Method for producing synthetic fuels

Abstract

The present invention provides a method for producing synthetic fuels, comprising gasifying a carbonaceous feedstock comprising waste and / or biomass to produce a raw synthesis gas; supplying the raw synthesis gas to a primary purification zone to wash away particulates and ammonia or HCl from the raw synthesis gas; contacting the synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone; contacting the desulfurized raw synthesis gas with a physical solvent for CO2 that effectively absorbs CO2 in a tertiary purification zone; removing at least a portion of the absorbed CO2 in a solvent regeneration stage to recover the CO2 in a sufficiently pure form for sequestration or other uses; and supplying the cleaned synthesis gas to a further reaction queue to produce synthetic fuels.

Description

Technical Field

[0001] The present invention relates to a chemical engineering process for producing useful products, such as synthetic fuels, from waste materials and / or biomass in a manner that reduces the carbon intensity of the process compared to conventional processes of this type. Background Art

[0002] The production of useful products such as synthetic fuels from waste materials and / or biomass is well known in the art. We may refer to such production methods as WTL (waste-to-liquid) and BTL (biomass-to-liquid) processes.

[0003] Typical WTL and BTL processes involve the gasification of waste or biomass feedstocks by steam reforming to produce a raw syngas, which may then be treated and purified in various ways before entering a chemical reaction train to produce useful products.

[0004] In the case where the useful product is a synthetic fuel (e.g., drop-in synthetic fuel), the chemical reaction train will typically include a Fischer-Tropsch (FT) reactor. The FT process is widely used to produce fuels from carbon monoxide and hydrogen and can be represented by the following reaction equation:

[0005] (2n+1)H2+nCO→C n H 2n+2 +nH2O

[0006] Carbon intensity (also known as CI) is a measure of the amount of carbon used or released by an industrial process relative to the actual results of the process, usually expressed as grams of carbon dioxide equivalent emitted per megajoule of energy produced by the process (or that can be produced from the products of the process).

[0007] The term "carbon intensity" or "CI" can also be interpreted in terms of models based on an overall life cycle assessment (e.g., from forest to tailpipe). For example, GREET (a publicly available spreadsheet model developed by Argonne National Laboratory (ANL)) or a California-specific version of the Argonne National Laboratory's GREET life cycle model for calculating GHG emissions according to the California Low Carbon Fuel Standard (LCFS) is the CA-GREET version 3.0 (Tier 1) model. Other suitable models are available, such as the Biomethane & Biogas Carbon Calculator published by NNFCC Ltd, Biocentre, York Science Park, Innovation Way, York, YO10 5NYUK. Carbon intensity provides a measure of the overall energy efficiency of a process. For example, carbon intensity can be understood as the grams of CO2 equivalent per MJ of fuel produced.

[0008] It is desirable to reduce the carbon intensity in chemical engineering processes for producing useful products such as synthetic fuels from waste and / or biomass to provide a more environmentally friendly process. Current U.S. environmental standards target a 60% or greater reduction in greenhouse gas emissions (measured in gCO2-eq / MJ fuel) compared to a baseline of fuel from a refinery for advanced biofuels produced in a WTL or BTL process that is eligible for RINs (Renewable Identification Numbers). Operationally, it is desirable to reduce greenhouse gas emissions for any given synthetic fuel production pathway by at least 65%.

[0009] The problem of reducing the carbon intensity in fuel production has been addressed to some extent in the art.

[0010] For example, WO2015042315 discloses a method for reducing the carbon emission intensity of a fuel, the method comprising capturing a carbon dioxide fluid from a first hydrocarbon fluid production process; and injecting the captured carbon dioxide from one or more wellbores into an underground area, which is said to increase the production of a second hydrocarbon fluid in the area, and at least one of the first or second hydrocarbon fluids is said to be processed into a hydrocarbon fuel comprising a low carbon intensity fuel based at least in part on the captured and injected CO2 fluid.

[0011] WO2013009419 discloses a low sulfur marine fuel composition derived from blending various bio-oils with petroleum-based heavy residual fuel oils and distillates, wherein the final sulfur content and carbon intensity are controlled by the ratio of the bio-oil to other heavy residual fuel oils and distillates.

[0012] To date, there appears to have been little consideration of how to reduce the carbon intensity of otherwise satisfactory WTL or BTL processes.

[0013] WTL and BTL processes are well known in the art.

[0014] For example, EP2350233A1 relates to a method for producing liquid hydrocarbon products from solid biomass, the method comprising gasifying the solid biomass to produce a crude synthesis gas, conditioning the crude synthesis gas to obtain a purified synthesis gas, and subjecting the purified gas to Fischer-Tropsch synthesis.

[0015] WO2018026388 describes the conversion of one or more carbon-containing feedstocks, such as plastics, agricultural residues and forest restoration wood, into hydrocarbons.

[0016] Some prior art WTL and BTL processes have sought to address environmental issues.

[0017] For example, WO2017011025A1 and WO2017039741A1 disclose systems for producing high biogenic carbon concentration Fischer-Tropsch (FT) liquids derived from municipal solid waste (MSW) and high biogenic content fuels derived from renewable organic feedstock sources.

[0018] Other prior art documents have considered ways to recycle carbon dioxide during production processes. For example, WO2016178915 discloses a method involving the formation and oxidation of hydrocarbons using oxygen provided by an ion transport membrane. The document relates in part to a method comprising steam reforming and subsequent production of a synthetic product, wherein carbon dioxide and / or hydrogen downstream of the process is recycled to produce the synthetic product.

[0019] US20110000366A1 describes a method for treating a process gas stream containing CO2, which is obtained in the production of pure synthesis gas from raw gas in the partial oxidation of heavy oil, petroleum coke or waste or in the gasification of coal, or in the treatment of natural gas or associated natural gas, CO2 is removed by physical or chemical adsorption and the solvent loaded with CO2 is expanded to a lower pressure to desorb CO2. In order to produce CO2 as pure as possible, the contaminated CO2 is condensed to at least 60 bar [a] or below its critical temperature to at least 70 bar [a], and the impurities contained in the liquid CO2 are removed by stripping with gaseous CO2 guided in countercurrent.

[0020] EP 0 629 685 describes a partial oxidation process for producing a hot clean gas stream substantially free of particulate matter, ammonia, halides, alkali metal compounds and sulphur-containing gases for use as synthesis gas, reducing gas or fuel gas.

[0021] US3540867 describes the production of a gas rich in carbon monoxide and / or hydrogen from a solid carbonaceous fuel by distillation or by gasification with steam and oxygen, cooling the hot raw gas from the distillation or gasification to a temperature above about 180°C to remove dust and condensable materials, heating the gas with steam enrichment, adding oxygen thereto, and cracking the gas-stream-oxygen mixture over a cracking catalyst to a temperature above about 700°C; cooling the gas from the cracking with or without converting the carbon monoxide contained therein with steam in a shift reaction, and removing CO2, H2S and NH3 from the cooled gas.

[0022] CN105505480 describes a desulfurization purification system for coke oven gas.

[0023] JP2015013940 describes a gas refining facility and an integrated coal gasification combined cycle facility.

[0024] US 4,073,862 describes a process for removing ammonia, hydrogen sulfide and hydrocyanic acid from gases such as coke oven gas.

[0025] US 4,810,417 describes a process for the simultaneous production of methanol synthesis gas and ammonia synthesis gas from a raw coal gas which is initially subjected to an H2S scrubbing at low temperature.

[0026] US5470361 describes a method for gasifying urban waste plastics, whereby pieces of waste material of 20 mm block size are compressed and heated at a pressure of 40 to 80 bar until a temperature of 230°C to 300°C is produced to produce HCl-containing gas and plastic waste containing less than 3000 mg / kg of HCl, and the produced HCl-containing gas is scrubbed with water to obtain a hydrochloric acid solution.

[0027] It appears that none of these documents provide a satisfactory approach to reducing the carbon intensity in an otherwise functional WTL or BTL process.

[0028] It is an object of the present invention to provide an improved process for producing useful products, such as synthetic fuels, from waste and / or biomass, wherein the carbon intensity of the process is reduced compared to conventional such processes. Summary of the invention

[0029] In a first aspect of the present invention, there is provided a method for producing a synthetic fuel, comprising:

[0030] a. gasifying a carbonaceous feedstock comprising waste and / or biomass to produce a raw syngas comprising H2, CO, CO2, at least one other carbonaceous material comprising at least CH4 and tar, and pollutants containing particulates, ammonia or HCl and sulfur-containing gases;

[0031] b. supplying at least a portion of the raw syngas to a primary purification zone, the primary purification zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the raw syngas, to provide a washed raw syngas comprising H2, CO, CO2 and contaminants comprising sulfur gases;

[0032] c. supplying at least a portion of the washed raw synthesis gas to a secondary purification zone;

[0033] d. contacting the washed raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone to effectively at least partially absorb the sulfur-containing materials from the washed raw synthesis gas, and recovering an at least partially desulfurized, detarred washed raw synthesis gas comprising H2, CO and CO2 from the secondary purification zone;

[0034] e. supplying the at least partially desulfurized, detarred washed raw synthesis gas to a tertiary purification zone;

[0035] f. contacting the at least partially sweetened, detarred, washed raw syngas with a physical solvent for CO2 in a tertiary purification zone to effectively at least partially absorb CO2 from the at least partially sweetened, detarred, washed raw syngas, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2, and a second stream comprising clean syngas comprising H2, CO and optionally remaining contaminants;

[0036] g. removing at least a portion of the absorbed CO2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover the CO2 separately in a sufficiently pure form for sequestration or other use; and

[0037] h. Supplying the second stream of cleaned synthesis gas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or optional purification stages to at least partially remove any remaining contaminants.

[0038] Also provided is a method for producing a synthetic fuel, comprising:

[0039] a. gasifying a carbonaceous feedstock comprising waste and / or biomass to produce a raw synthesis gas comprising H2, CO, CO2, at least one other carbonaceous material comprising at least CH4 and tar, and pollutants comprising particulates, ammonia or HCl and sulfur-containing gases and optionally containing an inert gas such as N2;

[0040] b. supplying at least a portion of the raw syngas to a primary purification zone, the primary purification zone at least partially supplying an aqueous stream to scrub particles and ammonia or HCl from the raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the raw syngas, to provide a washed raw syngas comprising H2, CO, CO2 and contaminants comprising sulfur gases;

[0041] c. supplying at least a portion of the washed raw synthesis gas to a secondary purification zone;

[0042] d. contacting the washed raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone to effectively at least partially absorb the sulfur-containing materials from the washed raw synthesis gas, and recovering from the secondary purification zone an at least partially desulfurized, detarred washed raw synthesis gas comprising H2, CO and CO2 and optionally remaining contaminants;

[0043] e. supplying the at least partially desulfurized, detarred washed raw synthesis gas to a tertiary purification zone;

[0044] f. contacting the at least partially desulfurized, detarred, washed raw syngas with a physical solvent for CO2 in a tertiary purification zone effective to at least partially absorb CO2 from the at least partially desulfurized, detarred, washed raw feedstock, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2 and a second stream comprising clean syngas comprising H2, CO and optionally remaining contaminants;

[0045] g. removing at least a portion of the absorbed CO2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover the CO2 separately in a sufficiently pure form for sequestration or other use; and

[0046] h. Supplying the second stream of cleaned synthesis gas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or optional purification stages to at least partially remove any remaining contaminants.

[0047] The steam saved by using physical solvents in step d can be used in other parts of the plant to further reduce energy consumption, for example, drying of raw materials, heating of process streams in different units and heat tracing.

[0048] The raw synthesis gas recovered from the gasification stage can be at least partially detarred before being purified by partial oxidation. Therefore, there is also provided a method for producing synthetic fuels, comprising:

[0049] a. gasifying a carbonaceous feedstock comprising waste and / or biomass to produce a raw synthesis gas comprising H2, CO, CO2, at least one other carbonaceous material comprising at least CH4 and tar, and pollutants comprising particulates, ammonia or HCl and sulfur-containing gases and optionally containing an inert gas such as N2;

[0050] b. partially oxidizing the raw synthesis gas to provide a partially oxidized raw synthesis gas comprising H2, CO, CO2, and pollutants comprising particulates, ammonia or HCl, and sulfur-containing gases;

[0051] c. optionally compressing at least a portion of the partially oxidized raw syngas and supplying it to a primary cleanup zone, the primary cleanup zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the partially oxidized raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the partially oxidized raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the partially oxidized raw syngas, to provide a water-washed partially oxidized raw syngas comprising H2, CO, CO2 and contaminants comprising sulfur-containing gases;

[0052] d. supplying at least a portion of the washed partially oxidized raw synthesis gas to a secondary purification zone;

[0053] e. contacting the washed partially oxidized raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone effective to at least partially absorb the sulfur-containing materials from the washed partially oxidized raw synthesis gas, and recovering from the secondary purification zone an at least partially desulfurized washed partially oxidized raw synthesis gas comprising H2, CO and CO2 and optionally remaining contaminants;

[0054] f. supplying the at least partially desulfurized washed partially oxidized raw synthesis gas to a tertiary purification zone;

[0055] g. contacting the at least partially desulfurized washed partially oxidized raw synthesis gas with a physical solvent for CO2 in a tertiary purification zone to effectively at least partially absorb CO2 from the at least partially desulfurized washed partially oxidized raw synthesis gas, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2 and a second stream comprising clean synthesis gas comprising H2, CO and optionally remaining contaminants;

[0056] h. removing at least a portion of the absorbed CO 2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover the CO 2 separately in a sufficiently pure form for sequestration or other use;

[0057] i. The second stream of cleaned synthesis gas is supplied to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or an optional purification stage to at least partially remove any remaining contaminants.

[0058] The process of the present invention reduces the carbon intensity of an otherwise practical WTL or BTL process in a number of interrelated ways.

[0059] The inventors of the present invention have surprisingly found that the method according to the present invention provides an effective method for reducing carbon intensity, which is superior to conventional methods in the art. This is because the method of the present invention reduces natural gas consumption and / or electricity input to the facility, and / or utilizes the saved steam from the downstream process for the upstream stage. Therefore, the method according to the present invention is more environmentally friendly than conventional methods.

[0060] For example, the carbon dioxide recovered in the present invention is purer than that produced using the processes in the art. Therefore, no additional purification process downstream is required in the present invention. In addition, the recovered pure carbon dioxide can be directly used for isolation or commercialization. This has a significant impact on carbon intensity.

[0061] Furthermore, although gas purification by physical absorption is more energy intensive than the alternative chemical adsorption method due to the need for refrigeration of the physical absorption solvent, when the entire facility was evaluated, it was surprisingly found that the overall facility electrical input was reduced. This is at least in part because the amount of steam required for chemical solvent regeneration is at least about an order of magnitude higher than the amount of steam required for the physical solvent; therefore, the amount of steam required for the entire facility is reduced. The lower steam requirement reduces the natural gas (or other fuel or energy source) input required to generate the steam. In addition, some of the low-pressure steam can also be used to dry the feedstock.

[0062] Thus, although the method of the present invention selects a more energy intensive gas cleaning sub-process, the overall electricity demand of the facility is lower, thereby helping to reduce the carbon intensity score.

[0063] The carbonaceous feedstock may include at least one of woody biomass, municipal solid waste, and / or commercial and industrial waste.The carbonaceous feedstock will have fluctuating compositional characteristics, depending on the source and chemical nature of the feedstock used.

[0064] The method according to the invention can ensure little or no landfill or waste that pollutes the environment. Furthermore, when using the method according to the invention, there is no land use change caused by fuel requirements because the method of the invention has the ability to process a wide variety of feedstocks.

[0065] Non-recyclable waste is often sent to landfills or burned, while woody biomass is often left on the forest floor and / or can cause forest fires. The method according to the invention provides a way to dispose of waste with lower emissions than burning or landfills. Carbon waste can be converted into useful products, such as sustainable fuels for aircraft or vehicles, rather than being burned.

[0066] The use of physical solvents to remove sulfur and carbon dioxide (acid gases) from crude syngas is a relatively energy intensive process that requires greater electrical input due to the refrigeration requirements of the physical solvents compared to conventional chemical removal methods widely taught in the art (such as amine scrubbing to remove carbon dioxide and liquid redox chemistry to remove sulfur). However, the steam demand in equipment operating conventional chemical methods for acid gas removal is at least two orders of magnitude higher than equipment operating in accordance with the method of the present invention to achieve acid gas removal by physical absorption. This lower steam demand reduces the energy requirements for steam generation and, therefore, reduces the energy consumption of the entire process / facility. By removing sulfur and carbon dioxide from crude syngas by physical adsorption, the method of the present invention reduces the net energy consumption (natural gas and electrical input) of the facility compared to conventional methods, and, therefore, reduces the carbon intensity.

[0067] Secondly, the "saved steam" available in the plant due to the use of a physical rather than a chemical acid gas removal stage can be used in other parts of the plant to further reduce energy consumption, as explained below in connection with the process according to the invention in a specific embodiment of the invention, wherein the further reaction train is a Fischer-Tropsch reaction train. Typically, the steam available at the LP (low pressure) level can be used to dry the feedstock in a biomass or waste boiler and then supply the dried feedstock to a gasifier, and / or for an oxygen heater in an air separation unit and / or for preheating a feedstream to one or more process stages. If further LP steam is available, it can be discharged to the LLP header and used for heating the guard bed and / or for the upgrading section and / or the wastewater stripping section (e.g., wastewater reboiler) and / or the fuel system (e.g., natural gas heater) and / or the deaerator and / or for heating and tracking intermediate or chemical storage tanks.

[0068] The inventors have discovered that drying the carbonaceous feedstock prior to gasification, particularly when using biomass or moist waste feedstocks, helps reduce carbon intensity. Drying of the carbonaceous feedstock reduces the required amount of steam that needs to enter the gasifier at the beginning of the process because it maximizes the use of combustion heat (in the gasification and partial oxidation units) to heat the process reactions. In addition, drying increases the fuel density (facilitating smaller storage) and the calorific value of the feedstock. If steam or liquid water is present in the gasifier, additional heat (generated by the combustion of the fuel with oxygen) is required to compensate, thereby consuming energy. Therefore, drying the feedstock prior to gasification overcomes the need for oxygen compensation. Since oxygen is expensive, drying the feedstock prior to gasification reduces the cost of the entire process.

[0069] Drying the carbonaceous feedstock can result in a carbonaceous feedstock having a moisture content of less than about 20 wt%, less than about 15 wt%, or less than about 10 wt%. Preferably, the carbonaceous feedstock has a moisture content of less than about 10 wt%.

[0070] Steam gained or "saved" from downstream processes as described above may be used to dry the carbonaceous feedstock.

[0071] Before feeding the carbonaceous feedstock into the biomass or waste boiler, the feedstock can be dried by a feedstock dryer. As non-limiting examples, the dryer can be a rotary tube dryer or a belt dryer.

[0072] Conventional processes typically use dryers to dry biomass or waste feedstocks. Conventionally, dryers are huge consumers of natural gas and / or other forms of power, which is undesirable from a carbon intensity perspective. It is therefore desirable to reduce the amount of natural gas and / or power used to reduce the carbon intensity of the process.

[0073] The inventors unexpectedly found that using at least a portion of the steam obtained from a downstream process such as a low steam physical absorption process is beneficial to reducing carbon intensity. The steam obtained from the low steam physical absorption process (which is additionally used to clean the raw synthesis gas) can be recovered and used to help dry the raw material before feeding the raw material to the biomass or waste boiler. This reduction in carbon intensity is achieved by significantly reducing or eliminating the need to provide fresh steam and / or natural gas to the dryer to help dry the raw material by selecting a more energy-intensive physical absorption process (which achieves a global reduction in energy utilization). This makes the method more environmentally friendly than conventional methods in the art.

[0074] Other suitable drying options for drying the carbonaceous feedstock may include the use of supplemental solar energy, natural gas, electric dryers, and / or microwave dryers. In some cases, the biomass and / or waste feedstock may be burned to generate the heat required in the dryer.

[0075] When dry waste is used as the carbonaceous feedstock source, the feedstock may not need to be dried before entering the gasification zone. After appropriate selection and pulverization, the dry waste can be fed directly into the gasifier.

[0076] Thus, the process of the invention may optionally include a step of drying the feedstock to a moisture content of less than, for example, 10% w / w prior to gasification. This step may be performed in a biomass or waste dryer supplied with low pressure steam available on the plant to dry the feedstock prior to gasification.

[0077] Not all carbonaceous feedstocks originating from waste or biomass may need to be dried prior to gasification. If the moisture content of the feedstock is already below, for example, 10% w / w, it may not be necessary to dry such feedstock. However, in an operational WTL or BTL plant, the incoming feedstock is likely to have a variable composition, including with respect to moisture. If the feedstock contains more than, for example, 10% w / w moisture, it may be desirable to dry the feedstock to a moisture content below, for example, 10% w / w. Excess moisture supplied to the gasifier with the feedstock results in the gasifier requiring more power to be supplied in the form of oxygen. As described above, such drying can be achieved in a variety of ways.

[0078] In the process of the invention, the gasification stage can be carried out at low pressure or high pressure. "Low pressure" means below about 5 bar. "High pressure" means above about 5 bar, for example above about 10 bar. In the case of high pressure gasification, a favorable consequence for carbon intensity is that the synthesis gas does not need to be compressed when entering the primary purification stage.

[0079] The process of the invention may optionally comprise a shift reaction or conditioning stage, the purpose of which is to adjust the hydrogen to carbon monoxide ratio of the synthesis gas ultimately supplied to the further reaction train.

[0080] Therefore, the present invention also provides a method for producing synthetic fuel, comprising:

[0081] a. Providing a carbonaceous feedstock comprising waste and / or biomass;

[0082] b. supplying the carbonaceous feedstock to the gasification zone;

[0083] c. Providing steam supply and supplying steam to the gasification zone;

[0084] d. raising the temperature of the gasification zone to a temperature effective for gasification of the carbonaceous feedstock in the gasification zone;

[0085] e. contacting the carbonaceous feedstock with steam in a gasification zone to effectively produce a raw synthesis gas comprising H2, CO, CO2, at least one other carbonaceous material comprising at least CH4, and contaminants comprising particulates, ammonia or HCl, sulfur-containing gases, and optionally an inert gas such as N2;

[0086] f. recovering raw synthesis gas from the gasification zone;

[0087] g. supplying at least a portion of the raw synthesis gas to a partial oxidation zone maintained at a high temperature;

[0088] h. contacting the raw synthesis gas with an oxygen-containing gas in a partial oxidation zone to effectively at least partially oxidize the at least one other carbonaceous material to provide a partially oxidized raw synthesis gas comprising H2, CO, CO2, and contaminants including particulates, ammonia or HCl, and sulfur-containing gases;

[0089] i. recovering partially oxidized synthesis gas from the partial oxidation zone;

[0090] j. supplying at least a portion of the partially oxidized raw syngas to a primary cleanup zone, the primary cleanup zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the partially oxidized raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the partially oxidized raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the partially oxidized raw syngas, to provide a water-washed partially oxidized raw syngas comprising H2, CO, CO2 and contaminants containing sulfur-containing gases;

[0091] k. supplying at least a portion of the washed partially oxidized raw synthesis gas to a secondary purification zone;

[0092] 1. contacting the washed partially oxidized raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone effective to at least partially absorb the sulfur-containing materials from the washed partially oxidized raw synthesis gas and recovering from the secondary purification zone an at least partially desulfurized washed partially oxidized raw synthesis gas comprising H2, CO and CO2 and optionally remaining contaminants;

[0093] m. supplying at least a first portion of the at least partially desulfurized washed partially oxidized raw syngas to a shift reaction or conditioning zone and shifting the ratio of H2 to CO of the at least partially desulfurized washed partially oxidized raw syngas to a selected ratio to provide a shifted at least partially desulfurized washed partially oxidized raw syngas comprising H2, CO, CO2, and optionally remaining contaminants;

[0094] n. supplying the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the at least partially desulfurized washed partially oxidized raw synthesis gas from step m, to a tertiary purification zone;

[0095] o. contacting the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the at least partially desulfurized washed partially oxidized raw synthesis gas from step m, with a physical solvent for CO2 in a tertiary purification zone, so as to be effective to at least partially absorb CO2 from the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2 and a second stream comprising clean synthesis gas, the clean synthesis gas comprising H2, CO and optionally remaining contaminants;

[0096] p. removing at least a portion of the absorbed CO2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover CO2 separately in a sufficiently pure form for sequestration or other purposes;

[0097] q. Supplying the second stream of clean syngas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or optional purification stages to at least partially remove any remaining contaminants.

[0098] The shift stage may be performed before the second purification stage rather than after (for example, if the gas shift is a water gas shift and if a sulfur-tolerant water gas shift catalyst is used in the water gas shift reaction zone). Thus, there is also provided herein a method for producing a synthetic fuel, comprising:

[0099] a. Providing a carbonaceous feedstock comprising waste and / or biomass;

[0100] b. supplying the carbonaceous feedstock to the gasification zone;

[0101] c. Providing steam supply and supplying steam to the gasification zone;

[0102] d. providing a means for increasing the temperature of the gasification zone to a temperature effective for gasification of the carbonaceous feedstock in the gasification zone;

[0103] e. contacting the carbonaceous feedstock with steam in a gasification zone to effectively produce a raw synthesis gas comprising H2, CO, CO2, at least one other carbonaceous material comprising at least CH4, and contaminants comprising particulates, ammonia or HCl, sulfur-containing gases, and optionally an inert gas such as N2;

[0104] f. recovering raw synthesis gas from the gasification zone;

[0105] g. supplying at least a portion of the raw synthesis gas to a partial oxidation zone maintained at a high temperature;

[0106] h. contacting the raw synthesis gas with an oxygen-containing gas in a partial oxidation zone to effectively at least partially oxidize at least one other carbonaceous material to provide a partially oxidized raw synthesis gas comprising H2, CO, CO2, and contaminants including particulates, ammonia or HCl, and sulfur-containing gases;

[0107] i. recovering partially oxidized synthesis gas from the partial oxidation zone;

[0108] j. supplying at least a portion of the partially oxidized raw syngas to a primary cleanup zone, the primary cleanup zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the partially oxidized raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the partially oxidized raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the partially oxidized raw syngas, to provide a water-washed partially oxidized raw syngas comprising H2, CO, CO2 and contaminants containing sulfur-containing gases;

[0109] k. supplying at least a first portion of the washed partially oxidized raw syngas to a shift reaction or conditioning zone and shifting the H2 to CO ratio of the washed partially oxidized raw syngas to a selected ratio to provide a shifted washed partially oxidized raw syngas comprising H2, CO, CO2, and optionally remaining contaminants;

[0110] i. supplying at least a portion of the shifted washed partially oxidized crude synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the washed partially oxidized crude synthesis gas from step j, to a secondary purification zone;

[0111] m. contacting the shifted washed partially oxidized raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone effective to at least partially absorb the sulfur-containing materials from the shifted washed partially oxidized raw synthesis gas, and recovering from the secondary purification zone an at least partially desulfurized shifted washed partially oxidized raw synthesis gas comprising H2, CO, CO2, and optionally remaining contaminants;

[0112] n. supplying the at least partially desulfurized shifted washed partially oxidized raw synthesis gas to a tertiary purification zone;

[0113] o. contacting the at least partially desulfurized shifted washed partially oxidized raw syngas with a physical solvent for CO2 in a tertiary purification zone effective to at least partially absorb CO2 from the shifted at least partially desulfurized washed partially oxidized raw syngas, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2, and a second stream comprising clean syngas comprising H2, CO and optionally remaining contaminants;

[0114] p. removing at least a portion of the absorbed CO2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover CO2 separately in a sufficiently pure form for isolation or other purposes;

[0115] q. Supplying the second stream of cleaned synthesis gas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or optional purification stages to at least partially remove any remaining contaminants.

[0116] The shift reaction or conditioning zone may be a water gas shift reaction zone. Alternatively, when hydrogen is readily available without unacceptably negatively impacting the carbon intensity of the process (e.g., when "green" or "blue" hydrogen is readily available), the shift reaction or conditioning zone may be a conditioning zone in which a hydrogen stream (preferably a "green" or "blue" hydrogen stream) is combined with at least partially desulfurized washed partially oxidized crude syngas or washed partially oxidized crude syngas, as the case may be.

[0117] In the above, "green hydrogen" refers to hydrogen obtained by electrolyzing water using renewable energy such as wind or solar power.

[0118] In the above, “blue hydrogen” refers to hydrogen produced from natural gas, typically via steam reforming, with associated carbon capture storage.

[0119] Partial oxidation can be carried out in a gasification zone. Also provided herein is a method for producing synthetic fuels, comprising:

[0120] a. Providing a carbonaceous feedstock comprising waste and / or biomass;

[0121] b. supplying the carbonaceous feedstock to the gasification and partial oxidation zone;

[0122] c. providing a steam supply and an oxygen-containing gas supply and supplying the steam and oxygen-containing gas to the gasification and partial oxidation zone;

[0123] d. raising the temperature of the gasification and partial oxidation zone to a temperature effective to gasify and partially oxidize the carbonaceous feedstock in the gasification zone;

[0124] e. contacting the carbonaceous feedstock in a gasification zone with steam and an oxygen-containing gas to effectively produce a partially oxidized raw synthesis gas comprising H2, CO, CO2 and contaminants including particulates, ammonia or HCl, sulfur-containing gases, and optionally an inert gas such as N2;

[0125] f. recovering partially oxidized raw synthesis gas from the gasification and partial oxidation zone;

[0126] g. supplying at least a portion of the partially oxidized raw syngas to a primary cleanup zone, the primary cleanup zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the partially oxidized raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the partially oxidized raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the partially oxidized raw syngas, to provide a water-washed partially oxidized raw syngas comprising H2, CO, CO2 and contaminants containing sulfur-containing gases;

[0127] h. supplying at least a portion of the washed partially oxidized raw synthesis gas to a secondary purification zone;

[0128] i. contacting the washed partially oxidized raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone effective to at least partially absorb the sulfur-containing materials from the washed partially oxidized raw synthesis gas and recovering at least partially desulfurized washed partially oxidized raw synthesis gas comprising H2, CO, CO2 and optionally remaining contaminants from the secondary purification zone;

[0129] j. supplying at least a first portion of the at least partially desulfurized washed partially oxidized raw syngas to a water-gas shift reaction zone and shifting the H2 to CO ratio of the at least partially desulfurized washed partially oxidized raw syngas to a selected ratio to provide a shifted at least partially desulfurized washed partially oxidized raw syngas comprising H2, CO, CO2, and optionally remaining contaminants;

[0130] k. supplying the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the at least partially desulfurized washed partially oxidized raw synthesis gas from step i, to a tertiary purification zone;

[0131] l. contacting the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the at least partially desulfurized washed partially oxidized raw synthesis gas from step k, with a physical solvent for CO2 in a tertiary purification zone to effectively at least partially absorb CO2 from the shifted at least partially desulfurized washed partially oxidized raw synthesis gas, and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2, and a second stream comprising clean synthesis gas comprising H2, CO and optionally remaining contaminants;

[0132] m. removing at least a portion of the absorbed CO 2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover the CO 2 separately in a sufficiently pure form for sequestration or other use;

[0133] n. Supplying the second stream of cleaned synthesis gas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or an optional purification stage to at least partially remove any remaining contaminants.

[0134] Also in the processes disclosed herein involving a single vessel for gasification and partial oxidation, the shift or conditioning stage can be performed before rather than after the secondary purification stage (for example, in the case of a water gas shift reaction stage, if a sulfur-tolerant water gas shift catalyst is used in the water gas shift reaction zone).

[0135] Therefore, the present invention also discloses a method for producing synthetic fuel, comprising:

[0136] a. Providing a carbonaceous feedstock comprising waste and / or biomass;

[0137] b. supplying the carbonaceous feedstock to the gasification and partial oxidation zone;

[0138] c. providing a steam supply and an oxygen-containing gas supply and supplying the steam and oxygen-containing gas to the gasification and partial oxidation zone;

[0139] d. raising the temperature of the gasification and partial oxidation zone to a temperature effective to gasify and partially oxidize the carbonaceous feedstock in the gasification zone;

[0140] e. contacting steam and an oxygen-containing gas in a carbonaceous feedstock with a gasification zone to effectively produce a partially oxidized raw synthesis gas comprising H2, CO, CO2 and contaminants including particulates, ammonia or HCl, sulfur-containing gases and optionally an inert gas such as N2;

[0141] f. recovering partially oxidized raw synthesis gas from the gasification and partial oxidation zone;

[0142] g. supplying at least a portion of the partially oxidized raw syngas to a primary cleanup zone, the primary cleanup zone supplying an aqueous stream to at least partially scrub particulates and ammonia or HCl from the partially oxidized raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the partially oxidized raw syngas, and the aqueous stream being selected to include an alkaline aqueous stream when HCl is a contaminant in the partially oxidized raw syngas, to provide a water-washed partially oxidized raw syngas comprising H2, CO, CO2, and contaminants including sulfur-containing gases;

[0143] h. supplying at least a first portion of the washed partially oxidized raw syngas to a shift reaction or conditioning zone and shifting the H2 to CO ratio of the washed partially oxidized raw syngas to a selected ratio to provide a shifted washed partially oxidized raw syngas comprising H2, CO, CO2, and optionally remaining contaminants;

[0144] i. supplying at least a portion of the shifted washed partially oxidized crude synthesis gas, optionally after recombining it with at least a portion of any remaining portion of the washed partially oxidized crude synthesis gas from step g, to a secondary purification zone;

[0145] j. contacting the shifted washed partially oxidized raw synthesis gas with a physical solvent for sulfur-containing materials in a secondary purification zone effective to at least partially absorb the sulfur-containing materials from the shifted washed partially oxidized raw synthesis gas and recovering an at least partially desulfurized shifted washed partially oxidized raw synthesis gas comprising H2, CO, CO2, and optionally remaining contaminants from the secondary purification zone;

[0146] k. supplying the at least partially desulfurized shifted washed partially oxidized raw synthesis gas to a tertiary purification zone;

[0147] 1. contacting the at least partially sweetened shifted washed partially oxidized raw syngas with a physical solvent for CO2 in a tertiary purification zone to effectively at least partially absorb CO2 from the shifted at least partially sweetened washed partially oxidized raw syngas and recovering from the tertiary purification zone a first stream comprising the physical solvent for CO2 and the absorbed CO2, and a second stream comprising clean syngas comprising H2, CO and optionally remaining contaminants;

[0148] m. removing at least a portion of the absorbed CO 2 from the first stream in the solvent regeneration stage to recover the regenerated solvent and to recover the CO 2 separately in a sufficiently pure form for sequestration or other use;

[0149] n. Supplying the second stream of cleaned synthesis gas to a further reaction train to produce synthetic fuel, optionally after passing through one or more guard beds and / or an optional purification stage to at least partially remove any remaining contaminants.

[0150] Further preferred features of the invention are defined in the dependent claims. These further preferred features may be combined with any of the above defined aspects and disclosures of the invention. DETAILED DESCRIPTION

[0151] Each optional or preferred feature or combination of features described below may be used in the present invention as defined in the claims.

[0152] Syngas

[0153] Unless the context indicates otherwise, the terms "raw syngas", "clean syngas" and any other phrases containing the term "syngas" will be interpreted as meaning a gas comprising primarily hydrogen and carbon monoxide. Other components such as carbon dioxide, nitrogen, argon, water, methane, tar, acid gases, higher molecular weight hydrocarbons, oil, asphalt, volatile metals, char, phosphorus, halides and ash may also be present. The concentrations of contaminants and impurities present will depend on the stage of the process and the source of the carbonaceous feedstock.

[0154] The use of these terms to describe syngas should not be considered limiting. Those skilled in the art will understand that each term is to be interpreted as meaning a gas comprising primarily hydrogen and carbon monoxide.

[0155] Useful products and further reaction chains

[0156] The further reaction train may be a Fischer-Tropsch reaction train and in this case the method of the invention may comprise subjecting the clean synthesis gas to Fischer-Tropsch reaction conditions to produce one or more liquid hydrocarbons as useful products.

[0157] The liquid hydrocarbons may optionally be upgraded to produce further useful products. At least a portion of the liquid hydrocarbons may be upgraded by at least one of hydrotreating, hydrotreating, product fractionation, hydrocracking and / or hydroisomerization.

[0158] The FT liquid upgrading unit may, for example, produce high quality naphtha and synthetic paraffinic kerosene (SPK). Other upgraded products may, for example, include gasoline, diesel and wax.

[0159] The FT liquid upgrading unit can be configured as a cyclic hydrocracker.

[0160] A further useful product may optionally be a sustainable liquid transportation fuel or gasoline blendstock. The transportation fuel or gasoline blendstock may optionally be used for aviation and / or vehicles. The sustainable liquid transportation fuel may optionally contain high quality SPK. The gasoline blendstock may optionally contain naphtha.

[0161] The further reaction train may additionally or alternatively be a methanol synthesis train, an ammonia synthesis train, an alcohol synthesis train, a water gas shift reaction train, and the obtained useful products may be methanol, ammonia, alcohols or hydrogen, respectively, for example.

[0162] Carbonaceous raw materials

[0163] For example, the carbonaceous feedstock may include at least one of woody biomass, municipal solid waste, and / or commercial and industrial waste.The carbonaceous feedstock will generally have fluctuating compositional characteristics, depending on the source and chemical nature of the feedstock used.

[0164] The carbonaceous feedstock may be in relatively bulky form. The carbonaceous feedstock may be processed to remove oversized items, recyclables, high-halogen plastics such as PVC, metals, and inert items. These items cannot be converted into syngas, or, in the case of PVC, produce undesirably high impurity loadings in the feed supplied to the gasification zone; therefore, the items are preferably removed prior to gasification. These items may be recycled.

[0165] The carbonaceous feedstock can be reduced to a size suitable for gasification. For example, the carbonaceous feedstock can be pulverized, chopped, or sliced ​​prior to gasification.

[0166] In some embodiments, the carbonaceous material feedstock is biomass, such as woody biomass feedstock. Examples of suitable woody feedstocks may include tree-length logs, pulp thinnings, whole trees, branches, twigs, tree tops, and / or waste wood.

[0167] A shredder may be used to reduce the carbonaceous material to a size suitable for the gasification zone.

[0168] In another embodiment, the carbonaceous feedstock is a waste material, such as municipal solid waste and / or commercial and industrial waste.

[0169] The carbonaceous feedstock may contain moisture. In this case, it is preferred that the carbonaceous feedstock is dried to at least some extent prior to gasification.

[0170] The carbonaceous feedstock can be transported to a dryer to reduce the moisture content to a suitable level. The moisture content can be reduced to less than about 20 wt%, less than about 15 wt%, or less than about 10 wt%.

[0171] When waste (as described above) is used as a carbonaceous feedstock source, the feedstock may not need to be dried before entering the gasification zone. In this case, the waste can be fed directly into the gasifier after appropriate pretreatment to remove unwanted components and pulverize the feedstock to a size suitable for feedstock processing.

[0172] The carbonaceous feedstock may be continuously fed into the gasification zone.

[0173] Gasification Zone

[0174] The method of the present invention obtains a raw synthesis gas by gasifying a carbonaceous feedstock in a gasification zone. Gasification may occur in the presence of steam and oxygen. The gasification zone may include a single queue, a dual queue or multiple queues. Preferably, the gasification zone includes more than one queue to minimize the impact of interruptions on the availability of the equipment.

[0175] The three main types of commercially available gasifiers are fixed / moving bed, entrained flow or fluidized bed types. The gasification zone may be an indirect gasification zone, in which the feedstock and steam are supplied to a gasification vessel which is indirectly heated. Alternatively, the gasification zone may be a direct gasification zone, in which the feedstock, steam and oxygen-containing gas are supplied to the gasification vessel and burned directly to provide the heat required for gasification. Also known in the art and suitable for use in the process of the present invention are hybrid gasifiers and gasifiers in combination with a partial oxidation unit. In this case, it will be appreciated that in the process of the present invention, the gasification zone and the partial oxidation zone may be separate regions of a single vessel.

[0176] In one embodiment, the gasification zone consists essentially of an indirectly heated deep fluidized bed and an auxiliary gasifier operating in dry ash rejection mode for maximum conversion of carbonaceous materials. In another embodiment, the gasification zone may consist only of an indirectly heated primary fluidized bed.

[0177] The fluidized bed operating temperature may vary depending on the composition characteristics of the carbonaceous feedstock. The fluidized bed operating temperature may be between about 400 and 1000°C, preferably between about 500 and 900°C, or more preferably between about 600 and 800°C.

[0178] It has been found that this temperature range of the fluidised bed avoids any constituent ash softening and slagging with the bed material.

[0179] The fluidized bed reactor can be pre-loaded with a certain amount of inert bed media, such as silica (sand) or alumina. The inert bed media can be fluidized with superheated steam and oxygen. The superheated steam and oxygen can be introduced through separate tube nozzles.

[0180] During the gasification process, the fluidized bed can perform drying (or dehydration), devolatilization (or pyrolysis) and gasification. Some combustion, water-gas shift and methanation reactions may also occur.

[0181] It is desirable to have a pressure within the gasification zone that minimizes the need for compression in downstream processes. Thus, it is preferred that the gasification zone have a pressure of at least about 3.5 bar, if not higher, for example about 4 bar or higher. Gasification zones operating at even much higher pressures, such as 10 bar or higher, are known in the art. Gasification zones operating at even much lower pressures, such as 1.5 bar or lower, are also known in the art. Gasification zones having all operating pressures are suitable for use in the process of the present invention.

[0182] The raw syngas exiting the gasification zone may typically have an outlet temperature of at least about 600° C., at least about 700° C., or at least about 800° C. Preferably, the raw syngas exiting the gasification zone has an outlet temperature of about 700° C. to about 750° C.

[0183] The main products leaving the gasification zone are usually steam and a crude synthesis gas containing hydrogen and carbon monoxide (CO) (the basic components of synthesis gas), carbon dioxide (CO2), methane and small amounts of nitrogen and argon. Additional tars such as benzene, toluene, ethylbenzene and xylenes, higher hydrocarbons, waxes, oils, ash, soot, bed media components and other impurities may be present.

[0184] In order to obtain high quality gas required for use as feedstock in downstream processes such as synthesis, impurities need to be removed. Non-limiting examples of suitable synthesis include Fischer-Tropsch (FT) synthesis, ammonia synthesis, methanol synthesis or as hydrogen product.

[0185] Cyclone separators may be used to remove unwanted solid materials from the raw syngas.

[0186] In operation of the gasification process, a sediment discharge system may be used to remove heavier contaminants from the bed material.

[0187] Sulfur, slag, and other byproducts and impurities of gasification may be suitable for capture, collection, and reuse. However, capturing, collecting, or reusing carbon dioxide is difficult unless it is fairly pure - i.e., at least about 90%, at least about 95%, or at least about 99% pure. The method of the present invention allows the production of high purity carbon dioxide in an otherwise practical WTL or BTL process.

[0188] Depending on the source of the carbonaceous feedstock and the gasification technology, raw syngas may typically contain about 3%-40% carbon dioxide, in addition to other impurities and contaminants.

[0189] Depending on the source of the feedstock being gasified, the raw syngas leaving the gasification zone may typically contain varying sulfur concentrations, typically hundreds of ppm.

[0190] The sulfur concentration in the raw syngas will affect the process conditions adopted downstream.

[0191] Partial oxidation zone

[0192] At least part of the raw synthesis gas from the gasification zone is recovered, and at least part of the recovered raw synthesis gas may be supplied to the partial oxidation zone (POx zone). The raw synthesis gas in the partial oxidation zone will undergo a partial oxidation reaction.

[0193] Conventional partial oxidation zones known in the art are generally either catalytic or non-catalytic (thermal).

[0194] The partial oxidation zone may partially combust tail gases from downstream synthesis units and / or synthesis gas produced in the process and / or natural gas with preheated oxygen.

[0195] The partial oxidation zone may include a burner to produce a stream of hot oxygen.

[0196] The partial oxidation zone is sufficient to effectively increase the temperature of the raw syngas to convert at least some of any tars, naphthalene, higher hydrocarbons and methane present into carbon oxides, hydrogen and water.

[0197] For example, the partial oxidation zone may be operated at a temperature of at least about 1100° C., at least about 1200° C., or at least about 1300° C. Preferably, the partial oxidation zone operating temperature is at least about 1300° C., most preferably in the range of about 1200° C. to about 1350° C.

[0198] The partial oxidation zone may convert the remaining methane, naphthalene, higher hydrocarbons and tar line components to carbon oxides, hydrogen and water. The syngas leaving the partial oxidation zone may be interpreted as an equilibrium syngas.

[0199] The inventors have found that the removal / destruction of tar components, residual methane and higher hydrocarbons increases the carbon utilization of the equipment / facility. By converting these impurities and pollutants into synthesis gas and co-processing recycle streams, product yields can be increased. The conversion of these unwanted components advantageously simplifies downstream processes, so no additional purification steps are required downstream compared to conventional processes. This results in a low carbon intensity of the method of the present invention.

[0200] The balanced syngas produces high pressure steam when leaving the POx zone. The high pressure steam has a high energy content and can be recovered and recycled for use in upstream and / or downstream processes, which allows energy recovery.

[0201] Heat recovery from the POx zone is typically radiative and convective. The advantage of this mode of recovery is the ability to obtain high-pressure steam (generated in the HRSG unit) for use in the facility. While water quenching is also an acceptable (and less expensive) heat recovery option, it can negatively impact the carbon intensity of the facility due to the need to generate high-pressure steam for the user in equipment such as the water-gas shift reaction unit and the gasification unit.

[0202] The solids may be removed from the POx zone as slag.

[0203] The raw syngas from the POx zone may be subjected to at least one of gas cleaning, compression and / or desulfurization.

[0204] The inventors surprisingly found that there is enough water in the raw syngas stream from the gasification zone to enable the POx zone to moderate the temperature, minimize soot formation, reform the methane and promote the downstream water-gas shift reaction. Therefore, unlike conventional methods, there is no need to add additional steam directly to the raw syngas. This reduces the amount of steam supplied for the entire process, thereby reducing carbon intensity.

[0205] Syngas can be purified by removing ammonia, sulfur and carbon dioxide impurities in sequence. The latter impurity can be considered as acid gas.

[0206] The overall method according to the invention may comprise additional stages.Thus, the synthesis gas purified by sequentially removing ammonia, sulphur and carbon dioxide impurities may be, for example, a raw synthesis gas and / or a balanced synthesis gas.

[0207] The equilibrium syngas leaving the partial oxidation zone is hot and can be cooled by generating steam. It is preferred to generate superheated steam and / or saturated high pressure steam to improve process efficiency and reduce carbon intensity. It is an object of the present invention to reduce the carbon intensity of a BTL or WTL process, and in certain aspects of the present invention, there are many influencing factors, of which generating superheated steam and / or saturated high pressure steam after partial oxidation is one of them.

[0208] The cooled, balanced syngas may be passed through a venturi scrubber to remove any water and particulates, such as ash and soot. For example, an alkaline scrubber may be used additionally to remove any other impurities, such as ammonia, halides, nitrogen oxides, and remaining particulates.

[0209] The partial oxidation zone may optionally be operated at a slightly lower or somewhat lower pressure than the gasification zone (to avoid any intermediate compression requirements). For example, for a gasification process operating at about 3.5 bar, the partial oxidation zone may be operated at a pressure between about 2 and 3 bar.

[0210] The inclusion of a partial oxidation zone in the process according to certain aspects of the present invention provides flexibility and enables the gasification zone to process a wide range of feedstocks having fluctuating compositional characteristics. The inventors have unexpectedly discovered that the use of a partial oxidation zone enables the removal of hydrocarbonaceous materials such as methane, benzene, toluene, ethylbenzene, xylenes, higher hydrocarbons and other tars to an extent sufficient to allow the carbon dioxide to be directly recovered in a sufficiently pure form downstream of the tertiary purification stage for sequestration or other uses, thereby reducing the carbon intensity of the process compared to conventional WTL and BTL processes.

[0211] Water Gas Shift or Hydrogen Shift

[0212] At least a portion of the at least partially desulfurized washed partially oxidized raw syngas from the partial oxidation zone is passed through a water gas shift (WGS) unit to obtain shifted syngas and optionally mixed with the remaining balanced syngas to adjust the hydrogen to carbon monoxide ratio to a desired range.

[0213] The term "water gas shift reaction" or "WGS" shall be interpreted as comprising a thermochemical process for converting carbon monoxide and water into hydrogen and carbon dioxide. The synthesis gas obtained after the WGS reaction may be interpreted as a shifted (ie conditioned) synthesis gas.

[0214] The presence of sulfur compounds is important when considering the selection of a WGS catalyst for the WGS reaction. Sulfur can be removed from the feed prior to the WGS process, or a sulfur-tolerant WGS catalyst (acid shift catalyst) can be used. Preferably, sulfur is removed from the feed prior to the WGS process.

[0215] In one embodiment, the syngas entering the WGS unit is substantially sweet gas (<0.1 ppmv) to achieve a sweet shift.The syngas entering the WGS unit may be a balanced syngas.

[0216] The process according to the present invention may further comprise removing ammonia, sulfur and carbon dioxide impurities sequentially from the raw synthesis gas and recovering the carbon dioxide in a substantially pure form.

[0217] Sulfur compounds poison the low-sulfur shift catalyst. If a low-sulfur shift catalyst is used in the process, it is important to ensure that very little sulfur is present in the synthesis gas entering the water-gas shift reaction. In such a process configuration, sulfur removal should be performed upstream of the water-gas shift reaction.

[0218] At least part of the desulfurized syngas may be subjected to a water gas shift reaction. The water gas shift reaction may produce a shifted syngas which, when recombined with non-shifted gas from the partial oxidation zone or gasification zone, produces a shifted syngas having a hydrogen to carbon monoxide ratio of 2.00 ± 0.4 (preferably ± 0.2). (The shifted portion itself may have a much higher hydrogen to carbon monoxide ratio - for example even up to 20:1 - but is then recombined with the non-shifted gas in the appropriate proportions to achieve a recombined syngas having the desired hydrogen to carbon monoxide ratio).

[0219] The WGS reaction is a thermochemical process that involves the conversion of carbon monoxide and water into hydrogen and carbon dioxide. The synthesis gas obtained after the WGS reaction can be interpreted as shifted synthesis gas.

[0220] The syngas entering the WGS unit is essentially a low-sulfur gas. The syngas may be a shifted syngas.

[0221] The process of sequentially removing ammonia, sulfur and carbon dioxide impurities from the raw syngas and recovering carbon dioxide in a substantially pure form can occur prior to the WGS reaction. The resulting syngas can be interpreted as sweetened syngas.

[0222] Removal of ammonia, sulfur and carbon dioxide impurities can be a low vapor physical absorption process.

[0223] According to a preferred embodiment of the invention, sulphur is removed in an upstream process.The balance of gas supplied to the water-gas shift unit is essentially a low-sulphur gas.

[0224] The water-gas shift reaction may use a low-sulfur shift catalyst, which may be a metal sulfide catalyst.

[0225] As an alternative to the water gas shift, the at least partially sweetened washed partially oxidized crude synthesis gas or the washed partially oxidized crude synthesis gas can be adjusted by simple combination with a hydrogen stream, preferably at least partially derived from "green" or "blue" hydrogen.

[0226] Gas purification

[0227] Low vapor physical absorption processes can be, for example, Rectisol TM or Selexol TM process or any suitable solvent-based physical absorption process.

[0228] In one embodiment, the physical absorption unit can be configured to operate a two-stage process with two independent absorption towers that contact the synthesis gas stream with methanol, including a common methanol regeneration system. The first absorption tower can selectively remove sulfur and can use a CO2-saturated solvent to minimize CO2 absorption in the desulfurization column. The second absorption tower can recover CO2.

[0229] This technology is further described elsewhere; for example in Fossil Fuel Emissions Confrol Technologies, Bruce Miller, 2015.

[0230] The carbon dioxide may optionally be recovered in a substantially pure form. For example, recovery of the carbon dioxide may be performed after the WGS reaction.

[0231] The WGS reaction converts carbon monoxide and water into hydrogen and carbon dioxide in the presence of high-pressure superheated steam.

[0232] The use of the WGS reaction in the process according to the invention enables the hydrogen to carbon monoxide ratio of the synthesis gas entering the WGS unit to be adjusted (or shifted) to a desired ratio.

[0233] Removal of ammonia, sulfur and carbon dioxide impurities can be a low vapor physical absorption process.

[0234] Physical absorption processes are typically carried out at low temperatures and high pressures. The inventors have found that the use of a physical absorption process, in particular a low steam physical absorption process, contributes to the low carbon intensity of the process according to the invention.

[0235] Conventional prior art processes involve amine-based gas removal solvent systems to remove CO2 due to their lower power input and expected lower capital cost (CAPEX). In addition, the desulfurization step can be Merichem TM A redox process and also includes a hydrolysis step to hydrolyze hydrogen cyanide and COS. Amine based gas removal solvent systems are chemical absorption processes.

[0236] The inventors have advantageously found that the physical absorption process according to the invention consumes significantly less steam than conventional cleaning processes in the prior art. Thus, the use of a physical absorption process contributes to the low carbon intensity of the process according to the invention.

[0237] As mentioned above, the low vapor physical absorption process can be Rectisol TM or Selexol TM In a non-limiting example, the low vapor physical absorption process is Rectisol TM Craftsmanship.

[0238] Rectisol TM The process uses chilled methanol at cryogenic temperatures (approximately -40°C) to remove acid gases, metal carbonyls and trace impurities from the synthesis gas stream by absorption.

[0239] Gaseous impurities may include acid gases such as hydrogen sulfide, carbonyl sulfide, hydrogen cyanide; and other gases such as CO2, all of which are absorbed much more preferentially than methane, hydrogen and carbon monoxide. Trace impurities that can be removed include HCN, NH3 and formic acid. Therefore, Rectisol TM The process advantageously minimizes loss of desired products and removes gaseous impurity components that could otherwise adversely affect downstream processes.

[0240] The inventors surprisingly found that the physical absorption process according to the preferred embodiment of the present invention is a low steam process with improved carbon intensity. As a non-limiting example, as described in Table 1, based on the synthesis gas produced from 1000 STPD (dry) biomass, Rectisol TMThe process uses about 2 tons / hour (<5,000 lb / hr) of steam. In comparison, prior art processes involving chemical absorption processes (such as amine-based gas removal systems) use about 50 tons per hour (>110,000 lb / hr) of steam for the same tonnage of feedstock. However, it should be noted that physical absorption processes require about 10% higher electricity usage, greater solvent makeup, and about 10-15% higher CAPEX than traditional amine-based systems.

[0241] Thus, the physical absorption process essentially "obtains" steam from the physical absorption process otherwise used when utilizing an amine-based gas removal solvent system. The physical absorption process according to the present invention is therefore interpreted as a "low steam physical absorption process".

[0242] The method according to the present invention may optionally further include using at least a portion of the steam obtained from the low steam physical absorption process for upstream and / or downstream processes. The upstream process may be drying the carbonaceous feedstock before feeding it into the biomass and / or waste boiler and / or for use in the oxygen heater of the air separation unit and / or for preheating the FT feed. If further LP steam is available, it can be discharged to the low-low pressure (LLP) header and used for heating the FT guard bed and / or for use in the reforming section and / or in the wastewater stripping section (e.g., wastewater reboiler) and / or in the fuel system (e.g., natural gas heater) and / or in the deaerator and / or for heating and tracking of intermediate or chemical storage tanks.

[0243] The inventors have found that using at least a portion of the steam obtained from a low steam physical absorption process to dry the feedstock before feeding it to a biomass or waste boiler significantly reduces the carbon intensity of the process.

[0244] The ammonia, sulfur, and carbon dioxide impurities removed may include at least one of hydrogen sulfide, carbonyl sulfide, hydrogen cyanide, NH 3 , and / or CO 2 . The presence of these impurities may be detrimental to downstream processes, and therefore it is desirable to remove these impurities.

[0245] Using a low steam physical absorption process can result in a syngas with extremely low total sulfur content. The removal of sulfur components eliminates the need for additional syngas purification in downstream processes. Small amounts of trace contaminants in the syngas can increase the operating time of the absorbent and provide greater assurance of syngas purity.

[0246] For example, the absorbed compounds can be removed from the methanol solvent by flash evaporation (desorption) and additional thermal regeneration. This makes the solvent ready for new absorption.

[0247] In one embodiment, the apparatus may include two separate Rectisols for contacting the synthesis gas stream with methanol. TMAbsorption towers, which include a shared methanol regeneration system. The first absorption tower can selectively remove sulfur and use a CO2-saturated solvent to minimize CO2 absorption in the sulfur removal tower. The second absorption tower can recover CO2.

[0248] This arrangement allows the selective removal of sulfur from the synthesis gas, followed by the subsequent removal of CO 2. At least a portion of the resulting CO 2 stream can be reused in the process.

[0249] In variations of the invention not utilizing a partial oxidation zone, it is also desirable to remove the tar by condensation prior to the desulfurization bed or by absorbing the tar using a physical absorption solvent and recovering the tar from a solvent regeneration stage.

[0250] The resulting synthesis gas may be construed as sweetened synthesis gas.

[0251] The sulfur-rich side stream can be optionally burned with excess air in an incinerator to convert all sulfur-containing compounds into SO 2 . The incinerator can optionally be operated at a temperature of about 1500° C. The SO 2 can, for example, be refined into sulfates.

[0252] The resulting gas can be used, for example, to generate steam and can therefore be cooled in this case. The cooled synthesis gas can optionally be scrubbed with sodium hydroxide solution to remove SO2 as sodium sulfite and sodium sulfate.

[0253] The carbon dioxide may optionally be recovered in a substantially pure form. The carbon dioxide may, for example, be substantially free of sulfur.

[0254] At least a portion of the recovered substantially pure carbon dioxide may optionally be sequestered.Sequestering the carbon dioxide may involve separating, compressing, and transporting the carbon dioxide to a suitable geological formation where the carbon dioxide is injected and permanently stored underground.

[0255] Additionally or alternatively, at least a portion of the recovered pure carbon dioxide may optionally be used in upstream and / or downstream processes with minimal purification required.

[0256] The purity of the recovered pure carbon dioxide thus produced may be at least about 60%, at least about 70%, at least about 80%, or at least about 85% pure.

[0257] The production of pure CO2 by a low steam physical absorption process significantly reduces the carbon intensity of the process.

[0258] As a non-limiting example, if the CO2 is sequestered or used in upstream and / or downstream processes, a carbon intensity reduction of approximately 110 gCO2e / MJ is obtained.

[0259] As disclosed in our co-pending application 18-005, the syngas hydrogen to carbon monoxide ratio can be balanced in a partial oxidation zone before entering the WGS shift unit; in this case, the fluctuations in the hydrogen to carbon monoxide ratio in the syngas are already greatly reduced. The resulting shifted syngas can optionally be mixed with the remainder of the balanced syngas (forming an optionally conditioned refined syngas), thus obtaining a desired hydrogen to carbon monoxide ratio characteristic for the intended synthesis, with even more reduced fluctuations.

[0260] At least a portion of the balanced syngas and / or raw syngas may be bypassed without subjecting the syngas to the WGS reaction or optional hydrogen conditioning stage, and the shifted and bypassed gases are then combined in an optimal ratio to obtain the desired hydrogen to carbon monoxide feed ratio in the optionally conditioned refined syngas. The proportion of bypassed gas will vary depending on the desired ratio of downstream synthesis reactions and the severity of the shift reaction. Controlling the proportion of bypassed gas sent to the reactor helps to obtain a specific hydrogen to carbon monoxide feed ratio.

[0261] As a non-limiting example, when it is desired to supply a shifted syngas to a Fischer-Tropsch reactor, it is often necessary to increase the hydrogen to carbon monoxide ratio of the balanced syngas produced by biomass or waste gasification.

[0262] HRU

[0263] Hydrogen can be recovered from the shifted synthesis gas downstream of the water gas shift reaction. Hydrogen can be recovered from several stages of the process according to the invention. The inventors have found that recovering hydrogen from the shifted gas stream downstream of the acid gas removal process has proven to be most effective. The inventors have found that less CO is lost from the overall process compared to hydrogen recovery at other locations. Therefore, the overall economics of the facility are improved due to the increase in product yield, the hydrogen recovery being carried out after the removal of ammonia, sulfur and carbon dioxide impurities.

[0264] At least a portion of the shifted synthesis gas can optionally be sent to a hydrogen recovery unit (HRU). The HRU can utilize a pressure swing adsorption (PSA) process to produce high purity hydrogen for different purposes. The high purity hydrogen can be used for upstream and / or downstream processes. The waste gas from the HRU can be used as a fuel gas to reach the desired combustion temperature in an incinerator, thereby further reducing the carbon intensity of the process of the present invention.

[0265] The high purity hydrogen from the HRU may be, for example, about at least 97%, at least about 98%, and at least about 99% pure at pressure. The impurities removed may include, but are not limited to, CO, CO2, CH4, N2, and Ar.

[0266] Upstream and / or downstream processes utilizing the recovered hydrogen may include, for example, removal of at least one of ammonia or sulfur or carbon dioxide impurities, catalyst regeneration of the synthesis reactor, and product upgrading.

[0267] The shifted synthesis gas from the WGS unit combined with the bypass synthesis gas may optionally be passed through an inlet filtration system, such as an inlet guard bed, prior to the synthesis unit.

[0268] The inlet guard bed may optionally be a sulfur guard bed.

[0269] For example, the inlet guard bed can be operated in a lead-lag configuration to remove residual trace contaminants such as hydrogen sulfide, phosphorus, COS, arsenic, chlorides, and mercury from the syngas. The lead bed can, for example, remove any contaminants present, and the lag bed can, for example, serve as a guard when the lead bed is breached.

[0270] The synthesis gas leaving the guard bed may be interpreted as optionally conditioned refined synthesis gas.

[0271] product

[0272] The syngas can be converted into useful products such as long chain hydrocarbon products, hydrocarbon fuels, or liquid or solid hydrocarbons.

[0273] The syngas may be, but is not limited to, shifted syngas, sweetened syngas and / or fresh syngas.

[0274] Useful products may, for example, include liquid hydrocarbons.Liquid hydrocarbons may be sustainable liquid transportation fuels.

[0275] Useful products may be produced, for example, by subjecting at least part of the synthesis gas to a Fischer-Tropsch synthesis unit.

[0276] The products obtained in the FT synthesis may include, for example, heavy FT liquid (HFTL) and light FT liquid (LFTL) fractions, naphtha and tail gas, which contains inerts and uncondensed light hydrocarbons, typically C1 to C4. FT process water may also be produced. Part of the tail gas containing light hydrocarbons in the C1 to C4 range may optionally be recycled back to the POx zone or sent to the fuel gas system.

[0277] A portion of the tail gas stream may optionally be combined with fresh synthesis gas before being fed to the FT reactor to maximize the use of the CO available in the synthesis gas. In this case, a purge stream may be used to prevent the accumulation of inert gases (such as CO2 and CH4) produced in the FT reactor. When the gas leaves the process loop, the use of the tail gas stream as a fuel as described above is suitable as a purge stream.

[0278] Liquid hydrocarbons may optionally be upgraded to produce useful products.

[0279] At least a portion of the liquid hydrocarbons may optionally be upgraded by at least one of hydrotreating, hydrotreating, product fractionation, hydrocracking, and / or hydroisomerization.

[0280] FT liquid upgrading units can, for example, produce high quality naphtha and synthetic paraffinic kerosene (SPK). Other upgraded products may include, for example, gasoline, diesel and waxes.

[0281] The FT liquid upgrading unit may, for example, comprise a cyclic hydrocracker.

[0282] A useful product may be, for example, a sustainable liquid transportation fuel or gasoline blendstock. Transportation fuel or gasoline blendstock may be used in aviation and / or vehicles.

[0283] Sustainable liquid transportation fuels may include, for example, high quality diesel and / or SPK.

[0284] The gasoline blendstock may, for example, comprise naphtha.

[0285] The method according to a preferred embodiment of the present invention can produce transportation (aviation and road) fuels with less greenhouse gas emissions compared to traditional fuels. Compared with conventional methods, the reduction of greenhouse gas emissions can be at least about 50%, at least about 60% or at least about 70%.

[0286] Depending on the feedstock, fuels produced using the method according to the invention generally enable significant reductions in greenhouse gases. The method according to a preferred embodiment of the invention can enable the production of aviation and road fuels with at least about 70% less greenhouse gas emissions compared to conventional fuels.

[0287] The purge gas stream (FT tail gas) from the FT reactor and a small amount of waste gas stream from the FT liquid upgrading system can optionally be recycled to an upstream process (eg, gasification or partial oxidation zone) to increase overall carbon recovery.

[0288] In a preferred embodiment, the process according to the invention aims to utilize any waste gases produced at any stage of the process according to the invention for power generation where appropriate, in order to reduce the consumption of natural gas or other external fuel sources.

[0289] For the avoidance of doubt, all features relating to a process for making useful products from a carbonaceous feedstock having fluctuating compositional characteristics also relate where appropriate to a low carbon intensity process, and vice versa.

[0290] The optionally conditioned refined syngas may be converted into useful products.

[0291] Useful products may, for example, include liquid hydrocarbons. Liquid hydrocarbons may, for example, be sustainable liquid transportation fuels.

[0292] Useful products may for example be produced by subjecting at least part of the optionally conditioned refined synthesis gas to a Fischer-Tropsch synthesis unit.

[0293] For example at least a portion of the synthesis gas may be fed into a synthesis unit. Non-limiting examples of suitable synthesis include Fischer-Tropsch, ammonia synthesis, methanol synthesis, alcohol synthesis or as a hydrogen product.

[0294] The synthesis reaction requires a specific hydrogen to carbon monoxide ratio ("desired ratio") in the feed gas for optimal performance to meet process requirements, maximize conversion and product yield. As a non-limiting example, a Fischer-Tropsch synthesis feed may have a hydrogen to carbon monoxide ratio of about 2. This desired ratio is typically lower than the used ratio. As a non-limiting example, the Fischer-Tropsch synthesis used ratio may be in the range of 2.04-2.14, typically about 2.1.

[0295] According to embodiments involving Fischer-Tropsch synthesis, the optionally conditioned refined synthesis gas may be fed to the FT reactor.

[0296] The synthesis unit may be a FT unit comprising a FT reactor.

[0297] The FT reactor may optionally include microchannels.

[0298] A filter may optionally be used to remove any particulates.

[0299] The FT reactor may optionally convert at least a portion of the carbon monoxide and hydrogen of the optionally conditioned refined synthesis gas into primarily straight-chain hydrocarbons.

[0300] The Fischer-Tropsch synthesis unit may optionally convert the optionally conditioned refined synthesis gas into liquid hydrocarbons.

[0301] The conversion of synthesis gas into liquid hydrocarbons can optionally be carried out in the presence of a catalyst. The chain length distribution can depend on the nature of the catalyst used and the operating conditions.

[0302] The Fischer-Tropsch reaction is exothermic and releases heat which must be removed to keep the reaction temperature approximately constant. Locally high temperatures in the catalyst bed have been found to adversely affect the FT product mix, yield, and may shorten catalyst life. Therefore, it is desirable to keep the temperature constant.

[0303] The temperature can optionally be controlled by varying the pressure of a steam drum associated with the FT reactor in conjunction with circulating cooling water.

[0304] The operating temperature for FT synthesis may optionally be between about 125 and 350° C., between about 150 and 300° C., between about 170 and 250° C., between about 180 and 240° C. Preferably, for low temperature FT techniques, the operating temperature is between about 180 and 240° C.

[0305] The catalyst may optionally be a metal or a composite metal catalyst with a support. In one embodiment, the metal is cobalt. The support may optionally be made of silicon dioxide, zirconium oxide and / or titanium dioxide.

[0306] Part of the tail gas stream may optionally be combined with fresh syngas before being fed to the FT reactor to maximize the utilization of the CO available in the syngas. In this case, a purge stream may optionally be used to prevent the accumulation of inert gases such as CO2 and CH4 produced in the FT reactor. The tail gas stream used as fuel as described above is suitable as a purge stream when the gas leaves the process loop.

[0307] It is desirable to upgrade liquid hydrocarbons into more useful products.

[0308] The liquid hydrocarbons may, for example, be upgraded to produce further useful products.At least part of the liquid hydrocarbons may, for example, be upgraded by at least one of hydrotreating, hydrotreating, product fractionation, hydrocracking and / or hydroisomerization.

[0309] The FT liquid upgrading unit may, for example, produce high quality naphtha and synthetic paraffinic kerosene (SPK). For example, other upgraded products may include gasoline, diesel and wax. The unit may, for example, be configured as a cyclic hydrocracker.

[0310] Further useful products may be, for example, sustainable liquid transportation fuels or gasoline blendstocks. Transportation fuels or gasoline blendstocks may, for example, be used for aviation and / or vehicles. Sustainable liquid transportation fuels may, for example, include high-quality SPK or diesel. Gasoline blendstocks may, for example, contain naphtha.

[0311] The product formed by the process according to the invention may, for example, constitute a cleaner form of fuel formed by conventional processes.

[0312] Fuels produced according to the invention can, for example, improve air quality, reducing particulate matter (soot) from aircraft engine exhaust by up to 90% and sulfur oxides by almost 100%. BRIEF DESCRIPTION OF THE DRAWINGS

[0313] Figure 1A schematic diagram of a process for FT synthesis from biomass and / or waste feedstocks is described. The schematic diagram describes the conventional teachings in the prior art (chemical absorption secondary gas purification route) and the process according to the present invention (physical absorption secondary gas purification route). Two aspects of the process of the present invention with and without a partial oxidation zone are also illustrated.

[0314] refer to Figure 1 Prior art methods typically include amine-based gas removal solvent systems for CO2 removal, Merichem for sulfur removal, TM Redox process and hydrolysis step for the hydrolysis of hydrogen cyanide and COS.

[0315] Comparing the amine-based purification route with the physical absorption route according to the present invention requires fewer stages, thus simplifying the overall process and providing a process with a reduced number of stages. The reduction in the number of stages stems from the ability of the physical absorption process to effectively remove HCN, COS and other mercaptans that would otherwise require an additional hydrolysis step according to the conventional route.

[0316] Preferred embodiments of the present invention will now be described in more detail with reference to the following non-limiting examples.

[0317] Example

[0318] Select woody biomass feedstock.

[0319] method

[0320] The selected raw materials are processed as follows:

[0321] The feedstock was initially processed by comminuting it to the required size and drying it to the desired moisture content (10% in this case) to obtain a dry biomass feedstock.

[0322] The dried biomass feedstock is continuously supplied to a fluidized bed gasification unit operating at a temperature <800°C, a pressure of 2.2 barg and supplied with superheated steam to achieve gasification and produce approximately 5-10 or 1-2 lbmols / hr of raw syngas per short ton of feedstock per day (STPD).

[0323] In one route, the raw syngas leaves the gasifier and is supplied to a partial oxidation reactor that is maintained at a temperature of approximately 1,250°C and supplied with oxygen combustion with all the raw syngas produced from the gasification step above while adjusting the oxygen rate to achieve the target temperature. The partial oxidation reaction converts the remaining methane and other hydrocarbons into syngas.

[0324] The resulting heat-balanced syngas is cooled (by producing superheated and saturated high-pressure steam) to a temperature below 200°C and then passed through a primary gas cleaning unit where it passes through a venturi scrubber to remove water and particulates (such as soot and ash), and then it is caustic scrubbed to remove ammonia, halides (e.g., HCl), nitrogen oxides and any remaining particulates.

[0325] In an alternative route, the raw syngas leaving the gasifier is supplied directly to the primary gas cleanup, thereby bypassing the oxy-fired partial oxidation reactor.

[0326] The syngas is then compressed and passed through a secondary gas cleaning and compression system where acid gases (H2S and CO2) are removed by Rectisol using methanol solvent. TM process is achieved, which makes the syngas "sweeten". This approach is used in Examples 1 and 2 discussed below. Example A depicts the conventional prior art, including an amine-based CO2 removal step followed by the use of Merichem TM The redox process has a sulfur removal step and a hydrolysis step to hydrolyze hydrogen cyanide and COS.

[0327] About 2.2 lbmol / hr / STPD of acid gas is sent to the battery limit to capture CO2. The acid gas stream contains small amounts of H2 (<0.5 mol%), CO (<0.5 mol%), H2O (<5%), and N2 (~10%). The amount of CO2 removed is about 1.5 lbmol / hr / STPD.

[0328] A portion of the syngas is extracted and recycled as fuel for the gasifier.

[0329] A portion of the syngas stream is passed through a water gas shift (WGS) unit to adjust the ratio of hydrogen to carbon monoxide (H2:CO) in the total feed stream when it is recombined.

[0330] A portion of the water-gas shifted syngas is sent to a hydrogen recovery unit to produce high purity hydrogen for downstream units. The high purity hydrogen is sent downstream and the tail gas is directed to fuel gas.

[0331] Throughout the secondary gas cleaning process, various guard beds are placed to remove substances such as mercury, arsenic and phosphorus.

[0332] The sweetened and shifted synthesis gas passes through a final Fischer-Tropsch (FT) inlet guard bed before being sent to the FT synthesis unit.

[0333] The purified synthesis gas is sent to a FT microchannel reactor where it is converted into synthetic liquid hydrocarbons in the presence of a cobalt catalyst supported on a silica / titania support.

[0334] The purge / excess tail gas is sent to the POx and fuel gas systems.

[0335] The FT reaction water is sent to a wastewater treatment unit where it is fractionated into a distillate containing alcohols and a bottoms fraction containing organic acids.

[0336] The bottom stream is then bio-upgraded for reuse in the facility.

[0337] The synthesized FT liquid is hydrocracked, hydroisomerized and then hydrotreated. Diesel fuel is subsequently obtained from the upgrading unit.

[0338] Wastewater recovered from the different process units is sent to the wastewater treatment unit before disposal or possible reuse.

[0339] result

[0340] Table 1 summarizes the individual stages and results present in the process of FT synthesis from selected feedstocks.

[0341] Table 1

[0342]

[0343] Explanation of symbols in Table 1:

[0344] Example A is a comparative example of using a conventional chemical absorption process for gas purification.

[0345] Example 1 An example according to the present invention using a physical absorption method for gas purification without using a POx reactor.

[0346] Example 2 An example according to the present invention using a physical absorption method for gas purification and including the use of a POx reactor.

[0347] The values ​​for Examples 1 and 2 in Table 1 are reported relative to Comparative Example A. For example, Comparative Example A had an O2 usage of -50 lb / h / stpd. Example 1 was 0.35 times the value of Example A, so the O2 usage was -17.5 lb / h / stpd.

[0348] Comparison of Examples 1 and 2 according to the present invention with Comparative Example A shows that when the physical absorption method (Rectisol TM ) replaces conventional chemical absorption processes (amines), the power input and natural gas input in the process are significantly reduced (and thus CI is improved).

[0349] In addition, the use of the physical absorption method according to the present invention does not require an auxiliary boiler to generate low-pressure steam as in the conventional method used in Comparative Example A. The Rectisol method according to Examples 1 and 2 of the present invention utilizes the saved steam from the downstream process and utilizes the steam for the upstream process, such as drying biomass, thereby reducing the natural gas input. Therefore, the examples according to the present invention provide a more environmentally friendly method compared to Comparative Example A.

[0350] In the absence of a POx zone, additional energy efficiencies are gained from lower O2 utilization (required only in the gasification stage) and result in a smaller ASU and ancillary equipment. Although some tar can be recovered as BTX and used as a blending stock for fuel, net C5+ hydrocarbon production from the FT unit is also lower due to the absence of POx to convert tar and methane into syngas. This can impact the economics of the facility through the value of the recovered saleable products. Although the reduction in CI is highest in this case, economics may dictate the feasibility of this option.

[0351] It can also be seen from the results that the CI scores in Examples 1 and 2 are significantly reduced compared to Comparative Example A. The reduction in CI is the result of multiple factors, including but not limited to reductions in natural gas input, O2 usage, and power input. The reduction in CI is beneficial and indicates that the method according to the present invention is more environmentally friendly than conventional methods.

[0352] It should also be noted that the CI scores shown in the table do not include CO sequestration, which is contemplated for use according to the present invention. Including carbon dioxide sequestration would further reduce the values ​​in the table.

Claims

1. A method for producing a synthetic fuel, comprising: a. gasifying a carbonaceous feedstock comprising waste and / or biomass to produce a raw syngas comprising H2, CO, CO2, at least one other carbonaceous material comprising CH4 and tar, and pollutants comprising one of ammonia or HCl, particulates and sulfur-containing gases; b. partially oxidizing the raw synthesis gas from step a) to provide a partially oxidized raw synthesis gas comprising H2, CO, CO2 and contaminants including particulates, ammonia or HCl and sulfur-containing gases; and supplying at least a portion of the partially oxidized raw synthesis gas to the primary purification zone in step c); c. supplying at least a portion of the raw syngas of step a) to a primary purification zone, the primary purification zone supplying an aqueous stream to at least partially scrub one of ammonia or HCl and particulates from the raw syngas, the aqueous stream being selected to be a neutral or acidic aqueous stream when ammonia is a contaminant in the raw syngas, and the aqueous stream being selected to comprise an alkaline aqueous stream when HCl is a contaminant in the raw syngas, to provide a washed raw syngas comprising H2, CO, CO2 and contaminants comprising sulfur-containing gases; d. supplying at least a first portion of the washed raw syngas to a shift reaction or conditioning zone and shifting the ratio of H2 to CO of the washed raw syngas to a selected ratio to provide a shifted raw syngas comprising H2, CO and CO2 and contaminants including sulfur-containing gases, thereby producing a shifted raw syngas; e. supplying at least a portion of said shifted raw synthesis gas to a secondary purification zone; f. contacting said shifted raw synthesis gas in said secondary purification zone with a physical solvent for sulfur-containing materials, said physical solvent being effective to at least partially absorb sulfur-containing materials from said shifted raw synthesis gas, and recovering from said secondary purification zone an at least partially desulfurized, detarred shifted raw synthesis gas comprising H2, CO and CO2; g. The at least partially desulfurized, detarred raw synthesis gas is supplied to a tertiary purification zone; h. contacting said at least partially sweetened, detarred, shifted raw synthesis gas with a physical solvent for CO2 in said tertiary purification zone, said physical solvent being effective to at least partially absorb CO2 from said at least partially sweetened, detarred, shifted raw synthesis gas, and recovering from said tertiary purification zone a first stream comprising said physical solvent for CO2 and absorbed CO2, and a second stream comprising clean synthesis gas comprising H2, CO and optionally remaining contaminants; i. removing at least a portion of said absorbed CO2 from said first stream in a solvent regeneration stage to recover the regenerated solvent and to recover the CO2 separately in a sufficiently pure form for sequestration or other use; j. supplying at least a portion of one of said at least partially desulfurized, detarred shifted raw syngas or said clean syngas to a hydrogen recovery unit, thereby producing high purity hydrogen; and k. supplying said clean synthesis gas of said second stream to a further reaction train for producing synthetic fuels, optionally after passing through one or more guard beds and / or optional purification stages to at least partially remove any remaining contaminants.

2. A method according to claim 1, comprising recombining the shifted raw synthesis gas with part of the washed raw synthesis gas from step c) and then supplying the combined stream to the secondary purification zone in step e) simultaneously with the process.

3. The method according to any one of claims 1 to 2, comprising: At least a portion of the sweetened, detarred, converted raw synthesis gas from step f) is supplied to a conversion reaction or conditioning zone, and the ratio of H2 to CO in the sweetened, detarred, converted raw synthesis gas is converted to a selected ratio to provide a converted raw synthesis gas comprising H2, CO and CO2; and simultaneously with this process, the above-mentioned converted raw synthesis gas is supplied to the tertiary purification zone in step g).

4. The method according to claim 3 comprises supplying at least part of the sweetened, detarred, shifted raw synthesis gas from step f) to a shift reaction or conditioning zone to obtain a shifted raw synthesis gas which is recombined with part of the sweetened, detarred, shifted raw synthesis gas from step f), and then simultaneously with the process supplying the combined stream to the tertiary purification zone in step g).

5. The method of claim 1, wherein the carbonaceous feedstock comprises at least one of woody biomass, municipal solid waste, commercial and industrial waste, or a combination of these, and the moisture content of the carbonaceous feedstock is reduced to less than 20% w / w by drying with at least a portion of steam obtained from a downstream process prior to gasification.

6. The method of claim 5, wherein the method further comprises using a biomass or waste boiler to generate high pressure steam and electricity.

7. The method of claim 1, wherein the removal of ammonia, sulfur and / or carbon dioxide impurities is a low steam physical absorption process.

8. The method of claim 7, wherein the method further comprises using at least a portion of the steam obtained from the low steam physical absorption process in upstream and / or downstream processes.

9. The method of claim 8, wherein the upstream process comprises drying the carbonaceous feedstock.

10. The method of claim 1, wherein at least a portion of the recovered pure carbon dioxide is sequestered or used ex-situ or in-situ in upstream and / or downstream processes.

11. The method of claim 1 , wherein the pure carbon dioxide has a purity of at least 60%.

12. The method according to claim 1, wherein at least a portion of the raw synthesis gas of step a) is subjected to a water gas shift reaction to produce a shifted synthesis gas by removing ammonia, sulfur and carbon dioxide impurities in sequence to obtain a sweetened synthesis gas.

13. The method of claim 12, wherein the shifted syngas is recombined with non-shifted gases to produce a syngas having a hydrogen to carbon monoxide ratio of 2.00 ± 0.

4.

14. A process according to claim 12 or 13, wherein the synthetic fuel is produced by subjecting at least a portion of the sweetened or shifted synthesis gas to Fischer-Tropsch reaction conditions in a Fischer-Tropsch synthesis unit.

15. A process according to claim 14, wherein the Fischer-Tropsch synthesis unit converts the sweetened or shifted synthesis gas into liquid hydrocarbons.

16. The method of claim 15, wherein the liquid hydrocarbons are reformed into the synthetic fuel.

17. The method of claim 16, wherein at least a portion of the liquid hydrocarbons are upgraded by at least one of hydroprocessing, product fractionation to produce the synthetic fuel.

18. The method of claim 1, wherein the synthetic fuel comprises synthetic paraffinic kerosene and / or diesel and / or naphtha.

19. The method according to claim 18, wherein the synthetic paraffinic kerosene and / or diesel and / or naphtha is used for transportation fuel.

20. The method of claim 16, wherein at least a portion of the liquid hydrocarbons are upgraded by at least one of product fractionation, hydrocracking, and / or isomerization to produce the synthetic fuel.

21. The method of claim 1, wherein the carbonaceous feedstock comprises at least one of woody biomass, municipal solid waste, commercial and industrial waste, or a combination of these, and the moisture content of the carbonaceous feedstock is reduced to less than 15% w / w by drying with at least a portion of steam obtained from a downstream process prior to gasification.

22. The method of claim 1, wherein the carbonaceous feedstock comprises at least one of woody biomass, municipal solid waste, commercial and industrial waste, or a combination of these, and the moisture content of the carbonaceous feedstock is reduced to less than 10% w / w by drying with at least a portion of steam obtained from a downstream process prior to gasification.

23. The method of claim 1, wherein the pure carbon dioxide has a purity of at least 70%.

24. The method of claim 1, wherein the pure carbon dioxide has a purity of at least 80%.

25. The method of claim 1, wherein the pure carbon dioxide has a purity of at least 85%.

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