Control of cleaning action in gasification

Abstract

Gasification processes utilizing a carbonaceous feed, preferably biomass, are disclosed that may implement one or more strategies for controlling the temperature of the scrubbing operation used to remove water-soluble contaminants from the gasifier effluent. The temperature of the scrubber feed (e.g., the unscrubbed gasifier effluent or a portion thereof that enters the scrubber directly) may be controlled by removing heat from the heated scrubber feed, such as by steam generation, which may be further integrated into the overall process. Suitable equipment for transferring heat from the hot gasifier effluent stream may include boilers that utilize convective heat exchange, as in the case of a kettle boiler that generates low- to medium-pressure steam, thereby improving the thermal efficiency of the overall process.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of priority to U.S. Provisional Patent Application No. 63 / 445,107, filed February 13, 2023, the contents of which are incorporated herein by reference in their entirety.

[0002] Aspects of the present invention relate to gasification processes, and more particularly to temperature control of unit operations in such processes, such as scrubbing operations used to remove water-soluble contaminants from gasifier effluent. [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 a waste stream containing hydrogen and oxides of carbon (CO, CO), and hydrocarbons such as methane. This waste stream, 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. In order to use the syngas in a number of subsequent reactions, increasing the H:CO molar ratio involves the use of the following exothermic water-gas shift (WGS) reaction gases: [ka] The thermodynamics of this reaction favor a shift in equilibrium toward hydrogen production at low temperatures, which is generally unfavorable from a kinetic standpoint.

[0005] Operations performed to purify gasifier effluent or syngas in preparation for catalytic WGS reactions include scrubbing to remove water-soluble contaminants, which requires a significant temperature reduction relative to the temperatures used in upstream gasification and tar removal operations. Attempts to recover valuable heat while achieving acceptable cooling for the scrubbing operation have involved integration with biomass drying equipment and the use of blowers to maintain scrubber temperatures. However, this requires interdependencies between the process equipment often used for heating / cooling purposes that are not always matched or even widely disproportionate. For example, this can occur when a biomass hot water loop is used to provide scrubber cooling, where the temperature exchange between the large volume of circulating hot water for biomass drying and the water supplied to the scrubber can result in process complications that are not easily managed. The control loops and associated equipment and instrumentation in such heat exchange schemes can ultimately prove unreliable and inefficient. Overall, the current state of the art could benefit from improvements in gasification technology regarding scrubber temperature management requirements.

[0006] Aspects of the present invention relate to the discovery of gasification processes utilizing a carbonaceous feed, preferably biomass, that can implement one or more strategies for controlling the temperature of a scrubbing operation used to remove water-soluble contaminants from the gasifier effluent. Particular aspects relate to controlling the temperature of the scrubber feed (e.g., the unscrubbed gasifier effluent or a portion thereof that enters the scrubber directly) by removing heat from the heated scrubber feed, such as by steam generation, which may be further integrated into the overall process. Suitable steam generation equipment upstream of the scrubber can include, for example, a boiler utilizing convective heat exchange, such as in the case of a kettle boiler. In either event, heat present in the gasifier effluent (e.g., the unscrubbed gasifier effluent) leading to the scrubber can be transferred to the boiler feedwater to generate, for example, low- to medium-pressure steam, thereby improving thermal efficiency. According to specific embodiments, the hot filtered gasifier effluent provided from the filtration operation is used as a heat source for steam generation before being fed to the scrubber.

[0007] Advantageously, temperature control of the scrubbing operation can be separated from preparatory steps (e.g., biomass drying) associated with the carbonaceous feed. In this way, complex temperature control loops can be replaced by simplified, single-loop flow or pressure control valves. Cooling requirements for the scrubber are thereby streamlined, making temperature control of this operation more reliable. For example, the likelihood of the scrubber overheating can be greatly reduced, making its performance (e.g., in terms of ammonia removal) more robust and consistent, particularly in the face of upstream and / or downstream operational disturbances. Further benefits reside in the availability of additional forms of heat recovery and improvements over conventional processes in how this heat recovery can be controlled and manipulated to facilitate scrubber operation. Other advantages include the reduction or elimination of boiler feedwater flow to the scrubber for temperature control, thereby improving overall process economics through a net savings in high-quality makeup water.

[0008] Thus, a typical process may include controlling the temperature of the scrubber feed by steam generation from heat in the heated scrubber feed (e.g., if the heated scrubber feed is upstream of a boiler and has a higher temperature relative to the temperature of the scrubber feed). Both the scrubber feed and the heated scrubber feed may contain uncleaned gasifier effluent, or in some embodiments, represent uncleaned gasifier effluent from which water-soluble contaminants have been removed by a scrubbing operation. With regard to this temperature control, steam generation may remove varying amounts of heat from the heated scrubber feed to provide generated steam that varies in quantity and / or quality (e.g., pressure). According to one embodiment, the set point temperature of the scrubber feed may be maintained according to the amount of steam generated at a constant pressure, which pressure is related to both the set point temperature and the corresponding steam saturation temperature of the generated steam (e.g., according to a standard steam table). For example, in response to a positive deviation in the scrubber feed temperature above the set temperature, generated steam may increase in amount (flow rate), thereby removing a greater amount of heat from the heated scrubber feed to increase cooling. Conversely, in response to a negative deviation in the scrubber feed temperature below the set temperature, generated steam may decrease in amount (flow rate), thereby removing a lesser amount of heat from the heated scrubber feed to decrease cooling. Thus, according to specific embodiments, control of the scrubber feed temperature includes feedback control that varies the flow rate of generated steam in response to such positive or negative deviations. However, it is also possible to vary the pressure of the generated steam, which, as discussed above, is related to its temperature and therefore also to the amount of heat removed upstream of the scrubber, with higher steam pressure / temperature corresponding to less heat removal from the scrubber feed. Thus, steam pressure may increase in response to a positive deviation or decrease in response to a negative deviation, as explained above.

[0009] These and other embodiments, aspects, and advantages of the present invention will become apparent from the detailed description that follows. [Brief explanation of the drawings]

[0010] 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.

[0011] [Figure 1] 1 is a flow scheme illustrating one embodiment of a process for gasification of a carbonaceous feed.

[0012] Figure 1 depicts a flow scheme illustrating one embodiment of a process for gasification of a carbonaceous feed, which process employs various aspects as described herein to improve temperature control of a scrubbing operation, such as through steam generation. While multiple features are illustrated and described in a single Figure 1 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 controlling the temperature of the scrubber feed and utilizing generated steam for various purposes (e.g., drying the carbonaceous feed and / or increasing the moisture level of a water-gas shift (WGS) operation), can be implemented independently of other features.

[0013] For ease of illustration and understanding, Figure 1 provides 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 practice 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 process objectives, will likewise be apparent. DETAILED DESCRIPTION OF THE INVENTION

[0014] As used herein, the expressions "wt. %" and "mol. %" are used to represent weight percentage and mole percentage, respectively. The expressions "wt-ppm" and "mol. ppm" represent weight and mole fraction, respectively. For an ideal gas, "mol. %" and "mol. ppm" correspond to volume percent and parts per million by volume, respectively. The terms "barg" and "psig" are used herein to designate gauge pressure (i.e., pressure above atmospheric pressure) in units of bar and pounds per square inch, respectively, while the terms "bar" and "psi" are used herein to designate absolute pressure. For example, gauge pressures of 0 barg and 0 psig correspond to absolute pressures of approximately 1 bar and 14.5 psi, respectively.

[0015] 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.

[0016] Reference to any starting material, intermediate product, or final product, preferably all of which is a process stream, in the case of a continuous process, 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 "the washer feed... is supplied to the washing operation" should be understood to mean "all or a portion of the washer feed... is supplied to the washing operation." As when "all or a portion" is expressly recited, this phrase should further be understood to encompass the specific and preferred embodiments as set forth above, when "all or a portion" is the meaning to be understood.

[0017] 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 carried out “before,” “prior to,” or “upstream of” another such operation, or one of such operations being performed or carried out “after,” “following,” or “downstream of” another such operation. These bracketed phrases, which refer to the order in which one operation is performed or carried out relative to another, 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, one or more "operations downstream of the gasifier" can, according to a specific embodiment, refer to the operation immediately following the gasifier, such as in the case of a tar removal operation according to the embodiment illustrated in Figure 1. However, the phrase more generally, and preferably, refers to any operation following the gasifier, with or without intervening operations, or any combination thereof, such as in the case of any one or more of a quenching operation, a convective syngas cooler (CSC) or a radiant syngas cooler (RSC), and / or a filtration operation following the tar removal operation as an intervening operation according to the embodiment illustrated in Figure 1. 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 use of the phrase "consisting of"), such processes do not exclude the use of other operations, whether or not specifically described herein.

[0018] 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.

[0019] 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, i.e., “tar-depleted gasifier effluent”, having a lower concentration of tar and oil relative to the raw gasifier effluent; (iii) raw gasifier effluent that has been subjected to at least a dry quench operation, i.e., “quenched gasifier effluent”, 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; and (iv) raw gasifier effluent that has been subjected to at least a convective synthesis gas cooler (CSC) or at least a dry quench operation, having 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., a "filtered gasifier effluent," which has a low solid particle content relative to the raw gasifier effluent and may provide all or a portion of the "heated scrubber feed," i.e., a "filtered gasifier effluent," (vi) raw gasifier effluent that has been subjected to heat removal and may provide all or a portion of the "scrubber feed" which has a low temperature relative to the raw gasifier effluent resulting from heat removal (e.g., to generate steam), and (vii) more specific terms that designate raw gasifier effluent that has been subjected to any other operation upstream of the scrubber operation, whether or not specifically described herein.

[0020] Similarly, the terms "gasifier effluent" and "scrubbed gasifier effluent" encompass more specific terms that designate (viii) raw or unscrubbed gasifier effluent that has been subjected to a scrubbing operation to reduce its content of water-soluble contaminants (e.g., chlorides), and (ix) raw or scrubbed gasifier effluent that has been subjected to other operations downstream of the scrubbing operation, whether or not specifically described herein. "Gasifier effluent," "unscrubbed gasifier effluent," and "scrubbed gasifier effluent," as well as any of the more specific examples (i)-(ix) of these terms, encompass products (e.g., flow streams) upstream of a WGS operation that may optionally be fed to the WGS operation.

[0021] 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.

[0022] 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.

[0023] The exemplary gasification process described herein is defined by various possible operations occurring downstream of the gasifier, which may include tar removal operations, cooling operations such as quenching operations, CSC, and / or RSC, filtration operations, steam generation such as by using a boiler, scrubbing operations, WGS 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 other embodiments defined in the claims and the embodiment illustrated in FIG.

[0024] 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.

[0025] 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 otherwise 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, digested sludge, and biosludge. Thus, a representative carbonaceous feed includes or comprises 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 (eg, in the form of wood chips).

[0026] In the gasifier (or, more specifically, the gasification reactor of the gasifier), the carbonaceous feed undergoes partial oxidation in the presence of an oxygen-containing gasifier feed, generally 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), 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).

[0027] 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 cracking. 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.

[0028] In addition to gasifier effluent tar, the raw gasifier effluent contains carbon present in the carbonaceous feed, and H and / or H O, generally CO, CO, and methane (CH), along with trace concentrations of other components, as described below. According to the embodiment illustrated in Figure 1, raw gasifier effluent 16 may be obtained directly from the gasifier 50 prior to further operations described herein.

[0029] 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 via a Fischer-Tropsch conversion to renewable syngas conversion products comprising higher molecular weight hydrocarbons and / or alcohols of varying carbon numbers, or (ii) conversion to renewable syngas conversion products comprising methanol via a catalytic methanol synthesis reaction, or (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, WGS operations are required to achieve a preferred H:CO molar ratio and / or preferred H concentration for these or other downstream syngas conversion and 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).

[0030] 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 mol %, at least about 95 mol %, or even at least about 99 mol %.

[0031] 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 several ppm to several percent by weight. 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 of 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.

[0032] Certain compounds that are undesirable for this reason include hydrocarbons with six or more carbon atoms and oxygenated 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.

[0033] 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., H O and / or CO ) present in and / or added to the syngas. In view of the gasifier effluent tar, conversion of these compounds, combined 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 the 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)).

[0034] According to one 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.

[0035] 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 including 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 for the operation.

[0036] According to other specific 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 in conjunction 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 consumption.

[0037] Regardless of the particular manner in which the tar removal operation is carried out, 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 the gasifier effluent tar. For example, the tar-depleted gasifier effluent emerging from or obtained directly from the 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.

[0038] Quenching operation High-temperature 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 quenching operation, and preferably a dry quenching operation, is used, in which water is added directly to the gasifier effluent to contribute to its overall water content, 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 quenching 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. When dry quenching is used without the further use of a RSC, the quenched gasifier effluent may have 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), to allow for further processing. A typical process 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 preferred embodiments, only partial quenching, rather than complete quenching, 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., not saturated. Generally, dry quenching operations can facilitate rapid and efficient cooling through direct contact between the high-temperature gasifier effluent and water or other aqueous quench medium.

[0039] Convective Synthetic Gas Cooler (CSC) or Radial Synthetic Gas Cooler (RSC) As described herein, according to a preferred embodiment, combining a CSC with a quenching operation characterized by direct contact of syngas (e.g., tar-depleted gasifier effluent exiting a tar removal operation) with a quenching medium such as water can provide effective cooling for further downstream operations. Alternatively, or in combination, an RSC can be utilized for effective removal of ash and formed slag. For example, a CSC or RSC 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 275°C (527°F) to about 450°C (842°F), to enable subsequent filtration. In some embodiments, a CSC or RSC may be used to achieve such temperatures for the cooled gasifier effluent in the absence of a quench operation. In either event, the CSC or RSC may operate by indirect heat transfer, such as with 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 or RSC may operate as a boiler (e.g., a fire-tube boiler or a water-tube boiler) for the generation of medium- and / or high-pressure steam.

[0040] 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 or RSC, 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 filtration device 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.

[0041] 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 throughout the 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).

[0042] 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, for example, 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.

[0043] Steam generation The steam may be generated from heat present in the gasifier effluent, such as the filtered gasifier effluent described above, that exits or is obtained directly from the filtration operation. In some embodiments, a boiler (e.g., a kettle boiler or other equipment utilizing convective heat exchange) may be used to perform indirect heat exchange. For example, the boiler may more specifically perform cooling of the heated scrubber feed to provide a scrubber feed (or cooled scrubber feed) that is directly input to the scrubber, in which case both the heated and cooled streams may include unscrubbed gasifier effluent, such as filtered gasifier effluent. Such cooling may involve heating boiler feedwater with heat removed from the heated scrubber feed, thereby performing steam generation and providing generated steam, which may optionally be integrated into the overall process. Thus, it can be understood that, according to specific embodiments, the "heated scrubber feed" may correspond to or include the "filtered gasifier effluent." Also, heated scrubber feed / filtered gasifier effluent and scrubber feed / cooled scrubber feed may be specific examples of "unscrubbed gasifier effluent."

[0044] Just upstream of the boiler used for steam generation, the heated scrubber feed, such as filtered gasifier effluent, may have a temperature within the ranges given above for this stream; for example, the temperature corresponding to the temperature of the cooled gasifier effluent may be from about 250°C (482°F) to about 600°C (1112°F), preferably from about 275°C (527°F) to about 450°C (842°F). In an exemplary embodiment, the scrubber feed may be cooled as a result of steam generation from a temperature within the ranges set forth above to a temperature of from about 100°C (212°F) to about 225°C (437°F), preferably from about 105°C (221°F) to about 185°C (365°F). Such temperatures may correspond to the scrubber gas inlet temperature or scrubber operating temperature, and any discrete temperature value within these ranges may serve as a control point, or setpoint, for the temperature of the scrubber operation. According to certain embodiments, the pressure of the generated steam can be constant and correspond to the desired steam saturation temperature. For example, maintaining the generated steam pressure at 5.9 barg (85 psig) provides a steam saturation temperature of approximately 169°C (337°F), which represents the theoretical lowest temperature of the scrubber feed, although the actual temperature of this scrubber feed will typically be somewhat higher given the approach temperature characteristics of a given scrubber feed cooler / boiler. Maintaining the generated steam pressure, in turn, allows for effective control of the temperature of the syngas entering the scrubber, which in preferred embodiments can be controlled to just above the dew point. This can provide the desired performance level with respect to energy extraction from the heated scrubber feed without the formation of water droplets that could damage equipment (e.g., via corrosion). An embodiment of the invention is directed to a process whereby the temperature and flow rate of the heated scrubber feed to a scrubber feed cooler (e.g., a boiler such as a kettle boiler) may vary, but the cooler nevertheless maintains a controlled (e.g., constant) scrubber feed temperature according to the rate of variation of steam production / heat removal at a given pressure of the generated steam.

[0045] Cleaning operation The scrubbing operation may be used to remove water and water-soluble contaminants from unscrubbed gasifier effluent, such as the filtered gasifier effluent exiting the filtration operation, following cooling of this stream by steam generation. For example, the filtered gasifier effluent may serve as a feed to a boiler that provides cooled effluent upstream of the scrubbing operation, following indirect heat exchange, with all or at least a portion of this effluent providing the scrubber feed to the scrubbing operation. The temperature of this scrubber feed may be controlled through varying the amount of heat removed by the boiler, according to embodiments described herein. The scrubbing operation itself may provide further cooling of the scrubber feed. For example, as described above, the scrubber feed entering the scrubber following cooling for steam generation may have a temperature similarly described above, which corresponds to the scrubber gas inlet temperature. The scrubbed gasifier effluent exiting the scrubber may have a temperature of from about 35°C (95°F) to about 100°C (212°F), preferably from about 38°C (100°F) to about 66°C (150°F).

[0046] A scrubbing operation, such as a 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, the unscrubbed gasifier effluent, such as the scrubber feed obtained following cooling, can be fed to a trayed column for cocurrent or countercurrent contact with water or an aqueous solution. Further cooling in the 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 the 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, so that the water content of the scrubbed gasifier effluent is reduced relative to the water content of the scrubber feed.

[0047] WGS operation The water-gas shift (WGS) operation reacts CO present in the gasifier effluent, e.g., the scrubbed gasifier effluent immediately after the scrubbing operation, with steam to increase the H concentration (as well as the CO concentration). In this manner, the scrubbed gasifier effluent may be characterized as a feed to the WGS operation (WGS feed). Following the tar removal, filtering, and scrubbing operations, the scrubbed gasifier effluent / feed to the WGS operation may have favorable properties for use in this operation in that it is free or substantially free of water-soluble contaminants, as well as tars and particulates, as described above.

[0048] In some embodiments, the scrubbed gasifier effluent / feed to the WGS operation may be heated and / or supplemented with moisture (steam) to further improve properties for kinetically and / or thermodynamically favorable WGS reactions, desirably increasing the H:CO molar ratio and / or H concentration of the WGS product relative to these properties of the WGS feed. For example, this feed may be heated to a temperature of about 225°C (437°F) to about 475°C (887°F), preferably about 260°C (500°F) to about 399°C (750°F), prior to input to the WGS operation. The moisture content of this feed may be increased by utilizing a supplemental steam source, such as at least a portion of generated steam provided from steam generation (e.g., using a boiler) as described above. For example, at least a portion of the steam generated in the boiler (e.g., low-pressure 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. In WGS operations, the use of more than stoichiometric amounts of steam can be beneficial for many purposes, especially in adiabatic fixed-bed reactors. These include driving the equilibrium toward hydrogen production, adding heat capacity to limit the increase in exothermic temperature, and minimizing side reactions such as methanation.

[0049] 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, particular 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).

[0050] 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.

[0051] In this manner, the WGS operation can be used to provide a WGS product exiting, immediately after, or obtained directly from the operation, having an increased H:CO molar ratio and increased H concentration relative to the feed to the WGS operation or the syngas obtained from an upstream operation (e.g., filtered gasifier effluent or cooled gasifier effluent). For example, the immediate WGS product can have an H:CO molar ratio of from about 0.5 to about 3.5, from about 1.0 to about 3.0, or from about 1.5 to about 2.5, and / or a hydrogen concentration of at least about 35 mol% (e.g., from about 35 mol% to about 80 mol%), at least about 40 mol% (e.g., from about 40 mol% to about 70 mol%), or at least about 45 mol% (e.g., from about 45 mol% to about 65 mol%). These 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.

[0052] 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. For the production of liquid hydrocarbons, 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 varying 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.

[0053] 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.

[0054] For 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 high-temperature 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.

[0055] 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 otherwise a membrane permeate or retentate, depending on the particular membrane used and whether the renewable hydrogen separation product is subsequently 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%).

[0056] Further Exemplary Embodiments of the Gasification Process FIG. 1 depicts a flow scheme illustrating an embodiment of a process that includes operations as described above and further utilizes control of scrubber feed temperature through steam generation. With reference to FIG. 1 , and with the understanding that embodiments disclosed herein do not necessarily require all illustrated features, such embodiments may be generally directed to a process for the gasification of a carbonaceous feed (e.g., wood). The process may include contacting a carbonaceous feed 10 (or a dried carbonaceous feed 10a following a dryer 85) with an oxygen-containing gasifier feed 14 (and optionally, another steam source) under gasification conditions in a gasifier 50 to provide an unscrubbed gasifier effluent containing H, CO, and water-soluble contaminants. The oxygen-containing gasifier feed 14 may include H, O, and O, and optionally CO, alone (or optionally in combination with another steam source), in a total concentration of at least about 90 mol%, at least about 95 mol%, or at least about 99 mol%. The unscrubbed gasifier effluent can be any process stream downstream of the gasifier 50 and upstream of the scrubbing operation 80, including raw gasifier effluent 16, tar-depleted gasifier effluent 18, quenched gasifier effluent 22, cooled gasifier effluent 24, filtered gasifier effluent 26, or scrubber feed 28.

[0057] The process may further include supplying at least a portion of the uncleaned gasifier effluent to a washing operation 80, for example, as scrubber feed 28, to remove at least a portion of the water-soluble contaminants and provide washed gasifier effluent 30. The uncleaned gasifier effluent or a portion thereof may also be supplied to a boiler 75, for example, as heated scrubber feed 26, for steam generation from heat in the heated scrubber feed and to provide scrubber feed 28 (which may be referred to as cooled scrubber feed). It may therefore be understood that either or both of the heated scrubber feed 26 and the scrubber feed 28 may correspond to or include uncleaned gasifier effluent, such as in the particular case of the uncleaned gasifier effluent being at a higher temperature as the heated scrubber feed relative to the uncleaned gasifier effluent as the scrubber feed. The unscrubbed gasifier effluent may have the same composition as the heated scrubber feed 26 and the scrubber feed 28. In an exemplary embodiment, the unscrubbed gasifier effluent provided to the boiler 75 as the heated scrubber feed 26 may be filtered gasifier effluent that has been subjected to a filtration operation 70 to remove solid particles. More specifically, in addition to being subjected to the filtration operation 70, the filtered gasifier effluent may be further subjected to one or more intervening operations downstream of the gasifier 50 and upstream of the filtration operation 70. For example, such intervening operations may include one or more of: (i) a tar removal operation 55 to remove at least a portion of the gasifier effluent tar (e.g., and providing tar-depleted gasifier effluent 18); (ii) a quenching operation 60 including direct contact with quench water 20 (e.g., and providing quenched gasifier effluent 22); and (iii) a convective syngas cooler (CSC) 65 or a radiant syngas cooler (RSC) 65 performing heat exchange contact with CSC feedwater or RSC feedwater (e.g., and providing cooled gasifier effluent 24).

[0058] In achieving the various benefits and advantages as described herein, an exemplary process may include controlling the temperature of the scrubber feed 28 by steam generation from heat in the heated scrubber feed. This heated scrubber feed may correspond to, for example, the filtered gasifier effluent 26, or optionally any other gasifier effluent upstream of the boiler 75. The steam generation may remove varying amounts of heat from the heated scrubber feed, such as from the filtered gasifier effluent 26, to provide generated steam 34 of varying quantity and / or quality (e.g., pressure). The steam generation may be performed (occur or occur) in a boiler 75 positioned downstream of the heated scrubber feed (e.g., the filtered gasifier effluent 26) and upstream of the scrubber feed 28. A suitable boiler may utilize convective heat exchange, such as in the case of a kettle boiler. More generally, however, any suitable heat exchanger (e.g., a shell-and-tube heat exchanger) may be used as the boiler. Regardless of the particular boiler, this equipment may perform the following steps: (a) cooling the heated scrubber feed to provide scrubber feed 28 (which may also be referred to as cooled scrubber feed), where both streams contain unscrubbed gasifier effluent (e.g., filtered gasifier effluent); and (b) heating boiler feed water 32 with heat (removed heat) from the heated scrubber feed to perform steam generation and provide generated steam 34.

[0059] An exemplary process may optionally include, following one or more intervening operations downstream of the gasifier 50, feeding at least a portion of the unscrubbed gasifier effluent to a boiler 75, for example, as heated scrubber feed 26, for steam generation from heat in the heated scrubber feed 26 and to provide a scrubber feed 28 (which may also be referred to as a cooled scrubber feed). In addition, heat exchange contact of the boiler feed water 32 with the heated scrubber feed 26 in the boiler 75 may be used to provide generated steam 34 of varying quantity and / or quality (e.g., pressure) in response to the temperature of the scrubber feed 28. Such temperatures may be measured at various points, such as immediately downstream of the boiler 75, immediately upstream of the scrubbing operation 80, or at any intermediate point, and this measurement may serve as the basis for control of the scrubber operation 80, and more specifically, the scrubber used in this operation. According to one embodiment, the temperature of the scrubber feed 28 is measured at the gas inlet of the scrubber used in the scrubber operation 80, and this measurement serves as the basis for control. Regardless of the particular point of measurement, the scrubber feed 28 is ultimately supplied to a scrubbing operation 80, and more specifically, to a scrubber used in this operation, to remove at least a portion of the water-soluble contaminants (e.g., HCl and ammonia) and to provide a cleaned gasifier effluent 30.

[0060] According to specific embodiments for controlling the temperature of the scrubber feed 28, the process is such that (a) in response to a positive deviation in temperature above the set temperature, the generated steam 34 is increased in quantity and / or quality (thereby removing a greater amount of heat from the heated scrubber feed 26), and (b) in response to a negative deviation in temperature below the set temperature, the generated steam 34 is decreased in quantity and / or quality (thereby removing a lesser amount of heat from the heated scrubber feed 26). In certain cases where the quality of the generated steam 34 is increased or decreased in response to these temperature deviations, the pressure of the generated steam 34 may be varied. In some embodiments, control of the temperature of the scrubber feed includes a feedback control that varies the pressure of the generated steam.

[0061] An exemplary control method may utilize a flow control valve (FCV) or a pressure control valve (PCV) that controls the flow rate or pressure of the generated steam 34, respectively, according to the temperature of the scrubber feed 28 received from a temperature indicator (TI) used to measure this temperature. The flow rate or pressure of the generated steam 34 may vary in response to deviations in this temperature from a setpoint temperature, as described above, thereby removing more or less heat from the heated scrubber feed 26 to maintain this temperature. Regardless of any particular control method, the setpoint temperature of the scrubber feed 28 may be any discrete value suitable for a given process and its associated configuration. In some embodiments, the setpoint temperature may be a discrete value within a range of about 100°C (212°F) to about 225°C (437°F), such as about 105°C (221°F) to about 185°C (365°F). In some embodiments, steam generation (e.g., from boiler 75) provides generated steam having a pressure from about 0 barg (0 psig) to about 20 barg (290 psig), such as from about 0 barg (0 psig) to about 10 barg (145 psig), from about 0 barg (0 psig) to about 7.5 barg (109 psig), from about 0.5 barg (7 psig) to about 20 barg (290 psig), from about 0.5 barg (7 psig) to about 10 barg (145 psig), or from about 0.5 barg (7 psig) to about 7.5 barg (109 psig). Such steam pressure ranges correspond to respective steam temperature ranges (based on steam saturation temperature) of about 100°C (212°F) to about 215°C (419°F), such as about 100°C (212°F) to about 184°C (363°F), about 100°C (212°F) to about 173°C (343°F), about 112°C (234°F) to about 215°C (419°F), about 112°C (234°F) to about 184°C (363°F), and about 112°C (234°F) to about 173°C (343°F). Thus, in some embodiments, the generated steam may be considered low-pressure steam or medium-pressure steam.

[0062] In preferred embodiments, the setpoint temperature of the scrubber feed is above its dew point temperature to obtain the benefits described herein for efficient heat extraction while avoiding condensation. For example, the setpoint temperature can be about 1°C (2°F) to about 15°C (27°F), about 1°C (2°F) to about 10°C (18°F), or about 1°C (2°F) to about 5°C (9°F) above the scrubber feed dew point temperature. In either event, the setpoint temperature of the scrubber feed has an effect on the pressure of the generated steam in terms of the relationship between this pressure and the saturation temperature of the generated steam. Such an effect can be particularly relevant in embodiments where steam generation provides generated steam that is maintained (e.g., fixed) at a given pressure but varies with respect to flow rate to vary the amount of heat removed from the heated scrubber feed, thereby maintaining the setpoint temperature. Considering the temperature proximity between the generated steam (which acts as a cold medium) and the scrubber feed (which acts as a hot medium), the steam generation can provide generated steam that is maintained (e.g., fixed) at a pressure corresponding to a steam saturation temperature that is equal to or within at least about 10°C (18°F), such as within about 5°C (9°F), of the set temperature. For example, the steam saturation temperature can be equal to the set temperature, but can also be about 1°C (2°F) to about 10°C (18°F), such as about 1°C (2°F) to about 5°C (9°F), below the set temperature.

[0063] Regardless of any particular control method, the generated steam 34 may be utilized for further integration within the process, either for direct input to a process stream or process equipment, or for utilization of its heat content, such as for heating and / or drying applications. For example, as shown in FIG. 1 , steam generation from a boiler 75 provides generated steam 34, at least a portion of which, e.g., a first portion 34a, is supplied to a dryer 85 for drying of the carbonaceous feed 10, thereby providing dried carbonaceous feed 10a for supply to the gasifier 50. Use of heat from the first portion 34a of the generated steam 34 may be particularly effective for drying certain types of biomass, such as wood. In this manner, temperature control of the scrubber operation 80 may be integrated with biomass drying but may be performed without relying on such drying to establish critical parameters related to the scrubber operation. Alternatively, or in combination with supplying a portion of the generated steam 34 to the dryer 85, an exemplary process may include supplying at least a portion of the generated steam 34, e.g., second portion 34b, to a WGS operation 90, such as by inputting such portion directly to a WGS reactor or by combining such portion with a feed to the WGS operation 90, such as scrubbed gasifier effluent 30. In either case, the steam added to the WGS operation 90 drives the intended WGS reaction toward H production, such that the WGS product 36 has an increased H:CO molar ratio relative to that of the scrubbed gasifier effluent 30.

[0064] According to an exemplary process, raw gasifier effluent 16 produced in gasifier 50 is fed to a tar removal operation 55 to provide 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, optionally including anywhere downstream of the tar-depleted gasifier effluent 16, as illustrated in Figure 1. 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 or a radiant syngas cooler (RSC) 65 that performs heat exchange contact between the gasifier effluent and the CSC feedwater or RSC feedwater; (iii) a filtration operation 70 for removing solid particles from the gasifier effluent; (iv) a boiler for further removing heat from the gasifier effluent and controlling the temperature of downstream scrubbing operations as described herein; and (v) a scrubbing operation 80 for removing water-soluble contaminants from the gasifier effluent.

[0065] 1 , an exemplary 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 specifically 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 CSC feedwater or RSC feedwater in a convective syngas cooler (CSC) 65 or a radiant syngas cooler (RSC) 65. This provides cooled gasifier effluent 24, which may then be subjected to a filtration operation 70, heat removal in a boiler 75, and a washing operation 80, as the specific details of these operations are described herein. At least a portion of the scrubbed gasifier effluent 30 provided from the scrubbing operation 80 is fed to the WGS operation 90 to provide a WGS product 36 having an increased H:CO molar ratio relative to the molar ratio of the syngas exiting the operation, such as the raw gasifier effluent 16 and / or tar-depleted gasifier effluent 18, the quenched gasifier effluent 22, the cooled gasifier effluent 24, the filtered gasifier effluent 26 exiting the filtration operation 70, the scrubber feed 18 to the scrubbing operation 80, or the scrubbed gasifier effluent 30 exiting the scrubbing operation 80.

[0066] 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 a renewable syngas conversion product 40 or a renewable syngas separation product 40, respectively. 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.

[0067] Generally, aspects of the present invention relate to gasification processes that implement control of scrubbing operations used to remove water-soluble contaminants from gasifier effluent, and more particularly, to control of the temperature of scrubbers used for this purpose. This can reduce process complexity while providing a valuable pathway for heat integration and steam generation. Those skilled in the art with knowledge of this 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. As such, 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 an uncleaned gasifier effluent containing CO and water soluble contaminants; providing at least a portion of the unscrubbed gasifier effluent as a scrubber feed to a scrubbing operation to remove at least a portion of the water-soluble contaminants and provide a scrubbed gasifier effluent; and controlling the temperature of the heated scrubber feed by steam generation from heat within said scrubber feed.

2. 10. The process of claim 1, wherein the steam generation removes varying amounts of the heat from the heated scrubber feed to provide varying amounts and / or qualities of generated steam.

3. 3. The process of claim 1 or 2, wherein the control setpoint for the temperature of the washer feed is from about 100° C. (212° F.) to about 225° C. (437° F.).

4. 4. The process of claim 3, wherein the set temperature is greater than the dew point temperature of the scrubber feed.

5. 5. The process of claim 4, wherein the set point temperature is about 1° C. (2° F.) to about 10° C. (18° F.) above the dew point temperature of the scrubber feed.

6. 6. The process of any one of claims 1 to 5, wherein the steam generation provides generated steam having a pressure of from about 0 barg (0 psig) to about 20 barg (290 psig).

7. 7. The process of any one of claims 3 to 6, wherein the steam generation provides generated steam maintained at a pressure corresponding to a steam saturation temperature equal to the set temperature or within about 10°C (18°F) of the set temperature.

8. 8. The process of any one of claims 1 to 7, wherein the steam generation provides generated steam, and at least a portion of the generated steam is supplied to a dryer for drying the carbonaceous feed.

9. The process of any one of claims 1 to 8, wherein the carbonaceous feed is wood.

10. and feeding at least a portion of the washed gasifier effluent to a water-gas shift (WGS) operation to obtain an increased H to W molar ratio of the washed gasifier effluent. ２ 10. The process of any one of claims 1 to 9, further comprising providing a WGS product having a :CO molar ratio.

11. The process of claim 10 , wherein the steam generation provides generated steam, and at least a portion of the generated steam is supplied to the WGS operation.

12. The process of any one of claims 1 to 11, wherein the control of the temperature of the scrubber feed comprises feedback control that varies the flow rate or pressure of the generated steam.

13. The process of any one of claims 1 to 12, wherein the steam generation is carried out in a boiler positioned downstream of the heated scrubber feed and upstream of the scrubber feed.

14. 14. The process of claim 13, wherein the boiler utilizes convective heat exchange.

15. 14. The process of claim 13, wherein the boiler is a kettle boiler.

16. The boiler, cooling the heated scrubber feed to provide the scrubber feed, wherein the heated scrubber feed and the scrubber feed comprise the unscrubbed gasifier effluent; heating boiler feed water with the heat from the heated scrubber feed to effect the steam generation and provide generated steam.

17. 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; optionally, following one or more intervening operations downstream of said gasifier, supplying at least a portion of the unscrubbed gasifier effluent as a heated scrubber feed to a boiler for steam generation from heat in said heated scrubber feed and for providing a scrubber feed; The process wherein the boiler provides varying amounts and / or qualities of generated steam in response to the temperature of the scrubber feed, which is fed to a scrubbing operation to remove at least a portion of the water-soluble contaminants and provide a scrubbed gasifier effluent.

18. the generated steam is increased in quantity and / or quality in response to a positive deviation of the temperature of the scrubber feed above a set temperature; 18. The process of claim 17, wherein the generated steam is reduced in quantity and / or quality in response to a negative deviation of the temperature of the scrubber feed below the set temperature.

19. 19. The process of claim 18, wherein the set point temperature of the washer feed is from about 100°C (212°F) to about 225°C (437°F).

20. 20. The process of any one of claims 17 to 19, wherein the unwashed gasifier effluent is filtered gasifier effluent that has been subjected to a filtration operation to remove solid particles.

21. 21. The process of claim 20, 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 gasifier effluent tar; (ii) a quenching operation including direct contact with quench water; and (iii) a convective syngas cooler (CSC) performing heat exchange contact with CSC feedwater.

22. 2. Supplying at least a portion of the washed gasifier effluent to a water-gas shift (WGS) operation to produce an increased H relative to tar-depleted effluent molar ratio. ２ 22. The process of any one of claims 17 to 21, further comprising providing a WGS product having a WGS:CO molar ratio of 0.1 to 0.

2.

23. 23. The process of claim 22, further comprising feeding 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.

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