Gasification process and system for producing renewable hydrogen

Abstract

Gasification processes for renewable hydrogen production utilize a sour water-gas shift (WGS) operation implemented at a stage where the gas composition and conditions are conducive to H production, thereby achieving efficiency benefits. The sour WGS operation can be carried out after increasing the concentration of sulfur in the gasifier effluent, for example, by combining it with a gas stream containing sulfur compounds. This gas stream is readily available downstream of an acid gas removal operation for recycling to the sour WGS operation, or as an acid gas product containing HS obtained upstream of this operation.

Description

[Technical Field]

[0001] An embodiment of the present invention relates to a gasification process in which gasifier effluent is passed through a series of operations, including a sour water-gas shift (WGS) operation, for the efficient production and recovery of renewable hydrogen. A further embodiment relates to the use of acid gas products containing sulfur compounds (e.g., HS) for recovery in a sour WGS operation. [Background technology]

[0002] Coal gasification has been carried out industrially for 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 as 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 possible 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, commonly referred to as synthesis gas in terms of its H and CO content, is then treated to remove a number of undesirable components, which can include particulates, alkali metals, and sulfur compounds, as well as gasification by-products called tar and oil. Such processing steps are necessary to render the gasifier effluent / syngas product, which contains significant concentrations of H and CO / CO, suitable for downstream conversion into valuable products. These include renewable natural gas (RNG) or biomethane produced by catalytic methanation to increase the methane content. Alternatively, Fischer-Tropsch synthesis can be used to provide higher molecular weight hydrocarbons and / or alcohols of various carbon numbers.

[0003] The hydrogen content of syngas is an important parameter for carrying out subsequent reactions utilizing its H2 and CO building blocks. In some cases, obtaining purified renewable hydrogen by gasification is the processing objective for potentially abundant end uses, such as electricity generation for fuel cells or refinery hydroprocessing. Depending on the specific needs or downstream conversion, significantly higher concentrations of hydrogen may be required compared to that available in the gasifier effluent. For some applications, an essentially all-hydrogen product is optimal. In this regard, the exothermic water-gas shift (WGS) reaction is widely implemented to increase the hydrogen content of syngas according to: CO+H2O⇔H2+CO2 Thermodynamics indicate that the equilibrium shifts to hydrogen production at lower temperatures, which is generally unfavorable from a reaction kinetics standpoint. Furthermore, operations performed to prepare gasifier effluent or syngas for catalytic WGS can dehydrate this stream, whereas higher steam concentrations can also drive the reaction in the intended direction.

[0004] In summary, process efficiency is compromised when certain conditions (e.g., temperature, humidity) present upstream of the WGS reaction are "failed" to obtain the required syngas purity characteristics and then "restored" to achieve acceptable conversion levels and associated hydrogen concentrations. This is performed, for example, when syngas produced by a gasifier is treated to remove tars and oils, followed by scrubbing to remove water and water-soluble contaminants. The former tar removal operation, necessary to clean the syngas for further processing, is often performed using a thermal approach, allowing for very high-grade heat recovery. However, the resulting high temperatures shift the equilibrium in the syngas toward undesirably low hydrogen concentrations, i.e., in favor of the left side of the reaction. The latter scrubbing operation causes a significant reduction in heat and water content. Consequently, to obtain the desired H2:CO molar ratio and / or H2 concentration, or the entire WGS reaction, it is necessary to reheat the gas entering the conversion process and supplement it with steam. Immediately upstream of the reaction, this gas is typically further pressurized and contacted with an adsorbent bed to remove residual amounts of sulfur compounds and other contaminants, and optionally to perform a "sweet" (i.e., sulfur-free) catalytic WGS operation.

[0005] The current state of the art would benefit from an efficient solution to address the conflicting requirements, including those mentioned above, faced in the treatment of gasifier effluent. This need is particularly relevant to the gasification of biomass to produce renewable hydrogen, in view of the challenges related to feed composition and implementation of the WGS reaction. Summary of the Invention

[0006] Aspects of the present invention relate to the discovery of a sour water-gas shift (WGS) operation, i.e., a gasification process for renewable hydrogen production that utilizes one or more WGS reactions carried out on a gas stream containing sulfur compounds (e.g., HS). Advantageously, this operation can be implemented in the overall process at a stage where the gas composition and conditions are "naturally" conducive to H production. The sour WGS operation may be carried out after increasing the concentration of sulfur in the gasifier effluent. This may be achieved by combining the gasifier effluent with a gas stream containing sulfur compounds obtained from a downstream operation, e.g., an acid gas product containing HS. For example, an acid gas removal operation may be used to separate the acid gas product, which may then be recycled to the sour WGS operation or upstream of this operation.

[0007] Importantly, the ability to concentrate sulfur by gas separation (e.g., using physical or chemical solvents) can overcome the very limited sulfur content of biomass, and more specifically, the catalysts for this operation, which have metals that are active when maintained in their sulfide form, that would otherwise prevent the use of sour WGS operations. The ability to use sour WGS operations, in turn, overcomes traditional limitations faced with the placement of "sweet" WGS operations within the overall process. Such placements are necessarily downstream of required washing and acid gas removal operations, primarily for purposes related to protecting the WGS catalyst. A further aspect of the present invention therefore relates to the discovery of a biomass gasification process having multiple unit operations in which a WGS operation (fed with syngas produced by a gasifier or gasifier effluent) occurs prior to (upstream from) the washing and / or acid gas removal operations.

[0008] Certain aspects of the present invention therefore relate to a gasification process that effectively addresses the problem that, according to conventional gasifier effluent treatment processes, the sulfur content of biomass (as opposed to coal) as a desirable feedstock is insufficient to support the use of catalysts for sour WGS. These catalysts are typically based on Co, Mo, Ni, and / or W, which are catalytically active in the sulfided state. Despite this potential incompatibility, the attractiveness of sour WGS operation, particularly when the hydrogen concentration of the syngas produced by the gasifier can be maximized, arises from the possibility of compensating for unacceptably low H:CO molar ratios obtained under conditions characterized by thermal tar conversion reactions (e.g., reformation and / or partial oxidation). That is, according to equilibrium-constrained WGS reactions, hydrogen production at the high temperatures associated with tar removal is thermodynamically unfavorable.

[0009] In this regard, and further considering that sufficient water in the syngas can drive the WGS reaction in the desired direction, adding water directly to the syngas after tar removal can be advantageous, serving the additional purpose of temperature reduction, enabling gas filtration and steam generation necessary for the overall process. The additional temperature reduction after steam generation also improves the thermodynamic environment in the sour WGS reactor(s) toward H2 production. These reactor(s) in sour WGS operations typically require a reaction environment with the necessary sulfur content (concentration) to maintain the catalytic metals in an active sulfided state, which in certain embodiments may be achieved by recycling sulfur in the acid gas product. This product may be obtained by separation from the sour WGS product, for example, by contact with a physical or chemical solvent used in downstream acid gas removal operations. In some cases, the operation may provide (i) an acid gas product (e.g., an H2S-enriched product) that forms at least a portion of the sulfur-containing recycle gas combined with the gasifier effluent upstream of or during the sour WGS operation, as well as (ii) a CO2-enriched product. Thus, the acid gas removal operation may be carried out using a physical or chemical solvent and in a manner that provides both products (i) and (ii) separately, with (i) being recycled and (ii) being sent for further processing.

[0010] Regardless of the particular manner in which acid gas products or other sulfur-containing gases are obtained to enrich the sulfur content of the gasifier effluent for use in a sour WGS operation, embodiments of the present invention relate to a biomass gasification process in which this operation is performed on the gasifier effluent under conditions within an overall multi-operation process that provide suitable, most favorable, or even optimal pressure, temperature, and water content for the WGS reaction proceeding to hydrogen production. Adjustments to these parameters, and specifically the loss of process efficiency associated with the need for one or more "de-energizing" adjustments (e.g., heating the gasifier effluent after upstream cooling or adding steam to the gasifier effluent after upstream dehydration), are advantageously avoided. Adding sulfur (e.g., as HS) to the sour WGS operation and preferably converting, recovering, and recycling sulfur originally present in the biomass (e.g., by accumulating HS to a desired concentration in the sulfur-containing recycle gas as part of a recycle loop), advantageously enables the use of a sour WGS catalyst in this operation. Thus, certain embodiments of the present invention relate to a biomass gasification process that preferably utilizes a series of unit operations, at least some of which are specifically sequenced upstream or downstream relative to other unit operations, to achieve the advantageous results described herein. According to certain processes, an acid gas removal operation is used to separate sulfur-containing (e.g., HS-containing) acid gas products from a sour WGS product obtained from a sour WGS operation downstream of the gasifier and upstream of the acid gas removal operation. Recycling the separated acid gas products, and more specifically, the level of recycle required for a given sour WGS catalyst, allows for effective control of parameters such as the H:CO molar ratio of the sour WGS product and / or the HS concentration of the sulfur-containing recycle gas. According to certain embodiments, the use of such catalysts in conjunction with physical or chemical solvents in downstream acid gas removal operations allows for effective recycling of biomass sulfur, which appears predominantly as HS after gasification, to maintain a desired sulfur concentration in the recycle loop, as needed, to effectively operate the sour WGS catalyst.

[0011] Several advantages of the present invention can reside both in using the steam and heat present in the gasifier effluent to increase its moisture content and provide cooling, and in using evaporative cooling by injecting water into the effluent. These conditioning steps upstream of the sour WGS operation, coupled with an H2S recycle to this operation to maintain catalyst performance, allow for the effective and efficient production of hydrogen by gasification of biomass according to the process described herein.

[0012] Certain embodiments of the present invention relate to the production of hydrogen from gasifier-produced and biomass-derived syngas that has been subjected to successive operations or processing steps, such as tar removal (e.g., thermal, catalytic, or adsorption), followed by a dry quench by direct contact with quench water, thereby providing a quenched gasifier effluent, or more specifically, a partially quenched gasifier effluent, whose temperature is above its dew point. For example, syngas obtained directly from a gasifier, or the raw gasifier effluent, may be fed to a tar removal operation, more specifically, a partial oxidation (Pox) unit, with an additional oxygen source (e.g., HO, CO) to reform tar and oil. Following this tar removal operation, the tar-depleted gasifier effluent may be fed to a dry quench operation, in which sufficient water is added so that evaporative cooling reduces the temperature of the resulting quenched gasifier effluent to a desired level (e.g., to about 480°C) for further processing. These operations include filtration to remove solid particles (e.g., dust) and pre-shift heat recovery to generate steam and further cool the gas, thereby providing a cooled gasifier effluent with a temperature suitable for feeding to the sour WGS operation. Water introduced into the dry quench operation, along with the recycled acid gas product containing sulfur compounds (e.g., HS), serves to adjust the syngas (or gasifier effluent) conditions and composition to redecorate the syngas for the sour WGS operation. This operation may be controlled, at least in part, by bypassing more or less syngas around the operation to achieve a target H:CO molar ratio. Post-shift heat recovery performed on the sour WGS product can recover at least a portion of the heat generated by the sour WGS operation and generate additional steam before feeding the sour WGS product to a scrubbing operation, optionally a compressor that redecorates the scrubbed and / or pressurized gas to make it more suitable for further downstream processing. Steam produced from pre-shift heat recovery and / or post-shift heat recovery may be utilized in gasifier and / or sour WGS operations.

[0013] After post-shift heat recovery, the cooled sour WGS product may be further cooled by direct water contact in a subsequent scrubbing operation (e.g., a wet scrubber), and lower-grade heat may be rejected to a system outside of battery limits. The syngas at this stage, which can be characterized as a scrubbed sour WGS product, such as when processed through a gas sweetening unit operating with physical or chemical solvents, may be compressed and fed to an acid gas removal operation. This can produce both a concentrated hydrogen sulfide gas stream (or H2S-enriched product) and a concentrated carbon dioxide gas stream (or CO2-enriched product), with the latter of these two acid gas products advantageously recycled to the sour WGS operation to the extent necessary for its effective performance. Sulfur losses throughout the process, such as losses to solution due to small amounts of solubilized H2S, can be offset by the small but finite amount of sulfur contained in the biomass feedstock (e.g., wood).

[0014] Certain embodiments of the present invention relate to a process for gasifying a carbonaceous feed to produce a renewable hydrogen product, wherein the sulfur concentration of the gasifier effluent is increased for use in sour WGS operations. An exemplary process includes: (a) contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier to provide a gasifier effluent containing syngas (containing both H and CO); (b) increasing the sulfur concentration of the gasifier effluent to provide a sulfur-enriched gasifier effluent (i.e., having an increased concentration of sulfur compared to the gasifier effluent); (c) feeding the sulfur-enriched gasifier effluent to a sour WGS operation to provide a sour WGS product having an increased hydrogen concentration compared to the hydrogen concentration of the sulfur-enriched gasifier effluent; and (d) recovering the renewable hydrogen product from the sour WGS product.

[0015] Other specific embodiments of the present invention relate to processes for the gasification of a carbonaceous feed to produce a renewable hydrogen product, in which the WGS reaction is more specifically carried out in a sour WGS operation upstream of a scrubbing and / or acid gas removal operation for overall process efficiency. Exemplary processes include contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasification conditions in a gasifier to provide a gasifier effluent containing syngas; feeding the gasifier effluent to a sour WGS operation to provide a sour WGS product having an increased concentration of hydrogen relative to that of the gasifier effluent; and recovering a renewable hydrogen product from the sour WGS product. According to these processes, after the sour WGS operation (and before recovering the renewable hydrogen product, e.g., by separating acid gas products from the sour WGS product), the sour WGS product is passed through a scrubbing operation (e.g., a wet scrubber) to remove water and water-soluble contaminants (e.g., chlorides).

[0016] Yet another specific embodiment of the present invention relates to a process for gasifying a carbonaceous feed to produce a renewable hydrogen product, where the defined operations are utilized to treat a gasifier effluent upstream of a sour WGS operation and / or to treat a sour WGS product downstream of the sour WGS operation, further providing processing efficiency advantages. An exemplary process includes contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasifying conditions in a gasifier to provide a gasifier effluent containing syngas (containing both H and CO), passing the gasifier effluent through at least a tar removal operation and a dry quench operation upstream of the sour WGS operation, increasing the sulfur concentration of the gasifier effluent to provide a sulfur-enriched gasifier effluent (i.e., having an increased concentration of sulfur compared to the gasifier effluent), and feeding the sulfur-enriched gasifier effluent to the sour WGS operation, where the hydrogen concentration of the sulfur-enriched gasifier effluent is increased compared to the hydrogen concentration of the sulfur-enriched gasifier effluent. providing a sour WGS product having an increased sulfur concentration; passing the sour WGS product through a washing operation (e.g., a wet scrubber) to remove water and water soluble contaminants to provide a washed sour WGS product; contacting the washed sour WGS product with a physical or chemical solvent to separate acid gas products from the washed sour WGS product and provide (e.g., recover) a renewable hydrogen product, wherein the acid gas products comprise sulfur compounds; and recycling the acid gas products to combine with the gasifier effluent to increase the sulfur concentration of the gasifier effluent.

[0017] Further advantages may be achieved in embodiments that benefit from incorporating the produced steam. For example, such embodiments may further include passing the gasifier effluent through a pre-shift heat recovery operation to provide pre-shift product steam and supplying the pre-shift product steam to one or both of the gasifier and sour WGS operations, and / or passing the sour WGS product through a post-shift heat recovery operation to provide post-shift product steam and supplying the post-shift product steam to one or both of the gasifier and sour WGS operations.

[0018] These and other embodiments, aspects, and advantages of the present invention will become apparent from the detailed description that follows.

[0019] 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]

[0020] [Figure 1] FIG. 1 shows a flow scheme illustrating one embodiment of a process for gasifying a carbonaceous feed to produce a renewable hydrogen product.

[0021] Figure 1 shows a flow scheme illustrating one embodiment of a process for gasifying a carbonaceous feed to produce a renewable hydrogen product, in which a sour water-gas shift (WGS) operation is fed a gasifier effluent that has been enriched in sulfur by combining it with an acid gas product containing gaseous sulfur compounds. The acid gas product is separated from the sour WGS product and recycled. In the illustrated embodiment, heat recovery is used for steam generation both upstream and downstream of the sour WGS operation (i.e., pre-shift product steam and post-shift product steam), and the generated steam is injected into the gasifier and / or sour WGS operation for improved process integration.

[0022] For ease of explanation and understanding, the figures are presented in simplified overviews. Some related equipment, such as vessels, heat exchangers, valves, instrumentation, utilities, etc., is not shown because its specific description is not necessary for implementing or understanding various aspects of the present invention. Such devices will be readily apparent to those skilled in the art. Other processes for producing renewable hydrogen products according to other embodiments within the scope of the present invention, whose structures and components are determined in part for specific process purposes, will likewise be apparent. DETAILED DESCRIPTION OF THE INVENTION

[0023] 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.

[0024] As used herein, the term "substantially" refers to a degree of at least 95%. For example, the phrase "substantially all" can be replaced with "at least 95%." The phrases "all or part" or "at least part" are meant to encompass, in certain embodiments, "at least 50% of," "at least 75% of," "at least 90% of," and in preferred embodiments, "all."

[0025] Reference to any starting material, intermediate product, or final product, preferably all process streams, 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 portion may be unused due to reasons such as sampling, purging, diversion for other purposes, mechanical losses, etc. Thus, for example, the phrase "feeding sulfur-enriched gasifier effluent to a sour WGS operation" should be understood to mean "feeding all or a portion of the sulfur-enriched gasifier effluent to a sour WGS operation." Even where "all or a portion" is the understood meaning, the phrase nevertheless encompasses certain specific and preferred embodiments described above where the phrase is explicitly stated.

[0026] 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 parenthetical terms, which refer to the order in which one operation is performed or occurring relative to another, refer to the overall process flow, as will be understood by those skilled in the art. More specifically, the overall process flow can be defined by the bulk gasifier effluent stream and / or the bulk sour WGS product stream, as such stream(s) are passed through the operations defined herein. To the extent that parenthetical terms are used to denote order, in certain embodiments, these terms mean that one operation immediately precedes or follows the other operation, but more generally, these terms do not exclude the possibility of intervening operations. Thus, for example, the phrase "following the sour WGS operation, the sour WGS product is passed through a washing operation" means, according to certain embodiments, that the washing operation immediately follows the sour WGS operation. However, the phrase more generally means that one or more intervening operations can be performed or carried out between the sour WGS operation and the washing operation (e.g., according to the illustrated embodiment, a post-shift heat recovery operation can be performed or carried out downstream of the sour WGS operation and upstream of the washing operation).

[0027] To the extent that the exemplary processes described herein are defined by the inclusion of certain 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 particular process described herein is defined by a gasifier operation, a sour WGS operation downstream of the gasifier operation, and an acid gas removal operation downstream of the sour WGS operation. The gasifier operation provides a "gasifier effluent," and the sour WGS operation provides a "sour WGS product."

[0029] The term "gasifier effluent" is a general term that refers to the effluent of a gasifier, regardless of whether it has been passed through one or more operations downstream of the gasifier and upstream of a sour WGS operation. Accordingly, the term "gasifier effluent" includes (i) the effluent provided directly by the gasifier, i.e., "raw gasifier effluent," (ii) the raw gasifier effluent that has been passed through at least a tar removal operation, i.e., "tar-depleted gasifier effluent," which has a lower concentration of tar and oil compared to the raw gasifier effluent, (iii) the raw gasifier effluent that has been passed through at least a dry quench operation, i.e., "quenched gasifier effluent," which has a lower temperature and a higher water (H2O) concentration compared to the raw gasifier effluent, and (iv) the raw gasifier effluent that has been passed through at least a filtration operation, i.e., "raw gasifier effluent." The term "gasifier effluent" encompasses more specific terms meaning (i) "filtered gasifier effluent," which has a lower solid particle content compared to the raw gasifier effluent, (ii) "cooled gasifier effluent," which has been passed through at least a pre-shift heat recovery operation, i.e., has a lower temperature compared to the raw gasifier effluent, (iii) "sulfur-enriched gasifier effluent," which has been passed through a process to increase its sulfur concentration, i.e., has a higher sulfur concentration compared to the raw gasifier effluent, and (iv) raw gasifier effluent that has been passed through any other operation upstream of the sour WGS operation, whether or not specifically described herein. The term "gasifier effluent," and any of the more specific embodiments (i)-(vii) of this term, refer to a product (e.g., a flow stream) that is upstream of the sour WGS operation and that may optionally be fed to the sour WGS operation.

[0030] The term "sour WGS product" is a general term that refers to the product of a sour WGS operation, whether or not it has been passed to one or more operations downstream of this operation and, optionally, to an acid gas removal operation that may be used to recover a renewable hydrogen product. Accordingly, the term "sour WGS product" includes (i) the product provided directly by the sour WGS operation, i.e., "instant sour WGS product"; (ii) an instant sour WGS product that has been passed to at least a post-shift heat recovery operation, i.e., a "cooled sour WGS product," which is at a lower temperature compared to the instant sour WGS product; (iii) an instant sour WGS product that has been passed to at least a washing operation (e.g., a wet scrubber), i.e., a "washed sour WGS product," which has a higher water (HO) concentration and a lower content of water-soluble contaminants (e.g., chlorides) compared to the instant sour WGS product; and (iv) an instant sour WGS product that has been passed to at least a compression operation (e.g., a compressor). The term "sour WGS product" encompasses (i) an immediate sour WGS product (i.e., a "pressurized sour WGS product"), i.e., a "pressurized sour WGS product" that is at a higher pressure than the immediate WGS product, and (v) a more specific term that refers to an immediate sour WGS product that is passed to any other operation upstream of the sour WGS operation, whether or not specifically described herein. The term "sour WGS product" and any of its more specific embodiments (i)-(v) refer to products (e.g., flow streams) that are downstream of the sour WGS operation. In preferred embodiments, these products are also upstream of the acid gas removal operation and, optionally, may be fed to the acid gas removal operation.

[0031] The exemplary process described herein, defined by a gasifier operation, a sour WGS operation downstream of the gasifier operation, and an acid gas removal operation downstream of the sour WGS operation, advantageously utilizes an acid gas product containing sulfur compounds (e.g., HS) and separated from the sour WGS product to increase the sulfur concentration of the gasifier effluent upstream of or within the sour WGS operation. Alternatively, or in combination, such a process may further benefit from the use of a scrubbing operation (e.g., a wet scrubber), and more specifically, from a configuration in which this operation is downstream of the sour WGS operation and upstream of the acid gas removal operation. Importantly, according to certain embodiments described herein, the efficient use of the sour WGS operation can eliminate the need for a separate sulfur removal operation; preferably, the production of a renewable hydrogen product is achieved without sulfur removal either upstream of the sour WGS operation or, optionally, anywhere else in the process, other than the acid gas removal operation that provides the renewable hydrogen product. For example, the processes described herein may avoid or eliminate the separate removal of sulfur compounds, such as by utilizing a guard bed that may include iron-containing or zinc oxide-containing materials, i.e., a step or operation for such separate removal of sulfur compounds may not be present in certain embodiments.

[0032] In addition to the gasifier operation, the sour WGS operation, and the acid gas removal operation, the exemplary process may optionally include other operations, such as one or more of a tar removal operation, a dry quench operation, a filtration operation, and a pre-shift heat recovery operation, any one of which, or any combination thereof, is preferably performed downstream of the gasifier and upstream of the sour WGS operation. Alternatively, or in combination, the exemplary process may optionally include a post-shift heat recovery operation, a scrubbing operation (e.g., a wet scrubber), and compression, any one of which, or any combination thereof, is preferably performed downstream of the sour WGS operation and upstream of the acid gas removal operation. Possible characteristics of these operations and their associated process streams and conditions according to preferred embodiments are provided in the description below. Gasifier

[0033] 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.

[0034] 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 preferred embodiments, the carbonaceous feed may include biomass (e.g., wood), and certain aspects of the present invention relate to the benefits of using feeds with sulfur contents (concentrations) of less than about 500 wt-ppm (e.g., from about 1 to about 500 wt-ppm), less than about 200 wt-ppm (e.g., from about 5 to about 200 wt-ppm), or less than about 100 wt-ppm (e.g., from about 10 to about 100 wt-ppm). The use of such feeds in conventional gasification processes is incompatible with sour WGS operations (e.g., without acid gas product recycle) having catalyst systems in which metals are active and therefore should be maintained in their sulfided state.

[0035] The term "biomass" refers to renewable (non-petroleum-derived) material derived from living organisms on the Earth's surface or in the Earth's oceans, rivers, and / or lakes. Exemplary biomass can include any plant material or mixture of plant materials, such as hardwoods (e.g., whitewood), softwoods, 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. Particularly 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, Anthracnose beech, birch, eucalyptus, poplar, willow, paper mulberry, Australian blackwood, sycamore, and various sycamores. Other examples of suitable biomass include vegetable oils, carbohydrates (e.g., sugars), organic waste materials such as waste paper, structural materials, demolition waste, digester sludge, and biosludge. Accordingly, exemplary carbonaceous feeds include or comprise any of these types of biomass. Specific carbonaceous feeds that include biomass include municipal solid waste (MSW) or MSW-derived products, such as refuse-derived fuel (RDF). Carbonaceous feeds may also include combinations of petroleum-derived materials and renewable materials, including those mentioned above. A preferred carbonaceous feed is wood.

[0036] In the 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 contains other oxygenated gaseous components, including HO and / or CO, which may act as oxidizers for the carbonaceous feed. The oxygen-containing gasifier feed can refer to all gases being fed to or added to the gasifier, regardless of whether they are combined upstream of or within the gasifier. For example, the oxygen-containing gasifier feed may include fresh or makeup gasifier feed in addition to at least a portion of the steam generated elsewhere in the process (e.g., pre-shift and / or post-shift product steam). 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 exiting the gasifier. One or more reactors (e.g., operating in series or parallel) of the gasifier may be operated under gasification conditions present in such reactor(s), which generally include temperatures from about 500°C (932°F) to about 1000°C (1832°F), and typically from about 750°C (1382°F) to about 950°C (1742°F). Other gasification conditions may include atmospheric pressure or elevated temperatures, for example, absolute pressures generally from about 0.1 megapascals (MPa) (14.5 psi) to about 10 MPa (1450 psi), and typically from about 1 MPa (145 psi) to about 3 MPa (435 psi).

[0037] 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, increased H yield, and / or reduced CO yield. Limestone may be added to the gasification reactor to promote tar reduction, for example, 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 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.

[0038] In addition to gasifier effluent tar, the raw gasifier effluent contains carbon present in the carbonaceous feed, as well as CO, CO, and methane (CH), which are typically derived from H and / or HO and both, along with trace concentrations of other constituents, as described below. According to the illustrated embodiment, raw gasifier effluent 16 may be obtained directly from the gasifier 50 prior to further operations as described herein.

[0039] The gasifier effluent, either raw or any gasifier effluent that has been subjected to one or more of the operations described herein, may contain synthesis gas, i.e., may contain both H and CO, with these components present in various amounts (concentrations) and preferably in a total amount 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 %). For any such total amount (concentration), the H:CO molar ratio of the gasifier effluent may be suitable for use in downstream reactions, such as (i) conversion to higher molecular weight hydrocarbons and / or alcohols of various carbon numbers via a Fischer-Tropsch conversion, or (ii) conversion to renewable natural gas (RNG) via catalytic methanation, which increases the methane content in the resulting RNG stream. More typically, however, sour WGS operation is required to achieve a preferred H:CO molar ratio and / or preferred H concentration for these or other downstream applications, including fuel cell electricity generation or refinery hydroprocessing.

[0040] 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 total amount of at least about 90 mole %, at least about 95 mole %, or even at least about 99 mole %. Tar removal operation

[0041] Raw gasifier effluent obtained directly from a gasifier typically 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 with 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 large molecular weights, are further 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 also interfere with downstream processing steps, which are optimally performed (e.g., from a stability standpoint) with pure feed gas to enhance the synthesis gas into more valuable products.

[0042] Specific compounds that are undesirable for these reasons are 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 tars and oils, 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.

[0043] Depending on the specific tar removal operation, tars and oils in the raw gasifier effluent can be catalytically or non-catalytically converted by oxidation, pyrolysis, and / or reformation to provide additional H and CO in the regenerated effluent. The conversion reaction(s) can be utilized to utilize available O or oxygen sources (e.g., H O and / or CO) present in and / or added to the syngas. In terms of gasifier effluent tars, converting these compounds, along with methane, which contains the majority of the energy in the raw gasifier effluent, can significantly increase the overall syngas yield. Therefore, 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 under high temperature conditions relative to the conditions used in a gasifier, such that the tar-depleted gasifier effluent obtained directly from the tar removal operation may have a temperature of greater than about 1000°C (e.g., from about 1000°C (1832°F) to about 1500°C (2732°F), e.g., from about 1000°C (1832°F) to about 1250°C (2282°F).

[0044] According to one embodiment, the tar removal operation may be used to convert (e.g., reform) tar and methane by non-catalytic partial oxidation (POX). 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). The fuel is combusted, raising the temperature above 1100°C (2012°F), which allows the combustion products and excess oxygen to accumulate through a nozzle to sonic speeds, thereby forming a turbulent jet that improves mixing of the tar / methane containing syngas with the reactive hot oxygen stream. HOB-based systems can effectively improve syngas yields.

[0045] 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 practiced in tar removal operations, catalytic tar conversion may also include introducing additional oxygen and / or steam reactants into the reactor used in the operation.

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

[0047] 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 the 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 total 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 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 total 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. Dry Quench Operation

[0048] 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 a preferred embodiment, at least one dry quench operation is employed in which water is added directly to the gasifier effluent, contributing to its overall water content, thereby favoring H2 production via the equilibrium-limited WGS reaction (i.e., resulting in an increased H2:CO molar ratio and increased H2 concentration). The dry quench operation utilizes the sensible heat of the gasifier effluent to vaporize the injected water, resulting in a resulting quenched gasifier effluent at a desired lower temperature, e.g., about 400°C (752°F) to about 550°C (1022°F), and preferably about 450°C (842°F) to about 500°C (932°F), sufficient to allow further processing. This can include a subsequent filtration operation (passing through a filter) to remove solid particles (e.g., dust). In a preferred embodiment, only a partial quench is used, as opposed to a full quench, so that the quenched gasifier effluent exiting or obtained directly from the dry quench operation is above its dew point, i.e., is not saturated. In general, a dry quench operation can facilitate rapid and efficient cooling due to direct contact between the gasifier effluent and water as the quench medium. Filtration operation

[0049] A filtration operation using any suitable filter may be used to remove solid particles (particulates) from the gasifier effluent, such as the quench gasifier effluent 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 content of solid particles in the gasifier effluent, e.g., to provide a filtered gasifier effluent exiting or obtained directly from the filtration operation having less than 1 wt-ppm, and in some cases less than 0.1 wt-ppm, of solid particles.

[0050] In some embodiments, a filtration operation may be performed upstream (before) a tar removal operation, allowing subsequent operations 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).

[0051] The filtration operation may be followed by or integrated with an additional cleaning operation to further purify the gasifier effluent, e.g., 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 result in more complete removal of benzene, naphthalene, toluene, phenol, and other condensable species that might otherwise be harmful to downstream operations, such as by deposition on equipment. Sour WGS operation

[0052] The sour water-gas shift (WGS) reaction involves reacting CO present in a sulfur-enriched gasifier effluent, such as that obtained by adding sulfur to the filtered gasifier effluent described above or, optionally, to the cooled gasifier effluent after the pre-shift heat recovery operation described herein, with steam to increase the H concentration (as well as the CO concentration) in the presence of HS. The use of a stoichiometric excess of steam can be beneficial, particularly in adiabatic fixed-bed reactors, for a number of purposes. 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. Reactors used in sour WGS operations may contain a suitable catalyst, such as a catalyst comprising one or more of Co, Ni, Mo, and W on a solid support; specific examples of suitable catalysts are Co / Mo and Ni / Mo catalysts. The presence of H2S during sour WGS operations (e.g., in the environment of the reactor(s) used in the operations) is generally necessary to maintain these metals in their active sulfided state (i.e., as their corresponding sulfided compounds). Other catalysts used in the operations (i.e., contained in one or more sour WGS reactors) include copper- and / or zinc-containing catalysts such as Cu-Zn-Al, chromium-containing catalysts, catalysts based on iron oxide, zinc ferrite, magnetite, chromium oxide, and any combination thereof (e.g., Fe2O3-Cr2O3 catalysts).

[0053] The choice of catalyst typically depends, at least in part, on the sulfur content of the gases fed to and reacted in the sour WGS operation (i.e., within the reaction environment of one or more reactors of the operation). Certain catalysts, such as those containing metals described above and desirably maintained in their sulfided (e.g., as opposed to oxidized) state, may be compatible with reaction environments having at least about 50 vol-ppm (e.g., from about 50 to about 2000 vol-ppm), at least about 100 vol-ppm (e.g., from about 100 to about 1000 vol-ppm), or at least about 150 vol-ppm (e.g., from about 150 to about 500 vol-ppm) total sulfur (e.g., present as HS, optionally combined with other sulfur-containing compounds). Other catalysts may be compatible with reaction environments having low sulfur contents, such as at least about 0.5 vol-ppm (e.g., about 0.5 to about 100 vol-ppm), at least about 1 vol-ppm (e.g., about 1 to about 100 vol-ppm), or at least about 5 vol-ppm (e.g., about 5 to about 100 vol-ppm). As described herein with respect to embodiments utilizing sulfur-containing recycle gas, this gas may contribute significantly to the sulfur content (e.g., at least about 25%, at least about 50%, or at least about 75%) in the reaction environment of one or more reactors of a sour WGS operation. The sulfur content of the carbonaceous feed may determine, at least in part, the sulfur content of the reaction environment of the sour WGS operation and / or the sulfur-containing recycle gas, and consequently, may determine, at least in part, the catalyst selection. In this regard, it can be understood that the term "sour WGS operation" can, in some embodiments, refer to a unit operation that utilizes one or more reactors containing a catalyst having a metal(s) active in its / their sulfided state and that utilizes a reaction environment with a relatively high sulfur content, such as those described above.In other embodiments, the term can refer to unit operations that utilize one or more reactors containing catalysts that exhibit low sulfur tolerance but nonetheless exhibit sufficient activity for use under conditions during sour WGS operations, in the case of the present catalysts, having metal(s) that are not necessarily more active in their / their sulfided state, and / or utilize reaction environments that are relatively low in sulfur content, such as those described above.

[0054] In a typical sour WGS operation, two or more reactors with interstage cooling are used, taking into account the thermodynamic characteristics of the sour shift 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 is then 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. The combined effect of the HTS and LTS reactors results in significant conversion to H with favorable residence times. In some cases, it may be desirable to carry out the sour WGS reaction using three or more reactors or catalyst beds, again with cooling between successive reactors or catalyst beds.

[0055] In this manner, the sour WGS operation may be used to provide an instant sour WGS product having an increased H:CO molar ratio and increased H concentration relative to the sulfur-enriched gasifier effluent exiting or directly obtained from the operation or the gasifier effluent (e.g., filtered or cooled gasifier effluent) obtained from an upstream operation. For example, the instant sour WGS product may 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 characteristics of the immediate sour WGS product may be controlled to a greater or lesser extent by bypassing the sour WGS operation (e.g., diverting a smaller or larger portion of the operation's feed, such as sulfur-enriched gasifier effluent, around the operation to provide a portion of the immediate sour WGS product). The sour WGS operation is further beneficial in terms of converting carbonyl sulfide (COS) to HS, which can be separated and recycled to the sour WGS operation to provide the benefits described herein. Cleaning operation

[0056] Washing operations may be used to remove water and water-soluble contaminants from a sour WGS product, such as the immediate sour WGS product emerging from the sour WGS operation described above, or, optionally, the cooled sour WGS product following a post-shift heat recovery operation described herein. Washing operations, such as wet washing, can be effective in removing chlorides (e.g., in the form of HCl) and ammonia, as well as fine solid particles (e.g., charcoal and ash). For example, when using a wet scrubber, the sour WGS product may 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. Washing operations can be used to provide a washed sour WGS product emerging from or obtained directly from this operation and having a total amount of chlorine, ammonia, and solid particles of less than 1 wt-ppm, and optionally less than 0.1 wt-ppm. The washing operation also typically serves to remove water from the sour WGS product, thereby reducing the moisture content of the washed sour WGS product compared to the feed to the washing operation (e.g., the immediate sour WGS product or the cooled sour WGS product). Acid gas removal operation

[0057] An acid gas removal operation may be used to separate an acid gas product from the sour WGS product, such as the washed sour WGS product described above or the pressurized sour WGS product after compression described herein. The acid gas product may be an H2S-enriched product (e.g., having an increased H2S concentration compared to the sour WGS product), which may be advantageously recycled to maintain the activity of the catalyst used in the sour WGS operation, as described herein. The acid gas product may also be enriched in other sulfur compounds, such as COS and / or SO2, as well as in overall sulfur content (concentration), compared to the sour WGS product. In some embodiments, the acid gas removal operation may further provide a CO2-enriched product (e.g., as a second acid gas product having an increased CO2 concentration compared to the sour WGS product, which may be a washed sour WGS product or a pressurized sour WGS product). If a CO2-enriched product is recovered, it may or may not be recycled to the process.

[0058] Thus, an acid gas removal operation may be used to reduce the concentration of HS and / or CO in the sour WGS product (e.g., a washed sour WGS product or a pressurized sour WGS product) and provide a renewable hydrogen product exiting or obtained directly from the operation. If an upstream scrubbing operation is utilized, it may provide the requisite degree of dehydration of the washed sour WGS product or the pressurized sour WGS product for use as a feed to the acid gas removal operation. The combined effect of the sour WGS operation (to produce H) and the acid gas removal operation (to purify H) can provide a renewable hydrogen product having a hydrogen concentration of at least about 50 mol % (e.g., from about 50 mol % to about 98 mol %), at least about 55 mol % (e.g., from about 55 mol % to about 95 mol %), or at least about 60 mol % (e.g., from about 60 mol % to about 90 mol %). The renewable hydrogen product may generally have a CO concentration of about 1 mol% to about 25 mol%, and typically about 2 mol% to about 20 mol%, and may have a total sulfur content (concentration) of less than about 0.1 mol-ppm.

[0059] The acid gas removal operation is performed using Selexol (登録商標) (Polyethylene glycol dimethyl ether), Rectisol (登録商標) The acid gas removal process may utilize one or more contacting steps with a physical solvent, such as ethanolamine, diethanolamine, methyldiethanolamine (MDEA), diisopropylamine, or a combination thereof. In the case of a physical solvent, the acid gases are selectively solubilized in the solvent at elevated temperatures, and the solvent may be regenerated upon depressurization, releasing the separated acid gas products. Alternatively, the acid gas removal process may utilize one or more contacting steps with a chemical solvent, such as amine solvents such as monoethanolamine, diethanolamine, methyldiethanolamine (MDEA), diisopropylamine, or diglycolamine. In the case of a chemical solvent, the acid gases are selectively adsorbed by chemical interaction, and the solvent may be regenerated upon heating, releasing the separated acid gas products. Other solvents, such as methanol, potassium carbonate, or solutions of sodium salts of amino acids, may also be used to remove at least a portion of the acid gases initially present in the sour WGS product (e.g., washed sour WGS product or pressurized sour WGS product). Physical or chemical solvents may facilitate the selective removal of H2S / COS in addition to the removal of CO2 in the product. (登録商標) For physical solvents such as HCl, temperatures up to 175°C (347°F) may generally be suitable. Acid gas products, such as H2S-enriched products, can be released by regenerating the rich physical or chemical solvent, such as after the capacity for removing acid gases has been substantially reached. For example, regeneration can be accomplished by desorption of the rich solvent by flashing (depressurization), thermal treatment, and / or use of a stripping gas. Further Exemplary Embodiments of the Gasification Process

[0060] The figure shows a flow scheme illustrating an embodiment of a process that includes the operations described above and is further integrated with pre-shift and post-shift heat recovery operations to generate steam that can be used in the process. 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 that contains syngas. The oxygen-containing gasifier feed 14 comprises both the makeup gasifier feed 12 and at least a portion of the pre-shift product steam 26. The oxygen-containing gasifier feed 14 may contain 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%.

[0061] In general, an exemplary process may include increasing the sulfur content (concentration) of a gasifier effluent to provide a sulfur-enriched gasifier effluent. According to the illustrated embodiment, the sulfur content of a gasifier effluent, such as cooled gasifier effluent 28, is increased prior to sour WGS operation 75 by combining an acid gas product 46 containing sulfur compounds (e.g., HS) with the gasifier effluent. However, the sulfur content may alternatively be increased in this operation, for example, by separately feeding the gasifier effluent and the acid gas product containing sulfur compounds to sour WGS operation 75. As illustrated, the sulfur content may be increased more specifically by recycling acid gas product 46 to provide at least a portion of the sulfur-containing recycle gas 42 that is combined with the gasifier effluent to provide sulfur-enriched gasifier effluent 30. The exemplary process may further include feeding the sulfur-enriched gasifier effluent 30 to a sour WGS operation 75 to provide a sour WGS product, which may more specifically be an instant sour WGS product 32 having an increased hydrogen concentration relative to the sulfur-enriched gasifier effluent 30.

[0062] As mentioned above, sufficient sulfur concentration in the environment of the sour WGS operation 75 may be necessary to maintain the catalyst used in the operation in its active, sulfided state. To this end, the sulfur content (concentration) in the sulfur-containing recycle gas 42 may be maintained, for example, in a range of about 100 to about 1000 vol-ppm, e.g., about 150 to about 500 vol-ppm. This sulfur concentration may also be exemplary of the sulfur concentration in any one or more of the sulfur-enriched gasifier effluent 30, the sour WGS feed 35, and the sour WGS operation 75. The sulfur concentration in these and other streams / operations in the recycle loop, where HS and other sulfur compounds are preferentially retained, may be controlled (increased or decreased), for example, by purging a smaller or larger portion, respectively, of this recycle through the recycle loop purge 47, which also mitigates excessive buildup of undesirable impurities in the recycle gas, such as certain non-condensable gases (e.g., nitrogen). The sulfur concentration may also be controlled by adding sulfur to the recycle loop (e.g., a gas stream that may include one or more of acid gas product 46, sulfur-containing recycle gas 42, sulfur-enriched gasifier effluent 30, sour WGS feed 35, sour WGS product 32, cooled sour WGS product 36, washed sour WGS product 38, and pressurized sour WGS product 40). In this regard, makeup sulfur-containing feed 44 may be combined with any stream of the recycle loop, e.g., acid gas product 46, to provide the illustrated sulfur-containing recycle gas 42. Makeup sulfur-containing feed 44 may have a higher sulfur content (concentration) than that present anywhere in the recycle loop and may include HS or, alternatively, a sulfur-containing precursor that can rapidly decompose to form HS in the recycle loop environment. Exemplary sulfur-containing precursors are dimethyl disulfide (DMDS) and di-tert-butyl polysulfide (TBPS), which are more easily handled than gaseous HS.The exemplary process may further include recovering a renewable hydrogen product 45 from the sour WGS product, e.g., pressurized sour WGS product 40, with the renewable hydrogen product (e.g., H-enriched product) obtained by separating an acid gas product 46 (e.g., an H2S-enriched product) and optionally a second acid gas product, e.g., a CO2-enriched product 48, from the sour WGS product using an acid gas removal operation 95.

[0063] Prior to the step of increasing its sulfur concentration, the gasifier effluent, such as raw gasifier effluent 16 obtained directly from the gasifier 50, may be passed through one or more of a tar removal (e.g., tar reformation) operation 55, such as to provide a tar-depleted gasifier effluent 18, a dry quench operation 60 to which quench water 20 is supplied for cooling, such as to provide a quenched gasifier effluent 22, a filtration operation 65, such as to provide a filtered gasifier effluent 24, and a pre-shift heat recovery operation 70, such as to provide a cooled gasifier effluent 28. In the preferred embodiment shown in the figure, all of these operations are used in the order described above before increasing the sulfur concentration of the gasifier effluent, such as by combining the cooled gasifier effluent 28 with the acid gas product 46, and also before feeding the sulfur-enriched gasifier effluent 30 to a sour WGS operation 75. While the steps of increasing the sulfur concentration of the gasifier effluent and feeding the sulfur-enriched gasifier effluent may be performed sequentially as shown, these steps may alternatively be performed (e.g., simultaneously) in a sour WGS operation 75, such as by feeding both the cooled gasifier effluent 28 and the acid gas product 46 directly to the operation or to a sour WGS reactor used in the operation.

[0064] As further shown, recovering renewable hydrogen product 45 may include separating acid gas product 46, which includes sulfur compounds (e.g., H2S), from the sour WGS product, in this case pressurized sour WGS product 40. This separation is or may be performed in acid gas removal operation 95. As noted above, this operation may utilize a physical or chemical solvent, whereby separating acid gas product 46 from the sour WGS product may involve removing this product from a physical solvent (e.g., Selexol (登録商標) ) or a chemical solvent (e.g., MDEA, or other amines as described above). In this case, an acid gas product 46 containing sulfur compounds (e.g., HS) may be released upon regeneration of the physical solvent. The released acid gas product 46 may then provide at least a portion of the sulfur-containing recycle gas 42. In this manner, the acid gas product 46 may be separated from the sour WGS product using a physical solvent before being combined with the gasifier effluent to increase its sulfur content (concentration). Thus, increasing the sulfur concentration of the gasifier effluent may more specifically include recycling the acid gas product 46 and combining it with the gasifier effluent, e.g., cooled gasifier effluent 28. As described above, in addition to providing the acid gas product 46 as, for example, an HS-enriched product, the acid gas removal operation 95 may also provide a CO-enriched product 48 as a second acid gas product.

[0065] Prior to separating the acid gas product 46 from the sour WGS product, the immediate sour WGS product 32 obtained directly from the sour WGS operation 75 may be passed through one or more of a post-shift heat recovery operation 80, such as to provide a cooled sour WGS product 36, a washing operation (e.g., a wet scrubber) 85, such as to provide a washed sour WGS product 38, and compression, such as with a compressor 90, to provide a pressurized sour WGS product 40. In the preferred embodiment shown in the figure, all of these operations are used in the order described above before recovering the renewable hydrogen product.

[0066] According to certain embodiments, heat recovery and steam generation may be integrated into the process. For example, a gasifier effluent, such as filtered gasifier effluent 24, may be passed through pre-shift heat recovery 70 prior to or upstream of sour WGS operation 75, thereby providing cooled gasifier effluent 28. Pre-shift product steam 26 may be obtained by indirect or heat exchange contact between the gasifier effluent and pre-shift boiler feedwater 25a. Similarly, a sour WGS product, such as immediate sour WGS product 32, may be passed through post-shift heat recovery 80 after or downstream of sour WGS operation 75, thereby providing cooled sour WGS product 36. Post-shift product steam 34 may be obtained by indirect or heat exchange contact between the sour WGS product and post-shift boiler feedwater 25b. To achieve the various objectives described herein, an exemplary process may include supplying pre-shift product steam 26 and / or post-shift product steam 34 to one or both of gasifier 50 and sour WGS operation 75. Accordingly, a combination of pre-shift product steam 26 and / or post-shift product steam 34 and makeup gasifier feed 12 may be used to provide oxygen-containing gasifier feed 14. Similarly, a combination of pre-shift product steam 26 and / or post-shift product steam 34 and sulfur-enriched gasifier effluent may be used to provide sour WGS feed 35.

[0067] Thus, recovering renewable hydrogen product 45 may involve the combined use of sour WGS operation 75 and acid gas removal operation 95 for H generation and H purification, respectively. Feeding a gasifier effluent, such as sulfur-enriched gasifier effluent 30, to the sour WGS operation provides a sour WGS product, such as instant sour WGS product 32, that has an increased hydrogen concentration relative to the gasifier effluent. Both the H concentration and H:CO molar ratio of the sour WGS product may be controlled by adjusting the relative amount of bypass portion 28a of the gasifier effluent, such as cooled gasifier effluent 28, that may be diverted around sour WGS operation 75. As described herein, for example, with respect to the operational sequence according to the illustrated embodiment, advantages may be realized by using a sour WGS operation as opposed to utilizing a water-gas shift operation, which cannot tolerate sulfur and other contaminants. After sour WGS operation 75 and prior to recovery of renewable hydrogen product 45 using acid gas removal operation 95, the pressurized sour WGS product, such as sour WGS product 40, may be passed through a scrubbing operation (e.g., wet scrubbing) 85 to remove water and water-soluble contaminants (e.g., chlorides). Thus, after or downstream of sour WGS operation 75, the sour WGS product may be passed through an acid gas removal operation 95, which is used to recover renewable H2 product 45, in addition to a scrubbing operation (e.g., wet scrubber) 85.

[0068] The illustrated embodiment relates to an exemplary process for gasifying a carbonaceous feed 10 to produce a renewable hydrogen product 45 . The process includes contacting a carbonaceous feed 10 with an oxygen-containing gasifier feed 14 under gasification conditions in a gasifier 50 to provide a gasifier effluent (e.g., raw gasifier effluent 16) comprising syngas; passing the gasifier effluent (e.g., raw gasifier effluent 16) through at least a tar removal operation 55 and a dry quench operation 60 upstream of a sour water-gas shift (WGS) operation 75; increasing the sulfur content (concentration) of the gasifier effluent (e.g., cooled gasifier effluent 28) to provide a sulfur-enriched gasifier effluent 30 having an increased sulfur concentration compared to the sulfur concentration of the gasifier effluent; feeding the sulfur-enriched gasifier effluent 30 to the sour water-gas shift (WGS) operation 75 to produce a sour WGS product (e.g., immediate sour WGS production) having an increased hydrogen concentration compared to the hydrogen concentration of the sulfur-enriched gasifier effluent 30. the sour WGS product 38 having a reduced water concentration and / or reduced water-soluble contaminants (e.g., chlorides) compared to the water concentration and / or water-soluble contaminants (e.g., chlorides) of the cooled sour WGS product 36; contacting the washed sour WGS product 38 with a physical solvent and separating an acid gas product 46 from the washed sour WGS product 38 (optionally after pressurization using a compressor 90 to provide a pressurized sour WGS product 40) to provide a renewable hydrogen product 45 having an increased H:CO molar ratio and / or H concentration compared to the washed sour WGS product (and, optionally, the pressurized sour WGS product 40). The acid gas product 46 contains sulfur compounds (e.g., H2S), and recycling this product and combining it with gasifier effluent (e.g., cooled gasifier effluent 28) advantageously increases the sulfur concentration for use in sour WGS operations, as described herein.

[0069] In summary, aspects of the present invention relate to renewable hydrogen product gasification processes that utilize sour WGS operations to carry out this reaction at a stage in the overall process that provides improved processing efficiency and resulting economic benefits (e.g., reduced utility requirements). Those skilled in the art 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 shown and described herein are illustrative only and do not limit the invention as defined by the appended claims.

Claims

1. 1. A process for gasifying a carbonaceous feed to produce a renewable hydrogen product, the process comprising: (a) contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasifying conditions in a gasifier to provide a gasifier effluent comprising synthesis gas; (b) increasing the sulfur concentration of the gasifier effluent to provide a sulfur-enriched gasifier effluent; (c) feeding the sulfur-enriched gasifier effluent to a sour water-gas shift (WGS) operation to provide a sour WGS product having an increased hydrogen concentration relative to the hydrogen concentration of the sulfur-enriched gasifier effluent; (d) recovering said renewable hydrogen product from said sour WGS product.

2. 10. The process of claim 1, wherein prior to step (b), the gasifier effluent is passed through one or more of a tar removal operation, a dry quench operation, a filtration operation, and a pre-shift heat recovery operation.

3. 3. The process of claim 1 or 2, wherein steps (b) and (c) are carried out in the sour WGS operation.

4. The process of any one of claims 1 to 3, wherein step (d) comprises separating an acid gas product from the sour WGS product.

5. 5. The process of claim 4, wherein prior to separating the acid gas product from the sour WGS product, the sour WGS product is passed through one or more of a post-shift heat recovery operation, a washing operation, and compression.

6. 5. The process of claim 4, wherein the acid gas product comprises sulfur compounds, and further wherein step (b) comprises recycling the acid gas product to combine with the gasifier effluent.

7. 5. The process of claim 4, wherein separating the acid gas product from the sour WGS product comprises contacting the sour WGS product with a physical or chemical solvent.

8. 8. The process of claim 7, wherein the acid gas products comprise sulfur compounds, the acid gas products are released during regeneration of the physical or chemical solvent, and step (b) comprises recycling the acid gas products and combining them with the gasifier effluent.

9. The process of any one of claims 1 to 8, wherein prior to step (b), the gasifier effluent is passed through a pre-shift heat recovery operation to provide pre-shift product steam.

10. 10. The process of claim 9, further comprising supplying the pre-shift product steam to one or both of the gasifier and the sour WGS operation.

11. The process of any one of claims 1 to 10, wherein after step (c), the sour WGS product is passed to a post-shift heat recovery operation to provide post-shift product steam.

12. 12. The process of claim 11, further comprising supplying the post-shift product steam to one or both of the gasifier and the sour WGS operation.

13. 1. A process for gasifying a carbonaceous feed to produce a renewable hydrogen product, the process comprising: contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasifying conditions in a gasifier to provide a gasifier effluent comprising synthesis gas; feeding the gasifier effluent to a sour water-gas shift (WGS) operation to provide a sour WGS product having an increased hydrogen concentration compared to the hydrogen concentration of the gasifier effluent; recovering the renewable hydrogen product from the sour WGS product; A process wherein, after said sour WGS operation, said sour WGS product is passed through a washing operation to remove water and water-soluble contaminants.

14. 14. The process of claim 13, wherein the sulfur concentration of the gasifier effluent is increased prior to or during the sour WGS operation.

15. 15. The process of claim 14, wherein the sulfur concentration of the gasifier effluent is increased by combining an acid gas product containing sulfur compounds with the gasifier effluent.

16. 16. The process of claim 15, wherein the acid gas product is separated from the sour WGS product after contacting the sour WGS product with a physical or chemical solvent.

17. 17. The process of any one of claims 13 to 16, wherein the sulfur content of the carbonaceous feed is less than about 500 wt-ppm.

18. 18. The process of any one of claims 13 to 17, wherein after the sour WGS operation, the sour WGS product is passed to an acid gas removal operation in addition to the wet wash operation to recover the renewable hydrogen product.

19. 1. A process for gasifying a carbonaceous feed to produce a renewable hydrogen product, the process comprising: contacting the carbonaceous feed with an oxygen-containing gasifier feed under gasifying conditions in a gasifier to provide a gasifier effluent comprising synthesis gas; passing the gasifier effluent through at least a tar removal operation and a dry quench operation upstream of a sour water-gas shift (WGS) operation; increasing the sulfur concentration of the gasifier effluent to provide a sulfur-enriched gasifier effluent; feeding the sulfur-enriched gasifier effluent to a sour water-gas shift (WGS) operation to provide a sour WGS product having an increased hydrogen concentration relative to the hydrogen concentration of the sulfur-enriched gasifier effluent; passing said sour WGS product through a washing operation to remove water and water-soluble contaminants to provide a washed sour WGS product; contacting the washed sour WGS product with a physical or chemical solvent to separate an acid gas product from the washed sour WGS product and provide the renewable hydrogen product, wherein the gas product comprises sulfur compounds; recycling and combining said acid gas product with said gasifier effluent to enrich said sulfur concentration of said gasifier effluent.

20. The gasification system waste liquid is passing a pre-shift product steam through a pre-shift heat recovery operation to provide pre-shift product steam, and supplying the pre-shift product steam to one or both of the gasifier and the sour WGS operation; 20. The process of claim 19, further comprising passing the sour WGS product through a post-shift heat recovery operation to provide post-shift product steam, and supplying the post-shift product steam to one or both of the gasifier and the sour WGS operation.

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