Heat recovery and integration with feed drying in gasification processes

Abstract

Gasification processes are disclosed, which can implement one or more strategies for valuable integration of process heat, such as that available in the gasifier effluent at various stages of refinement, by its transfer into a heated dryer feed for the energy-intensive function of feed drying. The utilization of low-grade heat in particular, by its recycle for drying of the carbonaceous feed that is converted to syngas, can result in both process efficiency and syngas product quality advantages. Higher temperatures, associated with gas streams to be maintained above their dew points under elevated pressure, allow for a favorable temperature approach between a given gasifier effluent, from which process heat is transferred, and heat-containing fluid(s), into which this heat has been transferred and which provide all or a portion of a heated dryer feed.

Description

HEAT RECOVERY AND INTEGRATION WITH FEED DRYING IN GASIFICATION PROCESSESCROSS REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of priority to U.S. Provisional Application No. 63 / 632,620, filed April 11, 2024, which is hereby incorporated by reference in its entirety.FIELD OF THE INVENTION

[0002] Aspects of the invention relate to processes for the gasification of a carbonaceous feed, and more particularly such processes in which process heat contained in a gasifier effluent that is fed to various downstream operations, is transferred and utilized for drying the carbonaceous feed.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 and / or separation of the synthesis gas to value-added products often requires conditioning to improve its suitability for these subsequent operations. For example, further purification to remove CO2 and other acid gas contaminants that include H2S and COS may be necessary.

[0004] Undesired tar components in the gasifier effluent, such as fused ring molecules (e.g., naphthalene and pyrene), pose significant challenges in terms of the tendency of such high boiling-temperature species to condense from the vapor phase onto lower-temperaturesurfaces 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 (2372°F), well exceeding those of the gasifier and sufficient to cause melting and / or slagging of ash that is also present in the 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 for acid gas removal, absorptive techniques such as those utilizing a physical or chemical solvent, or otherwise separations based on solid adsorbents (e.g., molecular sieves) or membranes, are typically implemented. In conjunction with a refined or conditioned syngas product, the removed acid gases are often provided in separate streams from distinct separation stages performed under differing operating pressures. Overall, the economics of biomass gasification, including both operating and equipment costs, are significantly impacted by a number of complex and interacting objectives encountered in addressing the significant heat removal and syngas purification demands of the technology. Therefore, the effective integration of available heat and material streams that are needed for various functions, remains critical for achieving an economical pathway toward the desired end products of gasification. The present state of the art would benefit from improvements in gasification technology, resulting from such integration.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 of process heat, such as that available in the gasifier effluent at various stages of refinement, by its transfer into a heated dryer feed for the energy-intensive function of feed drying. For example, the utilization of low-grade heat, or possibly even waste heat, by its recycle for drying of the carbonaceous feed that is converted to syngas, can result in both process efficiency and syngas product quality advantages. Embodiments of the invention are therefore directed to gasification processes and systems that remove heat from their component, unit operations, or from upstream of these unit operations, and transfer or recycle this heat to aid in removing moisture from the carbonaceous feed. Both the yield ofthe gasification reactions (e.g., yield of CO and / or H2) and overall energy efficiency may be increased.

[0007] Advantageously, the recycle of low-grade heat and / or waste heat may be integrated with other recycle systems of the gasification process, such as those associated with any operation downstream of the gasifier, including those operations generally requiring heat rejection. Representative operations performed on the gasifier effluent include, for example, heat exchange following tar removal (e.g., to provide a tar-depleted gasifier effluent following treatment via hot oxygen burner technology), quenching, radiant or convective cooling, as well as filtration, scrubbing, compression, and water-gas shift (WGS). Any of these operations, or combinations of these operations, may be used to “condition” the gasifier effluent (i.e., to provide a conditioned syngas product), rendering it suitable in terms of properties (e.g., temperature, pressure) and composition (e.g., acid gas and sulfur content) for a given, subsequent syngas conversion operation (e.g., Fischer-Tropsch synthesis or methanol synthesis) or syngas separation operation (e.g., to produce renewable hydrogen). According to preferred embodiments, a gasifier effluent, from which process heat may be transferred and utilized, may have an elevated pressure corresponding to an elevated dew point, and in particular a dew point that is above the normal boiling point of water. The higher temperatures, associated with gas streams to be maintained above their dew points under elevated pressure, allow for a favorable temperature approach between a given gasifier effluent, from which process heat is transferred, and heat-containing fluid(s) exiting operations, into which this heat has been transferred and which may provide all or a portion of a heated dryer feed. That is, elevated dew points can advantageously result in hotter streams for drying biomass or other carbonaceous feeds used for gasification.

[0008] Gasifier effluents having elevated dew points can therefore serve as sources for the transfer of latent heat energy, for drying of carbonaceous feed, that results from condensation at these elevated temperatures. Streams having dew points of at least about 180°C (356°F) may be representative of low-grade heat sources. Importantly, however, condensing or latent heat may likewise be used in the case of gasifier effluents having lower dew points, for example of at least about 125°C (257°F) or at least about 150°C (302°F), which may be representative of waste-heat sources. In fact, according to other particular embodiments, prevalent sources of condensing heat may include gasifier effluents having a dew point of less than about 150°C (302°F). Advantages associated with the use of such gasifier effluents for feed drying reside in the fact that, at temperatures below this value, the ability to generate any level ofsteam, such as typical low-pressure steam at 3-8 barg (140°C-165°C), becomes less practical. Importantly, in the case of heat transfer, and particularly condensing or latent heat transfer, from a gasifier effluent having a dew point of less than about 150°C (302°F), its utilization for feed drying can at least partly fulfill this necessary process requirement, rather than simply being disposed as waste heat, for example removed with an air (e.g., fan) cooler.

[0009] Aspects of the invention therefore relate to gasification processes that may benefit from the integration of a number of features, as well as advantages that may be realized from this integration. These advantages may include one or more of: (a) increased efficiency of the fuel conversion (gasification) process by removing moisture from the carbonaceous feed prior to entering the gasifier; (b) collection of reject heat that might otherwise be unusable, and possibly combining this heat from multiple operations downstream of the gasifier, for use with feedstock drying technologies; (c) improved temperature control of a scrubbing operation, a water-gas shift operation, or both of these in combination and possibly operating with parallel inputs of loop heat exchange fluid; and (d) elimination of potential point source emissions, by overcoming or ameliorating the requirements for combustion as a source of heat. Other important benefits reside in reducing the amount of resources such as natural gas, wood, or produced syngas deployed for the low-value purpose of combustion. Likewise, high-grade heat, such as high- pressure steam generated in tar removal, direct quenching, and / or radiant / convective cooling, may be diverted to applications more specifically tailored to the utilization of such heat, allowing for drying of the carbonaceous feed to utilize a proportionally greater amount of, or possibly all, low-grade heat, thereby more appropriately “matching” the energy balancing requirements of the process with the available sources of heat.

[0010] Particular aspects are associated with the recognition that a significant quantity of low-grade waste heat, for example equating to approximately 15% of the energy contained in the carbonaceous feedstock (e.g., biomass), must be removed. Importantly, however, given that the gasifier and downstream processing equipment operate at elevated pressure, the dew point of gasifier effluents, including the raw gasifier effluent directly exiting the gasifier as well as downstream gasifier effluents being fed to downstream unit operations, is likewise elevated. For example, such effluents may have typical operating temperatures of 180°C (356°F) or greater to exceed their respective dew points. Heat transfer from these effluents is therefore particularly aligned with the objective of providing a heated dryer feed, such as water, at temperature of 90°C-100°C as needed for effective moisture removal from the carbonaceousfeed. Reliance on less closely-matched heat sources, such as combustion heat supplied from external fuel or high pressure (e.g., 10 bar) steam can result in inefficiencies, as such heat sources can generally be diverted to more valuable purposes, compared to those that might otherwise be adequately maintained with waste heat.

[0011] In addition to more effective heat utilization, further advantages may reside in improved management of process cooling requirements, such as by providing at least some cooling that would otherwise be sourced externally (e.g., from a cooling tower). For example, a scrubbing operation is normally employed and requires cooling of the gasifier effluent being fed to this operation, in order to remove excess water, as well as water-soluble contaminants such as HC1 and NH3. Downstream syngas conditioning likewise has cooling requirements, particularly in connection with compression and water-gas shift (WGS) operations that may be used in preparation for a subsequent acid gas (e.g., CO2) removal operation. Heat removal and integration strategies described herein are advantageous in terms of capturing low- grade heat from syngas conditioning operations and using this heat for feedstock drying. The rejection of waste heat to the environment is thereby mitigated, in favor of its more complete utilization in the process, with the overall result of process intensification and increased overall energy efficiency. Possible advantages are therefore associated with improved heat integration, reduced capital and operating costs, increased product yield due to beneficial feedstock drying characteristics, and / or prevention of combustion emissions. Importantly, sources of available heat are aligned with uses of this heat, according to heat integration approaches described herein. Particular processes benefit in this manner from the recovery of heat from a process stream at elevated temperature and pressure, and transferring this heat to a heat exchange fluid (e.g., circulating through one or more operations of the process), to obtain a heated dryer feed for drying biomass.

[0012] These and other embodiments, aspects, and advantages relating to the present invention are apparent from the following Detailed Description.BRIEF DESCRIPTION OF THE DRAWING

[0013] 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 figures, in which the same reference numbers are used to indicate the same or similar features.

[0014] FIG. 1 depicts a flowscheme illustrating an embodiment of a process for the gasification of a carbonaceous feed, which process employs a number of possible options for transferring process heat from a gasifier effluent, at various positions downstream of a gasifier, into a heat exchange fluid that provides all or part of a heated dryer feed.

[0015] FIG. 2 depicts a process utilizing a circulating heat exchange fluid, portions of which are fed to operations of a gasification process and removed from these operations as respective, operation heat-containing fluids that provide all or part of the heated dryer feed.

[0016] Whereas the figures illustrate 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 of various inventive embodiments described herein. For example, according to some embodiments, various intervening operations, between gasifier 50 and acid gas removal operation 95, as shown in FIG. 1, may be omitted. Likewise, for example, bypasses portions 600, 200a, 300a, of loop heat exchange fluid, loop heat-containing fluid, and heated dryer feed, as shown in FIG. 2, as well as bypass cooler 275 may be omitted in some embodiments. It should be understood that various specific features can be implemented independently of others.

[0017] In order to facilitate explanation and understanding, the figures provide overviews of components that may be implemented 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 practice of various inventive embodiments. Such details would be apparent to those skilled in the art, having knowledge of the present disclosure. Other processes for producing syngas, including a conditioned syngas and / or its conversion products, 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

[0018] 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 (z.e., pressure in excess ofatmospheric 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.

[0019] 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,” “second portion,” or “bypass 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. 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 gasifier effluent” should be understood to mean “feeding all or a portion of the gasifier effluent.” As in the case of “all or portion” being expressly stated, when “all or a portion” is the understood meaning, this phrase is should likewise be understood to encompasses certain and preferred embodiments as noted above.

[0020] 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 the bulk flow of the raw gasifier effluent exiting the gasifier and proceeding through various unit operations, for example according to the embodiment illustrated in FIG. 1. Insofar as the above-quoted phrases are used to designate order, in specific embodiments these phrases mean that one operation immediately precedes or followsanother operation, whereas more generally these phrases do not preclude the possibility of intervening operations.

[0021] Therefore, for example, one or more “operations downstream of the gasifier” can refer, according to a specific embodiment, to an operation that immediately follows the gasifier, such as in the case of a tar removal operation according to the embodiment illustrated in FIG. 1. 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), a filtration operation, a scrubber feed cooler, a scrubbing operation, compression, and / or a WGS operation, that follow the tar removal operation, as an intervening operation, according to the embodiment illustrated in FIG. 1. In the same manner, “an upstream operation,” for example relative to an “acid gas removal operation” can refer, according to a specific embodiment, to an operation that immediately precedes the acid gas removal operation, such as in the case of a WGS operation according to the embodiment illustrated in FIG. 1. However, this phrase more generally, and preferably, refers to any of, or any combination of, operations that precede the acid gas removal operation, such as in the case of any one or more of compression and the above-noted scrubbing operation and / or other operations that precede the WGS operation, as intervening operation(s), according to the embodiment illustrated in FIG. 1. Also, “an upstream operation” relative to “the acid gas removal operation” in this context more generally, and preferably, refers to any of, or any combination of, operations that include the gasifier and also follow the gasifier, but nonetheless precede the acid gas removal operation, whether or not intervening operations are present. Therefore, “an upstream operation” relative to “the acid gas removal operation” may include, for example, a gasifier, a tar removal operation, a quenching operation, a radiant syngas cooler (RSC) or convective syngas cooler (CSC), a filtration operation, a scrubber feed cooler, a scrubbing operation, compression, and / or a WGS operation, as noted above and according to the embodiment illustrated in FIG. 1. Accordingly, 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.

[0022] The terms “syngas,” or alternatively “synthesis gas,” insofar as they relate to streams comprising H2 and CO, are used herein to generally refer to the gasifier effluent, whether ornot having been subjected to one or more operations downstream of the gasifier and / or upstream of an acid gas removal operation (if used). Characteristics of the gasifier effluent, in terms of its composition, including its thiCO molar ratio, are described herein and are applicable to any “syngas,” or alternatively “synthesis gas,” as described herein. The term “conditioned syngas product” generally refers to the product of a syngas conditioning stage as described herein, which may include one or more operations performed on a scrubbed gasifier effluent. Characteristics of a conditioned syngas product, in terms of its composition, including its FhiCO molar ratio, are as described herein with respect to any “gasifier effluent,” “syngas,” or alternatively “synthesis gas.” In processes that include an acid gas removal operation (e.g., as an operation of a syngas conditioning stage), all or substantially all acid gases, which encompass CO2 as well as sulfur-containing gases such as H2S and COS, may be absent from the conditioned syngas product. For example, the conditioned syngas product may comprise less than about 5 mol-%, less than about 1 mol-%, or less than about 100 mol-ppm, of individual amounts of any one of CO2, H2S, and COS, or otherwise of a combined amount of at least two of CO2, H2S, and COS.

[0023] 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 / or upstream of an acid gas removal operation (if used). The term “gasifier effluent” therefore encompasses 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, as well as a lower temperature relative to other upstream gasifier effluents, resulting from further 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,” orotherwise all or part of a “scrubber feed,” (vi) the raw gasifier effluent having been subjected to removal of heat, i.e., a “scrubber feed” or a “further cooled gasifier effluent,” having a lower temperature relative to the raw gasifier effluent, resulting from heat removal (e.g., to generate steam), (vii) the raw gasifier effluent or un-scrubbed gasifier effluent having been subjected to a scrubbing operation, i.e., a “scrubbed gasifier effluent,” having a lower content of water-soluble contaminants (e.g., chlorides), relative to the raw gasifier effluent, (viii) the raw gasifier effluent or scrubbed gasifier effluent having been subjected to compression (e.g., utilizing a compressor), i.e., a “compressed gasifier effluent” or “compressed, scrubbed gasifier effluent,” having an increased pressure relative to the scrubbed gasifier effluent, (ix) the raw gasifier effluent or scrubbed gasifier effluent having been subjected to a water-gas shift (WGS) operation, i.e., a “WGS product,” having an tkiCO molar ratio that is increased relative to that of raw gasifier effluent or scrubbed gasifier effluent, and (x), the raw gasifier effluent having been subjected to any other operation downstream of the gasifier and / or upstream of the acid gas removal operation (if used), whether or not specifically described herein.

[0024] A “conditioned syngas product,” may refer to a product of an acid gas removal operation, having an increased concentration of syngas and / or its components (e.g., H2 and / or CO) relative to that of a feed to that operation, such as a gasifier effluent as described herein (e.g., a WGS product of a WGS operation). A “conditioned syngas product” may, more generally, refer to a product of an overall syngas conditioning stage that may include any one or more of (a) compression, (b) a water-gas shift (WGS) operation, and (c) acid gas removal, preferably in this order but possibly in any other order, such that the “conditioned syngas product” of this stage may be rendered suitable, or more suitable, for a downstream syngas conversion operation or syngas separation operation. In particular, a conditioning stage may include various operations that provide the conditioned syngas product with characteristics that are more favorable for a given downstream conversion or separation, such as a higher pressure, an increased thiCO molar ratio (e.g., increased H2 concentration and / or decreased CO concentration), and / or a lower acid gas (e.g., lower CO2) concentration.

[0025] Regardless of any specific operations used in an overall syngas conditioning stage, representative processes may further comprise feeding all or a portion of the conditioned syngas product to a downstream 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 syngasseparation product. 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 renewable hydrogen).

[0026] 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). 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 a particular 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).

[0027] In some embodiments, any syngas conversion operation or syngas separation operation may be performed on a WGS product, obtained from a WGS operation as part of a syngas conditioning stage, as described above, with such WGS operation providing an increased, and more favorable, FhiCO molar ratio, in terms of efficiently performing the desired conversion or separation. In some embodiments, any syngas conversion operation or syngas separation operation may be performed on a CO2-depleted product of an acid gas removal operation, obtained as part of a syngas conditioning stage, as described above, with such acid gas removal operation providing a decreased, and more favorable, concentration of CO2 and / or sulfur-containing gases. In some embodiments, any syngas conversion operation or syngas separation operation may be performed on a conditioned syngas product obtained from a combination of a WGS operation and an acid gas removal operation, with such combination of operations providing more favorable characteristics of the conditioned syngas product, interms of both an increased Fh:CO molar ratio and a decreased concentration of CO2 and / or sulfur-containing gases.

[0028] Particular embodiments of the invention are directed to processes for gasification of a carbonaceous feed. Representative processes comprise: (a) 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 CO2. The carbonaceous feed is preferably a dried carbonaceous feed, obtained from drying (moisture removal) in a feed dryer. For example, such dried carbonaceous feed may have a moisture content of less than about 5 wt- %, less than about 3 wt-%, or even less than about 1 wt-%. The processes may further comprise: (b) feeding the gasifier effluent (e.g., successively or consecutively) to one or more operations downstream of the gasifier. Each operation is used to change a characteristic (e.g., temperature, pressure, and / or composition) of the gasifier effluent exiting the operation, with respect to the gasifier effluent being fed to that operation, and also with respect to the raw gasifier effluent immediately exiting the gasifier. The downstream operation(s), which are preferably multiple operations performed successively or consecutively, may be used to provide a conditioned syngas product. The processes may further comprise: (c) transferring process heat from the gasifier effluent, being fed to the one or more operations, into a heated dryer feed. The process heat being transferred is at least a portion of the heat that is available in the gasifier effluent, either upstream of a given operation or within that operation. The process heat may therefore more specifically refer to “operation heat” that is associated with a given operation. For example, the process heat may include (i) “cooling / filtration operation heat” that is associated with a filtration operation and that is present in a gasifier effluent, such as a cooled gasifier effluent, being fed to this operation or being processed in this operation. Optionally or in combination, the process heat may include (ii) “scrubbing operation heat” that is associated with a scrubbing operation and that is present in a gasifier effluent, such as a filtered gasifier effluent (or heated scrubber feed), being fed to this operation or being processed in this operation. This “scrubbing operation heat” encompasses heat present in such filtered gasifier effluent (or heated scrubber feed), which is fed more specifically to a scrubber feed cooler, upstream of the scrubbing operation, as well as heat present in a scrubber feed (or further cooled gasifier effluent), which is fed more specifically directly to the scrubbing operation. The process heat that is transferred in step (c) may be partly or completely latent heat that is released from condensation (formation of condensate from water vapor originally present) in the gasifier effluent.

[0029] Optionally or in combination, the process heat may include (iii) “compression heat” that is associated with compression (e.g., utilizing a compressor) and that is present in a gasifier effluent, such as a scrubbed gasifier effluent, being fed to this operation or being processed in this operation. Optionally or in combination, the process heat may include (iv) “WGS operation heat” that is associated with a WGS operation and that is present in a gasifier effluent, such as a compressed, scrubbed gasifier effluent, being fed to this operation or being processed in this operation. Optionally or in combination, the process heat may include (v) “acid gas removal operation heat” that is associated with an acid gas removal operation and that is present in a gasifier effluent, such as a WGS product, being fed to this operation or being processed in this operation. Optionally or in combination, the process heat may include any one or more of “tar removal operation heat,” “quenching operation heat,” and / or “RSC or CSC heat” that is / are associated with a respective tar removal operation, quenching operation, and / or RSC or CSC and that is / are present in a respective gasifier effluent, such as a raw gasifier effluent, tar-depleted gasifier effluent, and / or quenched gasifier effluent, being fed to such respective operation or being processed in such respective operation.

[0030] In preferred embodiments, process heat being transferred includes one or more of (i), (ii), (iii), (iv), and / or (v), or, more generally, process heat recovered downstream of initial cooling of the gasifier effluent by direct quenching, radiant heat exchange, and / or convective heat exchange. For example, the process heat may include (ii) and / or (iv), in view of cooling needs to achieve an efficient scrubbing operation, as well as an efficient acid gas removal operation that is often downstream of a WGS operation. Preferably, the process heat includes heat transferred or recovered from a gasifier effluent having a temperature, or maximum temperature, of less than about 500°C (932°F), less than about 400°C (752°F), less than about 300°C (572°F), or less than about 200°C (392°F). Preferably, this temperature, as a minimum temperature, is greater than about 100°C (212°F), or greater than about 150°C (302°F). Preferably, the process heat consists of exclusively one or more of (i), (ii), (iii), (iv), and / or (v) and / or, more generally, preferably excludes heat transferred or recovered from a gasifier effluent having a temperature of greater than about 300°C (572°F), greater than about 400°C (752°F), or greater than about 500°C (932°F), which process heat is more characteristic of higher-grade heat, as opposed to low-grade heat that may be more efficiently utilized in drying the carbonaceous feed (e.g., biomass). For example, a gasifier effluent from which process heat is transferred (e.g., and which is fed to an operation downstream of the gasifier), may have a temperature as described above, such as from about 150°C (302°F)to about 400°C (752°F), from about 150°C (302°F) to about 300°C (572°F), or within other ranges based on the preferred minimum / maximum temperatures as described above. In other embodiments, a gasifier effluent from which process heat is transferred, and which is fed to an operation downstream of the gasifier, may advantageously have a dew point according to a temperature as described above, such as from about 150°C (302°F) to about 400°C (752°F), from about 150°C (302°F) to about 300°C (572°F) or within other ranges based on the preferred minimum / maximum temperatures as described above.

[0031] In view of these dew points, which are characteristic of the gasifier effluent under elevated pressure, the transfer of process heat facilitates attaining a favorable temperature of the heated dryer feed, for example in the range from about 100°C (212°F) to about 200°C (392°F), or from about 100°C (212°F) to about 150°C (302°F). The attainment of such temperatures may be based on a reasonable heat-exchange approach temperature with a gasifier effluent from which process heat is transferred, and which has a temperature above its dew point. For example, according to an exemplary embodiment, the gasifier effluent being fed to the one or more operations may have a dew point of at least about 150°C (302°F), or possibly at least about 180°C (356°F). A representative temperature of such gasifier effluent, being above the dew point, may be at least about 200°C (392°F). In this case, even a sub-optimal approach upon heat transfer can nonetheless result in a favorable temperature of the heated dryer feed, such as within a range as described above. Gasifier effluent temperatures and dew point temperatures may therefore be characteristic of low- grade heat. In other embodiments, as described above, such temperatures and dew point temperatures may otherwise be characteristic of waste heat. For example, the gasifier effluent being fed to the one or more operations may have a dew point of less than about 150°C (302°F), or possibly less than about 125°C (257°F). Preferably, the gasifier effluent from which heat is transferred, regardless of its temperature or dew point temperature, has an elevated pressure, referring to a pressure that exceeds atmospheric pressure. Representative pressures are at least about 1 barg (e.g., from about 1 barg to about 25 barg), at least about 5 barg (e.g., from about 5 barg to about 25 barg), or at least about 10 barg (e.g., from about 10 barg to about 25 barg). The gasifier effluent may have any pressure as described herein, with respect to pressures utilized in particular operations.

[0032] In addition to steps (a), (b), and (c) as described above, representative processes may further comprise (d) utilizing at least a portion of the process heat, having been transferred into the heated dryer feed, for drying the carbonaceous feed (e.g., biomass). Preferably, step (d) isperformed on the carbonaceous feed that is input, following drying, to the gasifier and contacted, in step (a), with the oxygen-containing gasifier feed. This step (d) may therefore be considered to occur, at least to some extent, upstream of step (a), insofar as step (d) represents a valuable pretreatment of the carbonaceous feed for moisture removal. The transfer of heat from (1) the gasifier effluent into the heated dryer feed, according to step (c), and / or (2) the heated dryer feed to the carbonaceous feed, according to step (d), may utilize heat transfer between one medium and another, without an intermediary fluid. That is, the transfer of heat (1) and / or (2) may occur through heat-exchanging contact (e.g., in a suitable heat exchanger) between a gasifier effluent and the heated dryer feed and / or between the heated dryer feed and the carbonaceous feed. For example, with respect to transfer (1) above, process heat may be transferred from a filtered gasifier effluent into a scrubber heat exchange fluid, resulting in a scrubber heat-containing fluid, at least a portion of which is contained in the heated dryer feed. In other embodiments, the transfer of heat (1) and / or (2) may utilize an intermediary heat transfer, such as in the case of (1) and / or (2) occurring through heatexchanging contact with one or more intermediary heat exchange fluids. For example, with respect to transfer (1), process heat may be transferred from a tar-depleted gasifier effluent or a quenched gasifier effluent into an RSC- or CSC-generated steam, as an intermediary heat exchange fluid, and heat from this steam may then be transferred into an RSC or CSC heatcontaining fluid, at least a portion of which is contained in the heated dryer feed.

[0033] Other particular embodiments of the invention are directed to processes for drying a carbonaceous feed (e.g., biomass), or otherwise processes for integrating this drying with gasification of the carbonaceous feed. According to representative processes: (a) in a gasifier, the carbonaceous feed is contacted with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising Fh, CO, and CO2, and (b) the gasifier effluent is fed (e.g., successively or consecutively) to two or more operations, each of which is used to change a characteristic (e.g., temperature, pressure, and / or composition) of the gasifier effluent exiting each respective operation, relative to the gasifier effluent being fed to that operation, and also with respect to the raw gasifier effluent immediately exiting the gasifier. The two or more operations are used to provide a conditioned syngas product. Advantageously, these processes may comprise: feeding (e.g., in parallel) respective portions of loop heat exchange fluid, from a common heat exchange fluid circulation loop, to the two or more operations to transfer process heat into respective operation heat-containing fluids. These operation heat-containing fluids exit the respectiveoperations (e.g., in parallel) at higher temperatures, relative to the respective portions of loop heat exchange fluid being fed to these operations. The operation heat-containing fluids may have temperatures, for example, as described above with respect to the heated dryer feed, such as from about 100°C (212°F) to about 200°C (392°F), or from about 100°C (212°F) to about 150°C (302°F). Representative processes may further comprise: combining at least portions of the respective operation heat-containing fluids to provide a combined loop heatcontaining fluid, and utilizing at least a portion of the process heat, present in the combined loop heat-containing fluid, for drying the carbonaceous feed (e.g., in a feed dryer).Operations of Exemplary Processes

[0034] Exemplary gasification processes described herein are defined by various possible operations, occurring downstream of the gasifier and / or upstream of an acid gas removal operation (if used). These intervening operations 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 a boiler; and a scrubbing operation. As also described above, a syngas conditioning stage, for example downstream of the scrubbing operation, may utilize further operations such as compression, a WGS operation, and / or an acid gas removal operation. Representative processes may also include a syngas conversion operation or a syngas separation operation, downstream of the syngas conditioning stage and being fed by the conditioned syngas obtained from this stage. Certain possible features of the gasifier, these intervening operations, and downstream syngas conversion and syngas separation operations, as well as process streams and conditions associated with any of these operations, according to preferred embodiments and otherwise any embodiments described herein and / or illustrated in FIGS. 1 and 2, are provided as follows.Gasifier

[0035] 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. As described above, the carbonaceous feed is preferably a dried carbonaceous feed having undergone drying in a feed dryer to reduce its moisture content. According to advantageous embodiments described herein, heat utilized in the feed dryer is process heat, and preferably low-grade heat (e.g., obtained from a process stream at 200°C (392°F) or less, or 150°C (302°F) or less), that is transferred from a gasifier effluent into a heated dryer feed, provided to the feed dryer.

[0036] 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).

[0037] 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 generally comprise 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 thecarbonaceous 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).

[0038] 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 Fh 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.

[0039] 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-soluble contaminants, as undesired impurities, as described below. According to the embodiment illustrated in FIG. 1, the raw gasifier effluent 16 may be obtained directly from gasifier 50, prior to further operations as described herein.

[0040] 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 95mol-%), 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 or syngas separation operations), 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, (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 Fh 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). Relative to a feed to a WGS operation (e.g., the gasifier effluent, or any “syngas” or “synthesis gas product” that has not been subjected to a WGS reaction), a WGS product may have an FhiCO molar ratio that is increased by at least about 0.25, at least about 0.5, or at least about 1.0.

[0041] 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 (with the exception of an acid gas-depleted gasifier effluent, having been subjected to an acid gas removal operation), 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 gasifiereffluent, 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

[0042] 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, including syngas conversion operations and syngas separation operations, for upgrading synthesis gas to higher value products, which operations perform optimally (e.g., from the standpoint of stability) with pure feed gases.

[0043] 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.

[0044] 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)).

[0045] 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 hot oxygen burner (HOB) 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), causing the combustion products and excess oxygen to accelerate to sonic velocity through a nozzle, thereby forming a turbulent jet that enhances mixing between the tar / methane containing synthesis gas and the reactive hot oxygen stream. An HOB-based system can effectively improve synthesis gas yields.

[0046] 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 tar conversion may likewise include the introduction of supplemental oxygen and / or steam reactants, into a reactor used for this operation.

[0047] 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.

[0048] 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

[0049] Hot gasifier effluent, for example the tar-depleted gasifier effluent exiting the tar removal operation, may be cooled by various techniques that include heat exchange by direct quenching, as well as 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 (z.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 furthercooling (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 quench water (e.g., boiler feed water or demineralized water) or other aqueous quenching medium.Radiant Syngas Cooler (RSC) or Convective Syngas Cooler (CSC)

[0050] 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 for 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. Heat from this steam may be transferred, optionally in conjunction with other process heat (transferred from the gasifier effluent being fed to other operations, including downstream operations), to the heated dryer feed that is transferred, in turn, to the carbonaceous feed (e.g., biomass) for drying.Filtration Operation

[0051] 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 asdescribed 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 metals such 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.

[0052] 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).

[0053] The filtration operation may be followed by, or integrated with, a supplemental cleaning operation to further purify the gasifier effluent, by reducing 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

[0054] 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, inwhich 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, according to 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.”

[0055] 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 FIG. 1, 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). The cooled scrubber feed, directly downstream of scrubber feed cooler and being fed to the scrubbing operation, may have a temperature from about 50°C (122°F) to about 200°C (392°F), and preferably from about 75°C (167°F) to about 150°C (302°F).Scrubbing Operation

[0056] 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 scrubbermay 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).

[0057] 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 as fine 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.WGS Operation

[0058] The water gas shift (WGS) operation reacts CO present in a gasifier effluent (e.g., the scrubbed gasifier effluent exiting the scrubbing operation, or a compressed, scrubbed gasifier effluent exiting a compressor), 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 syngas purification (e.g., 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, or any downstream feed to the WGS operation, may have favorable properties for use in this operation, in terms of its being free or substantially free of water-soluble contaminants as described above, as well as tars and particulates. Compression (e.g., using a compressor) may be used to increase the pressure of the scrubbed gasifier effluent to a value that may be more favorable, in the resulting compressed, scrubbed gasifier effluent, for subsequent use in WGS operation. For example, the compressed, scrubbed gasifier effluent may have a pressure from about 5 barg to about 75 barg, or from about 10 barg to about 50 barg, which may also be representative of the pressure of WGS operation and the WGS product of this operation.

[0059] According to some embodiments, the scrubbed gasifier effluent, or any 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 tkiCO molar ratio and / or H2 concentration of the WGS product, compared to 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 of 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.

[0060] 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).

[0061] 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 a more 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 1may 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.

[0062] 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 thiCO molar ratio and increased H2 concentration, relative to the feed to the WGS operation or the synthesis gas obtained from upstream operations (e.g., scrubbed gasifier effluent (optionally following compression), filtered gasifier effluent, or cooled gasifier effluent). For example, the 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 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 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 scrubbing operation.Acid Gas Removal Operation

[0063] An acid gas removal operation may be used to separate an acid gas product from a gasifier effluent, for example the WGS product exiting the WGS operation, or, in the absence of a WGS operation, 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 separated acid gas product may be an H S-cnrichcd product (e.g., having a higher H2S concentration compared to that of the WGS product; 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 WGS product; scrubbed gasifier effluent; or compressed, scrubbed gasifier effluent). Any H S-cnrichcd 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).

[0064] The acid gas removal operation may therefore be used to reduce the concentration of H2S and / or CO2 in the WGS product; scrubbed gasifier effluent; or compressed, 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; compressed, scrubbed gasifier effluent; and / or WGS product, for use as a feed to the acid gas removal operation. The acid gas removal operation may beneficially increase the H2 concentration of CO2-depleted gasifier effluent, compared to that of the WGS product; scrubbed gasifier effluent; or compressed, scrubbed gasifier effluent such that, the H2 concentration and / or H2:CO molar ratio of the resulting process stream, and in particular the 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. As can be appreciated from the above description, the CO2- depleted gasifier effluent may provide all or at least a portion of, or may be synonymous with, the conditioned syngas product.

[0065] 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 WGS product (e.g., as a sour WGS product) and / or initially present in the scrubbed gasifier effluent and / or compressed, scrubbed gasifier effluent. The physical or chemical solvent can promote the selective removal of H2S / COS, in addition to the removal of CO2 in these products. 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 ofacid gases, can release the acid gas product, as an FFS-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.Syngas Conversion or Separation Operations

[0066] 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. According to particular embodiments, the feed to a syngas conversion operation or syngas separation operation may be the conditioned syngas product, following the syngas conditioning stage.

[0067] 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 of FT 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.

[0068] 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.

[0069] 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) maybe used to react CO and / or CO2 with 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.

[0070] 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-%).

[0071] According to other embodiments, 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. 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 H2-enriched off gas and an H2-depleted tail gas, optionally having properties that are characteristic of a renewable hydrogen separation product and a tail gas (e.g., PSA tail gas) as described above. These H -cnrichcd and H2-depleted gas streams may optionally be further utilized in the process, where suitable.Further exemplary embodiments of gasification processes

[0072] FIG. 1 depicts a flowscheme illustrating an embodiment of a process including operations as described above, and more particularly illustrating the transfer of process heat, for example available in these operations or gasifier effluents being fed to these operations, into a heateddryer feed used to dry biomass or other carbonaceous feed prior to its input to the gasifier. Representative processes may comprise any of the operations illustrated in FIG. 1, or any subsets of these operations, in any order but preferably in the order shown.

[0073] With reference to FIG. 1, 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 is preferably dried carbonaceous feed 10a having been subjected to drying (moisture removal) in feed dryer 1000, with oxygen-containing gasifier feed 14 (and optionally a separate source of steam). This contacting is performed under gasification conditions to provide a gasifier effluent, namely raw gasifier effluent 16, comprising H2, CO, and CO2. 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-%. A gasifier effluent can include syngas-containing effluents downstream of gasifier 50, for example including raw gasifier effluent 16, tar-depleted gasifier effluent 18, quenched gasifier effluent 22, cooled gasifier effluent 24, filtered gasifier effluent 26, scrubber feed 28, scrubbed gasifier effluent 30, compressed / scrubbed gasifier effluent 32, WGS product 34, or conditioned syngas product 36.

[0074] Generally, processes may comprise providing conditioned syngas product 36 following any of a number of intervening operations, or combinations of operations, with conditions and performance parameters of these operations as described in more detail above. Such intervening operations can include one or more of (i) tar removal operation 55 to remove at least a portion of gasifier effluent tar, (ii) quenching operation 60 comprising direct contact of the gasifier effluent with quench water 20, (iii) radiant syngas cooler (RSC) 65 or convective syngas cooler (CSC) 65, implementing heat-exchanging contact of the gasifier effluent with RSC feed water 25 or CSC feed water 25 (e.g., boiler feed water), as the case may be, which can then provide CSC-generated steam 23 or RSC-generated steam 23, (iv) filtration operation 70 to remove solid particles from the gasifier effluent, (v) scrubber feed cooler 75 to further remove heat from (for further cooling of) the gasifier effluent (e.g., and thereby control the temperature of the downstream scrubbing operation), and (vi) scrubbing operation 80 to remove water-soluble contaminants from the gasifier effluent.

[0075] 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 of utilizing scrubber feed cooler 75, a gasifier effluent may be fed, for example as filtered gasifier effluent / heated scrubber feed 26, to scrubber feed cooler 75, and also a gasifier effluent may be fed, for example as scrubber feed / further cooled gasifier effluent 28, to scrubbing operation 80. In some embodiments, scrubber feed cooler 75 may provide scrubber heat-containing fluid 801, into which process heat from filtered gasifier effluent / heated scrubber feed 26 is transferred. It can therefore be appreciated that the heated scrubber feed 26 and scrubber feed 28 may correspond to, or may comprise, gasifier effluents, having respective, higher and lower temperatures but typically having the same composition. The scrubber feed 28 to scrubbing operation 80 may therefore be a filtered and cooled gasifier effluent, having been subjected to filtration operation 70 to remove solid particles and also to scrubber feed cooler 75.

[0076] In addition to feeding a gasifier effluent to any of these operations, representative processes may alternatively, or in addition, comprise feeding at least a portion of a gasifier effluent, namely scrubbed gasifier effluent 30, to syngas conditioning stage 100 that may include one or more other operations performed on scrubbed gasifier effluent 30, with these including any one or more of compression (e.g., using compressor 85), WGS operation 90, and acid gas removal operation 95. In the case of two or more of such syngas conditioning operations, these may be performed in any order, but preferably in the order shown.

[0077] As further illustrated in FIG. 1, process heat associated with various operations, or present in the gasifier effluent being fed to these operations, may be transferred into heated dryer feed 300. For example, (A) cooling / filtration operation heat 70a associated with filtration operation 70 may be transferred from cooled gasifier effluent 24 into cooling / filtration heatcontaining fluid 701, which may provide all or a portion of heated dryer feed 300; (B) scrubbing operation heat 80a associated with scrubbing operation 80 may be transferred from filtered gasifier effluent / heated scrubber feed 26 into scrubber heat-containing fluid 801, which may provide all or a portion of heated dryer feed 300; (C) compression operation heat 85a associated with compressor 85 may be transferred from scrubbed gasifier effluent 30 into compression heat-containing fluid 851, which may provide all or a portion of heated dryer feed 300; (D) WGS operation heat 90a associated with WGS operation 90 may be transferred from compressed, scrubbed gasifier effluent 32 into WGS heat-containing fluid 901, which may provide all or a portion of heated dryer feed 300. In an analogous manner, heat fromother operations, including, but not limited to, those illustrated in FIG. 1, may likewise be transferred into respective operation heat-containing fluids and provide all or a portion of a heated dryer feed.

[0078] As further illustrated in FIG. 1, heat transfer into a given operation heat-containing fluid (z.e., with such fluid being heated as a result of this transfer) may be performed by establishing heat-exchanging contact between a gasifier effluent being fed to a given operation and an operation heat exchange fluid. For example, cooling / filtration heat exchange fluid 700 (e.g., fed to a heat exchanger associated with, or upstream of, filtration operation 70) may be heat- exchanged against cooled gasifier effluent 24, resulting in cooling / filtration heat-containing fluid 701 having a higher temperature relative to cooling / filtration heat exchange fluid 700, and also resulting in filtered gasifier effluent / heated scrubber feed 26 having a lower temperature relative to cooled gasifier effluent 24. Likewise, scrubber heat exchange fluid 800 (e.g., fed to a heat exchanger, such as scrubber feed cooler 75, associated with, or upstream of, scrubbing operation 80) may be heat-exchanged against filtered gasifier effluent / heated scrubber feed 26, resulting in cooling / filtration heat-containing fluid 801 having a higher temperature relative to scrubber heat exchange fluid 800, and also resulting in scrubber feed / further cooled gasifier effluent 28 and / or scrubbed gasifier effluent 30 having a lower temperature relative to filtered gasifier effluent / heated scrubber feed 26. In addition, compression heat exchange fluid 850 (e.g., fed to a heat exchanger associated with, or upstream of, compressor 85) may be heat-exchanged against scrubbed gasifier effluent 30, resulting in compression heat-containing fluid 851 having a higher temperature relative to compression heat exchange fluid 850, and also resulting in compressed, scrubbed gasifier effluent 32 having a lower temperature relative to scrubbed gasifier effluent 30. Moreover, WGS heat exchange fluid 900 (e.g., fed to a heat exchanger associated with, or upstream of, WGS operation 90) may be heat-exchanged against compressed, scrubbed gasifier effluent 32, resulting in WGS heat-containing fluid 901 having a higher temperature relative to WGS heat exchange fluid 900, and also resulting in WGS product 34 having a lower temperature relative to compressed, scrubbed gasifier effluent 32.

[0079] In an analogous manner, operation heat exchange fluids may be heated-exchanged against gasifier effluents being fed to other operations, including, but not limited to, those illustrated in FIG. 1, resulting in corresponding operation heat-containing fluids having higher temperatures relative to their respective operation heat exchange fluids and also resulting in gasifier effluents withdrawn from such other operations having lower temperatures relative tothe respective gasifier effluents being fed to such other operations. As described above, any of the resulting, operation heat-containing fluids, or combinations of such fluids, may provide all or a portion of heated dryer feed 300. That is, heated dryer feed 300 may contain one or more operation heat-containing fluids, or at least portions of one or more of these fluids, and consequently process heat that has been transferred into these fluids, or fluid portions. As is also evident from this description, operation heat-containing fluids may have higher temperatures relative to their respective operation heat exchange fluids used for transferring heat from, by virtue of being in thermal or heat-exchanging contact with, respective gasifier effluents being fed to the operations. Additionally, operation heat exchange fluids have lower temperatures relative to these respective gasifier effluents. Moreover, the thermal or heat-exchanging contact may be established using a suitable heat exchanger associated with (e.g., immediately upstream or immediately downstream of) a given operation, and / or the operation itself may establish the thermal or heat-exchanging contact (e.g., in the case of scrubber feed cooler 75 being considered part of scrubbing operation 80). As noted above, according to some embodiments, two or more heat transfers performed by establishing heatexchanging contact (e.g., through an intermediary fluid) may be utilized to achieve the transfer of process heat to the heated dryer feed.

[0080] In some embodiments, a gasifier effluent, from which heat is transferred into the heated dryer feed, is more particularly a gasifier effluent fed to one or more of tar removal operation 55 (e.g., as raw gasifier effluent 16), quenching operation 60 (e.g., as tar-depleted gasifier effluent 18), RSC or CSC 65 (e.g., as quenched gasifier effluent 22), filtration operation 70 (e.g., as cooled gasifier effluent 24), scrubbing operation 80 (e.g., as filtered gasifier effluent / heated scrubber feed 26), a compression operation (e.g., compressor 85, as scrubbed gasifier effluent 30), water-gas shift (WGS) operation 90 (e.g., as compressed, scrubbed gasifier effluent 32), and / or an acid gas removal operation 95 (e.g., as WGS product 34). Such gasifier effluents and the associated operations to which they are fed, may provide sources of high- and / or low-grade heat. More preferably, gasifier effluents at lower temperatures and downstream of initial cooling operations (e.g., utilizing direct quenching, convective heat exchange, and / or radiant heat exchange) may represent favorable candidate streams, in terms of utilization of their lower-grade heat content for drying biomass or other carbonaceous feeds. For example, syngas streams associated with operations such as tar removal, or cooling that occurs prior to filtration, may have temperatures sufficient for higher-values use such as in the generation of medium or high pressure steam. Therefore, inpreferred embodiments, the one or more operations to which a gasifier effluent, which suitably provides heat for the heated dry feed, is fed, may include or possibly consist of (be limited to) one or more of filtration operation 70, scrubbing operation 80, a compression operation (e.g., compressor 85), and / or WGS operation 90. According to more particular embodiments, the one or more operations may include or possibly consist of (be limited to) both scrubbing operation 80 and WGS operation 90, for example operating with portions of operation heat exchange fluid being fed to these operations in parallel.

[0081] In any event, in the case of the one or more operations including scrubbing operation 80, representative gasification processes may, more specifically, comprise transferring scrubbing operation heat (as the process heat) using scrubber feed cooler 75, into heated dryer feed 300. In such embodiments, as described above, scrubber feed cooler 75 may provide scrubber feed / further cooled gasifier effluent 28 to scrubbing operation 80. Also, the gasifier effluent being fed to scrubbing operation and from which process heat is transferred via scrubber feed cooler 75, may be filtered gasifier effluent / heated scrubber feed 26. Accordingly, representative processes may comprise transferring scrubbing operation heat (as the process heat), by heat-exchanging contact established in scrubber feed cooler 75, of filtered gasifier effluent 26 against scrubber heat exchange fluid 800. In this case, scrubbing operation heat (as the process heat) may be more specifically transferred into a scrubber heat-containing fluid 801 (as an operation heat-containing fluid), at least a portion of which is contained in heated dryer feed 300.

[0082] According to any embodiments described herein, the heated dryer feed, as well as any operation heat exchange fluids (e.g., scrubber heat exchange fluid 800), and furthermore any operation heat-containing fluids (e.g., scrubber heat-containing fluid 801) into which process heat may be transferred and which may be used to provide all or a portion of heated dryer feed 300, may comprise water. For example, the heated dryer feed and any of these fluids may comprise substantially all water, or consist of water.

[0083] As is illustrated in FIG. 2, two or more operation heat exchange fluids may be provided from a common heat exchange fluid circulation loop, for example as portions of the same heat exchange fluid circulating in this loop. The fluid circulation loop may be formed, for example, from loop heat exchange fluid 400, in conjunction with operation heat exchange fluids and their respective operation heat-containing fluids (e.g., scrubber heat exchange fluid 800 and respective scrubber heat-containing fluid 801 and / or WGS heat exchange fluid 900 and respective WGS heat-containing fluid 901), as well as combined loop heat-exchangingfluid 200, heated dryer feed 300, and cooled dryer effluent 301. Circulation may be established using loop circulation pump 250. In particular some embodiments, respective gasifier effluents, which are fed to two or more respective operations, may provide process heat for transfer into the heated dry feed. The transfers may be performed by establishing heat-exchanging contact of the respective gasifier effluents being fed to the respective operations, against respective portions of operation heat exchange fluid. Advantageously, these respective portions may be provided from a common heat exchange fluid circulation loop. That is, the operation heat exchange fluid to two or more operations may be provided as portions of the heat exchange fluid circulating in the fluid circulation loop. With respect to process heat being transferred from the two or more operations (or from gasifier effluents being fed to these operations) into respective operation heat-containing fluids, at least portions, and preferably all, of these resulting operation heat-containing fluids are contained in heated dryer feed 300. For example, these operation heat-containing fluids may be combined to provide heated dryer feed 300.

[0084] As illustrated in FIG. 1, therefore, two or more operations, such as scrubbing operation 80 and WGS operation 90, may be configured successively or consecutively (z.e., in an upstream / downstream relationship, but not necessarily adjacent) with respect to the flow of gasifier effluent through these operations, as in the case of upstream, filtered gasifier effluent / heated scrubber feed 26 being fed to scrubbing operation 80 and downstream, compressed, scrubbed gasifier effluent 32 being fed to WGS operation 90. As illustrated in FIG. 2, these two or more operations may be configured in parallel with respect to the flow of operation heat exchange fluid through these operations, as in the case of parallel flows of scrubber heat exchange fluid 800 to scrubbing operation 80 and WGS heat exchange fluid 900 to WGS operation 90. Also configured in parallel, as another portion of loop heat exchange fluid 400, is bypass heat exchange fluid 600, which does not exchange heat with any operation (or gasifier effluent being fed to any operation). In this regard, a portion of loop heat exchange fluid may be bypassed around any operation, or combination of operations, for improved temperature control of heated dryer feed 300. For example, bypass heat exchange fluid 600 may or may not be used, according to particular embodiments, in conjunction with parallel flows of operation heat exchange fluid, as illustrated in FIG. 2, to both scrubbing operation 80 and WGS operation 90. According to this embodiment, respective portions of loop heat exchange fluid 400 to these operations are namely scrubber heat exchange fluid 800 and WGS heat exchange fluid 900, and respective operation heat-containing fluids are namely scrubber heat-containing fluid 801 and WGS heat-containing fluid 901.

[0085] As further illustrated in FIG. 2, at least a portion, and possibly all, of combined loop heatcontaining fluid 200 may be heated in dryer preheater 500, which may, for example, be positioned downstream of the combining of portions of the respective operation heatcontaining fluids that provide combined loop heat-containing fluid 200. The dryer preheater 500 may act as a “trim” heater for final temperature adjustment of the provided, heated dryer feed 300. Accordingly, dryer preheater 500 is positioned upstream of the utilization of process heat, present in heated dryer feed 300, for drying carbonaceous feed 10 in feed dryer 1000. Utilizing at least a portion of the process heat, present in heated dryer feed 300, for drying carbonaceous feed 10, may comprise establishing heat-exchanging contact between heated dryer feed 300 and carbonaceous feed 10, using feed dryer 1000 downstream of dryer preheater 500.

[0086] At least a portion, and possibly all, of heated dryer feed 300 may be fed to feed dryer 1000 for heat exchange against, as well as heating and drying of, carbonaceous feed 10 (e.g., biomass) to provide dried carbonaceous feed 10a (e.g., dried biomass). Dryer preheater 500 may utilize external heating fluid (e.g., steam), supplied as inlet external heating fluid 501 and withdrawn as outlet external heating fluid 502, to adjust (e.g., increase) the temperature of heated dryer feed 300, in order to maintain a desired setpoint, such as any particular value within a temperature range as described above for this feed, in view of variations in temperature of combined loop heat-containing fluid 200. Alternatively, or in combination, dryer feed 500 may be used to maintain the presence of sufficient heat, in heated dryer feed 300, for adequately drying the carbonaceous feed, in view of variations of its quantity (e.g., flow rate) and / or its composition (e.g., moisture content).

[0087] According to further control aspects associated with the operation of a heat exchange fluid circulation loop, at least a portion, such as combined fluid bypass portion 200a, of combined loop heat-containing fluid 200, may be bypassed around both dryer preheater 500 and feed dryer 1000. Also, at least a portion, such as heated feed bypass portion 300a, may be bypassed around feed dryer 1000. Bypass cooler 275, which may be an air cooler (employing fans) or other type of cooler, may be used to further regulate the temperature of streams being returned to the heat exchange fluid circulation loop, such as by combining with cooled dryer effluent 301, and consequently the temperature of loop heat exchange fluid.

[0088] Representative processes may further comprise feeding at least a portion of conditioned syngas product 36, obtained following WGS operation 90 and / or acid gas removal operation 95, to a syngas conversion operation or a syngas separation operation, thereby providing a respective renewable syngas conversion product or renewable syngas separation product. According to more specific embodiments, for example, (i) a syngas conversion operation may comprise a Fischer-Tropsch reaction stage, such that the renewable syngas conversion product comprises liquid hydrocarbons and / or oxygenates (e.g., alcohols) of varying carbon numbers, (ii) a syngas conversion operation may comprise a catalytic methanol synthesis reaction stage, such that the renewable syngas conversion product comprises methanol, or (iii) a syngas conversion operation may comprise a catalytic methanation reaction stage, such that renewable syngas conversion product comprises RNG. According to other more specific embodiments, a syngas separation operation may comprise a renewable hydrogen separation stage, such that renewable syngas separation product comprises purified hydrogen.

[0089] Overall, aspects of the invention relate to the implementation of strategies for valuable integration of process heat removal to satisfy cooling needs, with carbonaceous feed drying to improve conversion efficiency. These strategies include the effective utilization of low-grade heat that might otherwise be discarded as waste heat. Those skilled in the art, having knowledge of the present disclosure, will recognize that various changes can be made to these processes in attaining advantages described herein, as well as 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:(a) 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 CO2;(b) feeding the gasifier effluent to one or more operations to provide a conditioned syngas product;(c) transferring process heat, from the gasifier effluent being fed to the one or more operations, into a heated dryer feed; and(d) utilizing at least a portion of the process heat, transferred into the heated dryer feed, for drying the carbonaceous feed, prior to step (a).

2. The process of claim 1, wherein the gasifier effluent being fed to the one or more operations has a dew point of at least about 180°C (356°F).

3. The process of claim 1, wherein the gasifier effluent being fed to the one or more operations has a dew point of less than about 150°C (302°F).

4. The process of any one of claims 1 to 3, wherein the process heat transferred in step (c) is partly or completely latent heat released from condensation in the gasifier effluent.

5. The process of any one of claims 1 to 4, wherein the gasifier effluent being fed to the one or more operations has a pressure of at least about 5 barg.

6. The process of any one of claims 1 to 5, wherein the one or more operations include two or more operations, and wherein step (c) comprises transferring said process heat, by heat-exchanging contact of the gasifier effluent being fed to the two or more operations with respective portions of operation heat exchange fluid, said respective portions being provided from a common heat exchange fluid circulation loop.

7. The process of claim 6, wherein said process heat is transferred from the two or more operations into respective operation heat- containing fluids, at least portions of which are contained in said heated dryer feed.

8. The process of any one of claims 1 to 7, wherein the one or more operations includes one or more of a tar removal operation, a quenching operation, a radiant syngas cooler (RSC) or convective syngas cooler (CSC), a filtration operation, a scrubbing operation, a compression operation, a water-gas shift (WGS) operation, and / or an acid gas removal operation.

9. The process of claim 8, wherein the one or more operations include one or more of a filtration operation, a scrubbing operation, a compression operation, and / or a water-gas shift (WGS) operation.

10. The process of claim 9, wherein the one or more operations include both a scrubbing operation and a WGS operation.

11. The process of claim 9 or claim 10, wherein the one or more operations include a scrubbing operation, and wherein step (c) comprises transferring scrubbing operation heat using a scrubber feed cooler, into the heated dryer feed.

12. The process of claim 11, wherein the scrubber feed cooler provides a scrubber feed to the scrubbing operation.

13. The process of any one of claims 9 to 12, wherein, in step (b), the gasifier effluent being fed to the scrubbing operation is a filtered gasifier effluent.

14. The process of claim 13, wherein step (c) comprises transferring said scrubbing operation heat, by heat-exchanging contact established by said scrubber feed cooler, of the filtered gasifier effluent with a scrubber heat exchange fluid, said scrubbing operation heat being transferred into a scrubber heat-containing fluid, at least a portion of which is contained in said heated dryer feed.

15. The process of any one of claims 1 to 14, wherein the heated dryer feed comprises water.

16. A process for drying a carbonaceous feed, wherein:(a) in a gasifier, said carbonaceous feed is contacted with an oxygen-containing gasifier feed, under gasification conditions, to provide a gasifier effluent comprising H2, CO, and CO2; and(b) the gasifier effluent is fed to two or more operations to provide a conditioned syngas product; the method comprising: feeding respective portions of loop heat exchange fluid, from a common heat exchange fluid circulation loop, to said two or more operations to transfer process heat into respective operation heat-containing fluids, combining at least portions of the respective operation heat-containing fluids to provide a combined loop heat-containing fluid; and utilizing at least a portion of the process heat, present in the combined loop heatcontaining fluid, for drying the carbonaceous feed.

17. The process of claim 16, wherein said two or more operations include a scrubbing operation and a water-gas shift (WGS) operation, said respective portions of loop heat exchange fluid include a scrubber heat exchange fluid and a water-gas shift (WGS) heat exchange fluid, and said respective operation heat-containing fluids include a scrubber heat-containing fluid and a WGS heat-containing fluid.

18. The process of claim 16 or claim 17, wherein at least a portion of the combined loop heatcontaining fluid is heated in a dryer preheater to provide a heated dryer feed.

19. The process of claim 18, wherein the dryer preheater is positioned downstream of said combining at least portions of the respective operation heat-containing fluids and upstream of said utilizing at least a portion of the process heat, present in the heated dryer feed, for drying the carbonaceous feed.

20. The process of claim 19, wherein said utilizing at least a portion of the process heat, present in the heated dryer feed, for drying the carbonaceous feed, comprises establishing heat-exchanging contact between the heated dryer feed and the carbonaceous feed, using a feed dryer downstream of said dryer preheater.

21. The process of claim 20, further comprising bypassing (i) a portion of the combined loop heat-containing fluid around both the dryer preheater and the feed dryer, and / or (ii) a portion of the heated dryer feed around the feed dryer.

2. The process of any one of claims 1 to 20, further comprising feeding at least a portion of the conditioned syngas product to a syngas conversion operation or a syngas separation operation, to provide a respective renewable syngas conversion product or renewable syngas separation product.

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