Increasing process flexibility in gasification

Abstract

Gasification processes utilizing carbonaceous feeds, and preferably biomass, are disclosed that can implement one or more strategies for tar and ash management, heat and / or steam integration, and by-product utilization to address many challenges that may often involve conflicting requirements regarding conditions (especially temperature) and composition. For example, a combination of direct and indirect cooling, along with other equipment, can avoid the need for a radiant syngas cooler to mitigate ash buildup. Alternatively, or in combination, available process heat and process steam can be utilized to achieve acceptable temperature and humidity levels in the syngas subjected to water-gas shift. Still other benefits arise from directly processing materials from gaseous or liquid by-products of downstream conversion or separation via combustion and / or conversion to improve heat integration and / or carbon utilization. Specific approaches utilize residence time variation, generated steam integration, cross-heat exchange, by-product utilization, and / or treated water recycling in the production of syngas or its downstream conversion products (e.g., hydrocarbons or methanol) to improve process flexibility and / or economics.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims priority to U.S. Provisional Patent Application No. 63 / 425,786, filed November 16, 2022, the contents of which are incorporated herein by reference in their entirety.

[0002] Aspects of the present invention relate to gasification processes where process flexibility and / or efficiency are increased through many possible operating strategies, including temperature / residence time management for tar conversion, heat integration, and utilization of by-products obtained from downstream conversion and separation of syngas produced by gasification. [Background technology]

[0003] Coal gasification has been carried out industrially for over 100 years to produce synthesis gas (syngas), which can be further processed into transportation fuels. More recent efforts to develop energy independence with reduced greenhouse gas emissions have led to significant interest in using biomass as a gasification feed and thereby a potential alternative source of synthesis gas and its downstream conversion products. Generally, biomass gasification is carried out by partial oxidation in the presence of a suitable oxidizing gas containing oxygen and possibly other components, such as steam. Gasification at high temperature and pressure, optionally in the presence of a catalytic material, produces an effluent containing hydrogen and oxides of carbon (CO, CO), and hydrocarbons such as methane. This effluent, often referred to as synthesis gas given its H and CO content, must be significantly cooled and treated to remove many undesirable components, which may include particulates, alkali metals, halides, and sulfur compounds, in addition to gasification by-products generally referred to as tar and oil. Additionally, downstream conversion of syngas to value-added products often requires an increase in hydrogen content relative to that available from gasification alone.

[0004] The economics of biomass gasification and the effective utilization of the produced syngas to obtain desired end products are influenced by many complex and interrelated process objectives and associated equipment requirements. For example, undesired tar components in the gasifier effluent may contain fused-ring molecules such as naphthalene and pyrene, posing significant challenges because such high-boiling molecules tend to condense from the vapor phase on cold surfaces they come into contact with downstream of the gasifier. Physical deposition of tar and oil is known to cause fouling / clogging of process lines, valves, reactors, and other equipment. For these reasons, pyrolysis of tar is commonly performed, which in turn requires sufficient temperatures to cause melting or slagging of ash present in the syngas obtained from biomass gasification. Like the tar itself, the "sticky" ash is known to deposit and clog downstream equipment operating at lower temperatures, including equipment used to upgrade the syngas to end products. Radiant synthesis gas coolers (RSCs), with the capability to treat and remove molten by-products, are seen as a promising means to address this problem, but at a significant cost.

[0005] In order to use the synthesis gas for many subsequent reactions, the molar ratio of H2:CO must be increased, which is why the exothermic water-gas shift (WGS) reaction gas:

[0006]

number

[0007] are widely used for this purpose. The thermodynamic properties of this reaction favor a shift in equilibrium toward hydrogen production at low temperatures, which is generally unfavorable from a kinetic standpoint. Another factor affecting performance is the concentration of steam in the WGS reaction feed, which favors the intended H2 production. However, operations performed to purify the gasifier effluent or syngas in preparation for the catalytic WGS reaction can lead to significant cooling of the stream and / or cause dehydration, thereby sacrificing process efficiency to later "restore" the conditions necessary to achieve acceptable conversion levels and associated hydrogen concentrations. For example, such treatment occurs when syngas produced in a gasifier is treated at high temperatures to remove tars and oils, and then scrubbed to remove moisture and water-soluble contaminants, resulting in a significant reduction in the heat and moisture content of the gas.

[0008] Thus, numerous technical challenges exist with respect to the requirements for heating, cooling, removal of tars and other contaminants, and adjustment of the H:CO molar ratio, necessary to obtain a syngas product suitable for downstream conversion to higher-value products. These include liquid hydrocarbons and / or oxygenates (e.g., alcohols) with different carbon numbers as produced according to the Fischer-Tropsch synthesis reaction. These also include methanol produced via catalytic methanol synthesis and renewable natural gas (RNG) or biomethane produced via catalytic methanation. Conversion of syngas according to these and other reactions also generally results in gaseous and / or liquid by-product streams that can cause inefficiencies due to yield losses. The current state of the art would benefit from improved flexibility and / or efficiency to alleviate the constraints imposed by these and other factors, which often involve conflicting processing objectives. Summary of the Invention

[0009] Aspects of the present invention relate to the discovery of a gasification process that utilizes a carbonaceous feed, preferably biomass, which can implement one or more strategies for tar and ash management, heat and / or steam integration, and effective utilization of by-products to address many of the challenges in the prior art, including those discussed above.

[0010] A more specific embodiment relates to addressing the effects associated with the higher reactivity of biomass compared to coal, and is associated with reducing the gasification temperature by approximately 300° C., which typically ranges from 750° C. to 1050° C. This lower gasification temperature, in combination with the higher content of volatile components in biomass, results in the significant production of tars, which, as noted above, include naphthalene and pyrene, and more generally, volatile compounds with two or more carbon atoms (e.g., C2 + The tar contains molecules with a high molecular weight (Hydrocarbon) which, upon cooling, can cause blockage problems downstream of the gasifier (either directly or by further reaction to form higher molecular weight by-products). Additionally, the process performed to pyrolyze this tar requires temperatures of approximately 1300°C, which is significantly higher than the gasifier temperature and sufficient to cause melting and / or slagging of ash present in the tar-rich syngas stream or gasifier effluent. This molten material or slag itself also poses a potential source of equipment fouling and blockage due to deposition at lower temperatures downstream. The use of a sufficiently large sized radiant syngas cooler (RSC) is considered as one possible means of separating the slag via a quench chamber at the bottom of the unit, but this would be very expensive.

[0011] To address these effects and related issues, i.e., tar and ash blockage / deposition, while potentially avoiding the expense of RSC, the temperature and / or residence time in the post-gasification tar removal operation can be effectively managed. This allows the tar removal operation to be "tuned" to the current state of the gasifier effluent or to a specific additional carbonaceous feed, advantageously reducing the temperature (or peak temperature) to which ash present in the gasifier effluent, such as raw gasifier effluent, is subjected while still achieving an effective degree of tar removal, if desired. The ability to increase the residence time of tar conversion can allow for such temperature reductions if tar breakthrough does not occur or otherwise remains at an acceptably low level. In an exemplary process, thermal reforming of tar can be performed immediately after the gasifier, i.e., directly on the gasifier effluent, to produce additional synthesis gas; in particular, the tar removal operation utilizes a high-temperature oxygen burner (HOB) in a partial oxidation (Pox) reactor. Downstream of, or as part of, this or other reactors in the tar removal operation, a tar conversion residence vessel (TCRV) with additional capacity can be used to provide the additional residence time (e.g., 15-60 seconds) necessary to completely or substantially completely decompose (convert) the tar prior to subsequent cooling of the gasifier effluent. Advantageously, the additional residence time via this TCRV effectively incorporates a "knob" into the reactor used for tar removal, allowing the reactor to operate at variable temperatures (e.g., 950°C-1350°C) as controlled by the overall temperature / residence time profile and the ability of these tar conversion conditions to reform the tar to the desired extent and produce H, CO, and CO.

[0012] Without the ability to modify this residence time, the typical effect of lowering the temperature is simply to increase the tar "slip" and C2 remaining in the tar-depleted gasifier effluent exiting the tar removal (e.g., tar reforming) operation. +This manifests as an increase in the number of components. However, using effective temperature / residence time combinations as described herein provides additional operational flexibility to establish conditions suitable for the specific tar component groups and amounts resulting from a particular gasifier run processing a particular carbonaceous feed. Varying residence time also provides the ability to manage (set and maintain) "minimum intensity" conditions that achieve the desired tar reduction while minimizing the generation of undesirable soft, "sticky" ash and slag. If such conditions can minimize the temperature (or peak temperature) used in a given tar removal run, such as one involving Pox, this has the additional beneficial effect of increasing or even maximizing the H:CO molar ratio of the tar-depleted gasifier effluent exiting this run, given the thermodynamics of the WGS reaction. This reduces the performance requirements of subsequent dedicated WGS runs, potentially further improving the overall process economics.

[0013] Downstream of the tar reforming operation, such as immediately after the TCRV in this operation, the tar-depleted gasifier effluent can be subjected to a quenching process, more specifically, a partial dry quench (PDQ) operation, such as by injecting water through the nozzles used in the quenching operation. The quenching process can effectively cool the resulting quenched gasifier effluent below the ash softening temperature, e.g., in the range of 600°C to 750°C, where the ash is no longer "sticky." The quenching process can facilitate the subsequent use of a convective synthesis gas cooler (CSC), which is generally significantly cheaper than an RSC (sometimes only 20-50% of the cost of an RSC). Moreover, a CSC is smaller and cheaper than an RSC, yet can often generate high-pressure steam sufficient to meet the steam demands of the gasifier or WGS, and preferably both of these operations. In this regard, certain aspects of the present invention relate to adding a first portion and / or a second portion of the steam generated in the CSC to the gasifier and / or WGS operation, respectively.

[0014] A further specific embodiment relates to efficiently conditioning the temperature and humidity levels (humidity) of syngas, such as scrubbed gasifier effluent, that is fed to a water-gas shift (WGS) reactor used to increase the hydrogen content, and thus the H:CO molar ratio. In this regard, after initial cooling of the syngas resulting from gasification, a filtration process is typically performed to remove particulates, such as fine ash, unconverted biomass, and / or condensed carbon. At this stage, the temperature and humidity levels are typically suitable for introducing the filtered syngas (e.g., filtered gasifier effluent) into the WGS reactor, but the syngas still typically contains trace amounts of contaminants, such as chlorides, that act as poisons for the catalyst used for the WGS reaction. For example, depending on the level of chloride initially present in the carbonaceous feed (e.g., biomass), the chloride content from compounds such as HCl in the filtered syngas (e.g., filtered gasifier effluent) may exceed 50 ppm, whereas WGS catalysts typically require concentrations of this contaminant to be less than 1 ppm, or even less than 0.1 ppm when operated under substantially sulfur-free conditions such as "sweet shift" catalysts. Chlorides and other water-soluble contaminants can be removed via scrubbing operations, such as wet scrubbing using an aqueous scrubbing medium. However, biomass gasifiers operate at relatively low pressures (e.g., less than 15 bar), which affects the pressures used for downstream cleaning, and the cleaned gasifier effluent, after water-soluble contaminants have been purified, typically has a temperature (e.g., less than 65°C) and moisture content (e.g., less than 5 mol%) that makes it unsuitable as a feed for a WGS reactor, which typically requires an inlet temperature in the range of 225°C to 325°C and a moisture content of more than 40 mol%.

[0015] To address these challenges of efficiently obtaining syngas from gasification (e.g., particularly biomass gasification) and having a suitable temperature, composition (e.g., moisture content), and purity (e.g., chloride and / or sulfur content) for effective use as a feed to a WGS operation, the gasifier effluent exiting a scrubbing operation (e.g., a wet scrubber) can be heat exchanged against a suitable process stream obtained upstream of this operation. For example, a cross heat exchange can be performed between the scrubbed gasifier effluent, or a portion thereof, and the syngas exiting the CSC (e.g., as cooled gasifier effluent, but with a high temperature and corresponding heat content), and optionally after a filtration operation. This cross heat exchange can reduce the requirement for additional heat input upstream of this operation and preferably increase the temperature of the scrubbed product (e.g., effluent heated in the cross heat exchanger) for introduction into the WGS operation without additional heat supply. Further advantageous process integration with a WGS operation may involve adding to the operation steam generated by cooling of gasifier effluent (e.g., unscrubbed gasifier effluent upstream of a scrubbing operation). Any source of such steam, such as that generated in a CSC, may be added directly to the syngas entering the WGS operation or to the reactor of the operation, thereby beneficially increasing the moisture content upstream of and / or within the operation.

[0016] Yet other, more specific aspects relate to the advantageous integration of process streams produced in the downstream conversion and / or separation of synthesis gas (e.g., obtained as a product of a WGS reaction) to produce, for example, renewable liquid conversion products (e.g., liquid hydrocarbons or methanol) or renewable gaseous products (e.g., renewable natural gas (RNG) or renewable hydrogen). For example, converting synthesis gas to Fischer-Tropsch (FT) liquid hydrocarbons and alcohols generally results in the formation of a gaseous by-product stream ("gaseous conversion by-product"), which is typically combusted to recover external process heat due to its moderate heating value. As a further example, separation of synthesis gas to obtain purified hydrogen generally results in the formation of a gaseous by-product stream ("gaseous separation by-product"), thus producing, in the case of separation by pressure swing adsorption (PSA), a tail gas enriched in non-hydrogen components in the synthesis gas (e.g., CO, CO, HO, and possibly methane) in addition to high-purity hydrogen. However, combustion of these and other gaseous by-products of downstream conversion / separation of syngas, as well as liquid by-products, represents a low efficiency utilization of their energy and carbon content.

[0017] Using gaseous and liquid by-products produced from syngas conversion and separation operations (e.g., occurring downstream of the WGS operation) as fuel for direct heating in a tar removal operation (e.g., HOB) and / or as a feed to the process itself improves integration and efficiency. Recovering such by-products for purposes within the gasification process, rather than as an indirect heat source, may involve combusting at least a portion (e.g., a first portion) of a given gaseous or liquid by-product in downstream conversion or separation in the HOB, and / or feeding at least a portion (e.g., a second portion in excess of the HOB's fuel requirements) to a gasifier, e.g., a gasifier reactor freeboard and / or into a fluidized particle bed of such a reactor. In this way, additional synthesis gas can be provided (optionally in conjunction with suitable adjustment of the oxygen requirements of the process) by directly introducing one or more by-products of the synthesis gas conversion or separation operation, thereby increasing the overall synthesis gas yield and also increasing the overall carbon recovery, both in the synthesis gas and in the renewable synthesis gas conversion or separation products themselves.

[0018] Thus, advantages according to these and other aspects of the present invention can be seen over prior art where tar in the gasifier effluent is reformed at temperatures of about 1300°C or higher, subjecting ash in the syngas to softening or slag-forming conditions. According to process configurations described herein, such as those utilizing both direct and indirect cooling (e.g., dry quench operations such as PDQ in conjunction with CSC), expensive RSCs traditionally required to mitigate ash buildup in the steam generators of the present systems can be avoided; i.e., RSCs may not be present in typical processes. Further advantages can be achieved in terms of addressing issues related to the low temperature and low moisture content of the syngas exiting the scrubber in certain processes that rely on external heat sources and / or steam addition to provide acceptable WGS characteristics. Still other advantages can result from adding materials from gaseous or liquid by-products of syngas conversion or separation operations directly to the process for combustion and / or conversion to improve heat integration and / or carbon utilization.

[0019] Accordingly, certain embodiments of the present invention relate to processes for the gasification of carbon-based feeds such as biomass, which may include, for example, various forms of wood (e.g., wood chips or wood pellets), wood (e.g., wood waste), municipal solid waste (MSW), plastics (e.g., plastic waste), and other waste materials (e.g., agricultural waste), which processes benefit from increased processing flexibility and / or management of process streams in various ways as described herein. Gasification, followed by downstream conversion and / or separation of the produced syngas, may produce renewable fuels, including liquid hydrocarbons (e.g., sustainable aviation fuel or RNG) or methanol (e.g., for marine fuel), or otherwise produce renewable hydrogen. Exemplary processes may utilize thermal conversion of tars in the gasifier effluent, with mitigation of ash deposition; use of steam recovered in the CSC in the gasifier and / or WGS operation; recovery of heat from the gasifier and / or downstream tar removal operation for input into the cleaned gasifier effluent prior to the WGS operation; and / or recycling at least a portion of gaseous or liquid by-products generated in the downstream conversion of syngas or downstream separation of syngas back into the process (e.g., gasifier or tar removal operation).

[0020] These and other embodiments, aspects, and advantages of the present invention will become apparent from the detailed description that follows.

[0021] Exemplary embodiments of the present invention and their advantages may be more fully understood by referring to the following description taken in conjunction with the accompanying drawings. [Brief explanation of the drawings]

[0022] [Figure 1]The figure depicts a flow diagram illustrating one embodiment of a process for gasification of a carbon-based feed, which employs several possible aspects described herein to improve process flexibility through tar and ash management, heat and / or steam integration, and / or by-product (e.g., tail gas and / or sour water) utilization. While multiple features are illustrated and described in a single figure for simplicity, it should be understood that not all features (e.g., every individual operation and its associated process streams and equipment) are required, and various specific features, such as residence time variation, generated steam integration, heat cross-exchange, by-product utilization, and treated water recycling, can be implemented independently of other features.

[0023] For ease of explanation and understanding, the figures provide an overview of these and other features for implementation in a gasification process. Some associated equipment, such as specific vessels, heat exchangers, valves, instrumentation, and utilities, is not shown because their specific description is not essential to the implementation or understanding of various aspects of the invention. Such equipment will be readily apparent to one of ordinary skill in the art with knowledge of this disclosure. Other processes for producing conversion products, such as synthesis gas and / or renewable liquids, according to other embodiments within the scope of the invention, and for having components configured and partially determined according to specific processing objectives, will likewise be apparent. DETAILED DESCRIPTION OF THE INVENTION

[0024] As used herein, the expressions "wt. %" and "mol. %" are used to denote weight percentage and mole percentage, respectively. The expressions "wt-ppm" and "mol. ppm" denote weight and mole fraction, respectively. For an ideal gas, "mol. %" and "mol. ppm" correspond to volume percent and parts per million by volume, respectively.

[0025] As used herein, the term "substantially" refers to an extent of at least 95%. For example, the phrase "substantially all" can be substituted with "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." Similarly, designated portions such as a "first portion" or a "second portion" can represent these percentages of the whole (but not all), and particularly these percentages of the whole (but not all) process stream to which they refer.

[0026] In the case of a continuous process, reference to any starting material, intermediate product, or final product, preferably all of which are process streams, 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 due to sampling, purging, diversion for other purposes, mechanical losses, etc. Thus, for example, the phrase "subjecting the gasifier effluent to a tar removal operation" should be understood to mean "subjecting all or a portion of the gasifier effluent to a tar removal operation." Even when the meaning "all or a portion" is understood, this phrase, when explicitly recited, encompasses specific and preferred embodiments as set forth above.

[0027] The exemplary processes described herein for the gasification of a carbonaceous feed may include multiple unit operations, with one of such operations being performed or occurring “before,” “prior to,” or “upstream of” other such operations, or one of such operations being performed or occurring “after,” “following,” or “downstream of” other such operations. These bracketed phrases, which refer to the order in which one operation is performed or occurring relative to other operations, refer to the overall process flow, as would be understood by one of ordinary skill in the art with knowledge of this disclosure. More specifically, the overall process flow may be defined by the bulk gasifier effluent stream, including both the raw gasifier effluent and scrubbed gasifier effluent bulk streams, and the bulk WGS product stream, which are subjected to the operations defined herein. To the extent that bracketed phrases are used to indicate order, in specific embodiments, these phrases mean that one operation immediately precedes or follows the other operation, although more generally, these phrases do not exclude the possibility of intervening operations. Thus, for example, the phrase "...a WGS operation...downstream of a tar removal operation..." means, according to a specific embodiment, that the water-gas shift (WGS) operation immediately follows the tar removal operation. However, the phrase more generally, and preferably, means that one or more intervening operations may be performed or carried out between these operations (e.g., a quench operation, a convective syngas cooler (CSC), a filtration operation, a cross heat exchange, a scrubbing operation, and compression, according to the embodiment illustrated in the Figures). Thus, to the extent that the representative processes described herein are defined as including particular unit operations, unless otherwise stated or specified (e.g., by using the phrase "consisting of"), such processes do not exclude the use of other operations, whether or not specifically described herein.

[0028] The specific process described herein is defined by a gasifier, a scrubbing operation downstream of the gasifier (e.g., a wet scrubber), and a WGS operation downstream of the scrubbing operation. The gasifier provides a "gasifier effluent," and the WGS operation provides a "WGS product." The term "gasifier effluent" is a general term that refers to gasifier effluent, regardless of whether it has been subjected to one or more operations downstream of the gasifier and upstream of the WGS operation. "Gasifier effluent" may be more specifically designated as "uncleaned gasifier effluent" or "cleaned gasifier effluent," which are also general terms but add more specificity in that they characterize the gasifier effluent depending on whether it has been subjected to a scrubbing operation.

[0029] The terms "gasifier effluent" and "uncleaned gasifier effluent" refer to (i) effluent provided directly by a gasifier, i.e., "raw gasifier effluent"; (ii) raw gasifier effluent that has been subjected to at least a tar removal operation, having a lower concentration of tar and oil relative to the raw gasifier effluent, i.e., "tar-depleted gasifier effluent"; (iii) raw gasifier effluent that has been subjected to at least a dry quench operation, having a lower temperature and higher water content (H2O concentration) relative to the raw gasifier effluent, resulting from direct quenching (e.g., partial quenching) with water, i.e., "quenched gasifier effluent"; and (iv) a lower temperature relative to the raw gasifier effluent, resulting from heat transfer for external steam generation. (v) raw gasifier effluent that has been subjected to at least a filtration operation, i.e., "cooled gasifier effluent," and has a low solid particle content relative to the raw gasifier effluent, i.e., "filtered gasifier effluent," (vi) raw gasifier effluent that has been subjected to a cross heat exchange, and has a low temperature relative to the raw gasifier effluent, resulting from heat exchange with at least a portion of the material removed from the scrubbing operation, i.e., "cross heat exchange cooled effluent," and (vii) raw gasifier effluent that has been subjected to any other operation upstream of the scrubbing operation, whether or not specifically described herein.

[0030] Similarly, the terms "gasifier effluent" and "scrubbed gasifier effluent" encompass more specific terms that designate: (viii) raw gasifier effluent or unscrubbed gasifier effluent that has been subjected to a scrubbing operation to reduce the content of water-soluble contaminants (e.g., chlorides); (ix) raw gasifier effluent or unscrubbed gasifier effluent that has been subjected to compression, having a higher pressure relative to the scrubbed gasifier effluent, i.e., "compressed scrubbed gasifier effluent"; (xi) raw gasifier effluent or scrubbed gasifier effluent that has been subjected to cross heat exchange, having a higher temperature relative to the scrubbed gasifier effluent, resulting from heat transfer with at least a portion of the raw gasifier effluent, such as at least a portion of the material removed from the filtration operation, i.e., "cross heat exchange heated effluent"; and (xii) raw gasifier effluent or scrubbed gasifier effluent that has been subjected to any other operation downstream of the scrubbing operation, whether or not specifically described herein.

[0031] With respect to cross heat exchange, when utilizing a gasifier effluent cross heat exchanger positioned upstream of the scrubbing operation, the feed heated in the cross heat exchanger and the effluent cooled in the cross heat exchanger provide examples of gasifier effluent that may be characterized as unscrubbed gasifier effluent, according to certain embodiments. The feed cooled in the cross heat exchanger and the effluent heated in the cross heat exchanger provide examples of gasifier effluent that may be characterized as scrubbed gasifier effluent, according to certain embodiments. According to specific embodiments, such as those illustrated in the figures, (a) the feed heated in the cross heat exchanger may comprise all or a portion of the filtered gasifier effluent, (b) the feed cooled in the cross heat exchanger may comprise all or a portion of the compressed, scrubbed gasifier effluent, and / or (c) the effluent heated in the cross heat exchanger may comprise all or a portion of the feed to the WGS operation (e.g., to which a steam source may be added prior to this operation).

[0032] "Gasifier effluent," "uncleaned gasifier effluent," and "cleaned gasifier effluent," as well as any of the more specific examples (i)-(xii) of these terms, all encompass products (e.g., flow-through streams) upstream of a WGS operation and, optionally, may be fed to a WGS operation.

[0033] The term "WGS product" is a general term referring to the product of a WGS operation, all or a portion of which may be provided to a syngas conversion operation or a syngas separation operation to provide a renewable syngas conversion product or a renewable syngas separation product as a value-added product, according to certain embodiments. The term "WGS product" encompasses all or a portion of the product provided directly from a WGS operation, or such product after being subjected to purification, such as heating, cooling, pressurization, depressurization, and / or acid gas removal. The terms "syngas" or alternatively "syngas product," insofar as they relate to streams comprising H and CO, are used herein generally to refer to the gasifier effluent, either unscrubbed or scrubbed gasifier effluent, or the WGS product, as defined above.

[0034] Specific 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). The modifiers "syngas conversion" and "syngas separation," and the modifiers "conversion" and "separation," as used in the terms "renewable syngas conversion product," "renewable syngas separation product," "gaseous conversion by-product," "liquid conversion by-product," and "gaseous separation by-product," are intended to more specifically designate the origin of these products and by-products as being obtained from a syngas conversion operation (e.g., including a Fischer-Tropsch reaction stage, a methanol synthesis reaction stage, or a methanation reaction stage) or a syngas separation operation (e.g., including a hydrogen purification stage, such as using pressure swing adsorption (PSA) syngas separation and / or membranes). Any such syngas conversion or syngas separation operation is preferably carried out on the WGS product, which may have an increased, more favorable, H:CO molar ratio from the standpoint of efficiently carrying out the desired conversion or separation. In the terms set forth above to modify products and by-products, the use of the modifiers "separated" and "converted" does not exclude those products and by-products from being obtained from a combination of separation and conversion.

[0035] In achieving various objects and related advantages described herein, certain embodiments of the present invention are directed to a process for the gasification of a carbonaceous feed to produce a syngas product, and / or, optionally, a process for producing downstream renewable syngas conversion products (e.g., liquid hydrocarbons or methanol) or downstream renewable syngas separation products (e.g., purified hydrogen) following reaction or separation of the syngas product. An exemplary process includes contacting a carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier to provide a gasifier effluent containing syngas, H, CO, and gasifier effluent tars, which may otherwise be referred to as tar-containing syngas, tar-laden syngas, or neat gasifier effluent. The process may further include subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the tars in the gasifier effluent and to provide a tar-depleted gasifier effluent. Advantageously, the temperature and / or residence time of the tar removal operation may be adjusted according to the measured amount of tar breakthrough in the gasifier effluent.

[0036] Tar breakthrough can be measured quantitatively or qualitatively (i) immediately downstream of a tar removal (e.g., tar reforming) operation (e.g., by analyzing the tar-depleted gasifier effluent from this operation), or (ii) further downstream, such as after cooling (e.g., in a quench operation and / or CSC). By analyzing the tar-depleted effluent or a downstream gasifier effluent (e.g., uncleaned gasifier effluent as described herein), the level of tar can be determined based on the amount (weight percent or concentration) of benzene, naphthalene, and / or pyrene, as follows: C2 + Based on the total amount of hydrocarbons, C6 + Hydrocarbons and / or C6 +The determination may be based on one or more tar components, such as the total amount of oxygen-containing hydrocarbons. In this regard, it can be understood that any one or more components (specific compounds) known to be present in the tar for a given operation can serve as an indicator of the total tar content and thereby serve as a basis for adjusting the temperature and / or residence time. In the case of a qualitative measurement, this can be performed, for example, by detecting tar condensed on process equipment or components of the condensed tar.

[0037] If the tar downstream of the tar removal operation exceeds a given threshold (e.g., based on the amount of any tar component or the combined amount of two or more components), the intensity of the tar removal operation may be increased by increasing the temperature and / or residence time of the tar removal operation. For example, according to preferred embodiments, only residence time may be modified, such as in the specific case of a tar removal operation utilizing a temperature (e.g., average temperature, or possibly peak temperature) that represents a maximum temperature that must not be exceeded to maintain acceptable properties of the ash generated within the gasifier. Thus, residence time alone, or optionally in combination with temperature, may represent a variable by which the intensity of the tar removal operation may be adjusted to maintain a given performance level.

[0038] More specifically, the temperature and / or residence time can be adjusted to achieve or toward (i.e., toward) a target tar conversion or target amount (weight percentage or concentration) of tar relative to a measured conversion or a measured amount (weight percentage or concentration), i.e., as an indicator of tar breakthrough. That is, the actual measured conversion or measured amount can be calculated or determined based on a determination of either tar or one or more components of tar (e.g., serving as an indicator of the total tar content), as described above. For example, the target conversion can be 90%, 95%, 99%, or other representative percentage representing a threshold conversion level. The target amount can be a target weight percentage or target parts per million by weight of 1000 ppm, 100 ppm, 10 ppm, or 1 ppm by weight, or other representative weight percentage representing a threshold amount. Thus, according to certain embodiments, the intensity of the tar removal operation can be increased (e.g., by increasing residence time alone, optionally in combination with increasing temperature) to achieve or adjust toward a target conversion rate above the measured conversion rate or a target amount below an otherwise measured amount. Conversely, the intensity of the tar removal operation can be decreased (e.g., by decreasing residence time alone, optionally in combination with decreasing temperature) to achieve or adjust toward a target conversion rate below the measured conversion rate or a target amount above an otherwise measured amount.

[0039] Given the adverse effects of ash softening and / or slag formation as a result of exposure to high temperatures, adjusting residence time is particularly beneficial in terms of promoting a desired performance level of the tar removal operation (e.g., based on a measured conversion or a measured quantity, as described above) while minimizing the temperature within the overall selection of temperature / residence time combinations that can be used to achieve performance for a particular operation of a gasifier processing a particular carbonaceous feed. In an exemplary embodiment, the temperature of the tar removal operation may be adjusted to a minimum value to achieve a target conversion or target quantity under the overall conditions of the tar removal operation. Such overall conditions include not only this minimum temperature but also residence time, pressure, carbonaceous feed composition, and other variables that affect the tar removal operation. This minimum temperature may be, for example, a minimum average temperature or a minimum peak temperature, with temperatures measured, for example, across the entire reactor (e.g., a Pox reactor) used in the tar removal operation or otherwise at one or more discrete points within such reactor. The average or peak temperature of the tar removal operation may also include temperatures measured elsewhere in the operation. For example, in some embodiments, the tar removal operation may include a tar conversion residence vessel (TCRV) that can facilitate variation in residence time, and optionally, the temperature of the tar removal operation (e.g., the temperature at which the minimum value is determined) may be based at least in part on one or more temperatures measured within this vessel.

[0040] The TCRV can be positioned immediately downstream of the reactor used in the tar removal operation and can be sized to add a predetermined residence time, i.e., residence time through the TCRV beyond that of the reactor used in the tar removal operation, for further decomposition of the tar and its components through desired reactions (e.g., reforming and / or oxidation). For example, the residence time through the TCRV can be in the range of about 5 seconds to about 5 minutes, such as about 10 seconds to about 2 minutes, or about 15 seconds to about 45 seconds. As described herein, in adjusting the residence time of the tar removal operation (e.g., in response to the measured breakthrough amount of gasifier effluent tar), such adjustment can include or consist (only) of adjusting the residence time through the TCRV. These adjustments nonetheless affect the overall residence time, such as the total or combined residence time of (i) the residence time of the reactor used in the tar removal operation and (ii) the residence time through the TCRV.

[0041] In an exemplary embodiment, adjustment of the reactor residence time may be performed, at least in part, by adjusting the overall material flow (e.g., raw gasifier effluent flow) through the reactor. Adjustment of the residence time through the TCRV may be performed by increasing or decreasing the degree of bypass of the TCRV. For example, a minimum residence time through the TCRV (e.g., no residence time through the TCRV) may be set by completely bypassing the TCRV, while a maximum residence time through the TCRV may be set by completely closing the bypass around the TCRV, thereby causing, for example, the entire reactor effluent used in the tar removal operation to flow through the TCRV. A partial bypass may be used to adjust the residence time through the TCRV between this minimum and maximum value, and thus the residence time of the entire tar removal operation may be adjusted or extended to the extent allowed by this additional “knob.” Thus, the conditions for the tar removal operation include the above-mentioned residence times (i) and (ii) as a fraction of the overall residence time, either or both of which can be adjusted or varied as described herein, preferably to provide additional flexibility in effectively achieving the combined objectives of tar removal and ash (or the effects of ash exposure to high temperatures) management without the need for a radiant syngas cooler (RSC).

[0042] In achieving various other objects and related advantages described herein, other specific embodiments of the present invention are directed to a process for the gasification of a carbonaceous feed to produce a syngas product and / or, optionally, a process for producing downstream renewable syngas conversion products (e.g., liquid hydrocarbons or methanol) or downstream renewable syngas separation products (e.g., purified hydrogen) following reaction of the syngas product. An exemplary process includes contacting a carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier to provide an unscrubbed gasifier effluent as syngas, H, CO, and water-soluble contaminants. These water-soluble contaminants may include poisons (e.g., chlorides, HS) for catalysts used to perform a subsequent water-gas shift (WGS) reaction and / or other undesired by-products (e.g., NH). The process may further include supplying at least a portion of the water-soluble, unscrubbed gasifier effluent to a scrubbing operation to remove at least a portion of the soluble contaminants and provide a scrubbed gasifier effluent.

[0043] The scrubbed gasifier effluent typically has a reduced amount of water (weight percentage or concentration) as well as a reduced amount of water-soluble contaminants (weight percentage or concentration) relative to the corresponding amount in the unscrubbed gasifier effluent (which may be, for example, any syngas product downstream of the gasifier and upstream of the scrubbing operation). The process may also include feeding at least a portion of the scrubbed gasifier effluent to a WGS operation to provide a WGS product having an increased H:CO molar ratio relative to that of the scrubbed gasifier effluent. Advantageously, such a process may further include cross-heat exchange between at least a portion of the scrubbed gasifier effluent and at least a portion of the unscrubbed gasifier effluent. Such cross-heat exchange may provide for efficient utilization of heat within the process (e.g., utilization of heat originally generated in the gasifier and / or tar removal operation) to achieve favorable conditions in the syngas that feeds the WGS operation, and may be effluent heated by a heat exchanger according to certain embodiments.

[0044] In achieving various other objects and related advantages described herein, still other particular embodiments of the present invention are directed to a process for the gasification of a carbonaceous feed to produce renewable syngas conversion products (e.g., liquid hydrocarbons or methanol) or renewable syngas separation products (e.g., purified hydrogen). An exemplary process includes contacting a carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier to provide a gasifier effluent comprising H, CO, and gasifier effluent tar; subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the tar in the gasifier effluent and to provide a tar-depleted gasifier effluent; optionally, following one or more intervening operations downstream of the gasifier, supplying at least a portion of the tar-depleted gasifier effluent to a WGS operation to provide a WGS product having an increased H:CO molar ratio relative to that of the tar-depleted effluent; and supplying at least a portion of the WGS product to (i) a syngas conversion operation to provide a renewable syngas conversion product, or (ii) a syngas separation operation to provide a renewable syngas separation product. According to a representative process, (a) the synthesis gas conversion operation provides gaseous conversion by-products, including unconverted synthesis gas components (H, CO), light hydrocarbons (e.g., CH, CH), and / or other non-condensable gases such as CO, and (b) the synthesis gas conversion operation provides heavy hydrocarbons (e.g., C ... 20 +(c) a synthesis gas separation operation provides a gaseous separation by-product comprising separated synthesis gas components (e.g., tail gas obtained from a pressure swing adsorption (PSA) process used to generate high purity hydrogen, the tail gas being enriched in CO, CO, HO, and possibly non-hydrogen components of synthesis gas such as methane).

[0045] Advantageously, such a process may further include combusting all or at least a portion (e.g., a first portion) of (a) the gaseous conversion by-products in the syngas conversion operation, (b) the liquid conversion by-products in the syngas conversion operation, or (c) the gaseous separation by-products in the syngas separation operation as fuel for the tar removal operation. For example, combustion of the tail gas obtained from the PSA or a portion thereof in the generation of high-purity hydrogen may occur directly in the Pox reactor, such as when fed to a hot oxygen burner (HOB) used in the reactor. According to certain embodiments, in addition to or instead of feeding the first portion of (a), (b), or (c) above as fuel, the process may include feeding a second portion of (a), (b), or (c) above to a gasifier. For example, when feeding both the first and second portions, the latter or second portion of the gaseous or liquid conversion by-products (a) or (b), or the latter or second portion of the gaseous separation by-products (c), may represent an amount in excess of the fuel requirements of the HOB. In either event, direct utilization of such fractions beneficially retains carbon within the process (i.e., provides a route for carbon recycling) for the purpose of improving combustion and / or synthesis gas yields and, consequently, yields of downstream conversion products.

[0046] The exemplary gasification process described herein is defined by various possible operations that occur downstream of the gasifier, which may include tar removal operations, cooling operations such as quenching and / or CSC, filtration operations, cross heat exchange, scrubbing operations, compression, WGS operations, sour water treatment operations, and syngas conversion operations. Specific possible features of the gasifier, as well as these downstream operations and their associated process streams and conditions, are provided in the following description, according to preferred embodiments and any alternative embodiments defined in the claims and illustrated in the figures.

[0047] Gasifier An exemplary process includes contacting a carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier and providing a gasifier effluent (e.g., neat gasifier effluent) comprising synthesis gas.

[0048] The carbonaceous feed may include coal (e.g., high-quality anthracite or bituminous coal, or lesser-quality subbituminous, lignite, or peat), petroleum coke, asphaltenes, and / or mobile petroleum residues, or other petroleum-derived materials. In a preferred embodiment, the carbonaceous feed may include biomass. The term "biomass" refers to renewable (non-petroleum-derived) material derived from living organisms that live on the Earth's surface or in the Earth's oceans, rivers, and / or lakes. Exemplary biomass may include any plant material or mixture of plant materials, such as hardwood (e.g., whitewood), softwood, hardwood or softwood bark, lignin, algae, and / or lemna (seaweed). Energy crops or other agricultural residues (e.g., logging residues), or other types of plant or plant-derived waste, may also be used as plant material. Specific exemplary plant materials include corn fiber, corn stover, and sugarcane bagasse, in addition to "target" energy crops such as switchgrass, miscanthus, and algae. Short-rotation forest products, such as energy crops, include alder, ash, Antarctic beech, birch, eucalyptus, poplar, willow, paper mulberry, Australian blackwood, sycamore, and various oak trees. Other examples of suitable biomass include vegetable oils, carbohydrates (e.g., sugars), organic waste materials such as waste paper, structures, demolition waste, digester sludge, and biosludge. Thus, exemplary carbonaceous feeds include or comprise any of these types of biomass. Specific carbonaceous feeds containing biomass include municipal solid waste (MSW) or MSW-derived products, such as refuse-derived fuel (RDF). Carbonaceous feeds can include combinations of petroleum-derived materials and renewable materials, including those described above. A preferred carbonaceous feed is wood.

[0049] In a gasifier (or, more specifically, the gasification reactor of the gasifier), the carbonaceous feed is subjected to partial oxidation in the presence of an oxygen-containing gasifier feed, typically added in a limited amount to provide only 20-70% of the oxygen required for complete combustion. The oxygen-containing gasifier feed generally includes other oxygenated gaseous components, including HO and / or CO, which may act as oxidizers for the carbonaceous feed. The oxygen-containing gasifier feed may refer to all gases fed to or added to the gasifier, or may refer to gases that are separate from other gases being fed or added, whether or not they are subsequently combined substantially upstream or within the gasifier. For example, the oxygen-containing gasifier feed may be introduced into the gasifier along with steam or a portion of steam generated elsewhere in the process (e.g., steam generated in a CSC) and used as a separate feed. Contacting the carbonaceous feed with the oxygen-containing gasifier feed in the gasifier provides gasifier effluent, and more specifically, neat gasifier effluent as a direct product from the gasifier. One or more reactors (e.g., in series or parallel) of the gasifier may operate under gasification conditions present in such reactors, which generally include temperatures 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 or elevated pressures, such as, for example, absolute pressures of generally from about 0.1 megapascals (MPa) (14.5 psi) to about 10 MPa (1450 psi), typically from about 1 MPa (145 psi) to about 3 MPa (435 psi), or from about 0.5 MPa (72 psi) to about 2 MPa (290 psi).

[0050] Gasification reactor configurations include countercurrent fixed bed ("updraft"), cocurrent fixed bed ("downdraft"), and entrained plasma. Various solid catalysts may be used with different activities for one or more desired functions during gasification, such as tar reduction, H yield enhancement, and / or CO yield reduction. Limestone may be added to the gasification reactor, for example, to promote tar reduction by pyrolysis. Various catalyst materials may be used in the gasification reactor, including dolomite, supported nickel, alkali metals, and solid particles of alkali metal compounds such as alkali metal carbonates, bicarbonates, and hydroxides. Gasifiers are often operated with a gasification reactor having a fluidized bed of particles of carbonaceous feed (and, optionally, particles of solid catalyst), with the oxygen-containing gasifier feed and, optionally, a separate fluidized H2O- and / or CO2-containing feed fed upward through the particle bed. Exemplary types of fluidized beds include bubbling fluidized beds and entrained fluidized beds.

[0051] In addition to gasifier effluent tar, the raw gasifier effluent contains carbon present in the carbonaceous feed, as well as H and / or H O and, generally, CO, CO, and methane (CH), along with trace concentrations of other components, as described below. According to the embodiment illustrated in the figures, raw gasifier effluent 16 may be obtained directly from the gasifier 50 prior to further operations described herein.

[0052] The gasifier effluent, either as is, or any gasifier effluent that has been subjected to one or more of the operations described herein, may contain syngas, i.e., may contain both H and CO, with these components present in various amounts (concentrations) and preferably in a total 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 such total amount (concentration), the H:CO molar ratio of the gasifier effluent may be suitable for use in downstream syngas conversion operations (reaction or separation), such as (i) conversion to renewable syngas conversion products comprising higher molecular weight hydrocarbons and / or alcohols of varying carbon numbers via a Fischer-Tropsch conversion, (ii) conversion to renewable syngas conversion products comprising methanol via a catalytic methanol synthesis reaction, (iii) conversion to renewable syngas conversion products comprising renewable natural gas (RNG) via catalytic methanation to increase the methane content in the resulting RNG stream, or (iv) separation of renewable syngas separation products comprising purified hydrogen. More typically, however, a WGS operation is required to achieve a preferred H:CO molar ratio and / or preferred H concentration for these or other downstream syngas conversion or separation operations. For example, a WGS operation may include parameters (e.g., reactor temperature and / or catalyst type) to obtain maximum yield / concentration of hydrogen through consumption of CO present in the syngas upstream of this operation when purified hydrogen is obtained as a renewable syngas separation product (e.g., by utilizing one or more PSA and / or membrane separation stages).

[0053] Independently of or in combination with the exemplary amounts (concentrations) of H and CO listed above, the gasifier effluent may contain CO in an amount of, for example, at least about 2 mol % (e.g., about 2 mol % to about 30 mol %), at least about 5 mol % (e.g., about 5 mol % to about 25 mol %), or at least about 10 mol % (e.g., about 10 mol % to about 20 mol %). Independently of or in combination with the exemplary amounts (concentrations) of H, CO, and CO listed above, the gasifier effluent may contain CH in an amount of, for example, at least about 0.5 mol % (e.g., about 0.5 mol % to about 15 mol %), at least about 1 mol % (e.g., about 1 mol % to about 10 mol %), or at least about 2 mol % (e.g., about 2 mol % to about 8 mol %). These non-condensable gases, H, CO, CO, and CH, along with any water vapor (H, O), may account for substantially all of the composition of the gasifier effluent. That is, these non-condensable gases, and optionally water, may be present in the gasifier effluent in a combined amount of at least about 90 mole %, at least about 95 mole %, or even at least about 99 mole %.

[0054] Tar removal operation Raw gasifier effluent obtained directly from a gasifier generally contains gasifier effluent tar, which typically requires a tar removal operation for further processing. This gasifier effluent tar can contain compounds referred to in the art as "tar" and "oil," more specifically, hydrocarbons and oxygenated hydrocarbons having molecular weights greater than that of methane, which may be present in the gasifier effluent at concentrations ranging from a few wt-ppm to several weight percent. Certain types of these compounds, which have relatively high molecular weights, are characterized as problematic due to their tendency to condense at low temperatures and coat the internal surfaces of processing equipment downstream from the gasifier, causing undesirable fouling, corrosion, and / or clogging. These compounds can also interfere with subsequent processing steps or syngas conversion operations to upgrade the syngas to higher-value products, which are best performed (e.g., from a stability standpoint) using a high-purity feed gas.

[0055] Certain compounds that are undesirable for this reason include hydrocarbons with six or more carbon atoms and oxygen-containing hydrocarbons (C6 + These compounds typically occur in concentrations of 1-100 g / Nm3 in the raw gasifier effluent. 3 Therefore, removal of these organic compounds (e.g., by conversion) is generally necessary to avoid serious problems caused by their buildup over time. Other types of tar and oil, such as ethane, ethylene, and acetylene, do not condense from the gasifier effluent but nevertheless "bind" hydrogen and carbon, with the effect of reducing the overall yield of H and CO as desired components of syngas.

[0056] Depending on the specific tar removal operation, tar and oil in the raw gasifier effluent can be converted by oxidation, decomposition, and / or reforming, either catalytically or non-catalytically, to provide additional H and CO in the tar-depleted gasifier effluent. Tar conversion reactions can utilize available O or oxygen sources (e.g., HO and / or CO) present in and / or added to the syngas. In terms of gasifier effluent tar, converting these compounds, along with methane, which contains the majority of the energy in the raw gasifier effluent, can substantially increase the overall syngas yield. Thus, according to certain embodiments, a tar removal operation, which may more specifically be a tar conversion operation, can effectively reduce the concentration of compounds present as tars in the raw gasifier effluent produced in the gasifier. Generally, tar removal, and more specifically, tar conversion reactions, may be carried out at higher temperatures compared to those used in the gasifier, such that a tar-depleted gasifier effluent obtained directly from the tar removal operation may have a temperature 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).

[0057] According to an embodiment, a tar removal operation can be used for the conversion (e.g., reforming) of tars and methane through non-catalytic partial oxidation (POX) in a reactor used for this operation. The efficiency of this particular operation can be enhanced using hot oxygen burner (HOB) technology, in which excess oxygen is mixed with a small amount of fuel (e.g., natural gas, propane, or recycled syngas). Combustion of this fuel in the reactor can result in a temperature increase of over 1100°C (2012°F), causing the combustion products and excess oxygen to accelerate to sonic speeds through a nozzle, thereby forming a turbulent jet that improves mixing between the tar / methane-containing syngas and the reactive hot oxygen stream. HOB-based systems can effectively improve syngas yields.

[0058] In the case of tar removal operations utilizing catalytic conversion of tar and methane, the 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 charcoal produced from gasification. As with non-catalytic processes that may be performed in tar removal operations, catalytic tar conversion may similarly include introducing additional oxygen and / or steam reactants into the reactor used in the operation.

[0059] According to certain other embodiments, the tar removal operation may utilize a suitable liquid or solid sorbent to selectively adsorb tar and oil from the raw gasifier effluent. For example, the tar removal operation may be carried out with an oil absorption system, whereby the raw gasifier effluent is passed through (contacted with) a liquid medium, such as a bio-oil liquid, to extract the tar and oil based on their selective solubility. The liquid sorbent may be combusted after being consumed.

[0060] Regardless of the particular manner in which the tar removal operation is performed, the raw gasifier effluent may contain tar and oil (e.g., present as compounds described above) in an amount of about 0.01% to about 5% by weight, e.g., about 0.1% to about 3% by weight, or about 0.5% to about 2% by weight, or in a combined amount. The tar removal operation may be effective to substantially or completely remove this gasifier effluent tar. For example, the tar-depleted gasifier effluent emerging from or obtained directly from this operation may contain tar and oil in an amount of less than about 0.5% by weight, less than about 0.1% by weight, or less than about 0.01% by weight, or in a combined amount. Exemplary levels of tar and oil removal (e.g., by conversion), as measured over 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.

[0061] Quenching operation Thermal gasifier effluent, e.g., tar-depleted gasifier effluent emerging from a tar removal operation, can be cooled by a variety of techniques, including radiant and / or convective heat exchange. In an exemplary embodiment, at least one quench operation, and preferably a dry quench operation, is used, in which water is added directly to the gasifier effluent, contributing to its overall water content and thereby favoring H production via the equilibrium-limited WGS reaction (i.e., to provide an increased H:CO molar ratio and increased H concentration). The dry quench operation utilizes the sensible heat of the gasifier effluent to vaporize the injected water, which is sufficient to obtain a resulting quenched gasifier effluent at the desired cooling temperature. According to a preferred embodiment, when the use of an RSC is avoided, the quenched gasifier effluent has a temperature of about 400°C (752°F) to about 900°C (1652°F), and preferably about 538°C (1000°F) to about 816°C (1500°F), allowing for further processing. This may include sufficient further cooling (e.g., using a CSC) followed by a subsequent filtration operation (passing through a filter) to remove solid particles (e.g., dust). In a preferred embodiment, only partial quenching, rather than complete cooling, is used in the quenching operation, so that the quenched gasifier effluent exiting or obtained directly from the dry quenching operation is above its dew point, i.e., is not saturated. In general, a dry quenching operation can facilitate rapid and efficient cooling through direct contact between the hot gasifier effluent and water or other aqueous quench medium.

[0062] Convection Synthetic Gas Cooler (CSC) As described herein, according to preferred embodiments, combining a syngas (e.g., tar-depleted gasifier effluent exiting a tar removal operation) with a quenching operation characterized by direct contact with a quenching medium, such as water, together with a CSC can provide effective cooling for further downstream operations without relying on an RSC for the required removal of ash and formed slag. For example, a CSC can be used to cool the quenched gasifier effluent exiting the quenching operation to provide cooled gasifier effluent, the quenched gasifier effluent optionally having a temperature within the ranges described above and / or the cooled gasifier effluent having a temperature of about 250°C (482°F) to about 600°C (1112°F), and preferably about 316°C (600°F) to about 399°C (750°F), to enable subsequent filtration. The CSC may operate by indirect heat transfer, such as when it has a shell-and-tube configuration, and typically generates steam from a portion of the heat recovered from the gasifier and tar removal operations. According to further specific embodiments, the CSC operates as a boiler (e.g., a fire-tube boiler or a water-tube boiler) for the generation of high- and / or medium-pressure steam.

[0063] Filtration Operation Filtration operations using any suitable filter may be used to remove solid particles (particulates) from gasifier effluent, such as the cooled gasifier effluent exiting a CSC, as described above. In the case of biomass gasification, these solid particles may include charcoal, tar, soot, and ash, any of which may generally contain alkali metals such as sodium. Corrosive and / or harmful species, such as chlorides, arsenic, and / or mercury, may also be included in such solid particles. For example, high-temperature filtration using a bundle of metal or ceramic filters may generally be sufficient to reduce the solid particle content in the gasifier effluent, thereby providing a filtered gasifier effluent exiting the filtration operation or obtained directly from the filter and having less than 1 ppm by weight, and in some cases less than 0.1 ppm by weight of solid particles. In an exemplary embodiment, the filtered gasifier effluent may have a temperature within the ranges described above for the cooled gasifier effluent.

[0064] In some embodiments, a filtration operation may be performed upstream (before) a tar removal operation, allowing the subsequent operation to be performed more efficiently. Removal of solid particles of various average particle sizes using filtration or other techniques may be performed at any of a number of possible stages within the overall process. For example, removal of coarse solids by centrifugation may be performed immediately downstream of the gasifier and / or may even be performed in situ within the gasifier (e.g., using an internal cyclone to remove solid particles located in the headspace of the fluidized particle bed).

[0065] The filtration operation may be followed by or integrated with an additional cleaning operation to further purify the gasifier effluent, for example, to further reduce its tar and total hydrocarbon content, by contacting it with a solid "abrasive" material such as a carbon bed, which can provide more thorough removal of benzene, naphthalene, pyrene, toluene, phenol, and other condensable species that may adversely affect downstream operations, such as deposition on equipment.

[0066] Cleaning operation A scrubbing operation may be used to remove water and water-soluble contaminants from the unscrubbed gasifier effluent, such as the filtered gasifier effluent exiting the filtration operation, and optionally following cooling of this stream by cross heat exchange. For example, the filtered gasifier effluent may be characterized as a cross heat exchanger-heated feed, providing a cross heat exchanger-cooled effluent, which may be characterized as a feed to the scrubbing operation. The scrubbing operation may provide further cooling of the cross heat exchanger-cooled effluent. For example, the cross heat exchanger cooled effluent, optionally following cooling of the filtered gasifier effluent having temperatures as described above, may have a temperature of from about 200°C (392°F) to about 450°C (842°F), and preferably from about 260°C (500°F) to about 371°C (700°F), while the scrubbed gasifier effluent exiting the scrubber, or optionally following additional compression, the compressed scrubbed gasifier effluent, may be characterized as the cross heat exchanger cooled feed and may have a temperature of from about 35°C (95°F) to about 100°C (212°F), and preferably from about 43°C (110°F) to about 66°C (150°F).

[0067] A scrubbing operation, such as wet scrubbing, can be effective for removing water-soluble contaminants such as chlorides (e.g., in the form of HCl), ammonia, and HCN, as well as fine solid particles (e.g., char and ash). For example, when using a wet scrubber, unscrubbed gasifier effluent (e.g., effluent cooled in a cross heat exchanger) can be fed to a trayed column for cocurrent or countercurrent contact with water. Further cooling in this column, for example to a temperature below 100°C (212°F), can assist in droplet condensation to improve the effectiveness of contaminant removal. A scrubbing operation can be used to provide a scrubbed gasifier effluent exiting or obtained directly from this operation and having a total amount of chlorides, ammonia, less than 1 ppm by weight, and possibly less than 0.1 ppm by weight of solid particles. The scrubbing operation also generally serves to remove water, thereby reducing the water content of the scrubbed gasifier effluent relative to the feed to the scrubbing operation (e.g., effluent cooled in a cross heat exchanger).

[0068] WGS operation The water-gas shift (WGS) operation reacts CO present in the scrubbed gasifier effluent, e.g., heated in a cross heat exchanger downstream of the scrubbing operation following cross heat exchange and, optionally, compression, with steam to increase the H concentration (as well as the CO concentration). In this manner, the effluent heated in the cross heat exchanger may be characterized as a feed to the WGS operation. Advantageously, the effluent / feed heated in the cross heat exchanger to the WGS operation following the tar removal, filtering, scrubbing, and cross heat exchange operations may have favorable properties for use in this operation in terms of its temperature and being free or substantially free of water-soluble contaminants, as described above, as well as tars and particulates. For example, following subjecting the scrubbed gasifier effluent to cross heat exchange heating and, optionally, compression, the cross heat exchanger heated effluent / feed to the WGS operation may have a temperature of from about 225°C (437°F) to about 475°C (887°F), and preferably from about 260°C (500°F) to about 399°C (750°F), while the scrubbed gasifier effluent exiting the scrubber may have a temperature as described above.

[0069] In WGS operations, the use of steam in excess of the stoichiometric ratio can be beneficial for many purposes, especially in adiabatic fixed-bed reactors. These include shifting the equilibrium toward hydrogen production, adding heat capacity to limit the increase in exothermic temperature, and minimizing side reactions such as methanation. In this regard, in addition to the steam present in the feed to the WGS operation, a supplemental steam source can be incorporated into the feed. The supplemental steam source can be readily available through in-process generation or can be external to the process. In a preferred embodiment, at least a portion of the steam generated in the CSC (e.g., high- or medium-pressure steam) can be fed or added to the WGS operation (e.g., one or more reactors used in the operation), thereby improving the overall heat balance / heat integration.

[0070] The reactors used in WGS operations may contain a suitable catalyst, such as one comprising one or more of Co, Ni, Mo, and W on a solid support, specific examples of which are sulfur-tolerant Co / Mo and Ni / Mo catalysts. Other catalysts used in this operation (i.e., contained within one or more WGS reactors) include those based on copper- and / or zinc-containing catalysts, such as Cu-Zn-Al; chromium-containing catalysts; iron oxide; zinc ferrite; magnetite; chromium oxide; and any combination thereof (e.g., Fe2O3-Cr2O3 catalysts).

[0071] In a typical WGS operation, two or more reactors with interstage cooling are used, given the thermodynamic characteristics of the WGS reaction. For example, a high-temperature shift (HTS) reactor may operate at a reactor inlet temperature of about 310°C (590°F) to about 450°C (842°F), with more favorable reaction kinetics and less favorable equilibrium conversion. The effluent from the HTS may then be cooled to a temperature suitable for the reactor inlet of the low-temperature shift (LTS) reactor, such as about 200°C (392°F) to about 250°C (482°F), to provide less favorable reaction kinetics and more favorable equilibrium conversion, so that the combined effect of the HTS and LTS reactors results in high conversion to H2 at favorable residence times. In some cases, it may be desirable to use three or more reactors or catalyst beds to carry out the WGS reaction, again with cooling between successive reactors or catalyst beds.

[0072] In this manner, the WGS operation can be used to provide a direct WGS product exiting or obtained directly from the operation, and having an increased H:CO molar ratio and increased H concentration relative to the feed to the WGS operation (e.g., effluent heated in a cross heat exchanger) or the syngas obtained from an upstream operation (e.g., filtered gasifier effluent or cooled gasifier effluent). For example, the direct WGS product can have an H:CO molar ratio of about 0.5 to about 3.5, about 1.0 to about 3.0, or about 1.5 to about 2.5, and / or a hydrogen concentration of at least about 35 mol% (e.g., about 35 mol% to about 80 mol%), at least about 40 mol% (e.g., about 40 mol% to about 70 mol%), or at least about 45 mol% (e.g., about 45 mol% to about 65 mol%). These properties of the immediate WGS product can be controlled by bypassing the WGS operation more or less (e.g., diverting a small or large amount of the feed to this operation around the operation to provide a portion of the immediate WGS product). The WGS operation can be further beneficial in terms of converting carbonyl sulfide (COS) to HS, which can be recycled and more easily removed elsewhere in the process, such as in an acid gas removal operation, or possibly, at least to some extent, in a scrubbing operation.

[0073] Acidic water treatment operation Acid water treatment operations are used to remove contaminants, such as H2S and NH3, that are present in the acid water by-product of scrubbing operations that utilize aqueous scrubbing media. Typically, a combination of heating and steam stripping of the acid water by-product is used to provide treated water that is substantially free of these contaminants, and a treated water condensate that is concentrated in these contaminants, which can be sent for recovery (e.g., to a sulfur recovery unit to recover H2S). In this regard, another aspect of the invention relates to the use or integration of treated water from the acid water treatment operation in a gasification process, as described herein. For example, treated water resulting from the scrubbing operation may provide all or at least a portion of the quench water for a quench operation used in the process. In this manner, the gasification process can include a water recovery "loop" (or recycled water loop) that includes the quench water input to the quench operation, any intervening operations between the quench operation and the scrubbing operation (e.g., CSC 65, filtration operation 70, and gasifier effluent cross heat exchanger 75 as illustrated in the figure), the sour water by-product of the scrubbing operation, and the treated water provided by the sour water treatment operation. The ability to recover and recycle quench water thereby improves the economics of the process.

[0074] Syngas conversion or separation operations In some embodiments, the processes described herein may also include a syngas conversion or separation operation to produce renewable syngas conversion or separation products, such as liquid hydrocarbons, methanol, or RNG as example conversion products and purified hydrogen as example separation products. In the case of liquid hydrocarbon production, the syngas conversion operation may include a Fischer-Tropsch (FT) reaction stage. One or more reactors in this stage are used to process a syngas mixture of hydrogen (H) and carbon monoxide (CO) by sequential cleavage of C-O bonds and formation of C-C bonds with the incorporation of hydrogen. This mechanism produces hydrocarbons, particularly linear alkanes, whose molecular weight distribution can be controlled to some extent by modifying the FT reaction conditions and catalyst properties. Such properties include pore size and other characteristics of the support material. The selection of the FT catalyst and its active metal (e.g., Fe or Ru) can also affect the yield of FT products in other ways, such as the production of oxygen-containing compounds.

[0075] In the case of methanol production, the syngas conversion operation may include a methanol synthesis reaction stage in which one or more reactors are used to form methanol according to the following catalytic reaction: CO+2H2→CH3OH(1) A representative catalyst for the synthesis of methanol by this route is characterized as "CZA," referring to copper and zinc on alumina, or Cu / ZnO / Al2O3. Alternatively, or in combination, various other catalytic metals and their oxides can be used, including one or more of W, Zr, In, Pd, Ti, Co, Ga, Ni, Ce, Au, Mn, and combinations thereof.

[0076] In the case of methanation 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 react CO and / or CO with hydrogen and thereby provide a hot methanation product having a significantly higher methane concentration relative to the methane concentration initially present (e.g., in the WGS product). Suitable catalysts for use in methanation reactors include ruthenium and / or other noble metals, and supported metals such as molybdenum and tungsten. However, supported nickel catalysts are generally the most cost-effective. Often, methanation reactors are operated using a fixed bed of catalyst.

[0077] In the case of a purified hydrogen product, the syngas separation operation may include a renewable hydrogen separation stage, which may utilize, for example, (i) an adsorbent in the case of PSA separation, or (ii) a membrane. A combination of such stages may be used in a given syngas separation operation. In any such operation, a gaseous separation by-product is also provided, generally enriched in non-hydrogen components of the syngas, such as CO, CO, and / or HO. This by-product may be, for example, a PSA tail gas or a membrane permeate or retentate, depending on the particular membrane used and, consequently, whether the renewable hydrogen separation product is recovered as a membrane retentate or membrane permeate. This hydrogen obtained by 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 greater, such as at least 99.9 mol%, or at least 99.99 mol%).

[0078] Regardless of the particular syngas conversion operation and / or syngas separation operation used to upgrade a syngas, such as a WGS product, these operations generally co-produce conversion or separation by-products (e.g., gaseous or liquid conversion by-products, or gaseous separation by-products) as described herein. For example, a Fischer-Tropsch reaction stage that provides a renewable syngas conversion product, including liquid hydrocarbons and / or oxygenates, may also produce (a) gaseous conversion by-products, including unconverted syngas components (H, CO), light hydrocarbons (e.g., CH, CH), and / or other non-condensable gases, such as CO, and / or (b) heavy hydrocarbons (e.g., C ... 20 +A methanol synthesis reaction stage providing a renewable synthesis gas conversion product comprising methanol may also provide a liquid conversion by-product comprising (a) gaseous conversion by-products comprising unconverted synthesis gas components (H, CO), light hydrocarbons (e.g., CH, CH), and / or other non-condensable gases such as CO, and / or (b) heavy alcohols (e.g., amyl alcohol, which may be present in fusel oil fractions). A methanation reaction stage providing a renewable synthesis gas conversion product comprising RNG may also provide a gaseous conversion by-product comprising unconverted synthesis gas components (H, CO), light hydrocarbons (e.g., CH, CH), and / or other non-condensable gases such as CO. A renewable hydrogen separation stage providing a renewable synthesis gas separation product that is or includes purified hydrogen may also provide a gaseous separation by-product enriched in non-hydrogen components of the synthesis gas, such as CO, CO, and / or HO. These non-hydrogen components may be present in the gaseous separation by-products (e.g., PSA tail gas, or otherwise membrane permeate or retentate) at a total concentration of, for example, at least about 80 mol %, at least about 90 mol %, or at least about 95 mol %. As described herein, all or a portion of these conversion and / or separation by-products may be advantageously integrated into the overall process to provide certain benefits as described herein.

[0079] Further Exemplary Embodiments of the Gasification Process The figure depicts a flow diagram illustrating one embodiment of a process including operations as described above, further integrated with cross-heat exchange, in addition to the production and recovery of steam, process water, and converted and / or separated by-products (e.g., PSA tail gas). According to this embodiment, within a gasifier 50, a carbonaceous feed 10 is combined with an oxygen-containing gasifier feed 14 under gasification conditions to provide a gasifier effluent, in this case, a raw gasifier effluent 16 comprising syngas. The oxygen-containing gasifier feed 14 is introduced into the gasifier 50, optionally along with a steam source, which may be a first portion 23a of the CSC-generated steam 23. The oxygen-containing gasifier feed 14, alone or optionally in combination with such a steam source, may comprise HO and O, and optionally CO, in a total concentration of at least about 90 mol%, at least about 95 mol%, or at least about 99 mol%.

[0080] The raw gasifier effluent 16 is fed to a tar removal operation 55, which optionally includes a tar conversion residence time vessel (TCRV) 55a, as described herein, due to residence time variations in this operation. This provides a tar-depleted gasifier effluent 18 having a reduced amount of tar relative to the raw gasifier effluent 16. Generally, the process includes recovering a syngas product from the tar-depleted gasifier effluent 16, including possibly anywhere downstream of the tar-depleted gasifier effluent 16, as illustrated in the figure. For example, the syngas product may be recovered as a water-gas shift (WGS) product 36 of a WGS operation 90, optionally following one or more intervening operations performed on the gasifier effluent downstream of the tar removal operation and upstream of the WGS operation. Such intervening operations may include one or more of: (i) a quenching operation 60 involving direct contact of the gasifier effluent with quench water 20; (ii) a convective syngas cooler (CSC) 65 implementing heat exchange contact between the gasifier effluent and boiler feed water 25; (iii) a filtration operation 70 for removing solid particles from the gasifier effluent; (iv) a washing operation 80 for removing water-soluble contaminants from the gasifier effluent; and (v) a cross heat exchange between at least a portion of the material input to the washing operation (e.g., cross heat exchanger heated feed / filtered gasifier effluent 26) and at least a portion of the material removed from the washing operation (e.g., washed gasifier effluent 30).

[0081] Exemplary processes may further include feeding at least a portion of the WGS product 36 to a syngas conversion operation 95 or a syngas separation operation 95 to provide, respectively, a renewable syngas conversion product 95 or a renewable syngas separation product 40. According to more specific embodiments, for example, (i) the syngas conversion operation 95 may include a Fischer-Tropsch reaction stage, whereby the renewable syngas conversion product 40 includes liquid hydrocarbons and / or oxygen-containing compounds (e.g., alcohols) of varying carbon numbers; (ii) the syngas conversion operation 95 may include a catalytic methanol synthesis reaction stage, whereby the renewable syngas conversion product 40 includes methanol; or (iii) the syngas conversion operation 95 may include a catalytic methanation reaction stage, whereby the renewable syngas conversion product 40 includes RNG. According to other more specific embodiments, the syngas separation operation 95 may include a renewable hydrogen separation stage, whereby the renewable syngas separation product 40 includes purified hydrogen. Typically, the syngas conversion operation provides the conversion by-products 37 or separation by-products 37 described herein (e.g., including unconverted syngas components, light hydrocarbons, heavy hydrocarbons, and / or fusel oil), and the process may further include recycling at least a portion of such by-products. For example, a portion of the by-products 37 described herein may be utilized in a different operation, such as when a first portion 37a is supplied to a tar removal operation 55 (e.g., as fuel for direct combustion in a hot oxygen burner (HOB) of the Pox reactor of the operation) and / or a second portion 37b is supplied to a gasifier 50 (for additional syngas production). In more specific embodiments, the second portion 37b may represent an amount of the conversion by-products 37 or separation by-products that exceeds the fuel requirements of the tar removal operation 55 (e.g., for the HOB used in the operation).

[0082] As more particularly illustrated in the figure, a representative process includes contacting tar-depleted gasifier effluent 18 with quench water 20 (e.g., by direct contact) in a quenching operation 60, which may more particularly be a partial dry quench (PDQ) operation, thereby providing a quenched gasifier effluent 22 having a temperature that is reduced relative to the temperature of the tar-depleted gasifier effluent 18. The process may additionally include further cooling the quenched gasifier effluent 22, such as by indirect heat exchange contact with boiler feed water 25, in a convective synthesis gas cooler (CSC) 65. This provides cooled gasifier effluent 24 and CSC-generated steam 23. In this case, all or at least a first portion 23a of the CSC-generated steam 23 may be supplied to the gasifier 50 such that its total steam demand is met, according to a preferred embodiment, meaning that no additional steam source is required for the gasifier. In a more specific embodiment, in addition to or instead of first portion 23a being utilized for gasification, second portion 23b of CSC-generated steam 23 (e.g., representing this total amount of steam in excess of gasifier demand) may be supplied to a water-gas shift (WGS) operation 90. This operation may also optionally be supplied by at least a portion of the cooled gasifier effluent 24 following one or more operations to which this stream is subjected, which may be any of the operations specifically illustrated in the figures, including filtration operation 70, cross heat exchange via gasifier effluent cross heat exchanger 75 (as both a heated feed and a cooled feed), scrubbing operation 80, and compression via compressor 85. Feeding the cooled gasifier effluent 24 to the WGS operation 90 provides a WGS product 36 having an increased H:CO molar ratio relative to the cooled gasifier effluent 24 and / or the syngas exiting any intervening operations, such as the filtered gasifier effluent 26 exiting the filtration operation 70, or the scrubbed gasifier effluent 30 exiting the scrubbing operation 80.

[0083] As will be discussed, aspects of the present invention relate to advantages obtained with respect to processes that include cross-heat exchange between scrubbed gasifier effluent, i.e., at least a portion of the syngas downstream of the scrubbing operation, as described herein, and unscrubbed gasifier effluent, i.e., at least a portion of the syngas upstream of the scrubbing operation, as described herein. These advantages relate more particularly to embodiments in which a scrubbing operation is used upstream of a WGS operation for the removal of water-soluble contaminants. According to the embodiment illustrated in the figures, for example, the unscrubbed gasifier effluent may be filtered gasifier effluent 26 that has been subjected to a filtration operation 70 to remove solid particles. Heat from the unscrubbed gasifier effluent, alternatively referred to as cross-heat-exchanger-heated feed 26, may be exchanged in a gasifier effluent heat exchanger 75 against the scrubbed gasifier effluent 30 exiting the scrubbing operation, or, optionally, against the compressed, scrubbed gasifier effluent 32 obtained downstream of the compressor 85. In this regard, the scrubbed gasifier effluent 30 or the compressed scrubbed gasifier effluent 32 may alternatively be referred to as a cross heat exchanger cooled feed 30, 32.

[0084] The unscrubbed gasifier effluent that is subjected to heat exchange against the scrubbed gasifier effluent may be subjected to various intervening operations between the gasifier and this cross-heat exchange, including those illustrated in the figure. For example, if the unscrubbed gasifier effluent is filtered gasifier effluent 26, in addition to being subjected to filtration operation 70, this stream may further be subjected (e.g., upstream of this operation) to one or more of: (i) a tar removal operation 55 to remove at least a portion of the tars in the gasifier effluent; (ii) a quench operation 60 including direct contact with quench water; and (iii) a convective synthesis gas cooler (CSC) 65 implementing heat exchange contact with boiler feed water. For example, (i), (ii), and / or (iii) may be considered intervening operations, and when used in combination, they are preferably performed in the order listed, such as (i), (ii), and (iii) from upstream to downstream.

[0085] For example, as illustrated in the figure, the cross heat exchange operation performed in gasifier effluent cross heat exchanger 75 includes: (a) cooling a cross heat exchanger heated feed (e.g., filtered gasifier effluent 26) to provide cross heat exchanger cooled effluent 28 (which may alternatively be referred to as a feed to scrubbing operation 80), where preferably both the cross heat exchanger heated feed and the cross heat exchanger cooled effluent are unscrubbed gasifier effluent, i.e., syngas upstream of a scrubbing operation as described herein, or and (b) heating a cross heat exchanger-cooled feed (e.g., scrubbed gasifier effluent 30 or compressed scrubbed gasifier effluent 32) to provide a cross heat exchanger-heated effluent 34 (which may alternatively be referred to as a feed to the WGS operation 90), preferably wherein both the cross heat exchanger-cooled feed and the cross heat exchanger-heated effluent are or comprise scrubbed gasifier effluent, i.e., syngas downstream of the scrubbing operation as described herein. In the specific case where the gasifier effluent cross heat exchanger 75 is configured as a shell-and-tube heat exchanger, the cross heat exchanger-heated feed and the cross heat exchanger-cooled effluent can pass through one side, either the shell side or the tube side, and the cross heat exchanger-cooled feed and the cross heat exchanger-heated effluent can pass through the other side, either the respective tube side or the shell side. In this manner, the use of the gasifier effluent cross heat exchanger 75 can effectively facilitate the objectives of providing a syngas feed to the WGS that has been cleaned of water-soluble contaminants and heated to a sufficient temperature (e.g., within the ranges described above for the cross heat exchanger heated effluent / feed to the WGS operation) and utilizing available heat in the process (e.g., heat from the gasifier and / or tar removal operations). In some cases, the use of auxiliary heat to heat the cleaned gasifier effluent upstream of the WGS operation can be avoided by the cross heat exchange.

[0086] As further illustrated in the figure, in addition to the washed gasifier effluent 30, the washing operation 80 additionally provides a sour water by-product 19. A typical gasification process includes supplying this by-product to a sour water treatment unit 65 to provide treated water 21b that can be advantageously used as a source of process water. For example, treated water 21b may be sufficient to provide the quench water 20 used in the quench operation 60, or possibly at least a portion of the quench water, with another portion being provided by make-up quench water 21a.

[0087] Overall, aspects of the present invention relate to gasification processes that implement one or a combination of strategies described herein, such as residence time variation, generated steam integration, cross heat exchange, utilization of gaseous and / or liquid by-products of conversion and / or separation operations, and process water recycling, in the production of synthesis gas or its downstream conversion products (e.g., hydrocarbons, methanol or other alcohols, RNG, or hydrogen), which may lead to improved process flexibility and / or economics. Specific advantages may include, for example, (i) reduced capital costs (e.g., by about 10% or more) when eliminating the radiant syngas cooler (RSC) in exchange for one or more of the TCRV, PDQ, CSC, and gasifier effluent cross heat exchanger; (ii) an increase in the H:CO molar ratio of the syngas downstream of the tar removal operation, enabled by the TCRV, to facilitate lower operating temperatures of this operation (e.g., in the Pox reactor); (iii) improved heat integration upstream of the WGS operation; and / or (iv) improved syngas yields through the use of gaseous and / or liquid by-product recycle for direct fuel combustion or conversion within the process (e.g., in the Pox reactor or gasifier).

[0088] Those skilled in the art with knowledge of the present disclosure will recognize that various modifications can be made to these processes to obtain these and other advantages without departing from the scope of the present disclosure. Thus, it should be understood that features of the present disclosure are susceptible to modification and / or substitution, and the specific embodiments illustrated and described herein are for purposes of illustration only and do not limit the invention as defined by the appended claims.

Claims

1. 1. A process for gasification of a carbonaceous feed, comprising: The carbonaceous feed is contacted with an oxygen-containing gasifier feed under gasification conditions in a gasifier to produce H ２ providing a gasifier effluent comprising: subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the tar in the gasifier effluent and provide a tar-depleted gasifier effluent; A process wherein the temperature and / or residence time of the tar removal operation is adjusted in response to the measured amount of tar breakthrough of the gasifier effluent.

2. 2. The process of claim 1, wherein the temperature and / or residence time is adjusted to achieve a target tar conversion or a target tar concentration.

3. The temperature of the tar removal operation is adjusted to a minimum value based on the target conversion or target concentration under conditions in the tar removal operation; the tar removal operation includes a tar conversion retention vessel (TCRV); The process of claim 2 , wherein the conditions include a residence time through a TCRV.

4. contacting the tar-depleted gasifier effluent with quench water in a partial dry quench (PDQ) operation to provide a quenched gasifier effluent; 4. The process of any one of claims 1 to 3, further comprising further cooling the quenched gasifier effluent in a convective syngas cooler (CSC) to provide cooled gasifier effluent and CSC-generated steam.

5. The process of claim 4 , further comprising supplying all or at least a first portion of the steam generated in the CSC to the gasifier.

6. and supplying the first portion of the steam generated in the CSC to the gasifier, wherein the process comprises supplying a second portion of the steam generated in the CSC to a water-gas shift (WGS) operation fed by at least a portion of the cooled gasifier effluent to produce an increased H relative to the molar ratio of the cooled gasifier effluent. ２ 6. The process of claim 5, further comprising providing a WGS product having a :CO molar ratio.

7. 7. The process of any one of claims 1 to 6, further comprising recovering a synthesis gas product from the tar-depleted gasifier effluent.

8. 8. The process of claim 7, wherein the synthesis gas product is recovered as a water-gas shift (WGS) product of a WGS operation, optionally following one or more intervening operations performed on the gasifier effluent downstream of the tar removal operation and upstream of the WGS operation.

9. 10. The process of claim 8, wherein the one or more intervening operations include one or more of: (i) a quenching operation including direct contact with quench water; (ii) a convective syngas cooler (CSC) implementing heat exchange contact with boiler feed water; (iii) a filtration operation to remove solid particles; (iv) a scrubbing operation to remove water-soluble contaminants; and (v) cross heat exchange between at least a portion of the material input to the scrubbing operation and at least a portion of the material removed from the scrubbing operation.

10. 10. The process of claim 8 or 9, further comprising feeding at least a portion of the WGS product to a syngas conversion operation to provide a renewable liquid conversion product.

11. 11. The process of claim 10, wherein the synthesis gas conversion operation comprises (i) a Fischer-Tropsch reaction stage and the renewable liquid conversion products comprise liquid hydrocarbons, or (ii) a methanol synthesis reaction stage and the renewable liquid conversion products comprise methanol.

12. 12. The process of claim 10 or 11, wherein the synthesis gas conversion operation provides gaseous conversion by-products comprising unconverted synthesis gas components and / or light hydrocarbons, or liquid conversion by-products comprising heavy hydrocarbons and / or heavy alcohols, and the process further comprises recycling at least a portion of the gaseous conversion by-products or the liquid conversion by-products.

13. 1. A process for gasification of a carbonaceous feed, comprising: The carbonaceous feed is contacted with an oxygen-containing gasifier feed under gasification conditions in a gasifier to produce H ２ providing an uncleaned gasifier effluent containing CO and water soluble contaminants; providing at least a portion of the uncleaned gasifier effluent to a cleaning operation to remove at least a portion of the water-soluble contaminants and provide a cleaned gasifier effluent; 2. Feeding at least a portion of the washed gasifier effluent to a water-gas shift (WGS) operation to produce an increased H relative to the molar ratio of the washed gasifier effluent. ２ providing a WGS product having a :CO molar ratio; The process further comprising cross-heat exchange between at least a portion of the washed gasifier effluent and at least a portion of the unwashed gasifier effluent.

14. the cross heat exchange occurs in a gasifier effluent cross heat exchanger; cooling the cross heat exchanger heated feed to provide a cross heat exchanger cooled effluent, wherein the cross heat exchanger heated feed and the cross heat exchanger cooled effluent comprise the unwashed gasifier effluent; 14. The process of claim 13, further comprising the steps of: heating a cross heat exchanger-cooled feed to provide a cross heat exchanger-heated effluent, wherein the cross heat exchanger-cooled feed and the cross heat exchanger-heated effluent comprise the washed gasifier effluent.

15. 15. The process of claim 14, wherein the unwashed gasifier effluent is filtered gasifier effluent that has been subjected to a filtration operation to remove solid particles.

16. 16. The process of claim 15, wherein the filtered gasifier effluent, in addition to being subjected to the filtration operation, is further subjected to one or more of: (i) a tar removal operation to remove at least a portion of the tars of the gasifier effluent; (ii) a quenching operation including direct contact with quench water; and (iii) a convective synthesis gas cooler (CSC) implementing heat exchange contact with boiler feed water.

17. In addition to the washed gasifier effluent, the washing operation further provides a by-product of acid water, and the process further comprises: feeding the acid water by-product to an acid water treatment operation to provide treated water; 17. The process of any one of claims 13 to 16, further comprising utilizing at least a portion of the treated water in the quenching operation.

18. 1. A process for the gasification of a carbonaceous feed to produce renewable syngas conversion products or renewable syngas separation products, comprising: The carbonaceous feed is contacted with an oxygen-containing gasifier feed under gasification conditions in a gasifier to produce H ２ providing a gasifier effluent comprising: subjecting the gasifier effluent to a tar removal operation to remove at least a portion of the tar in the gasifier effluent and to provide a tar-depleted gasifier effluent; Optionally, following one or more intervening operations downstream of the gasifier, at least a portion of the tar-depleted gasifier effluent is fed to a water-gas shift (WGS) operation to produce an increased H relative to the molar ratio of the tar-depleted gasifier effluent. ２ providing a WGS product having a :CO molar ratio; feeding at least a portion of the WGS product to (i) a syngas conversion operation to provide the renewable syngas conversion product, or (ii) a syngas separation operation to provide the renewable syngas separation product; (a) the synthesis gas conversion operation provides gaseous conversion by-products comprising unconverted synthesis gas components and / or light hydrocarbons, and the process further comprises combusting all or at least a first portion of the gaseous conversion by-products as fuel for the tar removal operation; or (b) the synthesis gas conversion operation provides liquid conversion by-products comprising heavy hydrocarbons and / or alcohols, and the process further comprises combusting all or at least a first portion of the liquid conversion by-products as fuel for the tar removal operation; or (c) the process, wherein the synthesis gas separation operation provides a gaseous separation by-product comprising separated synthesis gas components, the process further comprising combusting all or at least a first portion of the gaseous separation by-product as fuel for the tar removal operation.

19. (a) supplying the first portion of the gaseous conversion by-products as fuel for the tar removal operation, the process further comprising supplying a second portion of the gaseous conversion by-products to the gasifier; (b) supplying the first portion of the liquid conversion by-products as fuel for the tar removal operation, the process further comprising supplying a second portion of the liquid conversion by-products to the gasifier; or 20. The process of claim 18, comprising: (c) supplying the first portion of the gaseous separation by-product as fuel for the tar removal operation, the process further comprising supplying a second portion of the gaseous separation by-product to the gasifier.

20. 20. The process of claim 18 or 19, wherein the syngas conversion operation (i) comprises a Fischer-Tropsch reaction stage and the renewable syngas conversion products comprise liquid hydrocarbons, (ii) comprises a methanol synthesis reaction stage and the renewable syngas conversion products comprise methanol, or (iii) comprises a methanation reaction stage and the renewable syngas conversion products comprise renewable natural gas (RNG).

21. 20. The process of claim 18 or 19, wherein the syngas separation operation includes a renewable hydrogen separation stage and the renewable syngas separation product comprises purified hydrogen.

Images