arranged to receive the synthesis gas (23, 25), preferably the synthesis gas (25) from the last WGS conversion unit (22) of the WGS section, and provide a cooled synthesis gas (27);- optionally, a process condensate separator (PC-separator) arranged to receive the cooled synthesis gas (27) and provide: a process condensate stream and a water-depleted synthesis gas;- a 002-removal section (26) arranged to receive the cooled synthesis gas (27) or the optional water-depleted synthesis gas, and provide: a CO2-rich gas (31) and a CO2-de- pleted synthesis gas (29).

7. Plant according to claim 6, wherein the 002-removal section (26) is arranged as a CO2-absorption / desorption unit (26) which further provides a high-pressure flash gas (HP flash gas); and wherein the plant is arranged according to at least one of the following configurations:- the reforming unit (14) is a convection reformer i.e. a heat exchange reformer (HER) arranged in series or in parallel with an autothermal reformer (ATR); and the convection reformer is further arranged to receive at least a portion of at least one of: the CO2- depleted synthesis gas (29) and the HP flash gas;- the reforming section comprises a hydrocarbon feed gas purification section (10) arranged upstream the reforming unit (14) and arranged to receive the hydrocarbon feed gas (1), the hydrocarbon feed gas purification section (10) preferably comprises a hy- drogenator and sulfur absorber, and the hydrocarbon feed gas purification section (10)is further arranged to receive at least a portion of the CCh-depleted synthesis gas (29), optionally at least a portion of the HP flash gas;- the CC>2-absorption / desorption unit (26) is further arranged to receive at least a portion of the HP flash gas as an internal recycle stream;- at least a portion of the HP flash gas is provided as fuel to one or more burners of the reforming unit (14), the reforming unit being arranged as a steam methane reformer (SMR) or a convection reformer i.e. a heat exchanger reformer (HER);- the plant comprises a fired heater providing heat to at least the reforming unit (14); and at least a portion of the HP flash gas is provided as fuel to one or more burners of the fired heater, the reforming unit being arranged as an ATR.

8. Plant according to claim 6, wherein the CCh-removal section (26) is arranged as a membrane unit and provides: said CCh-rich gas (31) as a CO2-product (31), and said CC>2-depleted synthesis gas (29) as a hydrogen product (29); optionally, the plant comprises at least one of: a CCh-product booster compressor arranged to receive the CCh-product (31) and to supply the CCh-product (31) at the required pressure for use downstream; and a H2-product booster compressor arranged to receive the hydrogen product (29) and to supply the hydrogen product (29) at the required pressure for use downstream.

9. Plant according to claim 6,- wherein the CCh-removal section (26) is arranged as a membrane unit in series with: a CC>2-absorption / desorption unit or a cryogenic separation unit;- wherein the membrane unit is arranged to provide: a first CCh-rich gas, and said CO2- depleted synthesis gas (29) as a hydrogen product (29);- wherein the CCh-absorption / desorption unit or the cryogenic separation unit is arranged to receive said first CCh-rich gas and provide said CCh-rich gas (31) as a CO2- product, the CCh-product having a higher purity than the first CCh-rich gas;- optionally, the plant comprises at least one of: a CCh-product booster compressor arranged to receive the CCh-product (31) and to supply the CCh-product (31) at the required pressure for use downstream; and a H2-product booster compressor arranged to receive the hydrogen product (29) and to supply the hydrogen product (29) at the required pressure for use downstream.

10. Plant according to claim 6, wherein the CCh-removal section (26) is arranged as a CCh-absorption / desorption unit or a cryogenic separation unit; and wherein the plant further comprises:- a hydrogen purification unit (28) arranged to receive the CCh-depleted synthesis gas (29) and provide: a hydrogen purification unit H2-rich gas (33) as a hydrogen product (33), and a hydrogen purification unit off-gas (13);- a conduit arranged to supply at least a portion of the hydrogen purification unit off-gas (13) as fuel (13”) or as additional hydrocarbon feed (13’) to at least one of: the reforming section and the WGS section.

11. Plant (100’) according to anyone of claims 2-5, wherein the plant further comprises:- optionally, a synthesis gas cooling section (24) arranged to receive the synthesis gas (23, 25) and provide a cooled synthesis gas (27);- optionally, a process condensate separator (PC-separator) arranged to receive the cooled synthesis gas (27) and provide: a process condensate stream and a water-depleted synthesis gas;- a hydrogen purification unit (28) arranged to receive the synthesis gas (23, 25) or the optional cooled synthesis gas (27) or the optional water-depleted synthesis gas, and provide: a hydrogen purification unit H2-rich gas (33) as a hydrogen product (33), and a hydrogen purification unit off-gas (13); preferably, the hydrogen purification unit (28) is arranged to directly receive: the synthesis gas (23, 25) or the optional cooled synthesis gas (27) or the optional water-depleted synthesis gas;- a hydrogen purification unit off-gas compressor (16) and an optional drying unit, arranged to receive the hydrogen purification unit off-gas (13) and provide a compressed- and-optionally dried hydrogen purification unit off-gas (13’);- an off-gas CCh-removal section (44) arranged to receive at least a portion of the com- pressed-and-optionally dried hydrogen purification unit off-gas (13’), and provide: a CC>2-rich gas (47) as a CCh-product (47) and a CCh-depleted hydrogen purification unit off-gas (45);- a conduit arranged to supply at least a portion (45’, 45”) of the CCh-depleted hydrogen purification unit off-gas (45) as fuel (45”) or as additional hydrocarbon feed (45’) to at least one of: the reforming section and the WGS section.

12. Plant according to anyone of claims 1-5, wherein the plant (100”) further comprises:- optionally, a synthesis gas cooling section (24) arranged to receive the synthesis gas (23, 25) and provide a cooled synthesis gas (27);- optionally, a process condensate separator (PC-separator) arranged to receive the synthesis gas (23, 25) or the optional cooled synthesis gas (27), and provide: a process condensate stream and a water-depleted synthesis gas;- a second (34) high temperature hydrogen separation unit (second HT ^-separation unit, 34) arranged to receive at least a portion of the synthesis gas (23, 25) or at least a portion of the optional cooled synthesis gas (27) or at least a portion of the optional water-depleted synthesis gas, and provide: a second (35) HT hydrogen-rich gas (second HT H2-rich gas, 35), preferably a second (35) HT H2-rich low-pressure gas (second HT H2-rich LP gas, 35); and a second (37) HT hydrogen-lean gas (second HT H2-lean gas, 37), preferably a second (37) HT H2-lean high-pressure gas (second HT H2-lean HP gas, 37); wherein the plant further comprises:- a CC>2-rich gas cooling section (36) arranged to receive the second (37) HT H2-lean gas and provide: a cooled H2-lean gas (39) as a CCh-product (39);- optionally, a CCh-removal section arranged to receive the CCh-product (39) and provide a further purified CCh-product;- a H2-rich gas cooling section (40) arranged to receive: at least a portion of the second HT H2-rich LP gas (35), optionally together with a portion (19’) of the first HT H2-rich gas (19), via mixing point (38), as a combined H2-rich gas (41), and provide: a hydrogen product (43);- a H2-product booster compressor (42) arranged to receive the hydrogen product (43) and to supply the hydrogen product (43’) at the required pressure for use downstream.

13. Plant according to claim 12, wherein the plant further comprises a conduit arranged to supply a portion of the second HT H2-rich gas (35) as fuel to the reforming section, optionally together with the at least a portion of the first HT H2-rich gas (19).

14. Plant according to anyone of claims 12-13, wherein the plant is arranged to supply the at least a portion of the first HT H2-rich gas (19) and / or said portion of the second HT H2-rich gas (35):- as fuel to one or more burners of the reforming unit (14), the reforming unit being arranged as a steam methane reformer (SMR) or a convection reformer i.e. a heat exchanger reformer (HER); and / or- as fuel to one or more burners of a fired heater arranged in the plant for providing heat to at least the reforming unit (14), the reforming unit being arranged as an ATR.

15. Plant according to anyone of claims 1-10, 12-14,:- wherein the reforming section comprises a pre-reforming unit (12), preferably an adiabatic pre-reforming unit (12), arranged upstream the reforming unit (14);- wherein the plant comprises: a hydrogen purification unit off-gas compressor (16) arranged to receive the at least a portion of the hydrogen purification unit off-gas (13), and provide a high-pressure off-gas (HP off-gas 13’); a low-pressure off-gas (LP off-gas 13”) diverted upstream said hydrogen purification unit off-gas compressor (16) as a portion of the hydrogen purification unit off-gas (13);- wherein:- the pre-reforming unit (12) is arranged to receive, preferably to directly receive, at least a portion of the HP off-gas (13’); and / or- the plant is further arranged to supply, preferably to directly supply, at least a portion of the LP off-gas 13”: as fuel to one or more burners of the reforming unit (14), the reforming unit (14) being arranged as an SMR or a convection reformer i.e. heat exchange reformer (HER); or as fuel to one or more burners of a fired heater providing heat to the reforming unit (14), the reforming unit being arranged as an ATR.

16. Plant according to anyone of the preceding claims,- wherein any of the first high temperature hydrogen separation unit (first HT ^-separation unit, 18) and second high temperature hydrogen separation unit (second HT H2- separation unit, 34) is arranged as a membrane unit, preferably as a Pd-based membrane unit; and / or-wherein the hydrogen purification unit (28) is at least one of: a membrane unit, preferably a Pd-based membrane unit, a pressure swing adsorption (PSA) unit and a cryogenic separation unit.

17. Process (100, 100’, 100”) for producing a synthesis gas (21 , 23, 25), the synthesis gas being at least one of a raw synthesis gas (21) and a shifted synthesis gas (23, 25), the process comprising:- converting a hydrocarbon feed gas (1 , 3, 7) to a first raw synthesis gas (15) in a reforming section comprising a reforming unit (14);- splitting the first raw synthesis gas (15) into at least: a second (15’) raw synthesis gas and a third (15”) raw synthesis gas;- supplying the second (15’) raw synthesis gas to a first high temperature hydrogen separation unit (first HT ^-separation unit, 18) and withdrawing therefrom: a first (19) hydrogen-rich gas (first HT H2-rich gas, 19), preferably a first (19) HT H2-rich low-pressure gas (first HT H2-rich LP gas, 19); and a first (17) hydrogen-lean gas (first HT H2-lean stream, 17), preferably a first (17) HT H2-lean high-pressure gas (first HT H2-lean HP gas, 17);- supplying at least a portion of the first (19) HT H2-rich gas as fuel to the reforming section;- combining at least a portion of the third (15”) raw synthesis gas with at least a portion of the first (17) HT H2-lean gas into a fourth (21) raw synthesis gas as said raw synthesis gas (21);- optionally supplying the raw synthesis gas (21) to a water gas shift (WGS) section comprising one or more WGS conversion units (20, 22) and withdrawing therefrom said shifted synthesis gas (23, 25).

18. A method of modifying a plant for producing a synthesis gas, the synthesis gas being at least one of a raw synthesis gas and a shifted synthesis gas, the plant comprising a reforming section comprising a reforming unit arranged to convert a hydrocarbon feed gas to a first raw synthesis gas; the method of modifying the plant comprising the steps of:- providing a splitting point downstream of the reforming unit, said splitting point being arranged to split the first raw synthesis gas into at least a second raw synthesis gas and a third raw synthesis gas;- providing a first high temperature hydrogen separation unit and arranging said first high temperature hydrogen separation unit to receive the second raw synthesis gas, -the first high temperature hydrogen separation unit being configured to provide a first hydrogen-rich gas (first HT H2-rich gas), preferably a first HT H2-rich low-pressure gas(first HT H2-rich LP gas, 19) and to provide a first hydrogen-lean gas (first HT H2-lean stream), preferably a first HT H2-lean high-pressure gas (first HT H2-lean HP gas);- providing a conduit and arranging said conduit to supply at least a portion of the first HT H2-rich gas as fuel to the reforming section; -providing a mixing point and arranging said mixing point to combine at least a portion of the third raw synthesis gas with at least a portion of the first HT H2-lean gas into a fourth raw synthesis gas as said raw synthesis gas.

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