WO2026008860A1

WO2026008860A1 - Gasification with improved utilisation of carbon dioxide

Info

Publication number: WO2026008860A1
Application number: PCT/EP2025/069183
Authority: WO
Inventors: David MINGUEZ; Kim Aasberg-Petersen; Sudip DE SARKAR; Thomas Sandahl Christensen
Original assignee: Haldor Topsoe AS
Current assignee: Topsoe AS
Priority date: 2024-07-05
Filing date: 2025-07-04
Publication date: 2026-01-08
Anticipated expiration: 2027-01-05

Abstract

The present invention relates to a synthetic fuel plant, and a process for providing a synthetic fuel product stream from a carbonaceous feedstock via gasification of the said carbonaceous feedstock. The plant and process provide improved utilisation of carbon dioxide (CO₂).

Description

GASIFICATION WITH IMPROVED UTILISATION OF CARBON DIOXIDE

TECHNICAL FIELD

The present invention relates to a plant, preferably a synthetic fuel plant, and a process for providing a product stream from a carbonaceous feedstock. The plant and process provide improved utilisation of carbon dioxide (CO2).

BACKGROUND

Production of synthetic fuels from gasification of various renewable feedstocks (such as - biomass, municipal waste, 'black liquor' from paper and pulp industry etc.) has gained significant attention in recent years. There are various advantages of such processes, including relatively lower demand for renewable hydrogen energy compared to synthetic fuel production from CO2. However, in current gasification-based synthetic fuels process layouts, a large part of the carbon from the primary feedstock is converted to CO2, both during the gasification process and potentially also during the adjustment of gasification effluent composition via water gas shift (WGS) process, which would be necessary downstream synthesis processes, such as - Fischer-Tropsch synthesis, methanol synthesis etc. In low temperature Fischer- Tropsch processes, which are suitable for transportation fuel production, CO2 is inert and thus, excess of CO2 in the feed gas affects process efficiency. Therefore, a part of the CO2 is mostly captured and sequestered without further use within the process.

Similarly, the Fischer-Tropsch (FT) tail gas and off-gas from the upgrading unit, required to refine hydrocarbon product from Fischer-Tropsch process, are both carbon rich streams, and are typically used as fuel in the facility. Thus, carbon from renewable feeds get lost and therefore, this layout is not very carbon efficient.

As an alternative to adjust the module by shifting the gas from gasification, there is the option to add hydrogen to adjust the composition of the gasification effluent. In this case, CO2 removal is still necessary in order to limit the CO2 content in the syngas to FT (as CO2 is inert in the FT process).

Thus, there remains a need to provide plants and processes in which utilisation of carbon dioxide (CO2) can be improved. SUMMARY

It has been found that, by integrating a reverse water gas shift unit in the plant/process, it is possible to recover either both the CO2 and the tail gas and upgrading off-gas or a combination of these streams, to boost the production of syngas and therefore the production of final products. Moreover, effective use of CO2-removal can potentially improve the energy efficiency of such synthetic fuel plants.

Accordingly, a plant, preferably a synthetic fuel plant is provided, said plant comprising : a carbonaceous feedstock, a hydrogen feed, an oxygen feed, a steam feed, a gasification section arranged to receive said carbonaceous feedstock, said oxygen feed, and to gasify said carbonaceous feedstock so as to provide a gasification effluent in the form of a first syngas stream, optionally, a water gas shift section, arranged to receive the first syngas stream from the gasification section and at least a first portion of the steam feed and to provide a second syngas stream, such that the CO2 content in the second syngas stream is higher than that in the first syngas stream, a syngas clean-up section arranged to receive the first syngas stream (in the absence of the optional WGS section) or the second syngas stream (in the presence of the optional WGS section), and to output a third syngas stream, and a first offgas stream, optionally, a first syngas purification section, arranged to receive the third syngas stream from syngas clean-up section, to output fourth syngas stream, a CO2 separation section arranged to receive the third syngas stream (in the absence of the optional first syngas purification section) or the fourth syngas stream (in the presence of the optional first syngas purification section) and separate it into a CO2- enriched stream and a CO2-depleted stream, a Reverse Water Gas Shift (RWGS) section, being arranged to receive the CO2- enriched stream, at least a first portion of said hydrogen feed and at least a second portion of the steam feed, and to output a fifth syngas stream and optionally, a purge stream, optionally, a second syngas purification section, arranged to receive the CO2-depleted stream from the CO2-separation section, to output sixth syngas stream, a synthesis section arranged to receive the fifth syngas stream; and either the sixth syngas stream or the CC -depleted stream and, optionally a second portion of the hydrogen feed, and to provide a hydrocarbon product stream and a first tail gas stream.

A process is also described for providing a hydrocarbon product stream from a carbonaceous feedstock, in the plant described herein, said process comprising : gasifying the carbonaceous feedstock and the oxygen feed, in gasification section so as to provide a gasification effluent in the form of a first syngas stream, optionally, feeding the first syngas stream from the gasification section and at least a first portion of the steam feed to the water gas shift (WGS) section, and providing a second syngas stream, wherein the CO2 content in the second syngas stream is higher than that in the first syngas stream, feeding the first syngas stream from the gasification section (in the absence of the optional WGS section) or the second syngas stream (in the presence of the optional WGS section) to the syngas clean-up section and outputting a third syngas stream, and a first offgas stream, optionally, feeding the third syngas stream form the syngas clean-up section to the first purification section, and outputting a fourth syngas stream, separating the third syngas stream (in the absence of the optional first syngas purification section) or the fourth syngas stream (in the presence of the optional first syngas purification section), into a CC -enriched stream and a CO2-depleted stream in the CO2 separation section, feeding the CO2-enriched stream, at least a first portion of said hydrogen feed and at least a second portion of the steam feed, to the Reverse Water Gas Shift (RWGS) section, and outputting a fifth syngas stream, and optionally, a purge stream, optionally, feeding the CCh-depleted stream from the CCh-separation section to the second syngas purification section, and outputting a sixth syngas stream, feeding the fifth syngas stream; and either the sixth syngas stream or the CO2- depleted stream and, optionally a second portion of the hydrogen feed, to the synthesis section and providing a hydrocarbon product stream and a first tail gas stream.

Further details of the technology are provided in the enclosed dependent claims, figures and examples.

LEGENDS

Fig. 1 shows a first layout of the plant/process according to the invention. Figures 2 shows a further layout of the plant/process according to the invention.

Figure 3-4 show the layout within the reverse water gas shift (RWGS) section of the plant/process according to the invention.

DETAILED DISCLOSURE

Unless otherwise specified, any given percentages for gas content are % by volume. All feeds are preheated, compressed as required.

A plant is therefore provided, which is preferably a synthetic fuel plant. The plant comprises, as feeds/feedstocks: a carbonaceous feedstock, a hydrogen feed, an oxygen feed, and a steam feed.

The carbonaceous feedstock is a feedstock which can be gasified in the present plant/process. The carbonaceous feedstock may be a lignocellulosic biomass such as wood products, algae, grass, forestry waste and/or agricultural residue. Additionally, it may be municipal waste, in particular the organic portion thereof, where the municipal waste is defined as a feedstock containing materials of items discarded by the public, such as mixed municipal waste given in EU Directive 2018/2001 (RED II), Annex IX, part A. Furthermore, carbonaceous feedstock may comprise carbon containing byproducts from other plant/process, such as 'black liquor' from pulp and paper industry.

The hydrogen feed typically comprises above 90 vol%, above 92 vol% hydrogen gas such as above 95 vol% hydrogen gas such as above 98 vol% hydrogen gas, such as > 99% hydrogen gas. One source of the hydrogen feed can be one or more electrolyser units. In addition to hydrogen the hydrogen feed may for example comprise steam, nitrogen, argon, carbon monoxide, carbon dioxide, and/or hydrocarbons. In some cases, a minor content of oxygen may be present in this feed, typically less than 100 ppm.

In one embodiment, the electrolysis section comprises high temperature electrolysis, where at least part of steam feed to the electrolysis section comes from downstream synthesis unit and/or RWGS section. The oxygen feed is preferably a feed of high-purity oxygen, such as > 99% oxygen. The hydrogen feed and the oxygen feed are suitably generated by electrolysis. Accordingly, the plant may comprise an electrolysis section and a water/steam feed to said electrolysis section, said electrolysis section being arranged to provide at least a portion of said hydrogen feed and at least a portion of said oxygen feed in said plant, via electrolysis of said water feed. The steam feed suitably comprises > 99% steam.

A gasification section is arranged to receive said carbonaceous feedstock, said oxygen feed, and to gasify said carbonaceous feedstock so as to provide a gasification effluent in the form of a first syngas stream. Gasification is a process that converts biomass- or fossil fuel-based carbonaceous feedstock into a gas rich in carbon monoxide (CO), as well as other components such as: hydrogen (H2), carbon dioxide (CO2), and nitrogen (N2). This is achieved by reacting the carbonaceous feedstock at high temperatures (typically >700 °C) via controlling the amount of oxygen and/or steam present in the reaction.

"Syngas" is used as reference for a synthesis gas, a gas mixture comprising hydrogen, carbon monoxide, carbon dioxide, methane and typically water in the form of steam. It is referred to as syngas I synthesis gas because it is the feed for a downstream catalytic synthesis leading to the desired product.

The H2/CO ratio of the first syngas stream from gasification section is typically less than 2.0. The actual H2/CO ratio varies a lot depending on the gasification technology. In some cases, H2/CO ratio of < 1.0 in first syngas stream can be observed. Therefore, gasification effluent is processed before sending it to downstream Fischer-Tropsch (FT) synthesis, for which usually syngas H₂/CO of ca. 2.0 is required. This can be achieved different ways. The first syngas stream comprises CO, CO₂, H₂, CH₄, N₂, and may optionally comprise Ar, dust, sulphur species, halogenated species, nitrogen species, metals.

As an optional first step, a water gas shift (WGS) section can be arranged to receive the first syngas stream from the gasification section and at least a first portion of the steam feed and to provide a second syngas stream.

CO + H₂O CO₂ + H₂ (1)

In presence of steam, CO in the gasification effluent gets converted into H₂ and CO₂, increasing H₂/CO ratio in the resulting second syngas stream. However, the CO2 content in the second syngas stream is also higher than that in the first syngas stream. Such high CO2 content in syngas is not ideal for FT synthesis process. Therefore, further processing of second syngas stream is necessary before feeding it to FT synthesis. The second syngas stream comprises CO, CO2, H2, CH4, N2, may optionally comprise Ar, sulphur species, halogenated species, nitrogen species, metals, where the H2 and CO2 content is higher than that in the first syngas, when upstream WGS section is present.

A syngas clean-up section is arranged to receive the first or - where present - the second syngas stream and to output a third syngas stream, and a first offgas stream. Such syngas clean-up section removes the bulk impurities, present in the first and/or - where present - the second syngas, down to low ppm levels, via first off-gas stream. The impurities can be, dust, sulphur species (H2S, COS), nitrogen species (HCN, NH3), halogenated species (Cl, Br, F), metals. The third syngas stream comprises CO, CO2, H2, CH4, and may comprise N2, Ar, with low (in ppm) levels of: sulphur species, halogenated species and nitrogen species.

Optionally, a first syngas purification section, when present, is arranged to receive the third syngas stream from the syngas clean-up section, and to output a fourth syngas stream. The first syngas purification section may be required when second syngas purification section is not present. Typically, this section removes trace amounts of impurities, such as sulphur species (H2S, COS), nitrogen species (HCN, NH3), halogenated species (Cl, Br, F) down to low ppb levels by means of one or several catalytic absorbent beds. The fourth syngas comprises CO, CO2, H2, CH4, and may comprise N2, Ar, with low ppb levels of: sulphur and nitrogen species.

A CO2 separation section is arranged to receive the third syngas stream, when the first syngas purification section is not present, or the fourth syngas stream, when the first syngas purification section is present, and separate it into a CO2-enriched stream and a CO2-depleted stream. Removal of CO2 may take place vi a chemical absorption (e.g. using amine-based solvents, caustic etc.), physical absorption (e.g. Rectisol, Selexol etc.), or cryogenic CO2 separation process, or adsorption (e.g. Pressure Swing Adsorption (PSA) process, chemical adsorption etc.), or by membrane-based CO2 separation process. In a preferred embodiment CO2 separation section may comprise more than one of the abovementioned CO2 separation processes. Suitably, the CO2 separation section comprises at least one CO2 membrane separation unit, being arranged to separate the third syngas stream or the fourth syngas stream into a retentate stream, being said CC -depleted stream, and a permeate stream, being said CC -enriched stream. In this aspect, a compressor may be arranged to compress the CCh-enriched stream, upstream said Reverse Water Gas Shift (RWGS) section.

A Reverse Water Gas Shift (RWGS) section is arranged to receive the CO2-enriched stream, at least a first portion of said hydrogen feed and at least a second portion of the steam feed, and to output a fifth syngas stream and optionally, a purge stream. The RWGS section comprises at least one RWGS reactor which may be non-electrical RWGS or electrically heated RWGS reactors. Non-electrical RWGS reactors include but are not limited to one or more fired RWGS reactors and autothermal RWGS reactors. For fired RWGS, any sustainable fuel, including H₂, can be combusted to provide heat to the endothermic reaction. Oxygen is required as an additional feed when autothermal RWGS is used.

The RWGS section may comprise one or more electrically heated RWGS reactors, which includes but not limited to a resistance heated RWGS reactor or an induction heated RWGS reactor which may be arranged in series or parallel. Resistance heated RWGS reactors are described, inter alia, in WO2019228797A1. Preferably, the RWGS section is an electrically heated RWGS section.

The RWGS catalyst can be either selective or non-selective. Selective RWGS catalyst is only active in WGS and RWGS reaction (reaction 2, reverse of reaction 1). Non-selective RWGS catalyst can catalyse both RWGS (reaction 2) and methanation and steam reforming reactions (reaction 3).

CO₂ + H₂ CO + H₂O (2, reverse of (1))

CO₂ + 4H₂ « CH₄ + 2H₂O (3)

If a selective RWGS catalyst is used in the RWGS section, then first tail gas stream from the synthesis section and recycled byproduct stream from the upgrading section (when present), comprising hydrocarbons need to be processed in the presence of a separate catalyst, having steam methane reforming activity (opposite of reaction (3)).

In one aspect, the electrically heated RWGS section can comprise structured catalyst comprising a macroscopic structure of electrically conductive material capable of catalysing both a reverse water gas shift reaction and a methanation reaction. The RWGS reactors may comprise catalysts that are active in both RWGS and methanation reactions, and/or catalysts that are active in only RWGS reaction. The catalyst may also be active in steam reforming.

In another alternative, the RWGS section may comprise a methanation section followed by autothermal reforming section. The methanation section may comprise one or more methanation units arranged in series or parallel. Methanation units may be heated reactors or adiabatic reactors.

Other arrangements of the RWGS section are as follows: In one aspect, the reverse water gas shift (RWGS) section comprises: optionally, a CO2-enriched stream compression unit, comprising at least one compressor stage, being arranged to receive the CO2-enriched stream and to output compressed CO2-enriched stream, a CO2-enriched stream pretreatment unit, comprising at least one reactor, where the reactor can be an adiabatic or a gas-cooled or water-cooled reactor, said pretreatment unit being arranged to receive the CCh-enriched stream and a portion of the steam feed, and to output a pretreated CO2-enriched stream, such that the CO2 content in the pretreated CO2-enriched stream is higher than that in the CO2- enriched stream, a first tail gas preconversion unit, which may comprise at least one olefin hydrogenation reactor, water gas shift reactor and/or higher hydrocarbon conversion reactor, wherein the said first tail gas preconversion unit being arranged to receive at least a first portion of the first tail gas stream, a second portion of the steam feed and to output a preconverted first tail gas stream; a preconverted first tail gas cooling and separation unit arranged to receive the pretreated CO2-enriched stream from the CO2-enriched stream pretreatment unit and the preconverted first tail gas stream from the first tail gas preconversion unit - preferably in admixture - and to output a first mixed RWGS feed stream and a first process condensate stream, wherein the first mixed RWGS feed stream is arranged to be mixed with a first portion of the hydrogen feed and - optionally - a third portion of the steam feed to provide a second mixed RWGS feed stream, a Reverse Water Gas Shift (RWGS) unit comprising at least one RWGS reactor, being arranged to receive the second mixed RWGS feed stream, and to output a first RWGS effluent stream, a syngas cooling and separation unit, which may optionally comprise syngas cleaning unit for removal of nitrogenous component from syngas, being arranged to receive the first RWGS effluent stream, and to output fifth syngas stream and a second process condensate stream.

Suitably, the CO2-enriched stream pretreatment unit, comprises at least one adiabatic reactor with outlet temperature < 350°C. Furthermore, the first tail gas preconversion unit, may comprise at least one WGS reactor, adiabatic or gas cooled or water-cooled reactor, with effluent gas temperature < 350°C.

In another aspect, in which the at least a part of the CO2-enriched stream is arranged to be mixed with the first portion of the first tail gas stream to provide a mixed RWGS section feed stream, and wherein the reverse water gas shift (RWGS) section comprises: optionally, a CO2-enriched stream compression unit, comprising at least one compressor stage, being arranged to receive the CO2-enriched stream and to output compressed CO2-enriched stream, a first tail gas preconversion unit, which may comprise at least one olefin hydrogenation reactor, water gas shift reactor and/or higher hydrocarbon conversion reactor, where the said first tail gas preconversion unit being arranged to receive at least a first portion of the mixed RWGS section feed stream, a second portion of the steam feed and to output a preconverted mixed RWGS section feed stream; a preconverted first tail gas cooling and separation unit, arranged to receive said preconverted mixed RWGS feed stream and to output a first mixed RWGS feed stream and a first process condensate stream, wherein the first mixed RWGS feed stream is arranged to be mixed with a first portion of the hydrogen feed and - optionally - a third portion of the steam feed to provide a second mixed RWGS feed stream, a Reverse Water Gas Shift (RWGS) unit comprising at least one RWGS reactor, being arranged to receive the second mixed RWGS feed stream, and to output a first RWGS effluent stream, a syngas cooling and separation unit, which may optionally comprise syngas cleaning unit for removal of nitrogenous component from syngas, being arranged to receive the first RWGS effluent stream, and to output fifth syngas stream and a second process condensate stream.

In case the first syngas stream comprises inert such as N2, Ar etc., the RWGS section may output a purge stream to avoid build-up of inerts in the system.

The fifth syngas stream from the RWGS section comprises CO, CO2, H2, CH4, and may comprise N2 and Ar, steam etc.

A second syngas purification section, when present, is arranged to receive the CO2-depleted stream from the CO2 separation section, and to output a sixth syngas stream. The second syngas purification may be required when first syngas purification section is not present.

A synthesis section is arranged to receive the fifth syngas stream, the sixth syngas stream and, optionally, a second portion of the hydrogen feed, and to provide a hydrocarbon product stream and a first tail gas stream. The first tail gas comprises primarily H2, CO, CO2 and CH4. Additionally, the first tail gas may comprise higher hydrocarbons, including olefins. Suitably, the synthesis section is arranged to receive the fifth syngas stream and the sixth syngas stream in the form of a combined syngas stream. The synthesis section may be a Fischer-Tropsch (F-T) section or a methanol synthesis section (including methanol-to-jet and methanol-to-gasoline).

In one aspect of the plant, at least a portion of the first tail gas stream from the synthesis section is arranged to be fed to a RWGS reactor arranged in the RWGS section. Preferably the portion of the tail gas stream is arranged to be compressed and preconverted before being fed to the RWGS section.

Fischer-Tropsch section

The synthesis section may be a Fischer-Tropsch (F-T) section such that the product stream is a hydrocarbon product stream.

At the inlet of said F-T section, the fourth synthesis gas stream suitably has a H2/CO ratio in the range 1.00 - 4.00; preferably in the range 1.50-2.10. In another aspect, the combined syngas stream at the inlet of said synthesis section suitably has a (H2 - CO2)/(CO + CO2) ratio in the range 1.50 - 2.50; preferably 1.80 - 2.30, more preferably 1.90 - 2.20.

The product stream provided by the F-T section is a raw hydrocarbon product stream comprising higher hydrocarbons such as long chain hydrocarbons and olefins. The ratio between long chain hydrocarbons and olefins in the raw product from the F-T section depends on the type of catalyst, reaction temperature etc. used in the process.

The plant may further comprise an upgrading unit arranged to receive at least a portion of the hydrocarbon product stream from the synthesis section, and to output an upgraded hydrocarbon product stream (e.g. a synthetic fuel product stream) and a byproduct stream, and wherein - optionally - at least a portion of the byproduct stream is arranged to be fed to the inlet of the RWGS section.

In the upgrading unit, the hydrocarbon product stream from the synthesis section, which includes light gases, water, unreacted syngas, and heavier hydrocarbons (like wax), is processed. The upgrading unit may carry out one or more of the following processes:

• Wax Hydrocracking : The long-chain hydrocarbons in the wax are broken down into shorter chains, which are more suitable for use as liquid fuels (like diesel and jet fuel).

• Separation: The raw product stream is first separated into different components. Light gases (e.g., methane, ethane) and water are typically removed and can be recycled back into the process. • Product Upgrading : Depending on the desired end-product, the separated fractions may undergo further processing or upgrading to meet specific fuel standards.

• Distillation or fractionation: The hydrocracked product is distilled to separate it into different fractions based on boiling point. This results in different types of fuel products.

The upgrading unit upgrades the long chain hydrocarbons to fuel fractions with well-defined boiling point range, i.e. Kerosene and/or Diesel and/or Naphtha.

The specifics of the upgrading unit process can vary depending on the design of the FT plant and the desired end products.

A process is also described for providing a hydrocarbon product stream from a carbonaceous feedstock, in the plant described herein, said process comprising : gasifying the carbonaceous feedstock and the oxygen feed, in gasification section so as to provide a gasification effluent in the form of a first syngas stream, optionally, feeding the first syngas stream from the gasification section and at least a first portion of the steam feed to the water gas shift (WGS) section, and providing a second syngas stream, wherein the CO2 content in the second syngas stream is higher than that in the first syngas stream, feeding the first syngas stream from the gasification section (in the absence of the optional WGS section or the second syngas stream (in the presence of the optional WGS section) to the syngas clean-up section and outputting a third syngas stream, and a first offgas stream, optionally, feeding the third syngas stream form the syngas clean-up section to the first purification section, and outputting a fourth syngas stream, separating the third syngas stream (in the absence of the optional first syngas purification section) or the fourth syngas stream (in the presence of the optional first syngas purification section), into a CC -enriched stream and a CO2-depleted stream in the CO2 separation section, feeding the CO2-enriched stream, at least a first portion of said hydrogen feed and at least a second portion of the steam feed, to the Reverse Water Gas Shift (RWGS) section, and outputting a fifth syngas stream, and optionally, a purge stream, optionally, feeding the CCh-depleted stream from the CCh-separation section to the second syngas purification section, and outputting a sixth syngas stream, feeding the fifth syngas stream; and either the sixth syngas stream or the CO2- depleted stream and, optionally a second portion of the hydrogen feed, to the synthesis section and providing a hydrocarbon product stream and a first tail gas stream.

In the process, the CO2-enriched stream may comprise 50%-90% of the CO2 present in the third syngas stream. Suitably, the CO2-enriched stream comprises 25 mol% - 80 mol% CO2, the remainder being comprised of H2, CO and CH4. Also, the H2/CO ratio in the CO2- enriched stream may be higher than that in the third syngas stream. Furthermore, the pressure of the CO2-enriched stream is suitably higher or the same as the pressure of first tail gas from the synthesis section.

The advantages of the proposed layout are as follows improved overall C-efficiency utilizing at least a part of (H2 + CO) from the third or fourth syngas feed directly to the synthesis section by employing the CO2-separation section due to separation of part of the third or fourth syngas feed, the size of the CO2- enriched stream pretreatment unit can be significantly reduced. potentially simpler and less expensive CO2-enriched stream pretreatment unit, due to less flow of CO2-enriched flow compared to the third or fourth syngas feed flow, the size of the entire RWGS section including RWGS units and energy consumption can be reduced

Use of a membrane-based CO2-separation may allow routing of the CO2-enriched steam directly to the existing first tail gas preconversion unit, obviating the need for a separate CO2-enriched stream pretreatment unit

Using membrane-based CO2-separation may allow sufficient pressure of the CO2- enriched stream to avoid an additional compressor.

Detailed description of the figures

Figures 1-4 illustrate schematic layouts of embodiments of the invention.

In Figure 1 :

10 gasification section

20 syngas clean-up section 30 CO2 separation section

30A membrane-based CO2 separation section

40 RWGS section

50 second syngas purification section 60 synthesis section

80 upgrading section

90 WGS section

210 first syngas purification section

1 carbonaceous feedstock 2, 2A, 2B hydrogen feed

3 oxygen feed

4, 4A, 4B steam feed

11 first syngas stream from the gasification section (10)

21 third syngas stream from the syngas clean-up section (20) 22 first off-gas stream from syngas clean-up section

31 CO2-enriched stream from the CO2-separation section (30,30A)

32 CO2-depleted stream from the CO2-separation section (30,30A)

41 fifth syngas stream from the RWGS section (40)

42 purge stream from the RWGS section (40) 45 combined syngas feed stream to synthesis section (60)

51 the sixth syngas stream

61 hydrocarbon product from synthesis section (60)

62 first tail gas stream from synthesis section (60)

81 synthetic fuel product stream

82 byproduct stream(s) from upgrading section (80)

91 second syngas from the WGS section (90)

211 fourth syngas stream

In Figure 2, an electrolysis section (70) is also illustrated, which receives steam/water feed (7) producing hydrogen (2, 2A, 2B) which is used as feed. Moreover, at least a part of byproduct oxygen from electrolysis section is used as the third feed (3) in the gasification section (10). In one embodiment the electrolysis section (70) comprises high temperature electrolysis fed with steam feed, where at least a part of the steam feed to the electrolysis section comes from the downstream synthesis section (60) and/or the RWGS section (not shown in the figure).

In figure 3 and 4, detailed units within the RWGS section (40) are illustrated. Additional streams and units/sections are described below. Possible recycle of byproduct from upgrading section (80) is not shown.

71 first tail gas compression unit

72 optional, CO2-enriched stream compression unit

110 CO2-enriched stream pretreatment unit

120 first tail gas preconversion unit

130 preconverted first tail gas cooling and separation unit 140 RWGS unit

150 syngas cooling and separation unit

2A hydrogen feed to the RWGS unit (140)

2B hydrogen feed to the synthesis section (60) 4B' steam feed to the first tail gas preconversion unit (120)

4B" optional, steam feed to the RWGS unit (140)

4B'" steam feed to the CO2-enriched stream pretreatment unit (110)

31' compressed CO2-enriched stream

62' the first tail gas after purge 63 compressed first tail gas after purge

111 pretreated CO2-enriched stream

121 preconverted first tail gas stream

122 admixture of stream 111 and 121

131 first mixed RWGS feed stream 132 second mixed RWGS feed stream

141 first RWGS effluent stream

232 first process condensate stream

252 first process condensate stream

155 mixed process condensate stream The present invention has been described with reference to a number of embodiments and figures. However, the skilled person is able to select and combine various embodiments within the scope of the invention, which is defined by the appended claims. All documents referenced herein are incorporated by reference.

EXAMPLES

In Table 1, advantages of the invention are illustrated. The results are taken from a process simulation of gasifier effluent (11) conversion to fuels via Fischer-Tropsch (FT) synthesis. In such processes, gasifier effluent is the main feed comprising ca. 16 mol% CO₂, ca. 9 mol% CH₄, and H₂/CO ratio of ca. 1.3. The H₂ feed (2), from alkaline electrolysis, is used as needed.

Table 1

Case Cl represents an inefficient layout in which not all C-molecules, obtained from gasification of carbonaceous feedstock, are utilized to produce valuable end product. Instead, a large part of the C in gasifier effluent (the first syngas) exits the process without being converted to fuel, resulting in < 50% overall C-efficiency.

In case C2, a better alternative is shown, in which high C-efficiency (> 95%) is achieved by converting CO₂ and CH₄ in the gasifier effluent to syngas. This also requires more H₂ feed (2) compared to Cl. Typically, the source of renewable H₂ is electrolysis, requiring additional power. Moreover, the first tail gas from synthesis section is also recycled and processed together with gasifier effluent and other feeds in electrically heated reactor. The electrically heated reactor includes but not limited to the resistance heated RWGS reactor or the induction heated RWGS reactor. In this example, non-selective RWGS catalyst is utilized. However, due to significantly better C-efficiency overall process becomes more economical.

In case C3, as per the current invention, employing a CO₂ removal section (in this case membrane-based CO₂ separation section) overall efficacy of the process is further improved. Due to separation of a part of the CO₂ from the third or fourth syngas, the CO2-enriched gas that needs to be processed in the electrically heated reactor is reduced, resulting in ca. 28% smaller reactor compared to that in C2. Overall power consumption is reduced by ca. 8% compared to C2, while high C-efficiency is maintained.

Claims

1. A plant, preferably a synthetic fuel plant, said plant comprising : a carbonaceous feedstock (1), a hydrogen feed (2), an oxygen feed (3), a steam feed (4), a gasification section (10) arranged to receive said carbonaceous feedstock (1), said oxygen feed (3), and to gasify said carbonaceous feedstock (1) so as to provide a gasification effluent in the form of a first syngas stream (11), optionally, a water gas shift (WGS) section (90), arranged to receive at least a portion of the first syngas stream (11) from the gasification section (10) and at least a first portion (4A) of the steam feed (4) and to provide a second syngas stream (91), such that the CO2 content in the second syngas stream (91) is higher than that in the first syngas stream (11), a syngas clean-up section (20) arranged to receive the first (11) syngas stream or the second syngas stream (91), and to output a third syngas stream (21), and a first offgas stream (22), optionally, a first syngas purification section (210), arranged to receive the third syngas stream (21) from syngas clean-up section (20), to output a fourth syngas stream (211), a CO2 separation section (30) arranged to receive the third syngas stream (21) or the fourth syngas stream (211), and separate it into a CC -enriched stream (31) and a CC -depleted stream (32), a Reverse Water Gas Shift (RWGS) section (40), being arranged to receive the CO2- enriched stream (31), at least a first portion (2A) of said hydrogen feed (2) and at least a second portion (4B) of the steam feed (4), and to output a fifth syngas stream (41) and optionally, a purge stream (42), optionally, a second syngas purification section (50), arranged to receive the CO2- depleted stream (32) from the CO2-separation section (30), to output a sixth syngas stream (51), a synthesis section (60) arranged to receive the fifth syngas stream (41); and either the sixth syngas stream (51) or the CC -depleted stream (32) and, optionally a second portion (2B) of the hydrogen feed (2), and to provide a hydrocarbon product stream (61) and a first tail gas stream (62).

2. The plant according to claim 1, being a synthetic fuel plant, wherein the synthesis section (60) is a Fischer-Tropsch (F-T) section, and the product stream (61) is a hydrocarbon product stream.

3. The plant according to any one of the preceding claims, wherein at least a portion of the first tail gas stream (62) from the synthesis section (60) is arranged to be fed to a RWGS reactor arranged in the RWGS section (40), preferably wherein said portion of the tail gas stream (62) is arranged to be compressed and preconverted before being fed to the RWGS unit within the RWGS section (40).

4. The plant according to any one of the preceding claims, wherein the CO2 separation section (30) comprises at least one CO2 membrane separation unit (30A), being arranged to separate the third syngas stream (21) or the fourth syngas stream (211) into a retentate stream, being said CC -depleted stream (32), and a permeate stream, being said CO2- enriched stream (31).

5. The plant according to claim 4, further comprising a compressor, being arranged to compress the CC -enriched stream (31), upstream said Reverse Water Gas Shift (RWGS) section (40).

6. The plant according to any one of the preceding claims, further comprising an electrolysis section (70) and a water/steam feed (7) to said electrolysis section (70), said electrolysis section (70) being arranged to provide at least a portion of said hydrogen feed (2) and at least a portion of said oxygen feed (3) in said plant, via electrolysis of said water/steam feed (7).

7. The plant according to any one of the preceding claims, wherein the RWGS section (40), is an electrical RWGS section (40), comprising at least one electrically heated RWGS reactor.

8. The plant according to any one of the preceding claims, wherein the synthesis section

(60) is arranged to receive the fifth syngas stream (41) and either the sixth syngas stream (51) or the CO2-depleted stream (32) in the form of a combined syngas stream (45).

9. The plant according to any one of the preceding claims, further comprising an upgrading unit (80) arranged to receive at least a portion of the hydrocarbon product stream

(61) from the synthesis section (60), and to output an upgraded hydrocarbon product stream (81) e.g. a synthetic fuel product stream, and a byproduct stream (82), and wherein - optionally - at least a portion of the byproduct stream (82) is arranged to be fed to the inlet of the RWGS section (40).

10. The plant according to any one of the preceding claims, wherein the reverse water gas shift (RWGS) section (40) comprises: optionally a CC -enriched stream compression unit (72), comprising at least one compressor stage, being arranged to receive the CO2-enriched stream (31) and to output compressed CO2-enriched stream (31'), a CO2-enriched stream pretreatment unit (110), comprising at least one reactor, where the reactor can be an adiabatic or a gas-cooled or water-cooled reactor, said pretreatment unit being arranged to receive the CCh-enriched stream (31, 31') and a portion (4B'") of the steam feed (4) and to output a pretreated CO2-enriched stream (111), such that the CO2 content in the pretreated CO2-enriched stream (111) is higher than that in the CC -enriched stream (31, 31'), a first tail gas preconversion unit (120), said first tail gas preconversion unit (120) being arranged to receive at least a first portion (62, 63) of the first tail gas stream (62), a second portion (4B') of the steam feed (4) and to output a preconverted first tail gas stream (121); a preconverted first tail gas cooling and separation unit (130) arranged to receive the pretreated CO2-enriched stream (111) from the CO2-enriched stream pretreatment unit (110) and the preconverted first tail gas stream (121) from the first tail gas preconversion unit (120) - preferably in admixture (122) - and to output a first mixed RWGS feed stream (131) and a first process condensate stream (232), wherein the first mixed RWGS feed stream (131) is arranged to be mixed with a first portion (2A) of the hydrogen feed (2) and - optionally - a third portion (4B'") of the steam feed (4B) to provide a second mixed RWGS feed stream (132), a Reverse Water Gas Shift (RWGS) unit (140) comprising at least one RWGS reactor, being arranged to receive the second mixed RWGS feed stream (132), and to output a first RWGS effluent stream (141), a syngas cooling and separation unit (150), being arranged to receive the first RWGS effluent stream (141), and to output fifth syngas stream (41) and a second process condensate stream (252).

11. The plant according to any one of claims 1-10, wherein at least a part of the CO2- enriched stream (31, 31') is arranged to be mixed with the first portion (62") of the tail gas stream (62) to provide a mixed RWGS section feed stream (62", 63), and wherein the reverse water gas shift (RWGS) section (40) comprises: optionally, a CO2-enriched stream compression unit (72), comprising at least one compressor stage, being arranged to receive the CO2-enriched stream (31) and to output compressed CO2-enriched stream (31'), a first tail gas preconversion unit (120), said first tail gas preconversion unit (120) being arranged to receive at least a first portion of the mixed RWGS section feed stream (62", 63), a second portion (4B') of the steam feed (4) and to output a preconverted mixed RWGS section feed stream (121); a preconverted first tail gas cooling and separation unit (130) arranged to receive said preconverted mixed RWGS feed stream (121) and to output a first mixed RWGS feed stream (131) and a first process condensate stream (232), wherein the first mixed RWGS feed stream (131) is arranged to be mixed with a first portion (2A) of the hydrogen feed (2) and - optionally - a third portion (4B") of the steam feed (4B) to provide a second mixed RWGS feed stream (132), a Reverse Water Gas Shift (RWGS) unit (140), being arranged to receive the second mixed RWGS feed stream (132), and to output a first RWGS effluent stream (141), a syngas cooling and separation unit (150), being arranged to receive the first RWGS effluent stream (141), and to output fifth syngas stream (41) and a second process condensate stream (252).

12. A process for providing a hydrocarbon product stream from a carbonaceous feedstock (1), in the plant according to any one of the preceding claims, said process comprising : gasifying the carbonaceous feedstock (1) and the oxygen feed (3), in gasification section (10) so as to provide a gasification effluent in the form of a first syngas stream (11), optionally, feeding the first syngas stream (11) from the gasification section (10) and at least a first portion (4A) of the steam feed (4) to the water gas shift (WGS) section (90), and providing a second syngas stream (91), wherein the CO2 content in the second syngas stream (91) is higher than that in the first syngas stream (11), feeding the first syngas stream (11) from gasification section (10) or the second syngas stream (91) to the syngas clean-up section (20) and outputting a third syngas stream (21), and a first offgas stream (22), optionally, feeding the third syngas stream (21) from the syngas clean-up section (20) to the first syngas purification section (210), and outputting a fourth syngas stream (211), separating the third syngas stream (21) or the fourth syngas stream (211), into a CC -enriched stream (31) and a CCh-depleted stream (32) in the CO2 separation section (30), feeding the CO2-enriched stream (31), at least a first portion (2A) of said hydrogen feed (2) and at least a second portion (4B) of the steam feed (4), to the Reverse Water Gas Shift (RWGS) section (40), and outputting a fifth syngas stream (41), and optionally, a purge stream (42), optionally, feeding the CO2-depleted stream (32) from the CC -separation section (30) to the second syngas purification section (50), and outputting a sixth syngas stream (51), feeding the fifth syngas stream (41); and either the sixth syngas stream (51) or the CC -depleted stream (32) and, optionally a second portion (2B) of the hydrogen feed (2), to the synthesis section (60) and providing a hydrocarbon product stream (61) and a first tail gas stream (62).

13. The process according to claim 12, wherein the CCh-enriched stream (31, 31') comprises 50%-90% of the CO2 present in the third syngas stream (21).

14. The process according to any one of claims 12-13, wherein the CCh-enriched stream (31, 31') comprises 25 mol% - 80 mol% CO2, the remainder being comprised of H2, CO and CH₄.

15. The process according to any one of claims 12-14, wherein the H2/CO ratio in the CO2- enriched stream (31, 31') is higher than that in the third syngas stream (21).

16. The process according to any one of claims 12-15, wherein the pressure of the CO2- enriched stream (31) is higher or the same as the pressure of first tail gas (62) from the synthesis section (60).