Regulation of water vapor in gasification processes

Abstract

Gasification processes are disclosed, which can implement one or more strategies for heating and humidifying the gasifier effluent, as needed for effective hydrogen enrichment through the water-gas shift (WGS) reaction that converts H2O. Particular aspects, in carrying out these strategies, relate to the use of an evaporator upstream of a WGS reactor and operating at a comparable pressure (e.g., at least about 10 bar, at least about 20 bar, or at least about 30 bar, such as in a range from about 30 bar to about 100 bar). Such high-pressure evaporator may provide sufficient water vapor content, for effective generation of H2 via the WGS reaction, as needed for downstream uses. Advantageously, heat and / or material (e.g., condensate) sources may be available within the process itself, and integrated to meet at least some of the operational demands of the evaporator.

Description

Atty Docket No. 009503.00059REGULATION OF WATER VAPOR IN GASIFICATION PROCESSESCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of priority to U.S. Provisional Application No. 63 / 690,883, filed September 5, 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 to such processes in which an evaporator (e.g., saturator or saturation column) is used to increase the water vapor content of the gasifier effluent, by utilizing heat and / or material sources available in the process to meet operational demands of the evaporator.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, such as by direct and / or indirect heat exchange. Synthesis gas from gasification must also be treated to remove a number of undesired components that can include particulates, alkali metals, halides, and sulfur compounds, in addition to byproducts of gasification that are generally referred to as tars and oils. Furthermore, downstream conversion of the synthesis gas to value-added products often requires its hydrogen content to be increased, relative to that obtained from gasification alone.

[0004] Undesired tar components in the gasifier effluent, such as fused ring molecules (e.g., naphthalene and pyrene), pose significant challenges in terms of the tendency of these highAtty Docket No. 009503.00059 boiling-temperature species to condense from the vapor phase onto lower-temperature surfaces encountered downstream of the gasifier. Physical deposition of tars and oils is known to cause fouling / clogging of process lines, valves, reactors, and other equipment. For these reasons, the thermal destruction of tar is commonly practiced, but this, in turn, requires temperatures of about 1300°C (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 to increase the FhiCO molar ratio of the synthesis gas for its subsequent use in a number of reactions, the exothermic water-gas shift (WGS) reaction gas according to:CO + H2O H2+ CO2is widely exploited. The thermodynamics of this reaction govern an equilibrium shift toward hydrogen production at lower temperatures, which are generally unfavorable from the standpoint of reaction kinetics. Operations conducted to purify the gasifier effluent, or synthesis gas, in preparation for the catalytic WGS reaction, include scrubbing to remove water-soluble contaminants. The scrubbing operation, however, generally requires a reduction in both temperature and moisture content of the resulting scrubbed gasifier effluent, thereby directionally reducing its suitability in these respects for the WGS operation. The drying effect may be exacerbated by compression, as needed to achieve a desired, elevated pressure of the WGS reactor. Overall, the economics of biomass gasification and the effective utilization of the produced synthesis gas for obtaining desired end products are impacted by a number of complex and interacting processing objectives, as well as the associated equipment requirements. The present state of the art would benefit from improvements in gasification technology, relating to the management of the significant requirements for process water vapor content, associated with carrying out such objectives.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 forAtty Docket No. 009503.00059 heating and humidifying the gasifier effluent, as needed for effective hydrogen enrichment through the water-gas shift (WGS) reaction that converts H2O, as described above. Particular aspects, in carrying out these strategies, relate to the use of an evaporator upstream of a WGS reactor and operating at a pressure (e.g., at least about 10 bar, at least about 20 bar, or at least about 30 bar, such as in a range from about 30 bar to about 100 bar) comparable to that of the WGS reactor itself. Such high-pressure evaporator may provide sufficient water vapor content, or water vapor partial pressure, for effectively generating a desired amount of hydrogen (e.g., in terms of H2 concentration or PkiCO molar ratio) via the WGS reaction. The generated hydrogen is valuable for a number of downstream uses of the WGS product or a conditioned WGS product, including conversion and / or separation of commercially relevant end products. Advantageously, heat and / or material (e.g., condensate) sources may be available within the process itself, to meet at least some of the operational demands of the evaporator.

[0007] Other aspects of the invention relate to the integration of unit operations of gasification processes, in a manner that can reduce capital (e.g., equipment) costs and / or operating (e.g., water consumption) costs, optionally in conjunction with the use of an evaporator. These unit operations can include a gasifier, to produce a gasifier effluent; compression, to increase the pressure of a gasifier effluent; WGS, to increase the H2 content of a WGS product, relative to that of a gasifier effluent; acid gas removal, to decrease the CO2 content of a gasifier effluent, or of the WGS product in particular; and syngas conversion or syngas separation, to provide a renewable syngas conversion product or renewable syngas separation product. In some embodiments, a WGS operation may be performed downstream of the gasifier, without an intervening compression operation. This “low pressure WGS” option can result in relatively low water consumption and waste, due to the mitigation, or possibly elimination, of drying requirements upstream of the WGS operation, which are otherwise associated with compression. However, in this case compression costs may be relatively high, due to the pressure drop associated with the WGS operation, being taken at a relatively low pressure and therefore requiring a higher compression ratio to provide a given “end user” pressure. Depending on the particular, downstream syngas conversion or separation operation, this pressure may be broadly in the range of 30-90 bar, with lower and higher pressures being characteristic of operations such as, respectively, methanation to produce renewable natural gas and methanol synthesis to produce biomethanol. In other embodiments, a WGS operation may be performed downstream of the gasifier, with an intervening compressionAtty Docket No. 009503.00059 operation. This “high pressure WGS” operation can result in relatively high water consumption and waste, but with compression costs that may be relatively low, for the converse reasons stated above with respect to the “low pressure WGS” option. According to particular embodiments, the “high pressure WGS” operation, in which the gasifier and WGS operations are separated by compression, can benefit significantly from the use of a high- pressure evaporator to address water consumption, while retaining the reduced compression costs.

[0008] In various embodiments, particular advantageous operational / performance characteristics may be realized from one or more of: (1) The pumping of material that would otherwise constitute waste water, such as solids-free condensate obtained upstream of the WGS operation, for example from cooling of the gasifier effluent by direct quenching and / or by radiant or convective syngas cooling, or otherwise in a scrubbing operation, to a high- pressure evaporator. This effectively results in the “pumping” of the elemental hydrogen content of water, to produce H2 via WGS in the WGS product, as opposed to compressing an equivalent amount H2 to be provided in this product. Compression cost (e.g., energy consumption) is thereby reduced; (2) The recycle of high-pressure condensate, such as postshift condensate that may include, or may be entirely, unreacted water recovered from the WGS operation or downstream of this operation, to a high-pressure evaporator, optionally in combination with pre-shift condensate, such as the solids-free condensate described in (1) above; (3) The use of steam for indirect heat exchange and for providing vaporization heat in the evaporator, with the pressure of this steam relating to (or being “tied to”) the partial pressure of water vapor (or water vapor concentration) in the WGS feed, or humidified gasifier effluent, to the WGS operation, and with the pressure of this steam being lower than an operating pressure of the evaporator and / or WGS operation. A desired water vapor concentration (e.g., 30-50 mol-%) can be achieved, according to some embodiments, with a pressure (e.g., from about 60 bar to about 90 bar) of the heat-exchanging steam that is less than that otherwise required (e.g., 100 bar or more) for direct injection into a WGS reactor; (4) The use of heat from the hot WGS reactor effluent and / or the WGS product of the WGS operation, to provide all or a portion of the vaporization heat in the evaporator, thereby reducing the overall requirement (or demand) for external, high-pressure makeup steam; (5) The recycle of solids-free condensate, such as post-shift condensate as described in (2) above, formed by cooling of the WGS product, to upstream of the WGS operation, thereby reducing overall process water consumption; (6) The consolidation of compression requirements, suchAtty Docket No. 009503.00059 that the WGS operation, a hydrolysis operation, an acid gas removal operation, and optionally a syngas conversion or separation operation (e.g., a biomethanol synthesis operation), are performed at the same or substantially the same pressure, such as within about 5 bar, within about 3 bar, or within about 1 bar, with these nominal differences constituting the normal pressure drop between or among successive operations. The common pressures of these operations, may, for example, be within representative ranges of from about 50 bar to about 150 bar, from about 75 bar to about 100 bar, or from about 80 bar to about 90 bar. According to such embodiments, a process without available high-pressure utilities, such as steam at 100 bar or more, could nonetheless utilize a single (e.g., multi-stage) compressor downstream of the gasifier but upstream of the WGS operation, to achieve these common pressures. This may furthermore improve acid gas removal efficiency and allow the separated CO2 to be available at a higher pressure, thereby mitigating subsequent compression requirements (e.g., for CO2 sequestration).

[0009] Different process configurations, resulting from different uses of heat and material (e.g., condensate) sources from upstream and / or downstream of the WGS operation to meet at least some of the operational demands of the evaporator, can be implemented depending on overall process objectives. The heat and material sources may include, for example, (1) pre-shift steam, such as generated in a radiant syngas cooler (RSC-generated steam), in a convective syngas cooler (CSC-generated steam), or in a scrubbing operation (scrubber-generated steam), (2) pre-shift condensate, such as generated in a scrubbing operation, in a pre-shift heat recovery operation (e.g., downstream of the scrubbing operation), or in a compression operation, (3) post-shift steam, such as generated in the WGS operation, and / or (4) post-shift condensate, such as generated in the WGS operation or in a post-shift heat recovery operation (e.g., downstream of the WGS operation but upstream of an acid gas removal operation). The term “post-shift steam” further includes “end user steam” that may be used in any downstream syngas conversion or separation operation, such as used, for example, in the conversion operations of methanation to produce renewable natural gas and methanol synthesis to produce biomethanol. Uses of one or more of these and possibly other heat and material sources, alone or in various combinations, can be aligned with objectives of (A) reduction in clean water usage and total process wastewater generation, (B) reduction in total electricity demand, (C) integration of gasification and water-gas shift, with the pressure drop of the WGS operation being a relatively low percentage of a high operating pressure (downstream of a compressor) as opposed to a relatively high percentage of a low operatingAtty Docket No. 009503.00059 pressure, thereby reducing overall compression costs, and / or (D) consolidation of compression requirements to reduce the number of compressors and / or compression stages required of the process.

[0010] Importantly, particular aspects of the invention are associated with the discovery of processes in which an evaporator, for humidifying a gasifier effluent to be introduced to a WGS reactor (z.e., a WGS feed), can address drawbacks associated with conventional processes implementing various strategies to balance material and utility requirements. For example, the use of a WGS operation at a low pressure, such as that comparable to a gasification pressure before a compression operation, can improve water usage by avoiding the detrimental drying effect of such compression operation, prior to the WGS operation. However, overall compression costs and / or the number of compression stages may be increased, in view of (C) above. For purposes of a simplified explanation, if the gasifier effluent is available at 10 bar and must be raised to 90 bar following a WGS operation with 5 bar of pressure drop, (1) low pressure WGS operation, prior to compression, would require a compression ratio of 90 / (10-5)=18, whereas (2) high pressure WGS operation, following compression, would require a compression ratio of (90+5) / 10=9.5. The use of a WGS operation at a medium pressure, following a compression operation at a lower ratio (e.g., 4- 5), could operate with a relatively modest steam pressure (e.g., 60 bar) requirement for injection into the WGS operation, but would result in a lower acid gas removal operation pressure. This “medium pressure WGS” operation is therefore associated with a significant steam requirement, in addition to a low CO2 pressure recovered following the acid gas removal, with this pressure depending on the extent of conversion (shifting to form CO2) in the WGS operation. Otherwise, a “high pressure WGS,” operating at a pressure (e.g., about 90 bar) that is comparable to that of the acid gas removal operation, would require steam at a pressure (e.g., about 100 bar) that is not typically available. This problem is advantageously overcome using a high-pressure evaporator, with further benefits arising from integration with heat and material sources available from within the process as described herein.

[0011] In terms of advantages relating to implementation of an evaporator for reduction in wastewater generation and total process water usage, gasification and WGS operations can consume 90% or more of the clean demineralized water required for the overall process, and can generate a large majority, such as 70-95%, of its wastewater. The ability to integrate a high-pressure WGS operation, with utilization of water generated from gasification that would otherwise be discarded, can substantially reduce both demineralized water usage (e.g.,Atty Docket No. 009503.00059 by up to about 40%) and wastewater generation (e.g., by up to about 30%). Other advantages may arise, as described above, from consolidation of compression without a requirement for steam sources (e.g., 100 bar steam) that are often not readily available. The use of an evaporator allows the boiling point / pressure of heat-exchanging steam (i.e., its saturation pressure at a given temperature, as obtained from a common steam table) for vaporization in the evaporator (e.g., post-shift steam generated in the WGS operation) to be “tied to” the partial pressure of steam (or steam concentration) required in the WGS feed rather than to the actual pressure of the WGS operation. This advantageously enables high-pressure WGS operation (e.g., a WGS reactor at 90-100 bar), without the need for direct steam injection at a higher pressure (e.g., utilizing a 100 bar steam system that may or may not be accessible). More common steam systems, for example, provide 60-75 bar high-pressure steam, which cannot be directly injected into a WGS reactor operating at a higher pressure, but can nonetheless provide sufficient heat to evaporate water into a gasifier effluent at 100 bar, for subsequent feeding to a WGS operation with 30-50 mol-% water content. Again, this is due to the temperature of the heat-exchanging steam, for providing vaporization in the evaporator, being tied to boiling point of water at its partial pressure in the WGS feed, as opposed to the total (actual) pressure of the WGS operation.

[0012] Yet further advantages may reside in reducing the total process electrical demand by trading gas compression horsepower for liquid pump horsepower. In view of gas compressibility inefficiencies, process economics significantly favor pumping a fluid over compressing it. By pumping water to a WGS reactor at high pressure, the hydrogen produced via the WGS reaction has effectively been “pumped” in the form of the elemental hydrogen content of water, rather than compressed as water vapor (e.g., at a low or medium pressure) provided to a WGS reactor, or otherwise compressed as H2, provided to the WGS product (e.g., effluent of a WGS reactor), to achieve an thiCO molar ratio sufficient for downstream syngas conversion and / or separation. In the case of “high-pressure WGS” operation, downstream of a compression operation, still further advantages may reside in reduced compression ratios and associated energy (electricity) costs, as a result of the pressure drop of the WGS operation and associated operations, such as hydrolysis, being taken at a higher rather than lower pressure, as described above.

[0013] These and other embodiments, aspects, and advantages relating to the present invention are apparent from the following Detailed Description.Atty Docket No. 009503.00059BRIEF DESCRIPTION OF THE DRAWING

[0014] 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.

[0015] FIG. 1 depicts a flowscheme illustrating an embodiment of a process for the gasification of a carbonaceous feed, which process employs the introduction of a humidifying water source to an evaporator, as well as a number of possible options for integration of the evaporator operation with available heat (e.g., recovered steam) and material (e.g., condensate) sources.

[0016] FIG. 2 depicts, in an exemplary gasification process, certain details downstream of the gasifier, and more particularly from the point of processing a scrubber feed, as a gasifier effluent.

[0017] 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 certain 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. Eikewise, for example, not all options illustrated for integration of pre-shift condensate (501a, 501b, 501c), post-shift condensate (502a, 502b), and post-shift steam (602a), with operation of evaporator 88, are necessarily required, and, more typically, only one of such options, or a subset of such options, may be utilized. It should be understood that various specific features can be implemented independently of others.

[0018] 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 integrating an evaporator operation with gasification, 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.Atty Docket No. 009503.00059DETAILED DESCRIPTION

[0019] 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 of atmospheric pressure) in units of bars and pounds per square inch, respectively, whereas the terms “bar” and “psi,” when used herein, designate absolute pressures. For example, gauge pressures of 0 barg and 0 psig are approximately equivalent to absolute pressures of 1 bar and 14.7 psi, respectively.

[0020] 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 “subjecting the humidified gasifier effluent to a water-gas shift (WGS) operation” should be understood to mean “subjecting all or a portion of the humidified gasifier effluent” to such WGS operation. As in the case of “all or portion” being expressly stated, when “all or a portion” is the understood meaning, this phrase should likewise be understood to encompasses certain and preferred embodiments as noted above.

[0021] Embodiments of the invention are broadly directed to gasification processes in which water vapor in certain process streams such as a gasifier effluent (e.g., a scrubbed gasifier effluent) is regulated to achieve desired compositions and associated results. Representative processes may comprise increasing the amount of water vapor in the gasifier effluent by combining it with a humidifying water source, such as by feeding these streams to an evaporator. The term “evaporator” is meant to encompass apparatuses suitable for the evaporation of liquid water into a process stream such as a gasifier effluent to increase its moisture or water vaporAtty Docket No. 009503.00059 content. Such apparatuses extend to those which may be characterized in the art as a “saturator” or “saturation column,” although complete saturation of the process stream, while possible in particular embodiments, is not necessary in all cases to attain various advantages as described herein. Accordingly, an “evaporator” is meant to encompass, according to one example, a vessel having a heating element (e.g., a coil through which heat-exchanging steam is passed) submersed in a bottoms level of liquid water. This term is also meant to encompass, according to another example, a device such as gas / liquid mixer 505 shown in FIG. 2, configured to cause the injection of water (e.g., in humidifying water source 500) into a process stream, such as scrubbed gasifier effluent 32. This term is further meant to encompass, according to yet another example, a column (e.g., containing a suitable packing to improve vapor / liquid contacting) having a bottoms level of circulating liquid water (pumparound) that may be heated externally, such as with an external heat exchanger through which heat-exchanging steam is passed. Such column with bottoms recycle loop 88a that is heated externally with heat-exchanging steam (e.g., post-shift steam 602a) is also shown in FIG. 2. Accordingly, multiple apparatuses may be used in combination to achieve a suitable increase in moisture or water vapor content of a gasifier effluent.

[0022] 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,” “preceding,” or “upstream of’ another of such operations, or with one of such operations being performed or carried out “after,” “subsequent to,” “following,” 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 follows another operation, whereas more generally these phrases do not preclude the possibility of intervening operations.

[0023] 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.Atty Docket No. 009503.000591. 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 scrubbing operation, a compression operation, an evaporator, 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 post-shift heat recovery 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 a WGS operation, an evaporator, a compression operation, and / or other operations that precede the post-shift heat recovery 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.

[0024] 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 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). Characteristics of the gasifier effluent, in terms of its composition, including its H2:CO molar ratio (ratio of the concentration of H2 to the concentration of CO), 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 mayAtty Docket No. 009503.00059 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. According to the embodiment illustrated in FIG. 1, conditioned syngas product 36, obtained from acid gas removal operation 95, may have these particular characteristics, in terms of composition.

[0025] 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 and possibly relative to other upstream gasifier effluents, 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, and possibly 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 possibly relative to other upstream gasifier effluents, and which may provide all or part of a “heated scrubber feed,” or otherwise all or part of a “scrubber feed,” (vi) the raw gasifier effluent having been subjected to removal of heat, i.e., a “scrubber feed” or a “further cooled gasifier effluent,” having a lower temperatureAtty Docket No. 009503.00059 relative to the raw gasifier effluent, and possibly relative to other upstream gasifier effluents, resulting from heat removal (e.g., to generate steam), (vii) the raw gasifier effluent or scrubber feed having been subjected to at least 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, and possibly relative to other upstream gasifier effluents, (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, and possibly relative to other upstream gasifier effluents, (ix) the raw gasifier effluent, compressed gasifier effluent, or compressed, scrubbed gasifier effluent, having been combined with a humidifying water source (e.g., and provided from an evaporator to which both streams are fed), i.e., a “humidified gasifier effluent” having a higher water or moisture (H2O) concentration relative to the gasifier effluent with which the humidifying water source is combined (e.g., provided directly from a compression operation, or provided from a compression operation optionally following one of more intervening operations), (x) the raw gasifier effluent or humidified gasifier effluent having been subjected to at least a water-gas shift (WGS) operation, i.e., a “WGS product,” having a higher thiCO molar ratio relative to that of the raw gasifier effluent or humidified gasifier effluent, and possibly relative to other gasifier effluents, (xi), the raw gasifier effluent having been subjected to any other operation downstream of the gasifier and / or upstream of an acid gas removal operation (if used), whether or not specifically described herein.

[0026] 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) an evaporator following the introduction of a humidifying water source, (c) a water-gas shift (WGS) operation, and (d) 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 H2:COAtty Docket No. 009503.00059 molar ratio (e.g., increased H2 concentration and / or decreased CO concentration), and / or a lower acid gas (e.g., lower CO2) concentration.

[0027] Regardless of any specific operations used to provide a conditioned syngas product, representative processes may further comprise feeding all or a portion of this 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 syngas separation 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).

[0028] 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. This operation, 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).

[0029] In some embodiments, any syngas conversion operation or syngas separation operation may be performed on a WGS product, obtained from a WGS operation that provides an increased, and more favorable, Fh:CO molar ratio, for performing the desired conversion or separation. In some embodiments, any syngas conversion operation or syngas separation operation mayAtty Docket No. 009503.00059 be performed on a CCh-depleted product of an acid gas removal operation that provides 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 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, in terms of both an increased Fh:CO molar ratio and a decreased concentration of CO2 and / or sulfur-containing gases.

[0030] 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) optionally following one or more intervening operations, increasing an amount (e.g., in terms of added quantity or rate, such as added grams, added moles, added grams / hour, added moles / hour) of water (e.g., in the form of water vapor) in the gasifier effluent to provide a humidified gasifier effluent (e.g., having an increased concentration of water vapor). For example, the water vapor amount may be increased, relative to the immediately preceding gasifier effluent (e.g., a compressed, scrubbed gasifier effluent) by adding water vapor from a humidifying water source. The processes may further comprise: (c) subjecting the humidified gasifier effluent to a water-gas shift (WGS) operation (e.g., directly or optionally following one or more post-humidifying operations upstream of the WGS operation) to convert at least a portion of the water vapor to hydrogen, which is present in a WGS product of the WGS operation. Other particular embodiments of the invention are directed to processes for gasification of a carbonaceous feed, comprising (a) as described above. The processes may further comprise: (b) optionally following one or more intervening operations, combining liquid water with (e.g., vaporizing liquid water into) the gasifier effluent to provide a humidified gasifier effluent having an increased content of water vapor relative to the gasifier effluent. The combining may be performed by pumping the liquid water, and the humidified gasifier effluent may be subjected to a WGS operation. Advantageously, at least a portion of an elemental hydrogen content of the liquid water may be used to generate hydrogen in the WGS operation, with this hydrogen being present in aAtty Docket No. 009503.00059WGS product of the WGS operation. Yet other particular embodiments of the invention are directed to processes for gasification of a carbonaceous feed, comprising (a) as described above. The processes may further comprise: (b) optionally following one or more intervening operations, subjecting the gasifier effluent (e.g., a humidified gasifier effluent, or other WGS feed, as described herein) to a WGS operation to convert water vapor in the gasifier effluent to hydrogen, which is present in a WGS product of the WGS operation. At least a portion of the water vapor is provided from evaporating water that is recovered from upstream of and / or downstream of the WGS operation.

[0031] With respect to any of these particular embodiments, one or more intervening operations occurring downstream of the gasifier and upstream of (i) increasing an amount of water vapor in the gasifier effluent, (ii) combining liquid water with the gasifier effluent, or (iii) subjecting the gasifier effluent (e.g., humidified gasifier effluent) to a WGS operation, may be 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 intervening operation(s), which are preferably multiple operations performed successively or consecutively, may be used upstream of, and in combination with, humidifying the gasifier effluent and further subjecting it to a WGS operation and / or an acid gas removal operation, to provide a conditioned syngas product as described herein.Operations of Exemplary Processes

[0032] 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. To obtain a conditioned syngas product, additional operations, for example, following combining a humidifying water source with the gasifier effluent and feeding the combined streams to an evaporator, or otherwise following feeding these streams separately to an evaporator, may include a WGS operation and / or an acid gas removal operation. Representative processes may also include a syngas conversion operation or a syngas separation operation, being fed by the conditioned syngas product. Certain possible features of the gasifier, these intervening operations, the evaporator, the WGS operation, the acid gas removal operation, and downstream syngas conversion and syngas separation operations, as well as process streams and conditionsAtty Docket No. 009503.00059 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

[0033] 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.

[0034] 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,Atty Docket No. 009503.00059 including those described above. A preferred carbonaceous feed is wood (e.g., in the form of wood chips).

[0035] 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 the carbonaceous feed with the oxygen-containing gasifier feed in the gasifier provides a gasifier effluent, and more particularly a raw gasifier effluent as the product directly exiting the gasifier. One or more reactors (e.g., in series or parallel) of the gasifier may operate under gasification conditions present in such reactor(s), with these conditions including a temperature of generally from about 500°C (932°F) to about 1000°C (1832°F), and typically from about 816°C (1500°F) to about 1038°C (1900°F). Other gasification conditions may include atmospheric pressure or elevated pressure, for example an absolute pressure generally from 1 bar (14.5 psi) to about 100 bar (1450 psi), and typically from about 10 bar (145 psi) to about 30 bar (435 psi), or from about 5 bar (72 psi) to about 20 bar (290 psi).

[0036] Gasification reactor configurations include counter-current fixed bed (“up draft”), co-current fixed bed (“down draft”), and entrained flow plasma. Different solid catalysts, having differing activities for one or more desired functions in gasification, such as tar reduction, enhanced H2 yield, and / or reduced CO2 yield, may be used. Limestone may be added to a gasification reactor, for example, to promote tar reduction by cracking. Various catalytic materials may be used in a gasification reactor, including solid particles of dolomite, supported nickel, alkali metals, and alkali metal compounds such as alkali metal carbonates, bicarbonates, and hydroxides. Often, a gasifier is operated with a gasification reactor having a fluidized bed of particles of the carbonaceous feed (and optionally particles of solid catalyst), with the oxygen-containing gasifier feed, and optionally separate, fluidizing H2O-Atty Docket No. 009503.00059 and / or CCh-containing feeds, being fed upwardly through the particle bed. Exemplary types of fluidized beds include bubbling fluidized beds and entrained fluidized beds.

[0037] 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.

[0038] The raw gasifier effluent, or any gasifier effluent having been subjected to one or more operations as described herein, may comprise synthesis gas, i.e., may comprise both H2 and CO, with these components being present in various amounts (concentrations), and preferably in a combined amount of greater than about 25 mol-% (e.g., from about 25 mol-% to about 95 mol-%), greater than about 50 mol-% (e.g., from about 50 mol-% to about 90 mol-%), or greater than about 65 mol-% (e.g., from about 65 mol-% to about 85 mol-%). With respect to any such combined amounts (concentrations), the tb:CO 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 tb:CO 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 tb:CO molar ratio, and / or a favorable H2 concentration, for these or other downstream syngas conversion and separation operations. For example, the WGS operation may include parameters (e.g., reactor temperatures and / or catalyst types) for obtaining the highest yield / concentration of hydrogen, through consumption of CO present in the syngas upstream of this operation, in the case obtainingAtty Docket No. 009503.00059 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 PhiCO molar ratio that is increased by at least about 0.25, at least about 0.5, or at least about 1.0.

[0039] 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 gasifier effluent, or any gasifier effluent having been subjected to one or more operations as described herein, may comprise CPU, 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

[0040] 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, forAtty Docket No. 009503.00059 upgrading synthesis gas to higher value products, which operations perform optimally (e.g., from the standpoint of stability) with pure feed gases.

[0041] 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.

[0042] 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)).

[0043] 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 aboveAtty Docket No. 009503.000591100°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.

[0044] 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.

[0045] 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.

[0046] 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

[0047] 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 directAtty Docket No. 009503.00059 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 FhiCO molar ratio and an increased H2 concentration). A dry or partial quenching operation utilizes the sensible heat of the gasifier effluent to vaporize the injected water, which is sufficient for obtaining the resulting quenched gasifier effluent at a desired, cooler temperature. A full or complete quenching operation uses sufficient water to saturate the quenched gasifier effluent. In the case of using dry or full quenching without the further use of an RSC or CSC, the quenched gasifier effluent may have a temperature from about 250°C (482°F) to about 600°C (1112°F), and preferably from about 275°C (527°F) to about 350°C (662°F) to allow for further processing. Representative processes can otherwise include, however, sufficient further cooling (e.g., using an RSC or a CSC) as required upstream of a subsequent filtration operation (passage through a filter) to remove solid particles (e.g., dust). In preferred embodiments, only a partial quench is used in the quenching operation, as opposed to a full quench, such that the quenched gasifier effluent exiting, or obtained directly from, the dry quenching operation is above its dewpoint, i.e., not saturated. In general, the dry quenching operation can promote rapid and efficient cooling through direct contact between hot gasifier effluent and quench water (e.g., boiler feed water or demineralized water) or other aqueous quenching medium.Radiant Syngas Cooler (RSC) or Convective Syngas Cooler (CSC)

[0048] 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 byAtty Docket No. 009503.00059 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

[0049] A filtration operation, using any suitable filter, may be used to remove solid particles (particulates) from the gasifier effluent, for example the quenched gasifier effluent as described above, exiting a dry or full quenching operation, or the cooled gasifier effluent as described above, exiting an RSC or a CSC. In the case of biomass gasification, these solid particles can include char, tar, soot, and ash, any of which can generally contain alkali 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.

[0050] 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).Atty Docket No. 009503.00059

[0051] 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

[0052] Prior to the scrubbing operation, heat may be removed from the gasifier effluent, such as the filtered gasifier effluent described above and exiting, or obtained directly from, the filtration operation. According to some embodiments, a boiler and / or an air cooler (employing fans) may be used as a scrubber feed cooler to carry out indirect heat exchange. Regardless of the particular type, this cooler may more specifically perform cooling of a heated scrubber feed to provide the scrubber feed (or cooled scrubber feed) that is input directly to the scrubber, in which case both the heated and cooled streams may comprise an un-scrubbed gasifier effluent, such as the filtered gasifier effluent. It can therefore be appreciated that, 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.”

[0053] 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 75 downstream of the filtration operation 70, 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, or scrubber feed 28 as illustrated in FIGS. 1 and 2, directly downstream of scrubber feed cooler and being fed to theAtty Docket No. 009503.00059 scrubbing operation, may have a temperature from about 45°C (113°F) to about 200°C (392°F), and preferably from about 55°C (131°F) to about 100°C (212°F).Scrubbing Operation

[0054] 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 scrubbing operation, following cooling of overhead vapors exiting the scrubber vessel and further contacting in a downstream wash column of an overall scrubbing operation, may have a temperature from about 35°C (95°F) to about 100°C (212°F), and preferably from about 45°C (113°F) to about 70°C (158°F).

[0055] 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

[0056] The water gas shift (WGS) operation reacts CO present in a gasifier effluent, such as a humidified gasifier effluent exiting an evaporator that may optionally be subjected to sulfurAtty Docket No. 009503.00059(FhS) addition and / or preheating, with steam to increase H2 concentration (as well as CO2 concentration). In this manner, the humidified gasifier effluent, obtained after being combined with a humidifying water source and optionally after compression upstream of this water addition, may be characterized as a feed to the WGS operation (WGS feed). Following the tar removal operation, filtration operation, scrubbing operation, compression operation, and combining with a humidifying water source, the humidified 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) increases the pressure of the scrubbed gasifier effluent to a value more favorable in the resulting compressed, scrubbed gasifier effluent, for subsequent use in the WGS operation. For example, the compressed, scrubbed gasifier effluent may have a pressure from about 10 bar to about 120 bar, or from about 25 bar to about 100 bar, which may also be representative of the pressure of the WGS operation (or one or more WGS reactors used in this operation) and the WGS product of this operation. The use of a humidifying water source can increase the water vapor content in the humidified gasifier effluent, to achieve a concentration from about 20 mol-% to about 60 mol-%, and more typically from about 30 mol-% to about 50 mol-%, to further improve the favorability of the humidified gasifier effluent for a subsequent WGS operation.

[0057] According to some embodiments, the humidified gasifier effluent, or any feed to the WGS operation, may be sulfided, for example combined with H2S or an H2S precursor, such as a mercaptan or a sulfide (e.g., dimethyl disulfide or DMDS), in the case of the WGS operation being, more specifically, a sour WGS operation in which catalyst used in WGS reactor(s) of this operation is desirably maintained in a sulfided state. By virtue of being supplemented with sulfur and / or preheated, a humidified gasifier effluent, subjected to respective posthumidifying operations of sulfur addition and / or preheating, may thereby attain further improved characteristics that kinetically and / or thermodynamically favor a catalytic WGS reaction to desirably increase the FhiCO molar ratio and / or H2 concentration of the WGS product, compared to these characteristics of the WGS feed (e.g., the humidified gasifier effluent). For example, in the case of preheating, the humidified gasifier effluent may be heated to a temperature from about 200°C (392°F) to about 300°C (572°F), and preferably from about 225°C (437°F) to about 275°C (527°F), prior to its input to the WGS operation. The moisture or water vapor content of this feed may be within a range as described above,Atty Docket No. 009503.00059 and the use of steam in excess of the stoichiometric amount needed for the WGS reaction 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.

[0058] One or more 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).

[0059] 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 may be desirable to use three or more reactors, or catalyst beds, to perform the WGS reaction, again with cooling between consecutive reactors or catalyst beds.

[0060] 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 H2:CO molar ratio and increased H2 concentration, relative to the feed to the WGS operation (e.g., humidified gasifier effluent, optionally having been subjected to sulfur addition and / or preheating) 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 H2:CO molar ratio from about 1.0 to about 7.5, from about 1.0 to about 3.0, from about 3.0 to about 7.0, or from about 4.5 to about 6.0 and / or a hydrogen concentration of at least about 20 mol-% (e.g., from about 20 mol-% to about 60 mol-%), at least about 25 mol-% (e.g., from about 25 mol-% to about 50 mol-%), or at least about 30 mol-% (e.g., from about 30 mol-% to about 45 mol-%). TheseAtty Docket No. 009503.00059 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 feed to the WGS operation (e.g., humidified gasifier effluent, optionally having been subjected to sulfur addition and / or preheating) will in general have a lower tkiCO molar ratio, such as from about 0.2 to about 3.5, from about 0.3 to about 2.5, from about 0.5 to about 1.5, or less than about 1.0, and / or a lower hydrogen concentration, such as at most about 30 mol-% (e.g., from about 5 mol-% to about 30 mol-%), at most about 25 mol-% (e.g., from about 5 mol-% to about 25 mol-%), or at most about 20 mol-% (e.g., from about 10 mol-% to about 20 mol-%).

[0061] One or more reactors of a WGS operation may be utilized, as part of a WGS / hydrolysis system, in conjunction with a hydrolysis operation (e.g., comprising a hydrolysis reactor) for beneficially converting carbonyl sulfide (COS) to H2S and / or hydrogen cyanide (HCN) to ammonia (NH3), thereby providing both sulfur and nitrogen contaminants in forms that are more easily removed, such as upon being conveyed to elsewhere in the process (e.g., recycled to the scrubbing operation). Between the WGS operation (e.g., a final, downstream reactor of this operation) and hydrolysis operation, a post-shift heat recovery operation may be used to cool the WGS reactor effluent, for example by forming post-shift steam as a valuable heat source for operation of the evaporator. According to particular embodiments, the WGS reactor effluent may be cooled from a temperature from about 325°C (617°F) to about 500°C (932°F), and more typically from about 375°C (707°F) to about 450°C (842°F), to a temperature more suitable for a feed to a downstream hydrolysis reactor, such as from about 200°C (392°F) to about 375°C (707°F), and more typically from about 225°C (437°F) to about 325°C (617°F).Acid Gas Removal Operation

[0062] 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 inAtty Docket No. 009503.00059 overall sulfur content (concentration). In some embodiments, the acid gas removal operation may further provide a CCh-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 CCh-cnrichcd 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).

[0063] 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 CO2-depleted gasifier effluent exiting, or obtained directly from, this 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 a conditioned syngas product exiting the acid gas removal operation, may be within ranges as described above with respect to the WGS product. 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.

[0064] 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 mayAtty Docket No. 009503.00059 generally be suitable for temperatures up to 175 °C (347 °F). Regeneration of the rich physical or chemical solvent, such as after having reached substantially its capacity for the removal of acid gases, can release the acid gas product, as an 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

[0065] In some embodiments, processes described herein may also include a syngas conversion operation or syngas separation operation to produce a respective renewable syngas conversion product or renewable syngas separation product, such as liquid hydrocarbons, methanol, or RNG as examples of conversion products, and purified hydrogen as an example of a separation product. According to particular embodiments, the feed to a syngas conversion operation or syngas separation operation may be the conditioned syngas product, as described herein.

[0066] 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 (e.g., present in the WGS product) of hydrogen (Fh) 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.

[0067] 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)Atty Docket No. 009503.00059Representative 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 / Al Oa. 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.

[0068] In the case of methane production as a syngas conversion operation to provide a renewable natural gas (RNG) product, one or more methanation reactors (e.g., in series or parallel) may be used to react CO and / or 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.

[0069] 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-%).

[0070] 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 hydrogenAtty Docket No. 009503.00059 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.Evaporator, Compression, Pre-Shift and Post-Shift Heat Recovery Operations

[0071] Other possible features of operations described above, as well as the evaporator, compression operation, pre-shift heat recovery operations, and post-shift heat recovery operations, are described below in conjunction with the non-limiting embodiments illustrated in the drawing figures.Further exemplary embodiments of gasification processes

[0072] FIGS. 1 and 2 depict flowschemes illustrating embodiments of processes that include operations as described above, and more particularly illustrating the utilization of heat and / or materials, recovered from the process, for operating an evaporator, which, in preferred embodiments may be considered a high-pressure evaporator in view of its operating pressure (e.g., from about 60 bar to about 100 bar). Representative processes may comprise any of the operations illustrated in FIGS. 1 and 2, or any subsets of these operations, in any order but preferably in the orders 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, for example raw gasifier effluent 16, comprising Fh, 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, humidified gasifier effluent 33, WGS product 34, or conditioned syngas product 36.Atty Docket No. 009503.00059

[0074] Generally, processes may comprise providing conditioned syngas product 36 following any of a number of operations, or combinations of operations, with conditions and performance parameters of these operations as described in more detail above. In the case of intervening operations between gasifier 50 and the addition of humidifying water source 500, these 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), (vi) scrubbing operation 80a (which may include scrubber 80 alone or in combination with scrubber feed cooler 75) to remove water-soluble contaminants from the gasifier effluent, (vii) pre- shift heat recovery operation 101 to further cool and remove moisture (e.g., as condensate) from the gasifier effluent, and (viii) compression operation 85a to increase the pressure of and further remove moisture (e.g., as condensate) from the gasifier effluent. In the case of operations downstream of the addition of humidifying water source 500, these can include (ix) evaporator 88 for vaporization of the humidifying water source 500 into the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32), (x) WGS operation 90a, which includes WGS reactor 90 and, in the case of further including optional hydrolysis reactor 915 (FIG. 2), may be alternatively considered as a WGS / hydrolysis system 90a, in either case to increase H2 concentration and the FhiCO molar ratio of the gasifier effluent and in the latter case to optionally convert sulfur and nitrogen contaminants as described above, (xi) post-shift heat recovery operation 102 to cool and remove moisture (e.g., as condensate) from the WGS product, and (xii) acid gas removal operation 95 to remove CO2 from the WGS product.

[0075] According to particular embodiments, the one or more intervening operations may include one or more of a tar removal operation, a quenching operation, a radiant syngas cooler or convective syngas cooler, a filtration operation, a scrubbing operation, and / or a compression operation, which may be considered a pre-shift compression operation. Such pre-shift compression operation may be associated with water removal, forming pre-shift condensate. For example, as more particularly illustrated in FIG. 2, pre-shift condensate 501c may beAtty Docket No. 009503.00059 formed within, and removed from, pre-shift compression operation 85a, in order to achieve moisture removal between compression stages, via interstage condensate removal 851. Alternatively, or in combination, pre-shift condensate 501b may be formed, and removed, immediately upstream of pre-shift compression operation 85a, such as in pre-shift heat recovery operation 101, in order to achieve moisture removal prior to compression. Any condensate that is formed in this manner and removed from a process stream such as a gasifier effluent, may be used to provide at least a portion of humidifying water source 500. The same considerations apply with respect to pre-shift condensate 501a that is formed and removed from scrubbing operation 80a such as, more particularly, from scrubber wash column 801 (FIG. 2). In this manner, advantages in terms of condensate utilization may be realized in the case of the one or more intervening operations including both a scrubbing operation and a pre-shift compression operation.

[0076] 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 scrubber 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 scrubber 80. In some embodiments, scrubber feed cooler 75 may produce, from scrubber feed water 29, scrubber-generated steam 27 (as a particular example of pre-shift steam), into which process heat from filtered gasifier effluent / heated scrubber feed 26 is transferred. Such process heat may be utilized, in the same manner as described herein with respect to process heat from post-shift steam 602a, in evaporator 88, for example by transferring to and heating of, humidifying water source 500. In addition to scrubber-generated steam, other examples of pre-shift steam having heat that may be utilized for operating evaporator 88 include RSC- generated steam or CSC-generated steam 23, obtained from cooling a gasifier effluent with radiant syngas cooler (RSC) or convective syngas cooler (CSC), as described above.

[0077] Optionally following one or more intervening operations as described above, representative processes generally include increasing an amount of water vapor in the gasifier effluent, for example by combining, or otherwise by adding water vapor generated from, humidifying water source 500. That is, such humidifying water source 500 may be combined with the gasifier effluent, such as compressed, scrubbed gasifier effluent 32, or water vapor generated from humidifying water source, for example in evaporator 88, may be added to the gasifier effluent, such as compressed, scrubbed gasifier effluent 32. Increasing the amount of waterAtty Docket No. 009503.00059 vapor in the gasifier effluent may, more particularly, comprise feeding both the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32) and humidifying water source 500 to evaporator 88, with such streams being fed separately to this operation, or possibly being mixed initially and then fed. In the case of mixing upstream of evaporator 88, any suitable gas / liquid mixer 505 (FIG. 2), such as a mixing point injector, spray nozzle, or other device for promoting the formation of small droplets or mist from humidifying water source 500, thereby aiding distribution and evaporation, may be used. In exemplary embodiments, therefore, the gasifier effluent being combined with humidifying water source 500, or otherwise being fed to evaporator 88 in conjunction with humidifying water source 500, may be a compressed gasifier effluent, having been subjected to a pre-shift compression operation, or more particularly a compressed, scrubbed gasifier effluent, having been subjected to both a scrubbing operation and such pre-shift compression operation.

[0078] Evaporator 88 may operate as a saturation column with internal structures to achieve at least one, but preferably multiple, theoretical stages of equilibrium vapor-liquid contacting and heat exchange between process streams (e.g., humidifying water source 500 and compressed, scrubbed gasifier effluent 32), in providing a desired saturation level. According to one embodiment, prior to contacting, the humidifying water source 500 may be a higher temperature, liquid phase stream, with the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32) being a lower temperature, gas phase stream. Therefore, humidified gasifier effluent 33, formed from the combination of these streams (e.g., upstream of evaporator 88 or possibly within this apparatus) may have a temperature that is increased, relative to that of the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32), but with such temperature being lower than that of humidifying water source 500. According to particular embodiments, the humidified gasifier effluent (e.g., provided from, or directly exiting, the evaporator) may have a temperature from about 180°C (356°F) to about 315°C (599°F), and more typically from about 200°C (392°F) to about 260°C (500°F). In addition, the gasifier effluent being humidified (e.g., compressed, scrubbed gasifier effluent 32) may have a temperature from about 35°C (95°F) to about 175°C (347°F), and more typically from about 70°C (158°F) to about 140°C (284°F), such as at the point of being combined with the humidifying water source.

[0079] Recirculation in evaporator 88 can result in successive iterations of conductive heating of the gas phase stream, from a saturated state to an unsaturated state, together with evaporative cooling of the liquid phase stream, causing re-condensation of liquid water. Advantageously,Atty Docket No. 009503.00059 following multiple iterations, the resulting humidified gasifier effluent 33 exiting evaporator 88 may have a water vapor partial pressure that corresponds to the vapor pressure of water at a temperature of heat-exchanging steam (accounting for approach temperature offsets in the heat exchange), for example post-shift steam 602a and / or external makeup steam 610, used for transferring heat to humidifying water source 500. A heat exchanger for this heat transfer, such as evaporator heater 881 (FIG. 2), may be external to evaporator 88, for example in the case of providing heat to humidifying water source 500 through bottoms recycle loop 88a (FIG. 2). Alternatively, a heat exchanger may be internal to, or integrated with, evaporator 88. Accordingly, heat-exchanging steam, such as post-shift steam 602a and / or external makeup steam 610, can be input directly to evaporator 88 or into a water recycle loop, such as bottoms recycle loop 88a, to provide heat to this evaporator. Evaporator 88 may therefore operate using (i) indirect heat exchange, with an indirect heat exchange medium (e.g., post-shift steam 602a and / or external makeup steam 610) transferring heat to humidifying water source 500, in addition to (ii) direct heat exchange between humidifying water source 500 and the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32).

[0080] To achieve a desired water vapor partial pressure in humidified gasifier effluent 33, and consequently a desired water content for subsequent use in WGS operation 90a, humidifying water source 500 (e.g., at the point of being combined with the gasifier effluent, such as compressed, scrubbed gasifier effluent 32) may have a temperature from about 200°C (392°F) to about 320°C (608°F), and more typically from about 250°C (482°F) to about 290°C (554°F), and an absolute pressure from about 60 bar to about 120 bar, and more typically from about 75 bar to about 100 bar. For humidifying water source 500 to be in the liquid phase up to the point of being combined with the gasifier effluent or being fed into evaporator 88 (e.g., such that this liquid can be pumped through water feed pump 550), its temperature is preferably below the saturation temperature at its pressure, and therefore its pressure is higher than the vapor pressure at its temperature. The pressure is in any event suitable for the downstream WGS operation and is therefore at least equal to, or exceeds, the pressure of the WGS operation (e.g., exceeds the highest pressure at which a WGS reactor operates). More particularly, the pressures of both the humidifying water source 500 and the gasifier effluent, such as at the point where these streams are combined, or otherwise where they are introduced to evaporator 88, as well as the pressure of humidified gasifier effluent 33, may exceed the pressure of the WGS operation (e.g., exceed the highest pressure at which a WGS reactor operates). Importantly, compressor 85 and water feed pump 550 may provideAtty Docket No. 009503.00059 sufficient gas and liquid pressures for evaporator 88 and other downstream operations that include WGS operation 90a and acid gas removal operation 95. As described above, pumping of water advantageously allows at least a portion of its elemental hydrogen content to be used to generate molecular hydrogen (H2) via the WGS reaction. In terms of water vapor, present in the gasifier effluent (e.g., humidified gasifier effluent 33) and converted to molecular hydrogen in the WGS operation, at least a portion of such water vapor may be provided from evaporating water that is, more particularly, recovered from upstream and / or downstream of this operation. In exemplary embodiments, this recovered water may include pre-shift and / or post-shift condensate that is (i) formed in a heat recovery operation as described herein and / or (ii) formed in, for formed immediately upstream of, a compression operation. Such recovered water may advantageously be used to humidify, and possibly saturate, a WGS feed to WGS operation 90a, or to provide a relative humidity level of at least about 80%, or at least about 90%, in this WGS feed. This WGS feed may be humidified gasifier effluent 33, provided directly from evaporator 88 or optionally following one or more post-humidifying operations (e.g., sulfur addition 331 and / or preheating 335) upstream of WGS operation 90a. Whereas humidifying water source 500 may possibly include any preshift condensate (e.g., 501a, 501b, or 501c) or post-shift condensate (e.g., 502a, 502b) formed in the process, this water source may be supplemented, if necessary, with external makeup water 510.

[0081] The pumping of liquid water (e.g., humidifying water source 500) increases its pressure to a value equal to or exceeding the pressure of the WGS operation (e.g., exceeding the highest pressure at which a WGS reactor operates). For example, pumping may increase the pressure from a pump inlet, or pump suction, pressure of from about 5 bar to about 50 bar, and more typically from about 10 bar to about 35 bar, to a pump discharge pressure from about 60 bar to about 120 bar, and more typically from about 75 bar to about 100 bar. Operating costs, with respect to pumping the elemental hydrogen content of water, are reduced significantly compared to compressing water vapor as a source of hydrogen gas (via the WGS reaction) or otherwise compressing hydrogen gas itself. The combining of liquid water (e.g., humidifying water source 500) with the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32) may comprise contacting these process streams within, and / or upstream of, evaporator 88. This combining may result in vaporizing at least a portion of the liquid water into the gasifier effluent, at such point(s) of contact between these streams. The point(s) of contact may occur, for example, in gas / liquid mixer 505 upstream of evaporator 88. As described herein,Atty Docket No. 009503.00059 prior to combining the liquid water with the gasifier effluent, at least a portion of the liquid water may be recovered from the process, upstream of and / or downstream of, WGS operation 90a, such as in a respective pre-shift or post-shift heat recovery operation that forms, respectively, pre-shift or post-shift condensate.

[0082] Advantageous process integration may be realized in the case of humidifying water source 500 having a temperature that is obtained, at least in part, by transferring heat recovered from the process. For example, such heat may be conveniently available in the hot effluent of WGS operation 90a, which, as more clearly illustrated in FIG. 2, may be a WGS / hydrolysis system 90a having both a WGS reactor 90 (or two or more of such reactors as described above) and a hydrolysis reactor 915 of a hydrolysis operation as described above. Therefore, these reactors, optionally in conjunction with WGS operation heat exchanger 905 for removal of heat (e.g., from WGS reactor effluent 35 directly exiting WGS reactor 90) from a feed to hydrolysis reactor 915, may be considered components of WGS / hydrolysis system 90a. Directly exiting WGS reactor 90 (or a downstream one of such reactors operating in series), WGS reactor effluent 35 may have a representative temperature from about 325°C (617°F) to about 500°C (932°F), and more typically from about 375°C (707°F) to about 450°C (842°F). Prior to feeding of this effluent to hydrolysis reactor 915, it may be cooled to a suitable hydrolysis reactor inlet temperature from about 200°C (392°F) to about 375°C (707°F), and more typically from about 225 °C (437 °F) to about 325 °C (617 °F). Such cooling, together with steam generation to provide post-shift steam 602a, may be carried out in WGS operation heat exchanger 905, as a particular type of post-shift heat recovery operation, following WGS reactor 90, for forming post-shift steam. As further illustrated, the generated, post-shift steam 602a may then be available as a heat source for heating evaporator heater 881. In addition, residual heat may be available in WGS product 34, for example having a temperature from about 120°C (248°F) to about 290°C (554°F), and more typically from about 225°C (437°F) to about 260°C (500°F). Heat may be further recovered in downstream post-shift heat recovery operation 102, following hydrolysis reactor 915, for forming post-shift condensate 502b, all or a portion of which can contribute to humidified water source 500. Overall, it can be appreciated that WGS operation 90a, which may in some embodiments be more particularly WGS / hydrolysis system 90a as illustrated in FIG. 2, can be a source of heat and material (condensate) for useful integration with evaporator 88. For example, heat and / or water may be recovered from WGS product 34 and / or WGS reactor effluent 35.Atty Docket No. 009503.00059

[0083] In particular embodiments, therefore, heat for indirect heat exchange in evaporator 88, and / or condensate for direct heat exchange and humidifying in evaporator 88, may be recovered from WGS product 34. Likewise, such heat for indirect heat exchange and / or condensate for direct heat exchange may be recovered from WGS reactor effluent 35. More particularly, heat may be recovered by generating post-shift steam from cooling of WGS product 34 and / or WGS reactor effluent 35, such as in a post-shift heat recovery operation. Transferring of recovered heat may be performed by indirect heat exchange between such generated postshift steam (as the indirect heat exchange medium) and humidifying water source 500. This heat exchange may occur through an intermediary fluid, such as circulating water in bottoms recycle loop 88a as shown in FIG. 2, or possibly an upstream gasifier effluent such as compressed, scrubbed gasifier effluent 32. In this manner, post-shift steam may refer to steam generated to recover heat from a process stream downstream of the WGS operation, or possibly within the WGS operation (e.g., following a WGS reactor of this operation). In the same manner, heat from pre-shift steam generated upstream of the WGS operation, such as to recover heat from raw gasifier effluent 16, tar-depleted gasifier effluent 18, quenched gasifier effluent 22, cooled gasifier effluent 24, filtered gasifier effluent 26, and / or scrubber feed 28, may likewise be transferred for indirect heat exchange, to meet heating requirements of evaporator 88. Particular operations to achieve this process stream cooling and heat transfer include quenching operation 60, RSC or CSC 65 to provide RSC-generated steam or CSC- generated steam 23, and scrubber feed cooler 75 to provide scrubber- generated steam 27.

[0084] Advantageously, pre-shift or post-shift steam, despite having a pressure below that of the WGS operation (e.g., below the highest pressure at which a WGS reactor operates), may nonetheless be used effectively in carrying out humidification of the feed to this operation, through the incorporation of evaporator 88. That is, the need for a steam pressure exceeding that of the WGS operation, as would otherwise be required in the case of direct steam injection, is overcome for reasons relating to water vapor partial pressure considerations as described above. In this regard, humidifying water source 500 (e.g., at the point of being combined with the gasifier effluent, such as such as compressed, scrubbed gasifier effluent 32) may have a temperature at which the corresponding water vapor pressure is from about 20% to about 60%, and more typically from about 30% to about 50%, of the total pressure of the WGS operation (or highest pressure at which a WGS reactor operates). Analogously, such temperature may be that as needed to provide the same quantity, in terms of water content or water vapor concentration (e.g., from about 20 mol-% to about 60 mol-%, andAtty Docket No. 009503.00059 more typically from about 30 mol-% to about 50 mol-%), in the resulting humidified gasifier effluent, which may serve as the vapor feed to the WGS operation. As described above, such temperature may be determined by an exchange temperature with heat-exchanging steam (e.g., post-shift steam 602a and / or external makeup steam 610), and consequently by the pressure of this steam, used for indirect heat transfer.

[0085] The pressure of humidifying water source 500 may be substantially the same as that of the gasifier effluent with which it is combined, for example substantially the same as that of compressed, scrubbed gasifier effluent 32 at gas / liquid mixer 505 used for combining and distributing the gas 32 and liquid 500 streams, as illustrated in FIG. 2. This pressure may likewise be substantially the same as that of the evaporator (e.g., operating as a high-pressure evaporator) and of the WGS operation (or highest pressure at which a WGS reactor operates). As a result of feeding humidifying water source 500, either to the gasifier effluent (e.g., via gas / liquid mixer 505) and / or directly to evaporator 88, the humidified gasifier effluent may be saturated or have a water content of at least about 80%, or at least about 90%, of saturation, i.e., a relative humidity of these nominal percentages. This characteristic, in terms of water content expressed as a percentage of the saturation water content, is likewise applicable to the vapor feed to the WGS operation, optionally following one or more posthumidifying operations. In contrast, the gasifier effluent (e.g., compressed, scrubbed gasifier effluent 32) being fed to evaporator 88 and prior to being humidified (e.g., at the point of being combined with the humidifying water source) may have a significantly lower water content, such as a water content of less than about 10 mol-%, and more typically less than about 5 mol-%. Such low water contents are more particularly representative of a compressed gasifier effluent having been subjected to pre-shift compression operation 85a, or a compressed, scrubbed gasifier effluent, having been subjected to both a scrubbing operation and a pre-shift compression operation, with compression generally requiring water removal (dehydration).

[0086] In some embodiments, pre-shift steam or post-shift steam typically has a pressure of less than about 100 bar (e.g., from about 30 bar to about 100 bar), less than about 95 bar (e.g., from about 50 bar to about 95 bar), or less than about 90 bar (e.g., from about 60 bar to about 90 bar). Accordingly, pre-shift steam or post-shift steam may be suitable for use in conjunction with, or for combining with, other generally available steam (e.g., high-pressure steam) at comparable pressures, which may serve as external makeup steam 610 (not specifically illustrated in FIG. 2 for the sake of simplicity), to fulfill heating requirements of evaporatorAtty Docket No. 009503.0005988 if necessary. It can therefore be appreciated that the humidifying water source may have a temperature that is obtained by indirect heat exchange with steam, such as pre- shift steam and / or post-shift steam, as an indirect heat exchange medium, having a pressure in a range as described above, and generally less than (i) about 100 bar, (ii) the highest pressure of WGS operation 80a, and / or (iii) the pressure of humidifying water source 500 (e.g., measured as the discharge pressure of water feed pump 550). At least a portion of this steam may be generated from (i) cooling of the WGS product, (ii) other heat recovery operations, including other post-shift heat recovery operations, and / or (iii) pre-shift heat recovery operations. Advantages of the invention are associated with the ability to perform the WGS operation at high pressure, leading to reductions in electricity (compression) costs as described herein, without requiring steam pressures exceeding those of the WGS operation and / or those typically available (e.g., exceeding 100 bar) as utilities. According to some embodiments, the WGS operation may have a pressure (or pressure at which at least one WGS reactor operates) from about 50 bar to about 150 bar, and more typically from about 75 bar to about 100 bar, in the case of a high-pressure WGS operation. Insofar as other advantages may reside in medium-pressure WGS operation, the WGS operation may have a pressure (e.g., a pressure at which at least one WGS reactor operates) from about 10 bar to about 45 bar, and more typically from about 25 bar to about 40 bar.

[0087] The use of evaporator 88 provides humidified gasifier effluent 33, having a higher water content relative to the feed to evaporator 88, such as compressed, scrubbed gasifier effluent 32. The increased water content is favorable in terms of a process step comprising subjecting humidified gasifier effluent 33 to subsequent WGS operation 90a, optionally following one or more post-humidifying operations upstream of this operation. For example, such operations can include sulfur addition 331 and / or preheating 335 to further align characteristics of the humidified gasifier effluent with conditions, in terms of sulfur content and / or temperature, that are favorable for reactors and / or catalyst systems used in WGS operation 90a (e.g., for one or more WGS reactors and / or one or more hydrolysis reactors).

[0088] As illustrated in FIGS. 1 and 2, further beneficial process integration may be realized in the case of humidifying water source 500 comprising pre-shift condensate (z.e., condensate that is generated or recovered upstream of WGS operation 90a). Examples include pre-shift condensate 501a generated in scrubbing operation 80a, pre-shift condensate 501b generated in pre-shift heat recovery operation 101 (e.g., downstream of scrubbing operation 80a, for recovering heat from scrubbed gasifier effluent 30), and / or pre-shift condensate 501cAtty Docket No. 009503.00059 generated in compression operation 85a. As more specifically illustrated in FIG. 2, pre-shift condensate 501a may be generated in scrubber wash column 801, downstream of scrubber 80. Also, pre-shift condensate 501c may be generated from interstage condensate removal 851 from compressor 85. To the extent that humidifying water source 500 may comprise preshift condensate generally, humidified gasifier effluent 33 may comprise vaporized, pre-shift condensate. Alternatively, or in combination, humidifying water source 500 may comprise post-shift condensate (z.e., condensate that is generated or recovered downstream of WGS operation 90a). Examples include post-shift condensate 502a generated in WGS operation 90a and / or post-shift condensate 502b generated in post-shift heat recovery operation 102 (e.g., downstream of WGS operation 90a, for recovering heat from WGS product 34). Whereas post-shift condensate 502a is not specifically illustrated in FIG. 2 for the sake of simplicity, such condensate may be generated from cooling of any feed to, or effluent from, a WGS reactor or hydrolysis reactor utilized in WGS operation 90a, which, as noted above, may be considered in some embodiments a WGS / hydrolysis system 90a. Such condensate, as in the case of other examples of pre-shift condensate or post-shift condensate as noted above, may advantageously be recovered and utilized to provide at least a portion of humidifying water source 500.

[0089] Any pre-shift condensate (e.g., 501a, 501b, 501c) or post-shift condensate (e.g., 502a, 502b) may be formed in a heat recovery operation, such as a respective pre- shift heat recovery operation (e.g., 101) or post-shift heat recovery operation (e.g., 102). Heat recovered in such operation, from a process stream being cooled to form condensate, may be transferred elsewhere to the process, such as for drying of carbonaceous feed 10 in feed dryer 1000. In some cases, a pre-shift heat recovery operation or post-shift heat recovery operation may comprise cooling of a process stream (e.g., via indirect heat exchange with cooling water or air), without necessarily utilizing the recovered heat. In particular embodiments, compression of a process stream, as well as its preparation for compression, may be associated with the formation of pre-shift condensate or post-shift condensate. For example, as illustrated in FIGS. 1 and 2, compression operation 85a, including compressor 85 with interstage condensate removal 851, will generally involve the removal of water, as pre-shift condensate 501c, to facilitate compression. In addition, such water removal / condensate formation may likewise be desirable prior to compression, for example in the case of pre-shift heat recovery operation 101 forming pre-shift condensate 501b. Accordingly, pre-shift condensate and / or post-shift condensate may be formed in an associated compressionAtty Docket No. 009503.00059 operation (e.g., pre-shift condensate may be formed in a pre-shift compression operation and / or post-shift condensate may be formed in a post-shift compression operation). More typically, only pre-shift condensate is formed in a pre-shift compression operation (e.g., in the case of a high-pressure evaporator coupled with a high-pressure WGS operation). Alternatively, or in conjunction, pre-shift condensate and / or post-shift condensate (e.g., preshift condensate 501c) may be formed immediately upstream of an associated compression operation, for example according to phase separation and / or water washing steps (e.g., in preshift heat recovery operation 101) that may be used immediately downstream of a scrubbing operation, or as part of a scrubbing operation. In view of water removal that often accompanies compression, the gasifier effluent being combined with humidifying water source 500, or otherwise being fed to evaporator 88 in conjunction with humidifying water source 500, such as a compressed gasifier effluent, or more particularly a compressed, scrubbed gasifier effluent, may be completely in the vapor phase.

[0090] Representative processes may comprise subjecting the WGS product to one or more postshift operations (e.g., occurring downstream of WGS operation 90a) to provide a conditioned syngas product. For example, such conditioned syngas product may have the same, or substantially the same, FhiCO molar ratio as the WGS product (e.g., in a range as described above), but with contaminants (e.g., acid gases such as CO2) removed and / or with temperature / moisture level adjusted. Such post-shift operation(s) may include a post-shift heat recovery operation, for example occurring as part of WGS operation 90a, and more particularly, in the embodiment illustrated in FIG. 2, utilizing WGS operation heat exchanger 905 for forming post-shift steam 602a. Other post-shift heat recovery operations may likewise form post-shift steam (and may therefore be considered, more particularly, post-shift steam generation operations) or otherwise form post-shift condensate (and may therefore be considered, more particularly, post-shift condensate generation operations, or post-shift water removal operations), such as in the particular case of post-shift heat recovery operation 102 forming post-shift condensate 502b. Other post-shift operation(s) may include acid gas removal operation 95, and / or a post-shift compression operation (not shown in the figures). In the case of a combination of post-shift operations being used, these may be performed in any order.

[0091] By using compression operation 85a (e.g., including at least a single stage of compression, but more typically multiple stages) upstream of evaporator 88, it is possible for WGS operation 90a (including one or more WGS reactors, as well as hydrolysis reactor 915 of aAtty Docket No. 009503.00059 component hydrolysis operation), and post-shift operation(s) such as acid gas removal operation 95 to operate with the same or approximately the same (e.g., accounting for normal pressure drop) pressure. In some embodiments, both WGS operation 90a (including its one or more WGS reactors and one or more hydrolysis reactors) and acid gas removal operation 95 (including one of more of its component adsorption or desorption columns) may each have a pressure from about 50 bar to about 150 bar, and more typically from about 75 bar to about 100 bar. Advantageously, such pressures may be maintained with a single, pre-shift compression operation, which may likewise be used to maintain a pressure within this range, and being approximately the same (e.g., accounting for normal pressure drop) as other postshift operations, with respect to any downstream syngas conversion operation or syngas separation operation, such as a downstream methanol synthesis operation. In this regard, such a compression operation, upstream of the WGS operation, advantageously avoids incurring pressure losses associated with the WGS and hydrolysis reactions, optionally further in combination with acid gas removal, at lower pressures that would result in the need for higher compression ratios.

[0092] 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 syngas conversion operation 97 (FIG. 2) or syngas separation operation 97 (FIG. 2), thereby providing respective renewable syngas conversion product 38 (FIG. 2) or renewable syngas separation product 38 (FIG. 2). 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.

[0093] Overall, aspects of the invention relate to the implementation of strategies for valuable integration of heat and / or material (e.g., condensate) sources, available in gasification processes, to meet at least some of the operational demands of an evaporator that may advantageously provide effective humidification of a gasifier effluent, for efficient generationAtty Docket No. 009503.00059 of hydrogen via the WGS reaction. Those skilled in the art, having knowledge of the present disclosure, will recognize that various changes can be made to the disclosed 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

Atty Docket No. 009503.00059CLAIMS:

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) optionally following one or more intervening operations, increasing an amount of water vapor in the gasifier effluent to provide a humidified gasifier effluent;(c) subjecting the humidified gasifier effluent to a water-gas shift (WGS) operation to convert at least a portion of the water vapor to hydrogen, said hydrogen being present in a WGS product of the WGS operation.

2. The process of claim 1, wherein, in step (b), increasing the amount of water vapor in the gasifier effluent comprises combining a humidifying water source with the gasifier effluent.

3. The process of claim 2, wherein, in step (b), increasing the amount of water vapor in the gasifier effluent comprises feeding the gasifier effluent and the humidifying water source to an evaporator.

4. The process of claim 3, wherein the evaporator operates using both (i) indirect heat exchange, with an indirect heat exchange medium transferring heat to the humidifying water source and (ii) direct heat exchange between the humidifying water source and the gasifier effluent.

5. The process of any one of claims 2 to 4, wherein the humidifying water source has temperature from about 200°C (392°F) to about 300°C (572°F) and an absolute pressure from about 60 bar to about 100 bar.

6. The process of any one of claims 2 to 5, wherein the humidifying water source has a temperature that is obtained by transferring heat recovered from the process.

7. The process of claim 6, wherein said heat is recovered from the WGS product.Atty Docket No. 009503.000598. The process of claim 7, wherein said heat is recovered by generating post-shift steam from cooling of the WGS product and transferring heat is performed by indirect heat exchange between said post-shift steam and said humidifying water source.

9. The process of any one of claims 2 to 8, wherein the humidifying water source has a temperature that is obtained by indirect heat exchange with pre-shift or post-shift steam, as an indirect heat exchange medium, having a pressure of less than about 100 bar.

10. The process of any one of claims 2 to 9, wherein the humidifying water source has a temperature at which a corresponding water vapor pressure is from about 30% to about 50% of a pressure of the WGS operation.

11. The process of any one of claims 1 to 10, wherein the humidified gasifier effluent is saturated or has a water content of a least about 90% of saturation.

12. The process of any one of claims 1 to 11, wherein the humidified gasifier effluent has a temperature that is increased, relative to that of the gasifier effluent.

13. The process of any one of claims 1 to 12, wherein the humidified gasifier effluent has a temperature from about 180°C (356°F) to about 315°C (599°F), preferably from about 200°C (392°F) to about 260°C (500°F).

14. The process of any one of claims 1 to 13, wherein the gasifier effluent has a temperature from about 35°C (95°F) to about 175°C (347°F), preferably from about 70°C (158°F) to about 140°C (284°F).

15. The process of any one of claims 1 to 14, wherein both the gasifier effluent and the humidified gasifier effluent have a pressure that exceeds a pressure of the WGS operation.

16. The process of any one of claims 1 to 15, wherein the WGS operation has a pressure from about 50 bar to about 150 bar, preferably from about 75 bar to about 100 bar.

17. The process of any one of claims 1 to 16, wherein the gasifier effluent has a water content of less than about 10 mol-%, and preferably less than about 5 mol-%.Atty Docket No. 009503.0005918. The process of any one of claims 1 to 17, wherein the humidifying water source comprises pre-shift condensate, recovered upstream of the WGS operation, or post-shift condensate recovered downstream of the WGS operation.

19. The process of claim 18, wherein the pre-shift condensate or the post-shift condensate is formed in a heat recovery operation.

20. The process of claim 18, wherein the pre-shift condensate or the post-shift condensate is formed in a compression operation and / or formed immediately upstream of the compression operation.

21. The process of any one of claims 1 to 20, wherein the gasifier effluent is a compressed gasifier effluent, having been subjected to a pre-shift compression operation.

22. The process of any one of claims 1 to 21, wherein the gasifier effluent is completely in a vapor phase.

23. The process of any one of claims 1 to 22, wherein the WGS product has a thiCO molar ratio from about 1.0 to about 3.0.

24. The process of any one of claims 1 to 23, further comprising subjecting the WGS product to one or more post-shift operations to provide a conditioned syngas product.

25. The process of claim 24, wherein the one or more post-shift operations are selected from the group consisting of a post-shift heat recovery operation, an acid gas removal operation, a post-shift compression operation, and combinations thereof.

26. The process of claim 25, wherein the WGS operation and an acid gas removal operation each have a pressure from about 50 bar to about 150 bar, preferably from about 75 bar to about 100 bar.

27. The process of any one of claims 1 to 26, wherein the one or more intervening 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, and a pre-shift compression operation.Atty Docket No. 009503.0005928. The process of claim 27, wherein the one or more intervening operations include both a scrubbing operation and a pre-shift compression operation.

29. The process of any one of claims 1 to 28, wherein step (c) comprises subjecting the humidified gasifier effluent to the WGS operation, following one or more posthumidifying operations upstream of the WGS operation.

30. The process of claim 29, wherein the one or more post-humidifying operations upstream of the WGS operation include sulfur addition to, and / or preheating of, the humidified gasifier effluent.

31. 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) optionally following one or more intervening operations, combining liquid water with the gasifier effluent to provide a humidified gasifier effluent having an increased content of water vapor relative to the gasifier effluent, wherein the combining is performed by pumping the liquid water, wherein the humidified gasifier effluent is subjected to a water-gas shift (WGS) operation, and wherein at least a portion of an elemental hydrogen content of the liquid water is used to generate hydrogen in the WGS operation, said hydrogen being present in a WGS product of the WGS operation.

32. The process of claim 31, wherein pumping the liquid water increases a pressure of the liquid water to a pressure equal to or exceeding a pressure of the WGS operation.

33. The process of claim 31 or 32, wherein the combining comprises contacting the liquid water and the gasifier effluent, within and / or upstream of, an evaporator.

34. The process of claim 33, wherein the combining comprises contacting at least a portion of the liquid water and the gasifier effluent, in a gas / liquid mixer upstream of the evaporator.Atty Docket No. 009503.0005935. The process of any one of claims 31 to 34, wherein, prior to combining the liquid water with the gasifier effluent, at least a portion of the liquid water is recovered from the process, upstream of and / or downstream of, the WGS operation.

36. 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) optionally following one or more intervening operations, subjecting the gasifier effluent to a water-gas shift (WGS) operation to convert water vapor in the gasifier effluent to hydrogen, said hydrogen being present in a WGS product of the WGS operation, wherein at least a portion of the water vapor is provided from evaporating water that is recovered from upstream of and / or downstream of the WGS operation.

37. The process of claim 36, wherein the water is used to humidify a WGS feed to the WGS operation.

38. The process of claim 37, wherein the WGS feed is a humidified gasifier effluent, provided from an evaporator, optionally following one or more post-humidifying operations upstream of the WGS operation.

39. The process of any one of claims 36 to 38, wherein at least a portion of the water recovered from upstream of and / or downstream of the WGS operation is pre-shift condensate or post-shift condensate that is (i) formed in a heat recovery operation and / or (ii) formed in, or formed immediately upstream of, a compression operation.

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