Low-carbon hydrocarbon fuels

Abstract

The invention provides an apparatus and method for producing a hydrogen rich gas, the method comprising the steps of reforming a hydrocarbon feed in an autothermal reformer to obtain a synthesis gas; shifting the synthesis gas in a shift configuration comprising a high temperature shift step; removing CO2 in a CO2 removal section by amine washing to form a hydrogen rich stream, wherein a portion is used as a low carbon hydrogen fuel; and forming a CO2 rich gas stream and a high pressure flash gas stream. The high pressure flash gas stream is advantageously integrated into the apparatus and method to further improve carbon capture.

Description

Technical Field

[0001] This invention relates to the decarbonization of hydrocarbon gases such as natural gas. In particular, this invention relates to an apparatus and method for producing hydrogen from a hydrocarbon feedstock, comprising one or more flame heaters for preheating the hydrocarbon feedstock, reforming, shift conversion, and CO2 removal. Specifically, this invention relates to an apparatus and method for producing hydrogen from a hydrocarbon feedstock, wherein the hydrocarbon feedstock is reformed in an optional pre-reformer and autothermal reformer (ATR) to produce syngas, the syngas undergoes water-gas shift conversion in a shift section to enrich the syngas with hydrogen, and the shifted gas undergoes a carbon dioxide removal step, thereby producing a CO2-rich stream, an H2-rich stream, and a high-pressure flash stream, wherein at least a portion of the H2-rich stream is used as low-carbon hydrogen fuel for at least one or more flame heaters. The high-pressure flash stream is thus advantageously integrated into the apparatus and method, for example by combining it with the H2-rich stream. Therefore, the apparatus and method are able to provide such low-carbon hydrogen fuel and utilize the high-pressure flash gas to provide a carbon-free or low-carbon alternative to the hydrocarbon gas (e.g., natural gas) used as fuel gas in the apparatus and / or method. Background Technology

[0002] In hydrogen production, a typical process involves steam reforming of natural gas to form syngas, water-gas conversion of the syngas to increase its hydrogen content, removal of CO2 from the syngas, and finally hydrogen purification, usually carried out in a pressure swing adsorption (PSA) unit, to form hydrogen products and PSA waste gas.

[0003] In the context of hydrogen production, most hydrogen today is used as a feedstock for the production of, for example, ammonia, or as part of the hydrotreating process used in oil refineries.

[0004] Other hydrocarbon gases, such as biogas, which mainly contains methane and is produced by the fermentation of organic matter, are often used as a fuel alternative to natural gas.

[0005] US2013 / 0127163A1 describes a method and apparatus (system) for generating and using decarbonized fuel for power generation. The apparatus includes a syngas generation unit (2) using steam (3) from a steam generation unit (24), a water-gas shift unit (6), and an acid gas removal unit (7) for removing carbon dioxide exhaust gas stream (8) and decarbonized fuel stream (11). The decarbonized fuel stream (11) is divided into a first decarbonized fuel stream (12) for a gas turbine generator unit (13) and a second decarbonized fuel stream (23) for the steam generation unit (24). An optional fuel stream (34) from the acid gas removal unit (7) can also be supplied to the steam generation unit (24).

[0006] US2020055738 A1 describes a method and apparatus for synthesizing ammonia from a natural gas feedstock, the apparatus including a pre-reformer (PRE), an autothermal reformer (ATR), a shift converter (SHF), a CO2 removal section (CDR) in an amine washing unit to produce a CO2-rich stream and an H2-rich stream; optional a methanator (MET), an ammonia synthesis section (SYN), a hydrogen recovery unit (HRU), and an AUX flame heater for preheating the natural gas feedstock and using a portion of the H2-rich stream as fuel.

[0007] The aim is to provide a simpler and cheaper method and apparatus for converting hydrocarbon gases, which serve as energy carriers and therefore as fuels, into low-carbon fuels.

[0008] The goal is to use the majority of the hydrogen produced by the self-made hydrogen equipment as a carbon-free fuel for the equipment, rather than using hydrocarbon gases such as natural gas as fuel.

[0009] The aim is to reduce CO2 emissions associated with the use of hydrocarbon gases such as natural gas as fuel.

[0010] They also hope to save on the cost of capturing carbon from hydrocarbon gases, such as industrial gases containing large amounts of hydrocarbons, biogas, or natural gas. Summary of the Invention

[0011] Therefore, in a first aspect, the present invention provides an apparatus for producing an H2-rich stream from a hydrocarbon feedstock, the apparatus comprising:

[0012] - An autothermal reformer (ATR) is arranged to receive a hydrocarbon feed and convert it into a synthesis gas stream;

[0013] - A conversion section, the conversion section comprising one or more water-gas conversion (WGS) units, the one or more WGS units being arranged to receive the synthesis gas stream from the ATR and convert it in one or more WGS steps to provide a converted synthesis gas stream;

[0014] - The CO2 removal section is arranged to receive the transformed synthesis gas stream from the transformation section and separate a CO2-rich stream from the transformed synthesis gas stream, thereby providing the H2-rich stream and also providing a high-pressure flash stream.

[0015] - One or more flame heaters for preheating hydrocarbon feed before it is fed into the ATR;

[0016] The device is arranged to feed at least a portion of the H2-rich stream as hydrogen fuel to at least one or more flame heaters; wherein

[0017] The device (100) does not have a hydrogen purification unit, such as a pressure swing adsorption (PSA) unit, hydrogen membrane, or cryogenic separation unit; and

[0018] The CO2 removal section (170) is an amine washing unit, including a CO2 absorber and a CO2 stripper, as well as a high-pressure flash tank and a low-pressure flash tank, thereby separating the CO2-rich stream (10), the H2-rich stream (8), and the high-pressure flash stream (12); and the equipment (100) is arranged to feed at least a portion of the high-pressure flash stream into a unit or stream of the equipment.

[0019] The unit of the equipment is any unit of the aforementioned equipment, such as a flame heater or an amine washing unit. The flow of the equipment is any flow provided by any of the aforementioned units, such as an H2-rich flow.

[0020] Therefore, in an embodiment according to the first aspect of the invention,

[0021] a) The apparatus (100) is arranged to feed at least a portion of the high-pressure flash stream (12) as fuel to the at least one flame heater (135); and / or

[0022] b) The equipment (100) is arranged to recirculate at least a portion of the high-pressure flash gas flow (12) to the CO2 absorber of the amine washing unit, i.e., as an internal high-pressure (HP) flash gas recirculation flow; and / or

[0023] c) The equipment is arranged to mix at least a portion of the high-pressure flash vapor stream (12) with the H2-rich stream (8).

[0024] Therefore, hydrocarbon feedstock can be decarbonized in a simple way, thereby capturing at least 95% of the carbon while still achieving high hydrogen purity in an H2-rich stream.

[0025] High-pressure flash flow can thus be advantageously integrated into equipment and methods to further improve carbon capture.

[0026] In a second aspect of the invention, as further described below, a method for producing an H2-rich stream from a hydrocarbon feedstock using the apparatus defined herein is also provided.

[0027] Further details of the invention are set forth in the following description, drawings, aspects and dependent claims.

[0028] As used in this article, the term "syngas" refers to syngas, which is a fuel gas mixture rich in carbon monoxide and hydrogen. Syngas typically also contains some carbon dioxide.

[0029] As used herein, the term CO2-rich stream refers to a stream containing 95 vol.% or more, such as 99.5 vol.% or 99.8 vol.% carbon dioxide.

[0030] As used herein, the term H2-rich stream refers to a stream containing 95 vol.% or more, for example 98 vol.% or more of hydrogen, i.e. having a hydrogen purity of more than 95 vol.%, with the balance being small amounts of carbonaceous compounds CH4, CO, CO2, and inert gases N2 and Ar.

[0031] As used herein, the term “hydrogen fuel” is interchangeable with the term “low-carbon hydrogen fuel” and refers to a partially H2-rich stream used as fuel and having a small amount of carbonaceous compounds as described above.

[0032] As used herein, the term "at least a portion of the H2-rich stream" means that the H2-rich stream from the CO2 removal section can be diverted into a separate H2-rich stream, for example, also as an H2 recirculation stream.

[0033] As used herein, the term "for at least one or more of the aforementioned flame heaters" means that hydrogen fuel can also be used in other units for providing energy, such as any unit that typically uses natural gas, for example, an auxiliary boiler. It should be understood that hydrogen fuel is not only used in flame heaters. Hydrogen fuel can also be used as a hydrogen product as needed. Hydrogen fuel can be used in many applications that use natural gas, such as blending it into existing domestic natural gas networks, or for transport fuel, or blending it into the natural gas network of a cracking unit or furnace.

[0034] As used herein, the term "high-pressure flash flow" refers to a gas stream from the CO2 removal section that has a pressure significantly higher than atmospheric pressure, for example 3-10 barg, and has a significant hydrogen content, for example 20-40 vol.%, and a significant CO2 content, for example 60-80 vol.%.

[0035] In an embodiment of the first aspect of the invention, the hydrocarbon feedstock is selected from: natural gas, naphtha, LPG, biogas, industrial gases, or combinations thereof.

[0036] As used in this article, the term "hydrocarbon feed" refers to a gas stream containing hydrocarbons, which can be as simple as methane (CH4) or contain more complex molecules.

[0037] As used herein, the term "natural gas" refers to a mixture of hydrocarbons having methane as its main component. The methane content may be 85 vol% or higher, and other higher hydrocarbons (C2+) such as ethane and propane may also be present.

[0038] As used in this article, the term "naphtha" refers to C5-C... 10 A mixture of hydrocarbons within the specified range, preferably alkanes and alkenes. More specifically, the naphtha fraction contains C5-C64 hydrocarbons. 10The range of hydrocarbons, i.e., according to the characterization of ASTM D86, is IBP = 30°C, 50%BP = 115°C and FBP = 160°C.

[0039] As used herein, the term "LPG" refers to liquefied petroleum gas or liquid petroleum gas, and is a gaseous mixture of hydrocarbons that primarily consist of propane and butane.

[0040] As used in this article, the term "biogas" refers to the gas produced by the fermentation of organic matter, primarily composed of methane and carbon dioxide. The methane content can range from 40-70 vol.%, and the carbon dioxide content from 30-60 vol.%.

[0041] As used herein, the term "industrial gas" refers to hydrocarbon-containing waste gas with a calorific value sufficient for combustion. An example is refinery waste gas, which typically contains components such as dienes, alkenes, CO2, CO, hydrocarbons, H2S, and various organic sulfur compounds.

[0042] In one embodiment of the first aspect of the invention, the apparatus is arranged to divert the H2-rich stream into: i) the H2-rich stream as hydrogen fuel for at least one or more flame heaters, ii) an H2 product stream, and iii) an H2 recycle stream. The H2 product stream may comprise 90 vol.% or more of the H2-rich stream. The portion used for H2 recycle may also be less than 1 vol.%.

[0043] In an embodiment according to the first aspect of the invention, the hydrogen fuel used for at least one flame heater is preferably used in conjunction with a separate fuel gas, such as natural gas, and combustion air. Thus, the necessary heat is generated by burning the mixture of these gases. The use of hydrogen fuel reduces the amount of natural gas that would otherwise be required as a fuel gas. In addition to preheating the hydrocarbon feed gas supplied to the ATR or optionally the pre-reformer, the flame heater can also be used, for example, for superheated steam.

[0044] In an embodiment according to a first aspect of the invention, the equipment has no, i.e., no, steam methane reforming (SMR) unit upstream of the ATR. Therefore, the equipment lacks a primary reforming unit, and thus primary reforming is absent. For example, the equipment lacks a convective reforming unit, such as a gas-heated reforming unit. Therefore, the reforming section of the equipment includes the ATR and optionally a pre-reformer unit, but lacks a steam methane reforming (SMR) unit, i.e., the use of, for example, a conventional SMR (often also called a radiant furnace or tubular reformer) is omitted. This also achieves a reduction in equipment size. Other related technical advantages are further described below.

[0045] This equipment does not include hydrogen purification units such as pressure swing adsorption (PSA) units, hydrogen membranes, or cryogenic separation units. In other words, it lacks dedicated hydrogen purification units like these, which are typically required to further purify the H2-rich stream from the CO2 removal section. This further reduces the equipment size and consequently lowers capital expenditure (CapEx). Other related technical advantages are further described below.

[0046] In an embodiment according to a first aspect of the invention, after the water content as process condensate is removed, the converted gas stream is suitably introduced into the CO2 removal section via a CO2 absorber. Also suitably, in b), the internal HP flash gas recirculation stream is merged with the converted gas stream before being introduced into the CO2 absorber.

[0047] The present invention allows for the combination of embodiments a), b), and c). For example, a portion of the high-pressure flash vapor stream can be recycled as fuel for one or more flame heaters, while another portion of the high-pressure flash vapor stream is recycled (i.e., as an internal HP flash vapor recirculation stream) to the CO2 absorber of an amine washing unit, and yet another portion of the high-pressure flash vapor stream is mixed with an H2-rich stream.

[0048] In an embodiment according to a first aspect of the invention, the apparatus is arranged to combine a) and c) by arranging a mixing point, such as a mixing unit, therein to mix at least a portion of the H2-rich stream (8) as hydrogen fuel with the high-pressure flash stream (12) upstream of one or more flame heaters (135). Thus, a higher degree of integration is achieved, resulting in higher energy efficiency for the apparatus and method.

[0049] Unlike recirculating or mixing only a portion of the high-pressure flash flow as described above, recirculating or mixing the entire high-pressure flash flow can also be advantageous.

[0050] Therefore, in an embodiment according to the first aspect of the invention,

[0051] In a), the equipment is arranged to recycle the entire high-pressure flash vapor stream as fuel for said at least one flame heater; or

[0052] In b), the equipment is arranged to recycle the entire high-pressure flash stream back to the CO2 absorber; or

[0053] In c), the equipment is arranged to mix the entire high-pressure flash vapor stream with the H2-rich stream.

[0054] For example, in b), the apparatus is arranged to recycle at least a portion of the high-pressure flash stream, for example, via a compressor, back to the CO2 absorber. This achieves higher carbon capture, for example, from 95% without recirculation to 97% or higher, for example, when the entire (total) high-pressure flash stream is recirculated. While such partial recirculation of the high-pressure flash stream may result in a significantly lower carbon recovery rate, recirculating the total high-pressure flash stream by returning the entire stream to the CO2 absorber provides the benefit of maintaining both high CO2 purity and high carbon recovery rates.

[0055] For example, in c), the amount of hydrogen present in the high-pressure flash stream is added to the H2-rich stream, enabling the device to efficiently produce an equimolar amount of H2. While this may result in a significantly lower purity of the H2-rich stream, it is a cost-effective way to utilize the high-pressure flash stream without, for example, recirculating at least a portion of it to the CO2 absorber via a compressor or burning at least a portion of it in a flame heater (which would lead to potentially higher CO2 emissions). Mixing the entire high-pressure flash stream with the H2-rich stream further improves device efficiency and reduces costs by maintaining the same CO2 purity.

[0056] The term "equipment efficiency" refers to energy efficiency, which corresponds to the energy consumption of natural gas used in a method (or equipment). Therefore, improved equipment efficiency means reduced natural gas consumption.

[0057] In one embodiment of the invention's first aspect, the device is arranged to supply the hydrocarbon feed to the ATR at a temperature below 600°C, for example, 550°C or 500°C or lower, such as 300-400°C. These temperatures are lower than the typical ATR feed temperature of 600-700°C, which is generally necessary to reduce the oxygen consumption of the ATR. Therefore, the device may also be intentionally and counterintuitively arranged to have a lower ATR feed temperature. By having a lower ATR feed temperature, suitably 550°C or lower, such as 500°C or lower, such as 300-400°C, the heat required for the heater unit, such as a flame heater, to preheat the hydrocarbon is significantly reduced, thereby enabling a much smaller flame heater, or reducing the number of flame heaters, thereby further reducing CO2 emissions, i.e., reducing the device's carbon footprint. Suitably, the device is arranged accordingly without using a primary reforming unit such as an SMR.

[0058] In one embodiment of the first aspect of the invention, the equipment is arranged to add steam to: hydrocarbon feed, ATR and / or conversion section.

[0059] In one embodiment of the first aspect of the invention, the device is arranged to provide a steam / carbon ratio of 2.6-0.1, 2.4-0.1, 2-0.2, 1.5-0.3, or 1.4-0.4 in the ATR, for example, 1.2, 1.0, or 0.6. More preferably, the ATR is arranged to operate at 20-60 barg, for example, 30-40 barg.

[0060] In one particular embodiment, the device is arranged to provide a steam / carbon ratio of 0.4 or higher in the ATR, such as 0.6 or higher, or 0.8 or higher, such as 0.9, 1.0 or higher, for example in the range of 1.0-2.0, such as 1.1, 1.3, 1.5 or 1.7, but said steam / carbon ratio is below 2.0. It is also preferred that the ATR is arranged to operate at 20-30 barg, such as 24-28 barg. These steam / carbon ratios are higher than the ratios typically expected for ATR operation, which are usually in the range of 0.3-0.6. Furthermore, the pressure is lower than the pressures typically expected for ATR operation, which are typically 30 barg or higher, such as 30-40 barg.

[0061] Operating the equipment in an ATR with a low steam-to-carbon ratio, such as 0.4 or 0.6, can reduce energy consumption and equipment size because the equipment carries less steam / water.

[0062] As used herein, the term “steam / carbon ratio in ATR” refers to the molar ratio of steam to carbon, defined as the molar ratio of all steam added to the hydrocarbon feed and ATR (i.e., excluding any steam added to the downstream conversion section) to all carbon in the hydrocarbons in the feed gas (hydrocarbon feed), which is optionally pre-reformed and reformed in the ATR.

[0063] More specifically, the steam / carbon ratio is defined as the molar ratio of all steam added to the reforming section upstream of the conversion section, such as the high-temperature conversion section (i.e., steam that may have already been added via feed gas, oxygen feed, or added to the ATR) to the carbon in the hydrocarbons added to the feed gas (hydrocarbon feed) of the reforming section. Added steam includes only steam added to the ATR and steam upstream of the ATR.

[0064] As used herein, the term "syngas from the ATR" refers to the syngas at the ATR outlet without the addition of steam, such as any additional steam for downstream shift stages. Therefore, it should be understood that the steam / carbon ratio described in the ATR is the steam / carbon molar ratio in the reforming stage. The reforming stage includes the ATR and any pre-reformers, but excludes the shift stage.

[0065] In one embodiment of the first aspect of the invention, the steam / carbon ratio (including the steam added to the conversion section) in the conversion section is 0.9-3.0, for example 0.9-2.6, for example 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.2 or 2.4.

[0066] As used herein, the term "steam / carbon ratio in the shift section" refers to the addition of optional steam to the synthesis gas stream before entering the shift section and / or within the shift section (e.g., between the HTS and LTS units).

[0067] In an embodiment according to a first aspect of the invention, at least one or more WGS units comprise: a high-temperature shift unit (HTS unit); and a medium-temperature shift unit (MTS unit) and / or a low-temperature shift unit (LTS unit, 150). Thus, in one particular embodiment, the device comprises an HTS unit and a downstream MTS-unit. In another particular embodiment, the device comprises an HTS unit and a downstream LTS unit. In yet another particular embodiment, the device comprises an HTS unit and downstream MTS and LTS-units. Water-gas shift conversion is known in the art to enrich hydrogen in syngas.

[0068] In another specific embodiment, the HTS unit comprises a promoted high-temperature shift catalyst based on zinc-aluminum oxide, preferably arranged within the HTS unit in the form of one or more catalyst beds, and preferably, based on the weight of the oxidation catalyst, the promoted zinc-aluminum oxide-based HT shift catalyst in its active form comprises a Zn / Al molar ratio in the range of 0.5 to 1.0, an alkali metal content in the range of 0.4 to 8.0 wt%, and a copper content in the range of 0-10%. In particular, the zinc-aluminum oxide-based catalyst in its active form may comprise a mixture of zinc-aluminum spinel and zinc oxide with an alkali metal selected from Na, K, Rb, Cs, and mixtures thereof, and optionally with copper. As mentioned above, based on the weight of the oxidation catalyst, the catalyst may have a Zn / Al molar ratio in the range of 0.5 to 1.0, an alkali metal content in the range of 0.4 to 8.0 wt%, and a copper content in the range of 0-10 wt%, for example, as disclosed in the applicant's US2019 / 0039886A1.

[0069] In conventional hydrogen production equipment, the standard use of iron-based high-temperature shift catalysts requires a steam / carbon ratio of approximately 3.0 to avoid the formation of iron carbide, as iron carbide weakens catalyst particles and can lead to catalyst decomposition and increased pressure drop. Iron carbide also catalyzes the production of hydrocarbons as a byproduct of the Fischer-Tropsch reaction, consuming hydrogen and thus reducing the efficiency of the shift section.

[0070] By using non-ferrous catalysts, such as promoted zinc-aluminum oxide-based catalysts, for example SK-501Flex TM As HTS catalysts, ATR and HTS can operate at low steam / carbon ratios (steam / carbon molar ratios). Therefore, this HTS catalyst is not limited by strict requirements on the steam / carbon ratio, making it possible to reduce the steam / carbon ratio in both the shift converter and the ATR (i.e., reforming unit). This results in greater operational flexibility.

[0071] When operating at a low steam / carbon ratio (e.g., 0.9) in syngas including steam added to the shift unit, providing additional WGS units or steps (i.e., MTS and / or LTS) further increases the flexibility of the equipment and / or method. A low steam / carbon ratio can result in suboptimal shift conversion, meaning that in some implementations, providing one or more additional shift steps may be advantageous. Generally, the more CO converted in the shift steps, the more H2 is obtained, and the smaller the required reforming unit.

[0072] This can also be seen from exothermic transformation reactions:

[0073] Steam is preferably added upstream of the HTS unit. Optionally, steam may be added after the high-temperature conversion step, for example, before one or more subsequent MT or LT conversion and / or HT conversion steps, to maximize the performance of said subsequent HT, MT, and / or LT conversion steps.

[0074] HTS steps with two or more units in series, such as HTS steps involving two or more shift reactors in series (e.g., with the possibility of intermediate cooling and / or steam addition), can be advantageous because they can provide increased shift conversion at higher temperatures, which may reduce the required shift catalyst volume and thus potentially reduce capital expenditure. Furthermore, the higher temperature reduces methanol formation, a typical byproduct of water-gas shift.

[0075] Preferably, the MT and LT conversion steps are carried out on a promoted copper / zinc / alumina catalyst. For example, the low-temperature conversion catalyst model can be LK-821-2, which features high activity, high strength, and high sulfur poisoning tolerance. A special catalyst can be installed on the top layer to capture any chlorine that may be present in the gas and prevent droplets from reaching the conversion catalyst.

[0076] The MT conversion step can be performed at temperatures ranging from 190-360°C. The LT conversion step can be performed at temperatures ranging from T... dew The process is carried out at temperatures ranging from +15 to 290°C, for example, 200 to 280°C. For example, the low-temperature shift feed temperature is T. dew+15-250℃, for example 190-210℃.

[0077] Lowering the steam / carbon ratio reduces the dew point (T) of the treated gas. dew This means that the feed temperature for the MT and / or LT shift steps can be reduced. A lower feed temperature means less CO escapes from the shift reactor, which is also beneficial to the equipment and / or method.

[0078] In another embodiment of the invention's first aspect, the device includes a steam superheater arranged preferably to be heated by converted syngas downstream of a high-temperature conversion unit. This further reduces the additional combustion of supplemental fuels, such as natural gas and hydrogen fuel, in the combustion heater, thereby improving carbon recovery and reducing emissions.

[0079] It is well known that MT / LT shift catalysts readily produce methanol as a byproduct. The formation of this byproduct can be reduced by increasing the steam / carbon ratio. CO2 scrubbing is often part of the CO2 removal process after MT / LT shift, requiring heat to regenerate the CO2 absorbent solution. This heat is typically provided as the sensible heat of the treated gas (i.e., the shifted syngas), but this is not always sufficient. Typically, an additional steam-fired reboiler provides the supplemental load. Optionally adding steam to the gas can replace this additional steam-fired reboiler while ensuring reduced byproduct formation in the MT / LT shift process.

[0080] Therefore, the device is further envisioned to include a methanol removal section arranged between the shift section and the CO2 removal section, the methanol removal section being configured to separate a methanol-rich stream from the shifted syngas stream. Methanol formed by the MT / LT shift catalyst can optionally be removed from the syngas in a water wash arranged upstream of the CO2 removal section or in the CO2 product stream.

[0081] According to the invention, the reforming section includes an ATR and an optional pre-reformer unit, but preferably without a steam methane reforming (SMR) unit, i.e., omitting the conventionally used SMR, which is also commonly referred to as a radiant furnace, or a tubular reformer or another primary reforming unit.

[0082] SMR-based equipment typically operates at a steam / carbon ratio of approximately 3. While omitting the use of SMR offers significant advantages in terms of energy consumption and equipment scale, as ATRs can operate at steam / carbon molar ratios well below 1, thus significantly reducing the amount of steam carried over to the equipment / method, a hydrogen purification unit, such as a pressure swing adsorption (PSA) unit, is typically required to enrich the hydrogen content from the lean CO2 syngas stream obtained after CO2 removal. Therefore, lean CO2 syngas typically contains approximately 500 ppmv or lower CO2, for example, as low as 20 ppmv CO2, and approximately 90 vol.% H2. The hydrogen concentration is relatively low, thus requiring further purification to obtain an end-user-acceptable level of hydrogen purity, such as 98 vol.% or higher H2.

[0083] This invention omits the use of a hydrogen purification unit, but still enables the production of H2-rich streams with a purity higher than 95 vol.%, such as 98 vol.% or higher, from the CO2 removal section. This purity is significantly higher than the aforementioned 90 vol.%, and it can also produce CO2-rich streams with a purity higher than 95 vol.%, such as 99 vol.% or higher, for example, 99.5 vol.% or 99.8 vol.%. In particular, the lower the pressure in the ATR, the higher the steam / carbon ratio in the syngas extracted from the ATR and optionally also in the syngas including the steam added to the shift section, and the higher the purity of the H2-rich stream from the CO2 removal section.

[0084] Therefore, this invention also enables the simple production of hydrogen-rich streams, most of which can be used as hydrogen products with hydrogen purity acceptable to end users (e.g., refineries), and a portion of these hydrogen-rich streams can also be used in equipment as low-carbon hydrogen fuel diversions to replace the typical use of natural gas, thereby reducing CO2 emissions. The reduction in CO2 emissions is also achieved at a lower cost than, for example, by capturing carbon from industrial gases such as refinery exhaust gases. In other words, capturing carbon from the production of hydrogen-rich streams is more economical than capturing carbon directly from flue gas produced by burning industrial gases.

[0085] Furthermore, flue gas from flame heaters is typically emitted at low pressure, making CO2 removal from low-pressure flue gas energy and capital costs high. For example, in an amine washing CO2 removal unit, the energy required to compress the flue gas and regenerate CO2 is significantly higher than that required to recover CO2 from the shifted syngas. Additionally, extra unit operations are needed to cool and purify the flue gas, further increasing capital expenditure. Impurities in the flue gas are typically SO2. x and NO x This method is not suitable for amine-washed CO2 removal units. Therefore, the present invention removes CO2 from the process gas itself.

[0086] As used herein, the term "flue gas" refers to a gas obtained from the combustion of hydrocarbon streams and / or hydrogen, which mainly contains CO2, N2 and H2O as well as trace amounts of CO, Ar and other impurities, plus a small amount of excess O2.

[0087] The separated CO2-rich stream according to the invention can be processed, for example, by sequestration in geological structures, or used as an industrial gas for various purposes.

[0088] In one embodiment of the invention, the apparatus further includes one or more pre-reforming units arranged upstream of the ATR, said pre-reforming units being configured to pre-reform the hydrocarbon feed before it is fed into the ATR. In a particular embodiment, the apparatus includes two or more adiabatic pre-reforming units arranged in series with an interstage preheater, i.e., arranged between the pre-reforming preheaters. In the pre-reforming unit, all higher hydrocarbons can be converted to carbon oxides and methane, but the pre-reforming unit also favors lighter hydrocarbons. Providing a pre-reforming unit, and thus a pre-reforming step, can have several advantages, including reducing the O2 consumption required in the ATR and allowing for higher ATR feed temperatures because cracking risk is minimized through preheating. Furthermore, the pre-reforming unit can provide effective sulfur protection, allowing virtually sulfur-free feed gas to enter the ATR and downstream systems. The pre-reforming step can be carried out at temperatures of 300-650°C, preferably 390-480°C.

[0089] As used herein, the terms “pre-reformer,” “pre-reformer unit,” and “pre-reformer cell” are used interchangeably.

[0090] In another implementation, the device does not have a pre-reformer unit. This reduces the device size and consequently the cost.

[0091] In one embodiment of the invention's first aspect, the apparatus further includes a hydrogenator unit and a sulfur absorption unit disposed upstream of the one or more pre-reformer units or upstream of the ATR, and the apparatus is arranged to mix a portion of the H2-rich stream with the hydrocarbon feed before feeding it to the feed side of the hydrogenator unit. In other words, the apparatus is arranged to, preferably by providing a hydrogen recirculation compressor, mix a portion of the H2-rich stream (i.e., as hydrogen recirculation) with the hydrocarbon feed upstream of the hydrogenator unit. Therefore, sulfur, which is detrimental to downstream catalysts, is removed from the hydrocarbon feed, while energy consumption is further reduced because the hydrogen generated in the process is used as the main hydrocarbon feed before entering the hydrogenator, instead of using an external hydrogen source.

[0092] As used herein, the term "feed side" refers to the inlet side or simply the inlet. For example, the feed side of a hydrogenator unit refers to the inlet side of the hydrogenator unit.

[0093] It should also be understood that a reforming section is a section of equipment that includes units up to and including an ATR, i.e., an ATR, or one or more pre-reformer units and an ATR, or a hydrogenator and a sulfur absorber and one or more pre-reformer units and an ATR.

[0094] In another embodiment of the invention according to a first aspect, the apparatus further includes an air separation unit (ASU) arranged to receive an air stream and generate an oxygen-containing stream, which is then supplied to the ATR via a conduit. Preferably, according to the above embodiment, the oxygen-containing stream comprises vapor added to the ATR. Examples of streams containing an oxidant are: oxygen; a mixture of oxygen and vapor; a mixture of oxygen, vapor, and argon; and oxygen-enriched air.

[0095] The syngas temperature at the ATR outlet is 900 to 1100°C, or 950 to 1100°C, typically 1000 to 1075°C. This hot outflow syngas (syngas from the ATR) contains carbon monoxide, hydrogen, carbon dioxide, vapor, residual methane, and various other components, including nitrogen and argon.

[0096] Autothermal reforming (ATR) is widely described in the field and in the published literature. Typically, an ATR consists of a burner, a combustion chamber, and a catalyst arranged in a fixed bed, all housed within a refractory-lined pressure vessel. ATR is described, for example, in the following literature: “Studies in Surface Science and Catalysis”, Vol. 152 (2004), edited by Andre Steynberg and Mark Dry, Chapter 4; and in the following overview article: “Tubular reforming and autothermal reforming of natural gas – an overview of available processes”, Ib Dybkjaer, Fuel Processing Technology 42 (1995) 85-107.

[0097] The equipment preferably also includes piping for adding steam to the hydrocarbon feed, to the oxygenated stream and to the ATR, and optionally also to the inlet of the reforming section, for example to the hydrocarbon feed, to the inlet of the conversion section, particularly the HTS unit, and / or to an additional conversion unit downstream of the HTS unit.

[0098] The CO2 removal section is an amine washing unit, including a CO2 absorber, a CO2 stripper, a high-pressure flash tank, and a low-pressure flash tank, thereby separating a CO2-rich stream containing more than 99 vol.% CO2, such as 99.5 vol.% or 99.8 vol.% CO2, an H2-rich stream containing 98 vol.% hydrogen, and a high-pressure flash gas containing approximately 60 vol.% CO2 and 40 vol.% H2. In the amine washing unit, during the first high-pressure flash step through the high-pressure tank, most impurities, along with some CO2, are released into the gas phase as a high-pressure flash gas. During the low-pressure flash step through the low-pressure flash tank, primarily CO2 is released as a CO2-rich stream into the final product.

[0099] CO2 from the CO2 removal section, i.e., a CO2-rich stream, as further described above, is preferably captured and transported for, for example, to be stored in geological structures, thereby reducing carbon dioxide emissions into the atmosphere.

[0100] In a second aspect of the invention, a method for producing an H2-rich stream from a hydrocarbon feedstock is also provided, the method comprising the following steps:

[0101] - Provide an apparatus according to the first aspect of the invention;

[0102] - Supply hydrocarbon feed to the ATR and convert it into a synthesis gas stream;

[0103] - Take the syngas from the ATR and supply it to the conversion section, where the syngas is converted in the HTS step and optionally also in the MTS and / or LTS conversion steps, thereby providing a converted syngas.

[0104] - The converted gas stream from the conversion section is supplied to the CO2 removal section, which is an amine washing unit including a CO2 absorber and a CO2 stripper, as well as a high-pressure flash tank and a low-pressure flash tank; a CO2-rich stream is separated from the converted synthesis gas stream to provide an H2-rich stream and a high-pressure flash stream;

[0105] - Omit at least a portion of the H2-rich stream (8) being fed into a hydrogen purification unit such as a pressure swing adsorption (PSA) unit, hydrogen membrane, or cryogenic separation unit;

[0106] - Feed at least a portion of the H2-rich stream as hydrogen fuel to at least one or more flame heaters;

[0107] -The method further includes:

[0108] a) Feeding at least a portion of the high-pressure flash stream (12) as fuel into the one or more flame heaters (135); and / or

[0109] b) Recycle at least a portion of the high-pressure flash gas flow (12) to the CO2 absorber, i.e., as an internal high-pressure (HP) flash gas recirculation flow; and / or

[0110] c) Mix at least a portion of the high-pressure flash vapor stream (12) with the H2-rich stream (8).

[0111] It should be understood that the use of the article "a" in a given item refers to the same item in the first aspect of the invention. For example, the term "rich H2 stream" refers to a rich H2 stream according to the first aspect of the invention.

[0112] In one embodiment of the second aspect of the invention, after the water content as process condensate is removed, the converted gas stream is suitably introduced into the CO2 removal section by being introduced into a CO2 absorber. Also suitably, the internal HP flash gas recirculation stream is merged with the converted gas stream before being introduced into the CO2 absorber.

[0113] As described in the first aspect of the invention, embodiments of the invention according to the second aspect described above can be combined. For example, a portion of the high-pressure flash vapor stream is recycled as fuel for one or more flame heaters, while another portion of the high-pressure flash vapor stream is recycled to the CO2 absorber of the amine washing unit, i.e., as an internal HP recirculation stream, and a further portion of the high-pressure flash vapor stream is mixed with an H2-rich stream.

[0114] In one embodiment, the method includes mixing the partial H2-rich stream (8), which is used as hydrogen fuel, with the high-pressure flash vapor stream (12) upstream of the one or more flame heaters (135). For example, the high-pressure flash vapor stream (12) is mixed with the H2-rich stream (8) before being supplied to the one or more flame heaters (135).

[0115] Furthermore, unlike the above-mentioned recirculation or mixing of only a portion of the high-pressure flash flow, it may also be advantageous to recirculate or mix the entire high-pressure flash flow.

[0116] Therefore, in an embodiment of the second aspect of the present invention, the method includes:

[0117] The entire high-pressure flash stream can be recycled as fuel for the at least one flame heater; or the entire high-pressure flash stream can be recycled to the CO2 absorber; or the entire high-pressure flash stream can be mixed with the H2-rich stream.

[0118] In one embodiment of the second aspect of the invention, the method further includes adding steam to: the ATR, the hydrocarbon feed and / or the synthesis gas stream before entering the conversion section.

[0119] In an embodiment of the second aspect of the invention, the steam / carbon ratio in the ATR is 2.6-0.1, 2.4-0.1, 2-0.2, 1.5-0.3, 1.4-0.4, for example 1.2, 1.0, or 0.6. More preferably, the pressure in the ATR is 20-60 barg, for example 30-40 barg.

[0120] In one particular embodiment, the vapor / carbon ratio of the syngas in the ATR is 0.4 or higher, for example 0.6 or higher, such as 0.8 or higher, but the vapor / carbon ratio is not greater than 2.0, such as 1.0 or higher, for example in the range of 1.0-2.0, such as 1.1, 1.3, 1.5 or 1.7; the pressure in the ATR is 20-30 barg, for example 24-28 barg.

[0121] In one embodiment of the second aspect of the invention, the steam / carbon ratio in the conversion section, including the steam added to the conversion section, is 0.9-3.0, for example 0.9-2.6, for example 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.2 or 2.4.

[0122] The carbon feedstock in the ATR is mixed with oxygen and additional steam, and a combination of at least two types of reactions occurs. These two reactions are combustion and steam reforming.

[0123] Combustion zone:

[0124] (3)

[0125] (4)

[0126] Heat and catalytic zone:

[0127] (5)

[0128] (6)

[0129] The combustion of methane into carbon monoxide and water (reaction (4)) is a highly exothermic process. After all the oxygen has been converted, excess methane may remain at the outlet of the combustion zone.

[0130] The hot zone is part of the combustion chamber, where further hydrocarbon conversion occurs via homogeneous gas-phase reactions (primarily reactions (5) and (6)). Endothermic steam reforming of methane (5) consumes most of the heat generated in the combustion zone. Following the combustion chamber, there may be a fixed catalyst bed, i.e., the catalytic zone, where the final hydrocarbon conversion occurs via heterogeneous catalytic reactions. At the outlet of the catalytic zone, the syngas preferably approaches equilibrium with reactions (5) and (6).

[0131] In one implementation, the method operates without the addition of additional steam between the reforming step and the high-temperature conversion step.

[0132] In another embodiment of the second aspect of the invention, the space velocity in the ATR is low, for example, less than 20,000 Nm. 3 C / m 3 / h, preferably less than 12000 Nm 3 C / m 3 / h and the optimal value is less than 7000 Nm 3 C / m 3 / h. The space velocity is defined as the volumetric carbon flow rate per catalyst volume, and therefore is independent of the conversion rate in the catalyst zone.

[0133] In one embodiment of the second aspect of the invention, the method includes pre-reforming the hydrocarbon feed in one or more pre-reforming units before feeding the hydrocarbon feed into the ATR.

[0134] In another implementation, there is no pre-restructuring step.

[0135] In an embodiment of the second aspect of the invention, the method further includes providing a hydrogenator unit and a sulfur absorption unit to regulate the hydrocarbon feed, for example for desulfurization, before the pre-reforming or before feeding to the ATR, and mixing a portion of the H2-rich stream (i.e., as H2 recirculation) with the hydrocarbon feed before feeding it to the feed side of the hydrogenator unit.

[0136] It should be understood that any embodiment and related benefits of the first aspect of the present invention can be used in conjunction with any embodiment of the second aspect of the present invention, and vice versa.

[0137] Brief description of the attached figures

[0138] Figure 1 The layout of the hydrogen production method and equipment based on ATR is explained.

[0139] Figure 2 The embodiments of the present invention are described. Figure 1 The layout of an ATR-based hydrogen production method and equipment, which integrates a high-pressure flash vapor stream from the CO2 removal section into the method.

[0140] Detailed description

[0141] refer to Figure 1The diagram shows equipment / method 100, in which a hydrocarbon feed 1, such as natural gas, is fed to a reforming section comprising a pre-reformer unit 140 and an ATR 110. The reforming section may also include a hydrogenator and a sulfur absorber unit (not shown) upstream of the pre-reformer unit 140. Before entering the hydrogenator, the hydrocarbon stream 1 is mixed with a hydrogen recirculation stream 8”', which is diverted from an H2-rich stream 8 generated in a downstream CO2 removal section 170. Before entering the pre-reformer unit 140, the hydrocarbon feed 1 is also mixed with steam 13, resulting in a pre-reformed hydrocarbon feed 2 fed to the ATR 110, as is the oxidant stream formed by mixing oxygen 15 and steam 13. Steam may also be added separately, as shown. The oxygen stream 15 is generated by an air separation unit (ASU) 145, to which air 14 is supplied. In ATR 110, hydrocarbon feed 2 is converted into syngas gas 3, which is then extracted from ATR 110 and sent to the conversion section. Hydrocarbon feed 2 enters the ATR at 650°C, with an oxygen temperature of approximately 253°C. The steam / carbon ratio of the ATR is preferably 0.4 or higher, for example 0.6 or higher, or for example 0.8 or higher, but not greater than 2.0. Also preferably, the pressure in ATR 110 is 24-28 barg. The syngas exits the ATR at approximately 1050°C through a refractory-lined outlet section and a delivery pipeline to a waste heat boiler (not shown) in the syngas section, i.e., the process gas cooling section.

[0142] The shift conversion section includes a high-temperature shift conversion (HTS) unit 115, where additional or extra steam 13' can be added upstream to achieve a steam / carbon ratio preferably of about 1.0 or higher in the shift conversion section. Additional shift conversion units, such as a low-temperature shift conversion (LTS) unit 150, may also be included in the shift conversion section. Additional or extra steam can also be added downstream of the HTS unit 115 but upstream of the LTS unit 150 to increase the aforementioned steam / carbon ratio. From the shift conversion section, a hydrogen-rich shifted gas stream 5 is generated and then fed to a CO2 removal section 170. The CO2 removal section 170 is suitably an amine washing unit, which includes a CO2 absorber and a CO2 stripper that separates a CO2-rich stream 10 containing more than 99 vol.% and an H2-rich stream 8 containing 98 vol.% or higher of hydrogen. The CO2 removal section 170 also generates a high-pressure flash vapor stream 12. The apparatus 100 does not contain a hydrogen purification unit, such as a PSA.

[0143] The H2-rich stream 8 is divided into H2 product 8' for supply to end customers such as refineries; low-carbon hydrogen fuel 8"" for use in the flame heater unit 135; and hydrogen recirculation stream 8"' for mixing with hydrocarbon feed 1. The flame heater 135 provides indirect heating for hydrocarbon feed 1 and hydrocarbon feed 2.

[0144] Now for reference Figure 2The diagram illustrates an embodiment integrating the use of high-pressure flash stream 12. The CO2 removal section 170 includes a CO2 stripper 170', low-pressure and high-pressure tanks 170"", and a CO2 absorber 170'". In one embodiment, at least a portion of the high-pressure flash stream 12 is supplied as fuel 12' to the flame heater 135. In another embodiment, at least a portion of the high-pressure (HP) flash stream 12 is recirculated as stream 12" to the CO2 absorber 170'", i.e., as an internal HP recirculation stream. While these figures show the converted gas stream 5 entering the CO2 removal section 170 at its end furthest from the CO2 absorber 170", it should be understood that after removing its water content as process condensate, the converted gas stream 5 appropriately enters the CO2 removal section 170 by being introduced into the CO2 absorber 170"". Also appropriately, the internal HP recirculation stream 12" is combined with the converted gas stream 5 before being introduced into the CO2 absorber 170"". In another embodiment, at least part of the high-pressure flash vapor stream 12, as stream 12”', is mixed with the H2-rich stream 8 before being fed into the flame heater 135.

Claims

1. An apparatus (100) for producing an H2-rich stream (8) from a hydrocarbon feed (1, 2), the apparatus comprising: an autothermal reformer (ATR) (110) arranged to receive a hydrocarbon feed (1, 2) and convert it into a syngas stream (3); a shift section comprising one or more water gas shift (WGS) units (115, 150) arranged to receive the syngas stream (3) from the autothermal reformer (ATR) (110) and shift it in the one or more water gas shift (WGS) units (115, 150), thereby providing a shifted syngas stream (4, 5); a CO2 removal section (170) arranged to receive the shifted syngas stream (4, 5) from the shift section and separate a CO2-rich stream (10) from the shifted syngas stream (4, 5), thereby providing the H2-rich stream (8) and also providing a high pressure flash gas stream (12); one or more fired heaters (135) for preheating the hydrocarbon feed (1) before it is fed into the autothermal reformer (ATR) (110); wherein the apparatus (100) is arranged to feed at least part of the H2-rich stream (8) as hydrogen fuel to at least the one or more fired heaters (135); wherein the apparatus (100) is free of a hydrogen purification unit, by which is meant a pressure swing adsorption (PSA) unit, a hydrogen membrane or a cryogenic separation unit; and the CO2 removal section (170) is an amine wash unit comprising a CO2 absorber and a CO2 stripper and a high pressure flash tank and a low pressure flash tank, thereby separating the CO2-rich stream (10), the H2-rich stream (8) and the high pressure flash gas stream (12); and the apparatus (100) is arranged to feed at least part of the high pressure flash gas stream to a unit or stream of the apparatus, wherein a) the apparatus (100) is arranged to recycle the entire high pressure flash gas stream (12) as fuel back to the at least one fired heater (135); and c) the apparatus is arranged to mix the entire high pressure flash gas stream (12) with at least part of the H2-rich stream (8) that is fed as hydrogen fuel to at least the one or more fired heaters (135) upstream of the one or more fired heaters (135), wherein the apparatus is arranged to provide a steam / carbon ratio in the autothermal reformer (ATR) (110) of 2.6-0.1 and / or wherein the autothermal reformer (ATR) (110) is arranged to operate at 20-60 barg.

2. The apparatus (100) according to claim 1, wherein the steam / carbon ratio is 2.4-0.

1.

3. The apparatus (100) according to claim 1, wherein the steam / carbon ratio is 2-0.

2.

4. The apparatus (100) according to claim 1, wherein the steam / carbon ratio is 1.5-0.

3.

5. The plant (100) according to claim 1, wherein the steam / carbon ratio is 1.4-0.

4.

6. The plant (100) according to claim 1, wherein the steam / carbon ratio is 1.2, 1.0 or 0.

6.

7. The plant (100) according to claim 1, arranged to provide the hydrocarbon feed to an autothermal reformer (ATR) (110) at a feed temperature below 600°C.

8. The plant (100) according to claim 7, wherein the feed temperature of the hydrocarbon feed is 550°C or 500°C or lower.

9. The plant (100) according to claim 7, wherein the feed temperature of the hydrocarbon feed is 300-400°C.

10. The plant (100) according to claim 1, wherein the plant is arranged to provide a steam / carbon ratio of 0.4 or higher in the autothermal reformer (ATR) (110), however the steam / carbon ratio is not larger than 2.0, and / or wherein the autothermal reformer (ATR) (110) is arranged to operate at 20-30 barg.

11. The plant (100) according to claim 10, wherein the steam / carbon ratio is 0.6 or higher.

12. The plant (100) according to claim 10, wherein the steam / carbon ratio is 0.8 or higher.

13. The plant (100) according to any one of claims 10-12, wherein the autothermal reformer (ATR) (110) is arranged to operate at 24-28 barg.

14. The plant (100) as claimed in claim 1, wherein the at least one or more water gas shift (WGS) units (115, 150) comprises of: a high temperature shift (HTS) unit (115); and a medium temperature shift (MTS) unit (150) and / or a low temperature shift (LTS) unit (150).

15. The plant (100) according to claim 14, further comprising a steam superheater arranged to be heated by the shifted synthesis gas stream (4, 5) downstream of the high temperature shift (HTS) unit (115).

16. The plant (100) according to claim 1, further comprising one or more pre- reformer units (140) arranged upstream of the autothermal reformer (ATR) (110), the one or more pre-reformer units (140) being arranged to pre-reform the hydrocarbon feed (1) before feeding it to the autothermal reformer (ATR) (110).

17. The plant (100) according to claim 1, wherein the plant is free of pre- reformer units (140).

18. The plant (100) according to claim 16, further comprising a hydrogenator unit and a sulphur absorption unit arranged upstream of the one or more pre-reformer units or upstream of the autothermal reformer (ATR) (110), and the plant (100) is arranged for mixing a portion of the H2-rich stream (8) with the hydrocarbon feed (1, 2) before feeding it to the feed side of the hydrogenator unit.

19. A method for producing an H2-rich stream (8) from a hydrocarbon feed (1, 2), the method comprising the steps of: providing a plant (100) according to any one of claims 1-18; supplying a hydrocarbon feed (1, 2) to an autothermal reformer (ATR) (110) and converting it to a syngas stream (3); removing the syngas stream (3) from the autothermal reformer (ATR) (110) and supplying it to a shift section, where the syngas is shifted in a high temperature shift (HTS) step (115) and optionally also in a medium temperature shift (MTS) step (150) and / or a low temperature shift (LTS) step (150), thereby providing a shifted syngas stream (5); supplying the shifted syngas stream (5) from the shift section to a CO2 removal section (170), which is an amine wash unit comprising a CO2 absorber and a CO2 stripper and a high pressure flash drum and a low pressure flash drum; separating a CO2 rich stream (10) from the shifted syngas stream (5), thereby providing an H2 rich stream (8) and a high pressure flash gas stream (12); omitting feeding at least a portion of the H2 rich stream (8) to a hydrogen purification unit, which is a pressure swing adsorption (PSA) unit, a hydrogen membrane or a cryogenic separation unit; feeding at least a portion of the H2 rich stream (8) as hydrogen fuel to at least one or more fired heaters (135); the method further comprising: a) recycling the entire high pressure flash gas stream (12) as fuel back to the one or more fired heaters (135); and c) mixing the entire high pressure flash gas stream (12) upstream of the one or more fired heaters (135) with at least a portion of the H2 rich stream (8) that is fed as hydrogen fuel to the at least one or more fired heaters (135).

20. The method according to claim 19, wherein the steam / carbon ratio in the autothermal reformer (ATR) (110) is from 2.6 to 0.1; and / or wherein the pressure in the autothermal reformer (ATR) (110) is from 20 to 60 barg.

21. The method according to claim 20, wherein the steam / carbon ratio is from 2.4 to 0.

1.

22. The method according to claim 20, wherein the steam / carbon ratio is from 2 to 0.

2.

23. The method according to claim 20, wherein the steam / carbon ratio is from 1.5 to 0.

3.

24. The method according to claim 20, wherein the steam / carbon ratio is from 1.4 to 0.

4.

25. The method according to claim 20, wherein the steam / carbon ratio is 1.2, 1.0 or 0.

6.

26. The method according to claim 20, wherein the steam / carbon ratio in the autothermal reformer (ATR) (110) is 0.4 or higher, however the steam / carbon ratio is not more than 2.0; and / or wherein the pressure in the autothermal reformer (ATR) (110) is from 20 to 30 barg.

27. The method according to claim 26, wherein the steam / carbon ratio is 0.6 or higher.

28. The method according to claim 26, wherein the steam / carbon ratio is 0.8 or higher.

29. The method according to claim 26, wherein the steam / carbon ratio is 1.0 or higher. ​ 30. The method according to any one of claims 26-29, wherein the pressure in the autothermal reformer (ATR) (110) is 24-28 barg.

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