Integration of gasification and methanol synthesis

Abstract

Gasification processes utilizing carbonaceous feeds and preferably biomass are disclosed, which can implement one or more strategies for valuable integration with process streams generated when converting the syngas product of gasification to more valuable end products, such as biomethanol. For example, these waste stream generally referred to as fusel oil may be recycled to where it can be utilized in the gasification process, such as for the upstream conversion of biomass or other carbonaceous material, providing the syngas that is reacted to form the biomethanol. A particular use of fusel oil is in a tar conversion or tar destruction area that may operate with a partial oxidation (POX) burner as an integral or key part of the overall gasification.

Description

INTEGRATION OF GASIFICATION AND METHANOL SYNTHESISCROSS REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of priority to U.S. Provisional Application No. 63 / 532,445, filed August 14, 2023, which is hereby incorporated by reference in its entirety.FIELD OF THE INVENTION

[0002] Aspects of the invention relate to gasification processes, and more particularly the integration of gasification and methanol synthesis, including the use, in gasification, of products obtained from methanol synthesis.DESCRIPTION OF RELATED ART

[0003] The gasification of coal has been performed industrially for over a century in the production of synthesis gas (syngas) that can be further processed into transportation fuels and other valuable end products. More recent efforts toward developing energy independence with reduced greenhouse gas emissions have led to a strong interest in using biomass as a gasification feed, and thereby an alternative potential source of synthesis gas, as well as its downstream conversion products. Generally, biomass gasification is performed by partial oxidation in the presence of a suitable oxidizing gas containing oxygen and other possible components such as steam. Gasification at elevated temperature and pressure, optionally in the presence of a catalytic material, produces an effluent with hydrogen and oxides of carbon (CO, CO2), as well as hydrocarbons such as methane. This effluent, which is often referred to as synthesis gas in view of its H2 and CO content, must be cooled significantly and also treated to remove a number of undesired components that can include particulates, alkali metals, halides, and sulfur compounds, in addition to byproducts of gasification that are generally referred to as tars and oils. Furthermore, downstream conversion of the synthesis gas to value-added products often requires its hydrogen content to be increased, relative to that obtained from gasification alone.

[0004] Undesired tar components in the gasifier effluent, which can include fused ring molecules such as naphthalene and pyrene, pose significant challenges in terms of the tendency of such high boiling-temperature molecules to condense from the vapor phase onto lower- temperature surfaces encountered downstream of the gasifier. Physical deposition of tars and oils is known to cause fouling / clogging of process lines, valves, reactors, and other equipment. For these reasons, the thermal destruction of tar is commonly practiced, but this,in turn, requires temperatures of about 1300°C, well exceeding those of the gasifier and sufficient to cause melting and / or slagging of ash that is also present in tar-laden syngas stream or gasifier effluent. The molten material or slag is itself a source of potential fouling and plugging, due to deposition at cooler downstream temperatures, such as encountered in equipment for upgrading of synthesis gas to end products. To mitigate these problems, the use of a sufficiently large-sized radiant syngas cooler (RSC) is viewed as a possible way to separate slag via a quench chamber at the bottom of this apparatus.

[0005] Regarding the need to increase the thiCO molar ratio of the synthesis gas for its subsequent use in a number of reactions, the exothermic water-gas shift (WGS) reaction gas according to:CO + H2O H2+ CO2is widely exploited. The thermodynamics of this reaction govern an equilibrium shift toward hydrogen production at lower temperatures, which are generally unfavorable from the standpoint of reaction kinetics. Operations conducted to purify the gasifier effluent, or synthesis gas, in preparation for the catalytic WGS reaction, include scrubbing to remove water-soluble contaminants. The scrubbing operation, however, generally requires a reduction in both temperature and moisture content of the resulting scrubbed gasifier effluent, thereby directionally reducing its suitability in these respects for the WGS operation. Overall, the economics of biomass gasification and the effective utilization of the produced synthesis gas for obtaining desired end products are impacted by a number of complex and interacting processing objectives, as well as the associated equipment requirements. The present state of the art would benefit from improvements in gasification technology, relating to usage of products generated from syngas conversion operations, and particularly such products that provide valuable inputs to the gasification process and / or that would otherwise have little or no residual value (e.g., be considered waste byproducts). These improvements thereby render gasification processes more financially attractive.SUMMARY OF THE INVENTION

[0006] Aspects of the invention are associated with the discovery of gasification processes utilizing carbonaceous feeds and preferably biomass, which can implement one or more strategies for valuable integration with process streams generated when converting the syngas product of gasification to more valuable end products, such as biomethanol, liquid hydrocarbons, renewable natural gas, or renewable hydrogen. For example, certain embodiments aredirected to the recycle and utilization of a waste stream generally referred to as “fusel oil” that is obtained as a byproduct of methanol synthesis from syngas, such as from the separation (e.g.. by distillation) of a “green” or bio-derived methanol (z.e., biomethanol) product from the fusel oil and optionally other lower value streams. This recycle may be carried out by routing at least a portion of the fusel oil to where it can be utilized in the gasification process, such as for the upstream conversion of biomass or other carbonaceous material, providing the syngas that is reacted to form the biomethanol. A particular use of fusel oil is in a tar conversion or “tar destruction” area that may operate with a partial oxidation (POX) burner as an integral or key part of the overall gasification. For example, fusel oil, which might otherwise be considered a waste product of biomethanol manufacturing, can be recycled via pressurization and vaporization, prior to its injection into a POX reactor of the “Gasification Island” of a biomethanol production plant. More generally, a fusel oil byproduct, or portion thereof, may be fed directly to a tar removal operation or optionally upstream of this operation (e.g., by being added to a raw gasifier effluent), in either case resulting in the C2+alcohols of this byproduct being subjected to a reducing environment that is conducive for their conversion to additional synthesis gas. In the absence of such conversion, the recycle of fusel oil might undesirably result in the detrimental accumulation of C2+alcohols and other byproduct species (e.g., aldehydes) within the overall gasification / biomethanol synthesis complex.

[0007] Various features of the invention may therefore include (1) recycling fusel oil or other byproduct stream from a methanol production unit to a gasification unit, with the latter unit comprising a number of operations for the upstream generation of conditioned syngas, being converted in the former unit, (2) pressurizing, heating, and / or vaporizing fusel oil and feeding it into a tar removal reactor of a gasification process, (3) using equipment of the tar removal reactor, for example an auxiliary fuel gas line, which may be existing or otherwise specifically added, and which may be more particularly a component of the POX reactor, for injection of fusel oil waste and for its use in gasification, (4) increasing overall efficiency of producing renewable syngas conversion products and renewable syngas separation products, through enhanced utilization of waste chemical streams.

[0008] Further aspects of the invention relate to the removal, through beneficial utilization, of otherwise problematic waste streams such as fusel oil, which are necessarily generated in syngas conversion operations and / or syngas separation operations. In the case of biomethanol production in particular, the associated facilities often include two sections orstages, namely a reactor section or stage, for converting feed chemicals (CO, CO2, H2) into methanol, and a separation section or stage (e.g., which may include distillation), for resolving a purified biomethanol product by separation from other components of the raw biomethanol product being fed to this separation section or stage. These separated components can include waste streams such as a fusel oil byproduct, comprising one or more C2+alcohols, as well as other byproducts. Depending on its water content, fusel oil may be difficult to combust, thereby rendering heat recovery from this byproduct problematic.

[0009] Problems associated with the efficient monetization of fusel oil may be advantageously addressed, according to particular embodiments, by routing this byproduct back to the multioperation gasification processes, such as to the tar removal operation of this process. According to a specific implementation, an auxiliary fuel line of the POX reactor may be used to inject all or a portion of the fusel oil, produced in a downstream biomethanol synthesis operation or reaction stage, into a tar removal operation, which may be saturated with water. Reducing environments existing with, or even upstream of, the tar removal operation are especially conducive for reduction of alcohol byproduct species back to CO and H2, i.e., components of syngas. In this manner, both the carbon and hydrogen content of these species may be effectively utilized, or at least maintained in the overall process, for biomethanol production, rather than being discarded or utilized for lower value purposes. The efficiency of incorporating carbon and hydrogen into the purified biomethanol product, the yield of this product, and the reduction in overall system waste, are all sources of potential advantages gained from the practice of certain processes as described herein. Process economics are improved through the recycle of fusel oil, by introducing this byproduct to areas or sections of the process that provide conditions conducive for its conversion or degradation to additional, valuable synthesis gas. Simultaneously, the need for handling and / or discarding this byproduct is effectively overcome.

[0010] A tar removal operation provides a convenient reducing environment for converting C2+alcohols and other oxygenated byproduct species of fusel oil to CO and H2 (synthesis gas), as opposed to the more oxidized products CO2 and H2O that would result from conventional combustion. Representative processes therefore comprise feeding at least a portion of the fusel oil byproduct as a fuel for the tar removal operation, which may be carried out by direct recycle to this operation or recycle to a position upstream of this operation, such as to the effluent of the gasifier (e.g., raw gasifier effluent). Alternatively or in combination with feeding fusel oil either directly to a tar removal operation or upstream of this operation, thisbyproduct may be added directly to the gasifier, with its placement or introduction being possibly within the freeboard section of a fluidized bed reactor, within the particle bed itself, or to the feed injection screws, accounting for specific circumstances (e.g., superficial gas velocity, mixing characteristics, temperature, moisture limitations, etc.) associated with these specific locations. Advantageously, however, issues potentially arising from injection of fusel oil to the gasifier are obviated in the case of recycling this byproduct to an auxiliary gas line of the tar removal operation, such as in the POX reactor, according to certain embodiments described herein. Importantly, this configuration ensures excellent mixing, without significant concern for temperature shocks and related stresses (e.g., damage to refractory surfaces and / or stresses on components such as nozzles).

[0011] Yet another possibility for process integration resides in recycling a gaseous byproduct that is removed (e.g., by a flash vapor / liquid phase separation) following, or during, biomethanol synthesis in a reaction stage. For example, this gaseous byproduct may be subjected to hydrogen recovery, with the generated Fh-enriched off gas being recycled to a syngas conditioning stage (e.g., being combined with a water-gas shift (WGS) product of this stage), upstream of biomethanol synthesis and / or the generated Fh-depleted tail gas being recycled directly to the biomethanol synthesis (e.g., to a reactor used in this operation or to directly upstream of such reactor).

[0012] Advantages associated with any of these integration strategies, whether used alone or in combination, can include improved system efficiency, reduced capital expenses that would otherwise be incurred for a burner addition, improved product yields and utilization of C, H, and O atoms (e.g., in a biomass feed), mitigation of waste, and the alleviation of operational concerns relating to mixing and other processing requirements.

[0013] Particular embodiments of the invention are directed to a process for gasification of a carbonaceous feed. The process comprises, in a gasifier, contacting the carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, water-soluble contaminants, and gasifier effluent tar. The process may further comprise one or more processing steps, preferably, but not necessarily, in the following order: (i) subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the gasifier effluent tar and provide a tar-depleted gasifier effluent, (ii) feeding (e.g., as a scrubber feed) at least a portion of the tar-depleted gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent;(iii) feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product; (iv) feeding at least a portion of the conditioned syngas product to a biomethanol synthesis operation (or other syngas conversion operation) to provide a raw biomethanol product; and / or (v) separating, in a biomethanol separation stage, the raw biomethanol product to provide at least a purified biomethanol product (or other renewable syngas conversion product) and a fusel oil byproduct (or other liquid conversion byproduct, for example such product comprising heavy hydrocarbons and / or alcohols). The process may further comprise feeding at least a portion of the fusel oil byproduct as a fuel (for combustion) for the tar removal operation, with the potential realization of any of the advantages as described herein. Feeding all or a portion of the fusel oil byproduct as a fuel for the tar removal operation may comprise, for example, feeding it directly to the tar removal operation (e.g., to the POX reactor) and / or feeding it upstream of the tar removal operation (e.g., by combining it with the gasifier effluent), in either case subjecting byproduct species present in the fusel oil to reducing conditions effective for the generation of additional syngas.

[0014] Other particular embodiments of the invention are directed to a process for gasification of a carbonaceous feed. The process comprises, in a gasifier, contacting the carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, and water-soluble contaminants. The process may further comprise one or more processing steps, preferably, but not necessarily, in the following order: (i) feeding (e.g., as a scrubber feed) at least a portion of the gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent; (ii) feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product; and / or (iii) feeding at least a portion of the conditioned syngas product to a biomethanol synthesis operation (or other syngas conversion operation) to provide a raw biomethanol product and a gaseous byproduct (e.g., comprising noncondensable gases, such as unconverted CO and / or H2). The process may further comprise feeding all or a portion of the gaseous byproduct to a hydrogen recovery operation to provide an H2-enriched off gas and / or an Fh-depleted tail gas, and further utilizing one or both of these in the process as described herein.

[0015] Yet other particular embodiments of the invention are directed to a process for gasification of a carbonaceous feed. The process comprises, in a gasifier, contacting the carbonaceous feedwith an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, water-soluble contaminants, and gasifier effluent tar. The process may further comprise subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the gasifier effluent tar and provide a tar-depleted gasifier effluent. The process may further comprise feeding at least a portion of the tar-depleted gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent, and feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product. Advantageously, one or more C2+alcohols are fed as a fuel for the tar removal operation. This may comprise, for example, feeding the one or more C2+alcohols directly to the tar removal operation (e.g., to the POX reactor) and / or feeding the one or more C2+alcohols upstream of the tar removal operation (e.g., by combining with the gasifier effluent), in either case subjecting the one or more C2+alcohols to reducing conditions effective for the generation of additional syngas. The one or more C2+alcohols may, more particularly, be present in a fusel oil byproduct, or a portion of such byproduct, of a biomethanol synthesis operation. Yet more particularly, at least a portion of the conditioned syngas product may be fed to this biomethanol synthesis operation.

[0016] These and other embodiments, aspects, and advantages relating to the present invention are apparent from the following Detailed Description.BRIEF DESCRIPTION OF THE DRAWING

[0017] A more complete understanding of the exemplary embodiments of the present invention and the advantages thereof may be acquired by referring to the following description in consideration of the accompanying figure.

[0018] The figure depicts a flowscheme illustrating an embodiment of a process for the gasification of a carbonaceous feed, which process employs a number of possible features as described herein, including a biomethanol synthesis operation and the possibility for recycling byproducts of this operation, such as a fusel oil byproduct and / or an H2-enriched off gas. Whereas the figure illustrates multiple possible features that may be implemented individually or in any combination, not all features (e.g., not all individual operations and their associated process streams and equipment) are required in, or essential to, the practice ofvarious inventive embodiments described herein, i.e., it should be understood that various specific features can be implemented independently of others.

[0019] In order to facilitate explanation and understanding, the figure provides an overview of various features for implementation in gasification processes. Some associated equipment such as certain vessels, heat exchangers, valves, instrumentation, and utilities, are not shown, as their specific description is not essential with respect to the understanding or practice of various inventive embodiments. Such equipment would be readily apparent to those skilled in the art, having knowledge of the present disclosure. Other processes for producing syngas and / or its conversion products such as renewable liquids (e.g., biomethanol), according to other embodiments within the scope of the invention and having configurations and constituents determined, in part, according to particular processing objectives, would likewise be apparent.DETAILED DESCRIPTION

[0020] The expressions “wt-%” and “mol-%,” are used herein to designate weight percentages and molar percentages, respectively. The expressions “wt-ppm” and “mol-ppm” designate weight and molar parts per million, respectively. For ideal gases, “mol-%” and “mol-ppm” are equal to percentages by volume and parts per million by volume, respectively. The terms “barg” and “psig,” when used herein, designate gauge pressures (i.e., pressure in excess of atmospheric pressure) in units of bars and pounds per square inch, respectively, whereas the terms “bar” and “psi,” when used herein, designate absolute pressures. For example, gauge pressures of 0 barg and 0 psig are approximately equivalent to absolute pressures of 1 bar and 14.5 psi, respectively.

[0021] The term “substantially,” as used herein, refers to an extent of at least 95%. For example, the phrase “substantially all” may be replaced by “at least 95%. ” The phrases “all or a portion” or “at least a portion” are meant to encompass, in certain embodiments, “at least 50% of,” “at least 75% of,” “at least 90% of,” and, in preferred embodiments, “all.” Likewise, designated portions, such as a “first portion” or “second portion” may represent these percentages (but not all) of the total, and particularly these percentages (but not all) of the total process stream to which they refer.

[0022] The term “fusel oil” may refer specifically to a byproduct obtained from the conversion of syngas, or gaseous mixture comprising th and CO, to methanol (e.g., biomethanol). Whether or not obtained as such a byproduct, fusel oil may, in more general embodiments, refer to amixture that is liquid at room temperature and that comprises one or more alcohols having a higher molecular weight, i.e., a greater number of carbon atoms, relative to methanol. Such alcohols may be conveniently referred to as “C2+alcohols,” with this term encompassing alcohols having two or more carbon atoms. Whether or not obtained as a syngas conversion byproduct, fusel oil may comprise one or more C2+alcohols generally in a combined amount of at least about 30 wt-%, such as from about 30 wt-% to about 90 wt-%, or from about 30 wt-% to about 70 wt-%, and often in a combined amount of at least about 50 wt-%, such as from about 50 wt-% to about 90 wt-%, or from about 50 wt-% to about 75 wt-%. The one or more C2+alcohols may, more particularly, include one or more of ethanol, propanol, butanol, and / or pentanol, with the terms propanol, butanol, and pentanol embracing, respectively, all C3 alcohol isomers (e.g., n-propyl alcohol and i-propyl alcohol), all C4 alcohol isomers (e.g., butan-l-ol, butan-2-ol, 2-methyl-propan-l-ol, etc.), and all C5 alcohol isomers (e.g., pentan-1- ol, pentan-3-ol, 3-methyl-butan-l-ol, etc.). For example, ethanol alone may be present alone in any of the above amounts; propanol alone may be present alone in any of the above amounts; butanol alone may be present alone in any of the above amounts; pentanol alone may be present alone in any of the above amounts; combinations of any two of ethanol, propanol, butanol, and / or pentanol (e.g., ethanol and propanol in combination) may be present in any of the above amounts; combinations of any three of ethanol, propanol, butanol, and / or pentanol (e.g., ethanol, propanol, and butanol in combination) may be present in any of the above amounts; and / or ethanol, propanol, butanol, and pentanol in combination may be present in any of the above amounts. Aside from one or more C2+alcohols, the balance of the fusel oil may comprise substantially other oxygenated byproduct species including water, aldehydes, fatty acids and their esters, and / or terpenes.

[0023] Reference to any starting material, intermediate product, or final product, which are all preferably process streams in the case of continuous processes, should be understood to mean “all or a portion” of such starting material, intermediate product, or final product, in view of the possibility that some portions may not be used, such as due to sampling, purging, diversion for other purposes, mechanical losses, etc. Therefore, for example, the phrase “feeding the fusel oil byproduct as a fuel for the tar removal operation” should be understood to mean feeding all or a portion of the fusel oil byproduct as a fuel for the tar removal operation. As in the case of “all or portion” being expressly stated, when “all or a portion” is the understood meaning, this phrase is should further be understood to encompasses certain and preferred embodiments as noted above.

[0024] Representative processes described herein for the gasification of a carbonaceous feed may comprise a number of unit operations, with one of such operations stated as being performed or carried out “before,” “prior to,” or “upstream of’ another of such operations, or with one of such operations being performed or carried out “after,” “subsequent to,” or “downstream of,” another of such operations. These quoted phrases, which refer to the order in which one operation is performed or carried out relative to another, are in reference to the overall process flow, as would be appreciated by one skilled in the art having knowledge of the present specification. More specifically, the overall process flow can be defined by the bulk gasifier effluent flow, including bulk flows of both the un-scrubbed gasifier effluent and scrubbed gasifier effluent, as well as the bulk WGS product flow, as such flow(s) is / are subjected to operations as defined herein. Insofar as the quoted phrases are used to designate order, in specific embodiments these phrases mean that one operation immediately precedes or follows another operation, whereas more generally these phrases do not preclude the possibility of intervening operations. Therefore, for example, one or more “operations downstream of the gasifier” can refer, according to a specific embodiment, an operation that immediately follows the gasifier, such as in the case of a tar removal operation according to the embodiment illustrated in the figure. However, this phrase more generally, and preferably, refers to any of, or any combination of, operations that follow the gasifier, whether or not intervening operations are present, such as in the case of any one or more of a quenching operation, a radiant syngas cooler (RSC) or convective syngas cooler (CSC), and / or a filtration operation that follow the tar removal operation, as an intervening operation, according to the embodiment illustrated in the figure. Therefore, to the extent that representative processes described herein are defined as including certain unit operations, unless otherwise stated or designated (e.g., by using the phrase “consisting of’), such processes do not preclude the use of other operations, whether or not specifically described herein.

[0025] Specific processes described herein are defined by a gasifier, a scrubbing operation (e.g., wet scrubber) downstream of the gasifier, and a WGS operation downstream of the scrubbing operation. The gasifier provides a “gasifier effluent” and the WGS operation provides a “WGS product.” The term “gasifier effluent” is a general term that refers to the effluent of the gasifier, whether or not having been subjected to one or more operations downstream of the gasifier and upstream of the WGS operation. The “gasifier effluent” may be more particularly designated as an “un-scrubbed gasifier effluent” or a “scrubbed gasifier effluent,”which are also general terms but add specificity in terms of characterizing the gasifier effluent depending on whether or not it has been subjected to the scrubbing operation.

[0026] The terms “gasifier effluent” and “un-scrubbed gasifier effluent” encompass more specific terms that designate (i) the effluent provided directly by the gasifier, i.e., the “raw gasifier effluent,” (ii) the raw gasifier effluent having been subjected to at least a tar removal operation, i.e., a “tar-depleted gasifier effluent,” having a lower concentration of tars and oils relative to the raw gasifier effluent, (iii) the raw gasifier effluent having been subjected to at least a quenching operation (e.g., a dry quenching operation or a full quenching operation), i.e., a “quenched gasifier effluent,” having a lower temperature and higher moisture (H2O) concentration relative to the raw gasifier effluent, resulting from direct quenching (e.g.. partial quenching or complete quenching) with water, (iv) the raw gasifier effluent having been subjected to at least a radiant syngas cooler (RSC) or at least a convective syngas cooler (CSC), i.e., a “cooled gasifier effluent” having a lower temperature relative to the raw gasifier effluent, resulting from heat transfer for external steam generation, (v) the raw gasifier effluent having been subjected to at least a filtration operation, i.e., a “filtered gasifier effluent,” having a lower solid particle content relative to the raw gasifier effluent, and which may provide all or part of a “heated scrubber feed,” or otherwise all or part of a “scrubber feed,” (vi) the raw gasifier effluent having been subjected to removal of heat, i.e., a “scrubber feed,” having a lower temperature relative to the raw gasifier effluent, resulting from heat removal (e.g.. to generate steam), and (vii) the raw gasifier effluent having been subjected to any other operation upstream of the scrubbing operation, whether or not specifically described herein.

[0027] Likewise, the terms “gasifier effluent” and “scrubbed gasifier effluent” encompass more specific terms that designate (viii) the raw gasifier effluent or un- scrubbed gasifier effluent having been subjected to a scrubbing operation to reduce its content of water-soluble contaminants (e.g.. chlorides), (ix) the raw gasifier effluent or un-scrubbed gasifier effluent having been subjected to a scrubbing operation as noted above, and further subjected to at least compression, i.e., a “compressed, scrubbed gasifier effluent” having a higher pressure relative to the scrubbed gasifier effluent directly exiting the scrubbing operation, (x) the raw gasifier effluent or un-scrubbed gasifier effluent having been subjected to a scrubbing operation as noted above, and further subjected to at least an acid gas removal operation, i.e., a “CO2-depleted gasifier effluent” having a lower acid gas (e.g.. lower CO2) concentration relative to the scrubbed gasifier effluent directly exiting the scrubbing operation, (xi) the rawgasifier effluent or un-scrubbed gasifier effluent having been subjected to a scrubbing operation as noted above, and further subjected to any one or more of (a) compression, (b) acid gas removal, and (c) a WGS operation, i.e., a “conditioned syngas product” having been conditioned for a downstream syngas conversion operation or syngas separation operation, in terms of adjustments to its characteristics noted herein, such as to provide a higher pressure, a lower acid gas (e.g., lower CO2) concentration, and / or an increased thiCO molar ratio, and (xii) the raw gasifier effluent or un-scrubbed gasifier effluent having been subjected to a scrubbing operation as noted above, and further subjected to any other operation downstream of the scrubbing operation, whether or not specifically described herein.

[0028] The terms “gasifier effluent,” “un-scrubbed gasifier effluent,” and “scrubbed gasifier effluent,” and any of the more specific examples (i)-(x) and (xii) of these terms, encompass products (e.g., flow streams) that are upstream of, and optionally may be fed to, the WGS operation. With respect to the specific example (xi), a “conditioned syngas product,” having been subjected to a WGS operation, may correspond to the WGS product, for example obtained from a syngas conditioning stage.

[0029] The term “WGS product” is a general term that refers to a product of the WGS operation, all or a portion of which may, according to particular embodiments, be fed to a syngas conversion operation (e.g., a biomethanol synthesis operation) or a syngas separation operation to provide as a value-added product, a renewable syngas conversion product (e.g., purified biomethanol product) or a renewable syngas separation product. The term “WGS product” encompasses all or a portion of the product provided directly by the WGS operation, or otherwise such product after having been subjected to heating, cooling, pressurization, depressurization, and / or purification, such as acid gas removal.

[0030] The terms “syngas,” or alternatively “synthesis gas product,” insofar as they relate to streams comprising H2 and CO, are used herein to generally refer to the gasifier effluent, whether an un-scrubbed gasifier effluent or a scrubbed gasifier effluent as defined above, or the WGS product. Characteristics of the gasifier effluent, in terms of its composition, including its H2:CO molar ratio, are described herein and are applicable to any “syngas,” or alternatively “synthesis gas product,” as described herein.

[0031] Particular examples of renewable syngas conversion products and renewable syngas separation products include both renewable liquid products (e.g., liquid hydrocarbons or methanol) and renewable gaseous products (e.g., renewable natural gas (RNG) or renewablehydrogen). The modifiers “syngas conversion” and “syngas separation,” as well as the modifiers “conversion” and “separation,” as used in the terms “renewable syngas conversion product,” “renewable syngas separation product,” “gaseous conversion byproduct,” “liquid conversion byproduct,” and “gaseous separation byproduct” are meant to more specifically designate the origin of these products and byproducts, as being obtained from either a syngas conversion operation (e.g., comprising a Fischer-Tropsch reaction stage, a methanol (or biomethanol) synthesis reaction stage, or a methanation reaction stage) or a syngas separation operation (e.g., comprising a hydrogen purification (or hydrogen recovery) stage, such as in the case of syngas separation by pressure swing adsorption (PSA) and / or the use of a membrane). Any such syngas conversion operation or syngas separation operation is preferably performed on the WGS product that can yield an increased, and more favorable, Fh:CO molar ratio, in terms of efficiently performing the desired conversion or separation.

[0032] The use of the modifiers “separation” and “conversion” in the terms noted above to modify products and byproducts does not preclude such products and byproducts being obtained from a combination of separation and conversion, in either order. For example, in the particular case of a biomethanol synthesis operation, as an example of a syngas conversion operation, a gaseous byproduct of this operation may provide all or a portion of a feed to a downstream hydrogen recovery operation, as an example of a syngas separation operation, which in turn provides an H -cnrichcd off gas, which may be considered an example of either a syngas conversion product (or byproduct) or a syngas separation product (or byproduct).

[0033] Representative gasification processes described herein are defined by various possible operations, occurring downstream of the gasifier which may include a tar removal operation; operations for cooling, such as a quenching operation, an RSC and / or a CSC; a filtration operation; a scrubber feed cooler, such as by using a boiler; a scrubbing operation; operations of a syngas conditioning stage, such as one or more of compression, an acid gas removal operation, and a WGS operation; and a syngas conversion operation. Additional operations include separations performed to resolve the desired, purified biomethanol product, and these include flash vapor / liquid phase separations and separations using distillation (e.g., with multiple theoretical vapor / liquid equilibrium separation stages) to provide liquid fractions, including this product, having characteristic boiling point ranges. Certain possible features of the gasifier, as well as these downstream operations and their associated process streams and conditions, according to preferred embodiments and otherwise any embodiments as definedin the claims, as well as the embodiment illustrated in the figure, are provided in the following description.Gasifier

[0034] Representative processes comprise, in a gasifier, contacting a carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent (e.g., a raw gasifier effluent) comprising synthesis gas.

[0035] The carbonaceous feed may comprise coal (e.g., high quality anthracite or bituminous coal, or lesser quality subbituminous, lignite, or peat), petroleum coke, asphaltene, and / or liquid petroleum residue, or other fossil-derived substance. In a preferred embodiment, the carbonaceous feed may comprise biomass. The term “biomass” refers to renewable (non- fos sil-derived) substances derived from organisms living above the earth’s surface or within the earth’s oceans, rivers, and / or lakes. Representative biomass can include any plant material, or mixture of plant materials, such as a hardwood (e.g., whitewood), a softwood, a hardwood or softwood bark, lignin, algae, and / or lemna (sea weeds). Energy crops, or otherwise agricultural residues (e.g., logging residues) or other types of plant wastes or plant- derived wastes, may also be used as plant materials. Specific exemplary plant materials include corn fiber, corn stover, and sugar cane bagasse, in addition to “on-purpose” energy crops such as switchgrass, miscanthus, and algae. Short rotation forestry products, such as energy crops, include alder, ash, southern beech, birch, eucalyptus, poplar, willow, paper mulberry, Australian Blackwood, sycamore, and varieties of paulownia elongate. Other examples of suitable biomass include vegetable oils, carbohydrates (e.g., sugars), organic waste materials, such as waste paper, construction, demolition wastes, digester sludge, and biosludge. Representative carbonaceous feeds therefore include, or comprise, any of these types of biomass. Particular carbonaceous feeds comprising biomass include municipal solid waste (MSW) or products derived from MSW, such as refuse derived fuel (RDF). Carbonaceous feeds may comprise a combination of fossil-derived and renewable substances, including those described above. A preferred carbonaceous feed is wood (e.g., in the form of wood chips).

[0036] In the gasifier (or, more particularly, a gasification reactor of this gasifier), the carbonaceous feed is subjected to partial oxidation in the presence of an oxygen-containing gasifier feed, added in an amount generally limited to supply only 20-70% of the oxygen that would be necessary for complete combustion. The oxygen-containing gasifier feed will generallycomprise other oxygenated gaseous components including H2O and / or CO2 that may likewise serve as oxidants of the carbonaceous feed. The oxygen-containing gasifier feed can refer to all gases being fed or added to the gasifier, or otherwise can refer to gas that is separate from other gases being fed or added, whether subsequently combined upstream of, or within, the gasifier. For example, the oxygen-containing gasifier feed may be introduced to the gasifier, along with steam, or a portion of steam, generated elsewhere in the process (e.g., RSC- generated steam or CSC-generated steam) and used as a separate feed. Contacting of the carbonaceous feed with the oxygen-containing gasifier feed in the gasifier provides a gasifier effluent, and more particularly a raw gasifier effluent as the product directly exiting the gasifier. One or more reactors (e.g., in series or parallel) of the gasifier may operate under gasification conditions present in such reactor(s), with these conditions including a temperature of generally from about 500°C (932°F) to about 1000°C (1832°F), and typically from about 816°C (1500°F) to about 1038°C (1900°F). Other gasification conditions may include atmospheric pressure or elevated pressure, for example an absolute pressure generally from about 0.1 megapascals (MPa) (14.5 psi) to about 10 MPa (1450 psi), and typically from about 1 MPa (145 psi) to about 3 MPa (435 psi), or from about 0.5 MPa (72 psi) to about 2 MPa (290 psi).

[0037] Gasification reactor configurations include counter-current fixed bed (“up draft”), co-current fixed bed (“down draft”), and entrained flow plasma. Different solid catalysts, having differing activities for one or more desired functions in gasification, such as tar reduction, enhanced H2 yield, and / or reduced CO2 yield, may be used. Limestone may be added to a gasification reactor, for example, to promote tar reduction by cracking. Various catalytic materials may be used in a gasification reactor, including solid particles of dolomite, supported nickel, alkali metals, and alkali metal compounds such as alkali metal carbonates, bicarbonates, and hydroxides. Often, a gasifier is operated with a gasification reactor having a fluidized bed of particles of the carbonaceous feed (and optionally particles of solid catalyst), with the oxygen-containing gasifier feed, and optionally separate, fluidizing H2O- and / or CO2-containing feeds, being fed upwardly through the particle bed. Exemplary types of fluidized beds include bubbling fluidized beds and entrained fluidized beds.

[0038] The raw gasifier effluent comprises, as main constituents, CO, CO2, and methane (CH4) that are derived from the carbon present in the carbonaceous feed, as well as H2 and / or H2O, and generally both, together with other components in minor concentrations. For example, the raw gasifier effluent may further comprise gasifier effluent tar and / or water-solublecontaminants, as undesired impurities, as described below. According to the embodiment illustrated in the figure, the raw gasifier effluent 16 may be obtained directly from gasifier 50, prior to further operations as described herein.

[0039] The raw gasifier effluent, or any gasifier effluent having been subjected to one or more operations as described herein, may comprise synthesis gas, i.e., may comprise both H2 and CO, with these components being present in various amounts (concentrations), and preferably in a combined amount of greater than about 25 mol-% (e.g., from about 25 mol-% to about 95 mol-%), greater than about 50 mol-% (e.g., from about 50 mol-% to about 90 mol-%), or greater than about 65 mol-% (e.g., from about 65 mol-% to about 85 mol-%). With respect to any such combined amounts (concentrations), the FhiCO molar ratio of the gasifier effluent may be suitable for use in downstream syngas conversion operations (reactions or separations), such as (i) the conversion to a renewable syngas conversion product comprising higher molecular weight hydrocarbons and / or alcohols of varying carbon numbers via Fischer-Tropsch conversion or (ii) the conversion to a renewable syngas conversion product comprising methanol via a catalytic methanol synthesis reaction (e.g., performed in a biomethanol synthesis operation or stage), (iii) the conversion to a renewable syngas conversion product comprising renewable natural gas (RNG) via catalytic methanation that increases the methane content in a resulting RNG stream, or (iv) the separation of a renewable syngas separation product comprising purified hydrogen. For example, the gasifier effluent, or any “syngas” or “synthesis gas product” that has not been subjected to a water-gas shift (WGS) reaction, may have an FhiCO molar ratio from about 0.5 to about 3.5, from about 1.0 to about 3.0, or from about 1.5 to about 2.5. More typically, however, such a WGS operation is needed to achieve a favorable FhiCO molar ratio, and / or a favorable H2 concentration, for these or other downstream syngas conversion and separation operations. For example, the WGS operation may include parameters (e.g., reactor temperatures and / or catalyst types) for obtaining the highest yield / concentration of hydrogen, through consumption of CO present in the syngas upstream of this operation, in the case obtaining purified hydrogen as a renewable syngas separation product (e.g., by utilizing one or more PSA and / or membrane separation stages).

[0040] Independently of, or in combination with, the representative amounts (concentrations) of H2 and CO above, the raw gasifier effluent, or any gasifier effluent having been subjected to one or more operations as described herein, may comprise CO2, for example in an amount of at least about 2 mol-% (e.g., from about 2 mol-% to about 30 mol-%), at least about 5 mol-%(e.g., from about 5 mol-% to about 25 mol-%), or at least about 10 mol-% (e.g., from about 10 mol-% to about 20 mol-%). Independently of, or in combination with, the representative amounts (concentrations) of H2, CO, and CO2 above, the raw gasifier effluent, or any gasifier effluent having been subjected to one or more operations as described herein, may comprise CH4, for example in an amount of at least about 0.5 mol-% (e.g., from about 0.5 mol-% to about 15 mol-%), at least about 1 mol-% (e.g., from about 1 mol-% to about 10 mol-%), or at least about 2 mol-% (e.g., from about 2 mol-% to about 8 mol-%). Together with any water vapor (H2O), these non-condensable gases H2, CO, CO2, and CH4 may account for substantially all of the composition of the gasifier effluent. That is, these non-condensable gases and any water may be present in the gasifier effluent in a combined amount of at least about 90 mol-%, at least about 95 mol-%, or even at least about 99 mol-%.Tar Removal Operation

[0041] The raw gasifier effluent, obtained directly from the gasifier, will generally comprise gasifier effluent tar, such that a tar removal operation is typically necessary for further processing. This gasifier effluent tar can include compounds that are referred to in the art as “tars” and “oils” and are more particularly hydrocarbons and oxygenated hydrocarbons having molecular weights greater than that of methane, which may be present in the gasifier effluent at concentrations ranging from several wt-ppm to several wt-%. Certain types of these compounds, having relatively high molecular weight, are further characterized by being problematic due to their tendency to condense at lower temperatures and coat internal surfaces of processing equipment, downstream of the gasifier, causing undesirable fouling, corrosion, and / or plugging. These compounds also interfere with subsequent processing steps, or syngas conversion operations, for upgrading synthesis gas to higher value products, which perform optimally (e.g., from the standpoint of stability) with pure feed gases.

[0042] Particular compounds that are undesirable for these reasons include hydrocarbons and oxygenated hydrocarbons having six carbon atoms or more (C6+hydrocarbons and oxygenated hydrocarbons), with benzene, toluene, xylenes, naphthalene, pyrene, phenol, and cresols being specific examples. These compounds are typically present in the raw gasifier effluent in a total (combined) amount from 1-100 g / Nm3. The removal (e.g., by conversion) of these organic compounds is therefore generally necessary to avoid serious problems caused by their deposition over time. Other types of tars and oils, such as ethane, ethylene, and acetylene, will not condense from the gasifier effluent but will nonetheless “tie up”hydrogen and carbon, with the effect of reducing the overall yield of H2 and CO as the desired components of synthesis gas.

[0043] Depending on the specific tar removal operation, tars and oils in the raw gasifier effluent can be converted, either catalytically or non-catalytically, by oxidation, cracking, and / or reforming to provide, in the tar-depleted gasifier effluent, additional H2 and CO. The tar conversion reaction(s) can utilize available O2 or oxygen sources (e.g., H2O and / or CO2) that are present in, and / or added to, the synthesis gas. In view of the gasifier effluent tar, together with methane, containing a significant portion of the energy of the raw gasifier effluent, the conversion of these compounds can increase the overall yield of synthesis gas substantially. The tar removal operation, which may therefore, according to certain embodiments, be more specifically a tar conversion operation, can effectively reduce the concentration of compounds present as tar in the raw gasifier effluent, having been produced in the gasifier. In general, tar removal, and more particularly tar conversion reactions, may be performed under higher temperatures compared to those used in the gasifier, such that the tar-depleted gasifier effluent, obtained directly from the tar removal operation, may have a temperature of greater than about 1000°C (e.g., from about 1000°C (1832°F) to about 1500°C (2732°F), such as from about 1204°C (2200°F) to about 1427°C (2600°F)).

[0044] According to one embodiment, the tar removal operation may be used for the conversion (e.g., reforming) of tar and methane through non-catalytic partial oxidation (POX) in a reactor used for this operation. The efficiency of this specific operation can be promoted using partial oxidation (POX) burner technology, according to which an excess of oxygen is mixed with a small amount of fuel (e.g., natural gas, propane, or recycled synthesis gas). Combustion of this fuel within the reactor can result in a temperature increase to above 1100°C (2012°F). A POX reactor-based system can effectively improve synthesis gas yields. As described herein, a particularly advantageous source of fuel is a fusel oil byproduct obtained from a biomethanol synthesis operation.

[0045] In the case of a tar removal operation that utilizes catalytic conversion of tar and methane, this operation may include a reactor containing a bed of catalyst comprising solid or supported Ni, solid or supported Fe, and / or dolomite, for example in the form of a secondary fluidized bed downstream of the gasifier. Other catalysts for tar conversion include olivine, limestone, zeolites, and even metal-containing char produced from the gasification. As in the case of non-catalytic processes that may be performed in a tar removal operation, catalytic tarconversion may likewise include the introduction of supplemental oxygen and / or steam reactants, into a reactor used for this operation.

[0046] According to other particular embodiments, the tar removal operation may utilize a suitable liquid or solid adsorbent, to selectively adsorb tars and oils from the raw gasifier effluent. For example, the tar removal operation may be performed with an oil washing system, whereby the raw gasifier effluent is passed through (contacted with) a liquid medium such as bio-oil liquor, to extract the tars and oils based on their preferential solubility. The liquid adsorbent may be combusted after it has become spent.

[0047] Regardless of the particular method by which the tar removal operation is performed, the raw gasifier effluent may comprise tars and oils (e.g., present as compounds described above) in an amount, or combined amount, from about 0.01 wt-% to about 5 wt-%, such as from about 0.1 wt-% to about 3 wt-% or from about 0.5 wt-% to about 2 wt-%. The tar removal operation may be effective to substantially or completely remove this gasifier effluent tar. For example, the tar-depleted gasifier effluent exiting, or obtained directly from, this operation, may comprise tars and oils in an amount, or combined amount, of less than about 0.5 wt-%, less than about 0.1 wt-%, or less than about 0.01 wt-%. Representative levels of removal of tars and oils (e.g., by conversion), measured across the tar removal operation, may be at least about 90%, at least about 95%, or even at least about 99%, resulting in a tar-depleted gasifier effluent that may be substantially or completely free of tar.Quenching Operation

[0048] Hot gasifier effluent, for example the tar-depleted gasifier effluent exiting the tar removal operation, can be cooled by various techniques that include radiant and / or convective heat exchange. In representative embodiments, at least one quenching operation, such as a dry quenching operation or a full quenching operation, may be used, in which water is added directly to the gasifier effluent and contributes to its overall moisture content, thereby favoring H2 production via the equilibrium-limited WGS reaction (i.e., to provide an increased H2:CO molar ratio and an increased H2 concentration). A dry or partial quenching operation utilizes the sensible heat of the gasifier effluent to vaporize the injected water, which is sufficient for obtaining the resulting quenched gasifier effluent at a desired, cooler temperature. A full or complete quenching operation uses sufficient water to saturate the quenched gasifier effluent. In the case of using dry or full quenching without the further use of an RSC or CSC, the quenched gasifier effluent may have a temperature from about 250°C(482°F) to about 600°C (1112°F), and preferably from about 275°C (527°F) to about 350°C (662°F) to allow for further processing. Representative processes can otherwise include, however, sufficient further cooling (e.g., using an RSC or a CSC) as required upstream of a subsequent filtration operation (passage through a filter) to remove solid particles (e.g., dust). In preferred embodiments, only a partial quench is used in the quenching operation, as opposed to a full quench, such that the quenched gasifier effluent exiting, or obtained directly from, the dry quenching operation is above its dewpoint, i.e., not saturated. In general, the dry quenching operation can promote rapid and efficient cooling through direct contact between hot gasifier effluent and water or other aqueous quenching medium.Radiant Syngas Cooler (RSC) or Convective Syngas Cooler (CSC)

[0049] As described herein, according to representative embodiments, a combination of a quenching operation characterized by direct contact of a synthesis gas (e.g., the tar-depleted gasifier effluent exiting the tar removal operation) and a quenching medium such as water, together with an RSC or a CSC, can provide effective cooling for further downstream operations. An RSC may also be effective removal of ash and formed slag. For example, an RSC or a CSC may be used to cool a quenched gasifier effluent exiting the quenching operation to provide a cooled gasifier effluent having a temperature within a range as described above, with respect to a quenched gasifier effluent that does not require further cooling for downstream processing. In this case, the quenched gasifier effluent may have an intermediate temperature, such as 400°C (752°F) to about 900°C (1652°F), and preferably from about 538°C (1000°F) to about 816°C (1500°F). An RSC or a CSC may operate by indirect heat transfer, such as in the case of having a shell and tube configuration, typically with the generation steam from some of the heat recovered from the gasifier and tar removal operation. According to more particular embodiments, an RSC or CSC may operate as a boiler (e.g., a fire tube boiler or water tube boiler) for the production of medium and / or high pressure steam.Filtration Operation

[0050] A filtration operation, using any suitable filter, may be used to remove solid particles (particulates) from the gasifier effluent, for example the quenched gasifier effluent as described above, exiting a dry or full quenching operation, or the cooled gasifier effluent as described above, exiting an RSC or a CSC. In the case of biomass gasification, these solid particles can include char, tar, soot, and ash, any of which can generally contain alkali metalssuch as sodium. Corrosive and / or harmful species such as chlorides, arsenic, and / or mercury may also be contained in such solid particles. A high temperature filtration, for example using bundles of metal or ceramic filters, may generally be sufficient to reduce the content of solid particles in the gasifier effluent, such as to provide a filtered gasifier effluent exiting, or obtained directly from, the filtration operation and having less than 1 wt-ppm, and possibly less than 0.1 wt-ppm of solid particles. In representative embodiments, the filtered gasifier effluent may have a temperature in a range as described above to allow for the filtration, such as a temperature from about 250°C (482°F) to about 600°C (1112°F), and preferably from about 275°C (527°F) to about 350°C (662°F). That is, the filtration operation may involve little or no cooling of the gas stream being filtered.

[0051] In some embodiments, a filtration operation may be performed upstream of (prior to) the tar removal operation to allow the latter to operate more effectively. The removal of solid particles of varying average particles sizes, using filtration or other techniques, may be performed at any of a number of possible stages within the overall process. For example, coarse solids removal by centrifugation may be performed directly downstream of the gasifier, and / or may even be performed in situ in the gasifier (e.g., using internal cyclones, for removal of solid particles, positioned in a headspace above a fluidized particle bed).

[0052] The filtration operation may be followed by, or integrated with, a supplemental cleaning operation to further purify the gasifier effluent, such as to further reduce its tar and overall hydrocarbon content, for example by contact with a solid “polishing” material such as a carbon bed. This can provide for more thorough removal of benzene, naphthalene, pyrene, toluene, phenols, and other condensable species that could otherwise be detrimental to downstream operations, such as by deposition onto equipment.Scrubber Feed Cooler

[0053] Prior to the scrubbing operation, heat may be removed from the gasifier effluent, such as the filtered gasifier effluent described above and exiting, or obtained directly from, the filtration operation. According to some embodiments, a boiler and / or an air cooler (employing fans) may be used as a scrubber feed cooler to carry out indirect heat exchange. Regardless of the particular type, this cooler may more specifically perform cooling of a heated scrubber feed to provide the scrubber feed (or cooled scrubber feed) that is input directly to the scrubber, in which case both the heated and cooled streams may comprise an un-scrubbed gasifier effluent, such as the filtered gasifier effluent. It can therefore be appreciated that, accordingto specific embodiments, the “heated scrubber feed” may correspond to, or may comprise, the “filtered gasifier effluent.” Also, the heated scrubber feed / filtered gasifier effluent and the scrubber feed / cooled scrubber feed may be specific examples of an “un-scrubbed gasifier effluent.” In some embodiments, a scrubber feed cooler may be absent, such as in the case of sufficient cooling occurring upstream of the filtration operation for direct use of the filtered gasifier effluent in the scrubbing operation. In such cases, the “scrubber feed” may correspond to, or may comprise, the “filtered gasifier effluent.”

[0054] In representative embodiments, the scrubber feed, whether or not having been cooled in a scrubber feed cooler, may have been cooled generally, upstream and / or downstream of the filtration operation, to a temperature from about 200°C (392°F) to about 450°C (842°F), and preferably from about 225 °C (437 °F) to about 325 °C (617 °F). Such temperature may correspond to the scrubber gas inlet temperature or scrubber operating temperature. In the case of using a scrubber feed cooler downstream of the filtration operation, as illustrated in the figure, the heated scrubber feed, directly upstream of this cooler, may have a temperature within the ranges given above with respect to the filtered gasifier effluent, which may be from about 250°C (482°F) to about 600°C (1112°F), and preferably from about 275°C (527°F) to about 350°C (662°F).Scrubbing Operation

[0055] A scrubbing operation may be used to remove water and water-soluble contaminants from an un-scrubbed gasifier effluent, such as the filtered gasifier effluent exiting the filtration operation, optionally following the cooling of this stream by a scrubber feed cooler. For example, the filtered gasifier effluent may serve as a feed to a boiler that, following indirect heat exchange, provides a cooled effluent upstream of the scrubbing operation, all or at least a portion of which effluent may provide the scrubber feed to the scrubbing operation. Otherwise, in the absence of a scrubber feed cooler, the filtered gasifier effluent, at substantially the temperature exiting the filtration operation, may serve as a feed to the scrubbing operation. In either case, the scrubbing operation itself may provide further cooling of the scrubber feed. For example, the scrubbed gasifier effluent exiting the scrubber may have a temperature from about 35°C (95°F) to about 100°C (212°F), and preferably from about 35°C (95°F) to about 66°C (150°F).

[0056] The scrubbing operation, such as wet scrubbing, may be effective for removing, as water- soluble contaminants, chlorides (e.g., in the form of HC1), ammonia, and HCN, as well asfine solid particles (e.g., char and ash). For example, in the case of using a wet scrubber, an un-scrubbed gasifier effluent, such as the scrubber feed obtained optionally following cooling, may be fed to a trayed column to perform co-current or counter-current contacting with water or an aqueous solution. Further cooling in this column, such as to a temperature below 100°C (212°F) can aid in droplet condensation for improving the contaminant removal effectiveness. The scrubbing operation can be used to provide a scrubbed gasifier effluent exiting, or obtained directly from, this operation and having a combined amount of chloride, ammonia, and solid particles of less than 1 wt-ppm, and possibly less than 0.1 wt-ppm. The scrubbing operation also generally serves to remove water, such that the moisture content of the scrubbed gasifier effluent is reduced, relative to that of the scrubber feed.Acid Gas Removal Operation

[0057] An acid gas removal operation may be used to separate an acid gas product from a gasifier effluent, for example the scrubbed gasifier effluent directly exiting the scrubbing operation or optionally this scrubbed gasifier effluent following compression to provide a compressed, scrubbed gasifier effluent. The acid gas product may be an H S-cnrichcd product (e.g., having a higher FhS concentration compared to that of the scrubbed gasifier effluent or compressed, scrubbed gasifier effluent). The acid gas product may also be enriched in other sulfur compounds, such as COS and / or SO2, as well as being enriched in overall sulfur content (concentration). In some embodiments, the acid gas removal operation may further provide a CO2-enriched product (e.g., as a second acid gas product having a higher CO2 concentration compared to that of the scrubbed gasifier effluent or compressed, scrubbed gasifier effluent). Any FFS-enriched product or CO2-enriched product may be recycled to the process, where useful (e.g., for sulfiding of sulfur-tolerant catalyst systems or as a source of inert gas for reducing fire / explosion hazards).

[0058] The acid gas removal operation may therefore be used to reduce the concentration of H2S and / or CO2 in the scrubbed gasifier effluent, such as to provide a CCh-dcpIctcd gasifier effluent exiting, or obtained directly from, this operation. In the case of an upstream scrubbing operation being utilized, this may provide the requisite degree of dehydration of the scrubbed gasifier effluent or compressed, scrubbed gasifier effluent, for use as a feed to the acid gas removal operation. The acid gas removal operation may beneficially increase the H2 concentration of CCh-dcpIctcd gasifier effluent, compared to that of the scrubbed gasifier effluent or compressed, scrubbed gasifier effluent, such that, optionally in combination with a downstream WGS operation, the H2 concentration and / or FhiCO molar ratio of the resultingprocess stream, such as the WGS product or conditioned syngas product as described herein, may be within ranges as described above with respect to the gasifier effluent, which ranges are applicable to any “syngas,” or alternatively “synthesis gas product,” as described herein.

[0059] The acid gas removal operation may utilize one or more stages of contacting with a physical solvent such as Selexol® (dimethyl ethers of polyethylene glycol), Rectisol® (cold methanol), or a combination thereof. In the case of a physical solvent, acid gases are selectively solubilized in this solvent under elevated pressure, and the solvent may be regenerated, together with the release of a separated acid gas product, upon reducing pressure. Alternatively, the acid gas removal operation may utilize one or more stages of contacting with a chemical solvent, examples of which are amine solvents such as monoethanolamine, diethanolamine, methyldiethanolamine (MDEA), diisopropylamine, or diglycolamine. In the case of a chemical solvent, acid gases are selectively absorbed by chemical interactions, and the solvent may be regenerated, together with the release of a separated acid gas product, upon heating. Other solvents, such as methanol, potassium carbonate, a solution of sodium salts of amino acids, etc. can also be used to remove at least a portion of an acid gas initially present in the sour WGS product (e.g., scrubbed sour WGS product or pressurized sour WGS product). The physical or chemical solvent can promote the selective removal of H2S / COS, in addition to the removal of CO2 in this product. In the case of a physical solvent such as Selexol®, this may generally be suitable for temperatures up to 175 °C (347 °F). Regeneration of the rich physical or chemical solvent, such as after having reached substantially its capacity for the removal of acid gases, can release the acid gas product, as an FhS-enriched product. For example, regeneration can be carried out by desorption of the rich solvent by flashing (depressurization), thermal treatment, and / or the use of stripping gas.WGS Operation

[0060] The water gas shift (WGS) operation reacts CO present in a gasifier effluent (e.g., the scrubbed gasifier effluent exiting the scrubbing operation; the compressed, scrubbed gasifier effluent exiting a compressor; or the CO2-depleted gasifier effluent exiting the acid gas removal operation) with steam to increase H2 concentration (as well as CO2 concentration). In this manner, the scrubbed gasifier effluent, optionally after being subjected to compression and / or acid gas removal, may be characterized as a feed to the WGS operation (WGS feed). Following the tar removal operation, filtration operation, and scrubbing operation, the scrubbed gasifier effluent / feed to the WGS operation may have favorable properties for usein this operation, in terms of its being free or substantially free of water-soluble contaminants as described above, as well as tars and particulates.

[0061] According to some embodiments, the scrubbed gasifier effluent / feed to the WGS operation may be heated and / or supplemented with moisture (steam) to further improve its properties for kinetically and / or thermodynamically favoring the WGS reaction that desirably increases the H2:C0 molar ratio and / or H2 concentration of the WGS product relative these characteristics of the WGS feed. For example, this feed may be heated to a temperature from about 225°C (437°F) to about 475°C (887°F), and preferably from about 260°C (500°F) to about 399°C (750°F), prior to its input to the WGS operation. The moisture content of this feed may be augmented utilizing a supplemental source steam, such as at least a portion of the generated steam provided from steam generation (e.g., using a boiler) in any cooling operation described above. For example, at least a portion of steam (e.g., low or medium pressure steam) generated in the scrubber feed cooler, RSC (as RSC-generated steam), or CSC (as CSC-generated steam) may be fed or added to the WGS operation (e.g., to one or more reactors used in this operation), thereby improving overall heat balancing / integration. In the WGS operation, the use of steam in excess of the stoichiometric amount may be beneficial, particularly in adiabatic, fixed-bed reactors, for a number of purposes. These include driving the equilibrium toward hydrogen production, adding heat capacity to limit the exothermic temperature rise, and minimizing side reactions, such as methanation.

[0062] Reactors used in a WGS operation may contain a suitable catalyst, such as those comprising one or more of Co, Ni, Mo, and W on a solid support, particular examples of which are Co / Mo and Ni / Mo catalysts that exhibit sulfur tolerance. Other catalysts for use in this operation (z.e., contained within one or more WGS reactors) include those based on copper- containing and / or zinc-containing catalysts, such as Cu-Zn-Al; chromium-containing catalysts; iron oxides; zinc ferrite; magnetite; chromium oxides; and any combination thereof (e.g., Fe2O3-Cr2O3 catalysts).

[0063] In a typical WGS operation, two or more reactors with interstage cooling are used in view of the thermodynamic characteristics of the WGS reaction. For example, a high-temperature shift (HTS) reactor may operate with a temperature of the reactor inlet from about 310°C (590°F) to about 450°C (842°F), with more favorable reaction kinetics but a less favorable equilibrium conversion. The effluent from the HTS may then be cooled to a temperature suitable for the reactor inlet of a low-temperature shift (LTS) reactor, such as from about 200°C (392°F) to about 250°C (482°F), for providing less favorable reaction kinetics but amore favorable equilibrium conversion, such that the combined effect of the HTS and LTS reactors results in a high conversion to H2 with a favorable residence time. In some cases, it may be desirable to use three or more reactors, or catalyst beds, to perform the WGS reaction, again with cooling between consecutive reactors or catalyst beds.

[0064] In this manner, the WGS operation may be used to provide an immediate WGS product exiting, or obtained directly from, this operation and having an increased FhiCO molar ratio and increased H2 concentration, relative to the feed to the WGS operation or the synthesis gas obtained from upstream operations (e.g., filtered gasifier effluent or cooled gasifier effluent). For example, the immediate WGS product may have an FhiCO molar ratio from about 0.5 to about 3.5, from about 1.0 to about 3.0, or from about 1.5 to about 2.5 and / or a hydrogen concentration of at least about 35 mol-% (e.g., from about 35 mol-% to about 80 mol-%), at least about 40 mol-% (e.g., from about 40 mol-% to about 70 mol-%), or at least about 45 mol-% (e.g., from about 45 mol-% to about 65 mol-%). These characteristics of the immediate WGS product may be controlled by bypassing the WGS operation to a greater or lesser extent (e.g., diverting a smaller or larger portion of the feed to this operation, around this operation to provide a portion of the immediate WGS product). The WGS operation may be further beneficial in terms of converting carbonyl sulfide (COS) to H2S which can be recycled and more easily removed elsewhere in the process, such as in the acid gas removal operation or possibly, at least to some extent, in the scrubbing operation.Syngas Conversion or Separation Operations

[0065] In some embodiments, processes described herein may also include a syngas conversion operation or syngas separation operation to produce a respective renewable syngas conversion product or renewable syngas separation product, such as liquid hydrocarbons, methanol, or RNG as examples of conversion products, and purified hydrogen as an example of a separation product. In the case of liquid hydrocarbon production, the syngas conversion operation may comprise a Fischer-Tropsch (FT) reaction stage. One or more reactors in this stage are used to process the synthesis gas mixture of hydrogen (H2) and carbon monoxide (CO) by successive cleavage of C-0 bonds and formation of C-C bonds with the incorporation of hydrogen. This mechanism provides for the formation of hydrocarbons, and particularly straight-chain alkanes, with a distribution of molecular weights that can be controlled to some extent by varying the FT reaction conditions and catalyst properties. Such properties include pore size and other characteristics of the support material. The choice ofFT catalyst and its active metals (e.g., Fe or Ru) can impact FT product yields in other respects, such as in the production of oxygenates.

[0066] In the case of methanol production, the syngas conversion operation may comprise a methanol synthesis reaction stage, or more specifically a biomethanol synthesis reaction stage. One or more reactors in this stage are used to form methanol according to the catalytic reaction:CO + 2H2^ CH3OH (1)Representative catalysts for the synthesis of methanol by this route are characterized by “CZA,” which is a reference to copper and zinc on alumina, or Cu / ZnO / AhOa. Alternatively, or in combination, various other catalytic metals and their oxides may be used, including one or more of W, Zr, In, Pd, Ti, Co, Ga, Ni, Ce, Au, Mn, and their combinations.

[0067] In the case of methane production as a syngas conversion operation to provide a renewable natural gas (RNG) product, one or more methanation reactors (e.g., in series or parallel) may be used to react CO and / or CO2with hydrogen and thereby provide a hot methanation product having a significantly higher concentration of methane relative to that initially present (e.g., in the WGS product). Catalysts suitable for use in a methanation reactor include supported metals such as ruthenium and / or other noble metals, as well as molybdenum and tungsten. Generally, however, supported nickel catalysts are most cost effective. Often, a methanation reactor is operated using a fixed bed of the catalyst.

[0068] In the case of purified hydrogen production, the syngas separation operation may comprise a renewable hydrogen separation stage that can utilize, for example, (i) an adsorbent in the case of separation by PSA or (ii) a membrane. Combinations of such stages may be used in a given syngas separation operation. In any such operation, a gaseous separation byproduct is also provided that is generally enriched in the non-hydrogen components of syngas, such as CO, CO2, and / or H2O. This byproduct may be, for example, a PSA tail gas or otherwise a membrane permeate or retentate, depending on the particular membrane used and consequently whether the renewable hydrogen separation product is recovered as the membrane retentate or permeate. This hydrogen, obtained as a result of utilizing a syngas separation operation downstream of the WGS operation, may, in some embodiments, be characterized as high purity hydrogen (e.g., having a purity of at least about 99 mol-% or more, such as at least 99.9 mol-% or at least 99.99 mol-%). 1

[0069] According to an exemplary embodiment, the syngas conversion operation may comprise a methanol synthesis reaction stage, or more specifically a biomethanol synthesis reaction stage, which, in addition to a raw biomethanol product, may provide a separated, gaseous byproduct. This gaseous byproduct may, in turn, be beneficially subjected to a hydrogen recovery operation, as a syngas separation operation described above, which is specifically configured in the overall gasification process. That is, the hydrogen recovery operation may utilize, for example, (i) an adsorbent in the case of separation by PSA or (ii) a membrane, to further separate the gaseous byproduct into both an H -cnrichcd off gas and an H -dcplctcd tail gas, optionally having properties as described above with respect to a renewable hydrogen separation product and a tail gas (e.g., PSA tail gas) as described above. These H2- enriched and H -dc ictcd gas streams may optionally be further utilized in the process as described herein.Further exemplary embodiments of gasification processes

[0070] The figure depicts a flow scheme illustrating an embodiment of a process including operations as described above, and more particularly including, as a specific type of syngas conversion operation, a biomethanol synthesis operation or reaction stage, and as a specific type of syngas separation operation, a hydrogen recovery operation for concentrating valuable H2 present in a gaseous byproduct of the biomethanol synthesis operation or reaction stage.

[0071] With reference to the figure, and with the understanding that embodiments disclosed herein do not necessarily require all of the illustrated features, such embodiments may be directed to a process for gasification of a carbonaceous feed (e.g., wood) generally. The process may comprise, in gasifier 50, contacting carbonaceous feed 10 (which may be a dried carbonaceous feed, following drying) with oxygen-containing gasifier feed 14 (and optionally a separate source of steam) under gasification conditions to provide an un- scrubbed gasifier effluent comprising H2, CO, and water-soluble contaminants. Oxygen-containing gasifier feed 14 alone (or possibly in combination with a separate source of steam), may comprise H2O and O2, as well as optionally CO2, in a combined concentration of at least about 90 mol- %, at least about 95 mol-%, or at least about 99 mol-%. The un-scrubbed gasifier effluent may be any process stream downstream of gasifier 50 and upstream of scrubbing operation 80, including raw gasifier effluent 16, tar-depleted gasifier effluent 18, quenched gasifier effluent 22, cooled gasifier effluent 24, filtered gasifier effluent 26, or scrubber feed 28.

[0072] The process may further comprise feeding at least a portion of the un-scrubbed gasifier effluent, for example as scrubber feed 28, to scrubbing operation 80 to remove at least a portion of the water-soluble contaminants and provide scrubbed gasifier effluent 30. In the absence of scrubber feed cooler 75, the scrubber feed may correspond to, or may comprise, filtered gasifier effluent 26, which may be fed directly to scrubbing operation 80. In the case utilizing scrubber feed cooler 75, an un-scrubbed gasifier effluent or portion thereof may be fed, for example as filtered gasifier effluent / heated scrubber feed 26, to cooler 75. In some embodiments, cooler 75 may provide generated steam 33 from heat in this heated scrubber feed being transferred to boiler feed water 31, as well as provide scrubber feed 28 (which may also be referred to as a cooled scrubber feed in such embodiments). It can therefore be appreciated that either or both of heated scrubber feed 26 and scrubber feed 28 may correspond to, or may comprise, an un-scrubbed gasifier effluent, such as in the particular case of an un-scrubbed gasifier effluent, that, as a heated scrubber feed, is at a higher temperature relative to this un-scrubbed gasifier effluent, as a scrubber feed. The unscrubbed gasifier effluent, as heated scrubber feed 26 and scrubber feed 28, may have the same composition.

[0073] In exemplary embodiments, the un-scrubbed gasifier effluent, which is optionally fed to cooler 75 as heated scrubber feed 26 or directly fed to scrubbing operation 80 as scrubbed feed 28, may be a filtered gasifier effluent, having been subjected to filtration operation 70, as an intervening operation, to remove solid particles. More particularly, in addition to having been subjected to filtration operation 70, the filtered gasifier effluent may have been further subjected to one or more other intervening operations downstream of gasifier 50 and upstream of filtration operation 70. For example, such intervening operations may include one or more of (i) tar removal operation 55 to remove at least a portion of gasifier effluent tar (e.g., and provide tar-depleted gasifier effluent 18), (ii) quenching operation 60 (which may be a partial or full quenching operation) comprising direct contact with quench water 20 (e.g., and provide quenched gasifier effluent 22), and (iii) radiant syngas cooler 65 (RSC) or convective syngas cooler (CSC) 65, implementing heat-exchanging contact with, respectively, RSC feed water or CSC feed water (e.g., and provide cooled gasifier effluent 24). The RSC feed water or CSC feed water may be, for example, boiler feed water 25 which, following heat exchange in RSC 65 or CSC 65, provides RSC-generated steam 23 or CSC-generated steam 23, respectively. Optionally in combination with any of these particular intervening operations, other intervening operations may include both filtrationoperation 70 and scrubber feed cooler 75 downstream of this operation. In this case, the unscrubbed gasifier effluent, at least a portion of which is fed as a scrubber feed to scrubbing operation 80, according to any exemplary process as described herein, may be more particularly a filtered and cooled gasifier effluent, having been subjected to filtration operation 70 to remove solid particles and also to scrubber feed cooler 75.

[0074] With respect to various features of representative processes, therefore, raw gasifier effluent 16 produced in gasifier 50 is fed to tar removal operation 55, to provide tar-depleted gasifier effluent 18, having a lower amount of tar relative to raw gasifier effluent 16. Generally, processes comprise recovering a synthesis gas product from tar-depleted gasifier effluent 16, with such synthesis gas product possibly including any of those downstream of tar-depleted gasifier effluent 16 as illustrated in the figure. For example, the synthesis gas product may be recovered as water-gas shift (WGS) product 36 of WGS operation 90, optionally following one or more intervening operations performed on the gasifier effluent, downstream of the tar removal operation and upstream of the WGS operation. Such intervening operations can include one or more of (i) quenching operation 60 comprising direct contact of the gasifier effluent with quench water 20, (ii) radiant syngas cooler (RSC) 65 or convective syngas cooler (CSC) 65, implementing heat-exchanging contact of the gasifier effluent with RSC feed water or CSC feed water (e.g., boiler feed water), as the case may be (iii) filtration operation 70 to remove solid particles from the gasifier effluent, (iv) scrubber feed cooler 75 to further remove heat from the gasifier effluent and control the temperature of the downstream scrubbing operation as described herein, and (v) scrubbing operation 80 to remove water-soluble contaminants from the gasifier effluent.

[0075] According to exemplary embodiments, quenching operation 60, may be more particularly a partial dry quench (PDQ) operation. Representative processes may further comprise, in any order but preferably in the following order: in the PDQ operation, contacting (e.g., by direct contact) tar-depleted gasifier effluent 18 with quench water 20 to provide quenched gasifier effluent 22; in the RSC 65 or CSC 65, further cooling quenched gasifier effluent 22 to provide cooled gasifier effluent 24 and, respectively, RSC-generated steam 23 or CSC- generated steam 23; in filtration operation 70, removing solid particles from cooled gasifier effluent 24 to provide filtered gasifier effluent 26; and in scrubber feed cooler 75, cooling filtered gasifier effluent 26 to provide the tar-depleted effluent, as a scrubber feed, to the scrubbing operation. Generally, according to certain embodiments as illustrated in the figure, quenching operation 60 provides quenched gasifier effluent 22, having a temperature that isdecreased relative to that of tar-depleted gasifier effluent 18. The process may additionally comprise, in radiant syngas cooler (RSC) 65 or convective syngas cooler (CSC) 65, further cooling quenched gasifier effluent 22, such as by indirect, heat-exchanging contact with RSC feed water or CSC feed water, respectively. This provides cooled gasifier effluent 24, which may then be subjected to filtration operation 70, heat removal in scrubber feed cooler 75, and scrubbing operation 80, with particular details of these operations as described herein.

[0076] Representative processes may further comprise feeding at least a portion of scrubbed gasifier effluent 30 to conditioning stage 100 that provides conditioned syngas product 105 that may, relative to scrubbed gasifier effluent 30, have characteristics that are more favorable for downstream syngas conversion operations and / or downstream syngas separation operations. Such characteristics may include (a) a higher pressure, resulting from compression utilizing compressor 85 to provide compressed, scrubbed gasifier effluent 32; (b) a lower acid gas (e.g., lower CO2) concentration, resulting from acid gas removal utilizing acid gas removal operation 87 to provide CCh-dcpIctcd gasifier effluent 34; and / or (c) an increased thiCO molar ratio and / or increased H2 concentration, resulting from utilizing WGS operation 90 to provide WGS product, and optionally further utilizing recycle of recycle portion 38a of H2- enriched off gas 38, optionally further in combination with makeup H2 source 45. Accordingly, syngas conditioning stage 100 may include one or more operations performed on scrubbed gasifier effluent 30, with these including any one or more of compression (e.g., using compressor 85), acid gas removal operation 87, and WGS operation 90, performed in any order but preferably in the this listed order.

[0077] Whether or not operations of compression or acid gas removal are specifically used, according to some embodiments feeding at least a portion of scrubbed gasifier effluent 30, provided from scrubbing operation 80, to WGS operation 90, provides WGS product 36 having a H2:CO molar ratio that is increased relative to that of raw gasifier effluent 16, and / or syngas exiting any of intervening operations, such as tar-depleted gasifier effluent 18, quenched gasifier effluent 22, cooled gasifier effluent 24, filtered gasifier effluent 26, scrubber feed 28, or scrubbed gasifier effluent 30. Representative processes may further comprise feeding at least a portion of WGS product 36 to syngas conversion operation 95 or syngas separation operation 95 to provide respective renewable syngas conversion product 40 or renewable syngas separation product 40. According to more specific embodiments, for example, (i) syngas conversion operation 95 may comprise a Fischer-Tropsch reaction stage, such that renewable syngas conversion product 40 comprises liquid hydrocarbons and / oroxygenates (e.g., alcohols) of varying carbon numbers, (ii) syngas conversion operation 95 may comprise a catalytic methanol synthesis reaction stage, such that renewable syngas conversion product 40, or a purified product 42 obtained from purification in a separation stage 99, comprises methanol, or (iii) syngas conversion operation 95 may comprise a catalytic methanation reaction stage, such that renewable syngas conversion product 40 comprises RNG. According to other more specific embodiments, syngas separation operation 95 may comprise a renewable hydrogen separation stage, such that renewable syngas separation product 40 comprises purified hydrogen.

[0078] In achieving various benefits as described herein, according to the specific embodiment illustrated in the figure, representative processes may comprise feeding at least a portion of conditioned syngas product 105 to biomethanol synthesis operation 95 (as a specific type of syngas conversion operation) to provide raw biomethanol product 40. Such processes may further comprise separating, in biomethanol separation stage 99, this raw biomethanol product to provide at least purified biomethanol product 42 (as a specific type of renewable syngas conversion product), having a higher concentration of biomethanol relative to that of raw biomethanol product 40, such as in the case of purified biomethanol product having a methanol purity of at least about 90 wt-%, at least about 95 wt-%, or at least about 98 wt-%. As further illustrated in the figure, separation stage 99 may further provide fusel oil byproduct 44 (e.g., a specific type of liquid conversion byproduct, generally comprising C2+alcohols and / or other oxygenated byproduct species). Additional separated products of biomethanol separation stage 99 may include light ends fraction 46 (e.g., comprising predominantly non-condensable gases such as CO, H2, and CH4) and aqueous product 48. Depending on the operation of separation stage 99, aqueous product 48 may comprise predominantly water, or a mixture of water and methanol, with optionally minor amounts of C2+alcohols. For example, aqueous product 48 may comprise water, and / or may comprise water and methanol in combination, in an amount, or combined amount, of at least about 50 wt-%, at least about 75 wt-%, at least about 90 wt-%, or at least about 95 wt-%. In any event, according to particular embodiments, in addition to purified biomethanol product 42 and fusel oil byproduct 44, biomethanol separation stage 99 may further provide light ends fraction 46 and / or aqueous product 48.

[0079] Advantageously, as illustrated in the figure, at least a portion of fusel oil byproduct 44 may be fed as a fuel for (e.g., may be combusted in) tar removal operation 55. This use as a fuel may comprise, for example, feeding all or a portion of fusel oil byproduct 44 directly to tarremoval operation 55 and / or feeding all or a portion of this byproduct upstream of the tar removal operation (e.g., by combining it with the gasifier effluent). Direct feeding to tar removal operation 55 may be performed, for example, by feeding to a POX reactor, such as through an auxiliary line used to inject fuel. Feeding upstream of tar removal operation 55 may be performed, for example, by combining fusel oil byproduct 44 with raw gasifier effluent 16 upstream of tar removal operation 55 or with another process stream, otherwise leading directly this operation or ultimately having the contents of such process stream passed to this operation. Utilization of light ends fraction 46 in the process may involve recovery of its heating value. Also, aqueous product 48 may be utilized for direct and / or indirect cooling (e.g., as a source of quench water 20, RSC feed water 25 or CSC feed water 25, and / or boiler feed water 31 to scrubber feed cooler 75), or may alternatively, or in combination, be utilized for sump and slagwater systems of the process, for example of quenching operation 60, RSC 65, and / or CSC 65.

[0080] Further options for process integration may utilize gaseous byproduct 37 (e.g., comprising non-condensable gases, such as unconverted CO and / or Fh), separated from biomethanol synthesis operation 95, for example as a vapor fraction, with the liquid fraction being raw biomethanol product 40. In some embodiments, processes may further comprise feeding at least a portion of gaseous byproduct 37 to hydrogen recovery operation 97 (e.g., utilizing a membrane or PSA separation system) to provide Fh-enriched off gas 38, at least a portion of which, such as first portion 38a, may be recovered as a renewable syngas separation product. Alternatively, or in combination, all or at least a portion, such as second portion 38b of F - enriched off gas 38, may be recycled to syngas conditioning stage 100, for example by being combined with WGS product 36 to increase the H2 concentration and / or Fh:CO molar ratio of conditioned syngas product 105, thereby potentially benefitting its further use in biomethanol synthesis operation 95. In addition to Fh-enriched off gas, hydrogen recovery operation 97 may further provide Fh-depleted tail gas 39, all or a portion of which may be beneficially recycled to biomethanol synthesis operation 95.

[0081] Overall, aspects of the invention relate to gasification processes implementing operations as described herein, including a tar removal operation, with methanol being fed as a fuel to this operation (e.g., through an auxiliary fuel gas line). Advantageously, this methanol may be readily available in a fusel oil byproduct of a biomethanol synthesis operation, to which a conditioned syngas product, obtained from gasification in a gasifier of the process, is fed. Other integration strategies involve the use of other products and byproducts of biomethanolsynthesis. Those skilled in the art, having knowledge of the present disclosure, will recognize that various changes can be made to these processes in attaining these and other advantages, without departing from the scope of the present disclosure. As such, it should be understood that the features of the disclosure are susceptible to modifications and / or substitutions, and the specific embodiments described herein are for illustrative purposes only, and not limiting of the invention as set forth in the appended claims.

Claims

CLAIMS:

1. A process for gasification of a carbonaceous feed, the process comprising: in a gasifier, contacting the carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, water- soluble contaminants, and gasifier effluent tar; subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the gasifier effluent tar and provide a tar-depleted gasifier effluent; feeding at least a portion of the tar-depleted gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent; feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product; feeding at least a portion of the conditioned syngas product to a biomethanol synthesis operation to provide a raw biomethanol product; separating, in a biomethanol separation stage, the raw biomethanol product to provide at least a purified biomethanol product and a fusel oil byproduct; and feeding the fusel oil byproduct as a fuel for the tar removal operation.

2. The process of claim 1, wherein the fusel oil byproduct comprises one or more C2+alcohols in a combined amount of at least about 50 wt-%.

3. The process of claim 1, wherein said feeding the fusel oil byproduct as a fuel for the tar removal operation comprises feeding all or a portion of the fusel oil byproduct directly to the tar removal operation or upstream of the tar removal operation.

4. The process of claim 1, wherein the one or more intervening operations include one or more of (i) a quenching operation comprising direct contact with quench water, (ii) a radiant syngas cooler (RSC) or convective syngas cooler (CSC) implementing heatexchanging contact with boiler feed water, (iii) a filtration operation to remove solid particles, and (iv) a scrubber feed cooler for further cooling, upstream of the scrubbing operation.

5. The process of claim 4, wherein the quenching operation is a partial dry quench (PDQ) operation, the process further comprising: in the PDQ operation, contacting the tar-depleted gasifier effluent with quench water to provide a quenched gasifier effluent; in the radiant syngas cooler (RSC) or convective syngas cooler (CSC), further cooling the quenched gasifier effluent to provide a cooled gasifier effluent and RSC-generated steam or CSC-generated steam; in the filtration operation, removing solid particles from the cooled gasifier effluent to provide a filtered gasifier effluent; and in the scrubber feed cooler, cooling the filtered gasifier effluent to provide the tar- depleted effluent, as a scrubber feed, to the scrubbing operation.

6. The process of any one of claims 1 to 5, wherein the conditioning stage comprises one or more conditioning operations performed on the scrubbed gasifier effluent, said one or more conditioning operations selected from the group consisting of (a) compression, (b) an acid gas removal operation, and (c) a water-gas shift (WGS) operation.

7. The process of claim 6, wherein the conditioning stage comprises (a) said compression to provide a compressed, scrubbed gasifier effluent, (b) said acid gas removal operation to provide a CCh-depleted product, and (c) said WGS operation to provide the conditioned syngas product.

8. The process of any one of claims 1 to 7, wherein the conditioned syngas product is a water-gas shift (WGS) product of a WGS operation of the syngas conditioning stage.

9. A process for gasification of a carbonaceous feed, the process comprising: in a gasifier, contacting the carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, and water-soluble contaminants; feeding at least a portion of the gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent;feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product; feeding at least a portion of the conditioned syngas product to a biomethanol synthesis operation to provide a raw biomethanol product and a gaseous byproduct.

10. The process of claim 9, further comprising feeding at least a portion of the gaseous byproduct to a hydrogen recovery operation to provide an H -cnrichcd off gas.

11. The process of claim 10, further comprising recovering at least a portion of the H2- enriched off gas as a renewable syngas separation product.

12. The process of claim 10 or claim 11, further comprising recycling all, or at least a second portion, of the fT-cnrichcd off gas to the syngas conditioning stage.

13. The process of any one of claims 10 to 12, wherein all, or at least said second portion, of the H2-enriched off gas, is combined with a WGS product of the syngas conditioning stage.

14. The process of any one of claims 10 to 13, wherein, in addition to said FT-cnrichcd off gas, the hydrogen recovery operation further provides an FT-dc Ictcd tail gas.

15. The process of claim 14, further comprising recycling at least a portion of the H2-depleted tail gas to the biomethanol synthesis operation.

16. The process of any one of claims 9 to 15, wherein the one or more intervening operations includes a tar removal operation to remove at least a portion of gasifier effluent tar and provide a tar-depleted gasifier effluent.

17. The process of claim 16, further comprising: separating, in a biomethanol separation stage, the raw biomethanol product to provide at least a purified biomethanol product and a fusel oil byproduct; and feeding at least a portion of the fusel oil byproduct as a fuel for the tar removal operation.

18. A process for gasification of a carbonaceous feed, the process comprising: in a gasifier, contacting the carbonaceous feed with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, water- soluble contaminants, and gasifier effluent tar; subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the gasifier effluent tar and provide a tar-depleted gasifier effluent; feeding at least a portion of the tar-depleted gasifier effluent, optionally following one or more intervening operations, to a scrubbing operation to remove at least a portion of the water-soluble contaminants, and provide a scrubbed gasifier effluent; and feeding at least a portion of the scrubbed gasifier effluent to a syngas conditioning stage to provide a conditioned syngas product, wherein one or more C2+alcohols are fed as a fuel for the tar removal operation.

19. The process of claim 18, wherein the one or more C2+alcohols are present in a fusel oil byproduct of a biomethanol synthesis operation.

20. The process of claim 19, wherein at least a portion of the conditioned syngas product is fed to the biomethanol synthesis operation.

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