Method for producing synthesis gas from biomass by removing tar from tail gas

Abstract

Systems and methods for generating syngas by gasification of biomass are disclosed herein. Some aspects of the present disclosure relate to a biomass gasification process utilizing tail gas byproducts as fuels.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of priority to U.S. Provisional Patent Application Serial No. 63 / 331,606 filed on April 15, 2022 and U.S. Provisional Patent Application Serial No. 63 / 333,773 filed on April 22, 2022, each of which is incorporated herein by reference in its entirety. Background and field I. Field

[0002] The present disclosure and related inventions relate at least to the field of renewable fuel production, and in particular to systems and methods for performing biomass gasification. II. Background

[0003] Gasification is a process that uses a partial oxidation process involving heat, steam and oxygen (or air) to convert any carbon-containing feedstock, such as biomass, into synthesis gas (syngas for short). Syngas is mainly composed of hydrogen (H 2 ), carbon monoxide (CO) and carbon dioxide (CO 2 ) and can be further processed and converted into a variety of products such as hydrogen, ammonia, methanol, gasoline, aviation fuel and electricity. The carbon generated by the process can be captured and stored for use.

[0004] This patent will focus primarily on biomass gasification for the production of hydrogen, but it can be applied to the production of other fuels or chemicals. Biomass is a renewable organic resource that includes agricultural crop waste, forestry waste, specialty crops grown specifically for energy purposes (such as switchgrass or willow), municipal solid waste, and animal manure. This renewable resource can be used to produce syngas and other byproducts through gasification.

[0005] In the gasification process, biomass is converted to syngas at high temperatures (e.g. >700°C) using controlled amounts of oxygen (or air) and steam. To maximize hydrogen production, a water-gas shift reactor is used downstream of gasification to convert carbon monoxide and water into carbon dioxide and more hydrogen. Acid gases, i.e. hydrogen sulfide (H2S), are produced by the conversion of carbon monoxide and water into carbon dioxide and more hydrogen. 2 S) and carbon dioxide (CO 2 ) is removed from the syngas in the subsequent syngas purification section. High-purity hydrogen is separated from the clean syngas stream by pressure swing adsorption (PSA) or special membranes. The remaining tail gas can be used to generate steam and / or electricity.

[0006] Problems with existing biomass gasification methods include the generation of tar as a byproduct during the gasification process, especially when the tar generation level exceeds the tar tolerance level of the downstream system. Tar refers to organic compounds with a molecular weight higher than benzene, and its removal or reduction is a significant challenge. Therefore, there is a need for improved methods and systems for removing tar generated during the gasification of biomass feed.

[0007] As will be explained in detail below, the present invention overcomes these and other problems. Summary of the invention

[0008] In conventional oxygen-blown biomass gasification systems with tar thermal decomposition (or thermal cracking), about 4% to 14% of the generated synthesis gas is used as a fuel for the tar removal (or tar burner) system. If natural gas is available, it can also be used together with synthesis gas or alone as a fuel for the tar removal system. The inventors have found that by providing at least a portion of the tail gas by-products from the post-gasification process to the tar removal system of the synthesis gas generation system, the net amount of synthesis gas used to produce hydrogen or other final products is increased. In a method model in which the tar removal system is configured to use tail gas rather than synthesis gas as a fuel source, the amount of hydrogen produced at the PSA outlet increases by 8% to 11%. Tail gas is usually a low-value by-product discharged into the atmosphere after combustion. Therefore, the tail gas by-product can be used as an alternative, lower-value substitute for higher-value natural gas or recycled synthesis gas.

[0009] Therefore, some aspects of the present disclosure relate to a biomass gasification method using tail gas byproducts as fuel. In some aspects, the method includes: a biomass receiving and preparing system for feeding biomass to a biomass feed port of a syngas generation system; gasification using one or more gasifiers of the syngas generation system under conditions that result in the generation of tar byproducts, the syngas generation system including a tar removal system configured to remove tar byproducts from syngas; a post-gasification process including a separation or purification system that results in the generation of tail gas byproducts; a tar removal system that provides at least a portion of the tail gas byproducts to the syngas generation system; and operating the tar removal system using at least a portion of the tail gas byproducts as fuel to remove or reduce tar in the syngas.

[0010] In some aspects, the method also includes increasing the concentration of at least one tail gas by-product component by a separation process before providing at least a portion of the tail gas by-product to the tar removal system of the synthesis gas generation system. In some aspects, increasing the concentration of at least one tail gas by-product component includes using a separation technology selected from pressure swing adsorption (PSA), cryogenic distillation and membrane separation. In some aspects, the component whose concentration increases is an oxidizable component. In some aspects, the oxidizable component is selected from hydrogen, carbon monoxide and a combination thereof.

[0011] In some aspects, the tail gas byproduct provided to the tar removal system of the syngas generation system does not undergo a component concentration increase step. In other words, the untreated raw tail gas is recycled to the tar removal system.

[0012] In some aspects, natural gas or recycled syngas for the tar removal system is replaced or supplemented by providing at least a portion of the tail gas byproduct to the tar removal system.

[0013] Some aspects of the present disclosure relate to a synthesis gas (syngas) generation system. In some aspects, the syngas generation system includes: a biomass feed port, which is configured to receive a biomass feed; a gasifier, which is in communication with the biomass feed port and is configured to receive and gasify the biomass feed to produce syngas under conditions that result in the generation of tar byproducts; a post-gasification process, which includes a separation or purification system that results in the generation of tail gas byproducts; and a transport system, which is configured to transport the tail gas byproducts to a tar removal system within the syngas generation system that is configured to use the tail gas byproducts received by the transport system as a fuel to process the syngas to remove the tail gas byproducts from the syngas.

[0014] In some aspects, the delivery system includes a component separation device that increases the concentration of at least one tail gas by-product component by a separation process. In some aspects, the component separation device increases the concentration of at least one tail gas by-product component by adopting a separation technology selected from pressure swing adsorption (PSA), cryogenic distillation and membrane separation. In some aspects, the component whose concentration increases is an oxidizable component. In some aspects, the oxidizable component is selected from hydrogen, carbon monoxide and a combination thereof. In some aspects, the system does not include a component separation device for increasing the concentration of at least one tail gas by-product component. In some aspects, compared with a comparable synthesis gas generation system lacking a tail gas delivery system, the delivery system enables the synthesis gas generation system to generate an increased net amount of synthesis gas.

[0015] As used herein, various terms are used only for the purpose of describing a particular implementation, and are not intended to limit implementation. For example, as used herein, ordinal terms (e.g., "first," "second," "third," etc.) used to modify elements such as structures, components, operations, etc. do not themselves indicate any priority or order of an element relative to another element, but only distinguish the element from another element with the same name (but using ordinal terms). The term "coupled" is defined as connected, although such connection is not necessarily directly connected or mechanically connected; "coupled" two items can be independent of each other (unitary). Do not use plural references unless the present disclosure explicitly requires otherwise. As understood by those of ordinary skill in the art, the term "substantially" is defined as being largely but not necessarily completely specified (and including completely specified content; for example, substantially 90 degrees includes 90 degrees, and substantially parallel includes parallel). In any disclosed configuration, the term "substantially" can be replaced with "within [percentage] of the specified range," where percentages include 0.1%, 1%, 5%, and 10%.

[0016] Throughout the application, the term "about" is used to represent a numerical value including a variation of the inherent error of a measurement or metering method. In various embodiments, as used herein, the term "about" refers to a common error range including a corresponding value that is easily known. "About" a certain numerical value or "about" a certain parameter mentioned herein includes (and describes) embodiments for the numerical value or the parameter itself. For example, a description referring to "about X" includes a description of "X". In some embodiments, as understood by those skilled in the art, "about" can refer to ± 15%, ± 10%, ± 5% or ± 1%.

[0017] When used in conjunction with the term "comprising", the term without a quantifier means "a", but also means "one or more", "at least one" and "one or more than one".

[0018] The phrase "and / or" means "and" or "or". For illustration, A, B, and / or C includes: A alone, B alone, C alone, a combination of A and B, a combination of A and C, a combination of B and C, or a combination of A, B, and C. In other words, "and / or" is used to include or. Similarly, the phrase "A, B, C, or a combination thereof" or "A, B, C, or any combination thereof" includes: A alone, B alone, C alone, a combination of A and B, a combination of A and C, a combination of B and C, or a combination of A, B, and C.

[0019] The words "comprise" (and any form thereof, such as "including", "comprising", etc.), "have" (and any form thereof, such as "have", "have", etc.), "include" (and any form thereof, such as "including", "containing", etc.) or "contain" (and any form thereof, such as "containing", "including", etc.) are inclusive or open-ended and do not exclude additional elements or method steps not mentioned.

[0020] Compositions and methods of use thereof may "comprise / include," "consist essentially of," or "consist of" any component or step disclosed throughout the specification. Compositions and methods that "consist essentially of" any disclosed component or step limit the scope of the claim to specific materials or steps that do not materially affect the basic and novel features of the claimed invention. Any implementation of any system, method, apparatus, and article of manufacture may consist of or consist essentially of any of the described steps, elements, and / or features, rather than including / containing / comprising any of the described steps, elements, and / or features. Therefore, in any claim, any of the above open-ended linking verbs may be replaced with the term "consisting of" or "consisting essentially of" to change the scope of a given claim from the original scope when the open-ended linking verb is used. Apparatus, systems, and methods that "consist essentially of" any disclosed component, device, or step limit the scope of the claim to specific materials or steps that do not materially affect the basic and novel features of the claimed implementation. In addition, the term "wherein" may be used interchangeably with "in..."

[0021] It is contemplated that any embodiment discussed in this specification can be implemented with respect to any method or any composition of the invention, and vice versa. In addition, the compositions of the invention can be used to implement the methods of the invention.

[0022] Other objects, features and advantages of the present invention will become apparent in the detailed description below. However, it should be understood that although the detailed description and specific examples indicate specific embodiments of the present invention, they are given by way of illustration only, because various changes and modifications from the detailed description that do not depart from the spirit and scope of the present invention are obvious to those skilled in the art. BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The following drawings constitute part of this specification and are used to further illustrate certain aspects of the present invention. The present invention may be better understood by referring to one or more of these drawings in conjunction with the detailed description of specific embodiments presented herein.

[0024] Figure 1 It uses biomass to generate hydrogen and capture carbon dioxide (CO 2) is a schematic diagram of a synthesis gas generation method. According to an embodiment of the present disclosure, the method includes a synthesis gas generation system that uses tail gas as fuel to remove tar.

[0025] Figure 2 is a schematic diagram of a syngas generation method of a syngas generation system for removing tar by using tail gas as fuel according to an embodiment of the present disclosure. DETAILED DESCRIPTION OF THE INVENTION

[0026] refer to Figure 1 and Figure 2 , showing the gasification of biomass by a syngas generation system to ultimately generate hydrogen (H 2 ), while removing fine powder, hydrogen sulfide (H 2 S) and other pollutants. In some aspects, gaseous carbon dioxide (CO 2 ). In some aspects, gaseous CO 2 Can be compressed and optionally further utilized and / or stored.

[0027] The synthesis gas generation method begins with the preparation of a biomass feed for the production of synthesis gas. The biomass may include one or more of the following: forest biomass, such as branches, bushes, etc. from forest management, sawmill waste, or shrubs and bushes; agricultural residues, such as but not limited to nut shells and orchard prunings; marine waste, such as but not limited to seaweed, seaweed, etc.; urban waste, such as but not limited to dry urban solid waste, construction wood, green waste, etc.; or may be derived from crops specifically grown for use as biomass, such as sawgrass.

[0028] Figure 1 The use of biomass to produce hydrogen (H 2 ) while capturing carbon dioxide (CO 2 ) is a schematic diagram of a syngas generation method of the present invention. According to various embodiments of the present disclosure, the method uses tail gas as a fuel to remove tar. In various embodiments, the syngas generation process 111 includes preparation 102 of a biomass feed for feeding 104 the biomass feed into a gasifier for gasification 106 to generate syngas. The gasification process 106 also includes a cyclone separator, tar removal, syngas cooling, syngas filtering, syngas washing, etc., as well as processing and removing 110 wet waste fines (or ash or slag), dry waste fines (or ash or slag), waste bed materials, etc. Reference Figure 2 Discussions related to preparation of biomass feed 102, feeding of biomass to a gasifier 104, gasification of biomass 106, and treatment and removal of waste 110 are provided, including more details of the processes. In various embodiments, Figure 1The biomass feed preparation process 102 and the biomass feed 104 are composed of Figure 2 The biomass feeding system 10 and the bed material feeding system 20 are implemented. Figure 1 The gasification 106 is Figure 2 The gasifier and cyclone separator 30, the tar removal system 60, the syngas cooler 70, the syngas filter 80 and the syngas scrubber 90 are implemented. Figure 1 The processing and removal process 110 is performed by Figure 2 The wet waste fine powder removal system 50, the dry waste fine powder removal system 100 and the waste bed material removal system 40 are implemented.

[0029] refer to Figure 2 In various embodiments, the syngas generation system 222 includes a biomass feed system 10, which includes one or more lock hopper-based feed lines for feeding biomass to the gasifier 30. Multiple feed lines can be arranged in parallel, and one or more of the feed lines can be designed to feed biomass at a capacity even higher than the gasification capacity of the gasifier 30 (for example, for a gasifier system with a capacity of about 350 short tons per day, or sTPD, each of the one or more feed lines can be designed to feed biomass at a capacity of about 114% of the total 350 sTPD feedstock or about 400 sTPD per feed group). Multiple parallel full-capacity feed lines improve the reliability of the syngas generation system 222 in the event that a feed line is shut down for maintenance.

[0030] Biomass feed can be delivered to the synthesis gas generation system 222 by chain conveyor. Biomass feed system 10 starts with a biomass distribution screw conveyor located at the top of biomass feed system 10. The conveyor delivers biomass to one or more feed lines as follows. Biomass falls into a biomass storage silo from the biomass distribution screw conveyor, and an inert gas such as nitrogen is used to purge to avoid dust explosion or spontaneous combustion of dry fuel. From the storage silo, the fuel enters one or more than one (e.g., two) lock hoppers through a biomass storage silo discharger and a biomass distribution screw, in which the biomass feed pressure is alternately increased from atmospheric pressure to system pressure with an inert gas such as nitrogen and / or carbon dioxide in the lock hopper. It is then discharged into a biomass buffer hopper as described below and decompressed to start the filling step. Biomass is fed to a biomass buffer hopper with a live bottom screw from a pressurized lock hopper by a lock hopper discharger. The biomass is fed from the buffer hopper, through a metering screw conveyor, to a biomass feed screw conveyor, which feeds the biomass into the gasifier 30 .

[0031] In various embodiments, the syngas generation system 222 includes a bed material feed system 20, which includes a bed material storage silo for storing bed materials (e.g., dolomite). In some cases, the bed material feed system 20 is a single bed material feed (e.g., 1×100% capacity) lock hopper system per gasification group, and may include a bed material weigh hopper and a bed additive weigh hopper, wherein the bed material and bed additive are fed into the lock hopper / buffer hopper and pressurized to system pressure with nitrogen. A bed material splitter screw conveyor located at the bottom of the lock hopper / buffer hopper moves the bed material to at least one biomass feed screw conveyor, and then feeds the bed material to the gasifier 30.

[0032] In various embodiments, the syngas generation system 222 includes a gasifier 30 designed or configured for gasifying a biomass feed received from the biomass feed system 10 and / or the bed material feed system 20. In various embodiments, the gasifier 30 includes a startup heater fueled by natural gas for heating the gasifier during startup of the gasifier reactor. In some implementations, the gasifier reactor can be designed to process biomass at a rate of about 10,000 kg / h to about 60,000 kg / h, 14,000 kg / h to about 60,000 kg / h, 18,000 kg / h to about 60,000 kg / h, 22,000 kg / h to about 60,000 kg / h, 26,000 kg / h to about 60,000 kg / h, 30,000 kg / h to about 60,000 kg / h, 34,000 kg / h to about 60,000 kg / h, 38,000 kg / h to about 60,000 kg / h, 42,000 kg / h to about 60,000 kg / h, 46,000 kg / h to about 60,000 kg / h, 50,000 kg / h to about 60,000 kg / h, 55,000 kg / h to about 60,000 kg / h, including values ​​and subranges therebetween. In some aspects, the biomass flow rate can be about 15,000 kg / h to about 50,000 kg / h, about 20,000 kg / h to about 45,000 kg / h, about 30,000 kg / h to about 40,000 kg / h, about 13,230 kg / h, about 40,000 kg / h, and values ​​and subranges therebetween, and the water content of the biomass is about 7% to 35% by weight, 8% to 35% by weight, 9% to 35% by weight, 10% to 35% by weight, 11% to 35% by weight, 12% to 35% by weight, 13% to 35% by weight, 14% to 35% by weight, 15% to 35% by weight, 16% to 35% by weight, 17% to 35% by weight, 18% to 35% by weight, 19% to 35% by weight, 20% to 35% by weight, %, 21 wt % to 35 wt %, 22 wt % to 35 wt %, 23 wt % to 35 wt %, 24 wt % to 35 wt %, 25 wt % to 35 wt %, 26 wt % to 35 wt %, 27 wt % to 35 wt %, 28 wt % to 35 wt %, 29 wt % to 35 wt %, 30 wt % to 35 wt %, 31 wt % to 35 wt %, 32 wt % to 35 wt %, 33 wt % to 35 wt %, 34 wt % to 35 wt %, including values ​​and subranges therebetween. In some aspects, the biomass moisture content is about 7 wt % to about 30 wt %, about 10 wt % to about 25 wt %, about 15 wt % to about 20 wt %, about 17 wt %, including values ​​and subranges therebetween.In various embodiments, the biomass can be at a higher moisture content, such as about 33 weight %, 34 weight %, 35 weight %, 36 weight %, 37 weight %, 38 weight %, 39 weight %, 40 weight %, even higher than 40 weight %, and can be dried to the above moisture levels (e.g., with a feed dryer, such as a belt dryer using hot air to dry the raw biomass). During startup, air for drying the biomass is provided by a startup air system (e.g., outside the research device boundary line), which includes an air compressor and an air receiver.

[0033] In various embodiments, the biomass feed is gasified by a gasifier reactor in the presence of oxygen (or air) and steam at a pressure of about 5 bar to about 15 bar gauge, 6 bar to about 15 bar gauge, 7 bar to about 15 bar gauge, 8 bar to about 15 bar gauge, 9 bar to about 15 bar gauge, 10 bar to about 15 bar gauge, 11 bar to about 15 bar gauge, 12 bar to about 15 bar gauge, 13 bar to about 15 bar gauge, 14 bar to about 15 bar gauge, including values ​​and subranges therebetween, and a temperature of about 650° C. to about 1100° C., 700° C. to about 1100° C., 750° C. to about 1100° C. ℃, 800℃ to about 1100℃, 825℃ to about 1100℃, 850℃ to about 1100℃, 875℃ to about 1100℃, 900℃ to about 1100℃, 950℃ to about 1100℃, 1000℃ to about 1100℃, 1050℃ to about 1100℃, including values ​​and subranges therebetween. A non-limiting example of the gasifier 30 is a pressurized bubbling fluidized bed pressure vessel with a refractory lining. Oxygen (or air) and steam are both introduced into the gasifier 30. For example, oxygen (or air) and steam are both introduced into the gasifier 30 at multiple locations through a valve system. In various embodiments, oxygen (or air) is provided from the limit and preheated in an oxygen preheater to about 150℃, 160℃, 170℃, 177℃, 180℃, 190℃, 200℃, including values ​​and subranges therebetween. The feedstock is rapidly devolatilized in the gasifier 30, while the remaining char is gasified and a portion of the char is burned to maintain the desired gasification temperature. The produced gas (syngas) is discharged from the reactor top gasifier 30. Entrained dust is at least substantially removed from the hot syngas in a cyclone separator and returned to the fluidized bed of the reactor through a cyclone separator return pipe (e.g., a dip tube).

[0034] In various embodiments, the syngas generation system 222 includes a tar removal system 60 configured to remove tar from the syngas produced by the gasifier 30 by thermal cracking. In the tar removal system 60, the fuel gas enters a tar removal burner (or hot oxygen burner), where the tar component and other unsaturated hydrocarbon components are converted into hydrogen and carbon monoxide. Reducing or eliminating heavier hydrocarbons helps prevent them from condensing in downstream equipment and pipelines. The oxidation temperature is reached by injecting oxygen and fuel gas into the tar removal burner.

[0035] In some embodiments, the tar removal burner utilizes recycled syngas compressed downstream of the gasification island as fuel. Both the syngas and the molten solids flow downward through the tar removal vessel to the syngas cooler. In some cases, about 4% to about 14% of the syngas generated by the syngas generation system 222 is circulated or provided to the tar removal system 60 to be used as fuel for operating the tar removal system 60. As described below, in various embodiments, the tail gas as a by-product of the post-gasification process 108 is circulated and used as a fuel for the tar removal system 60 to remove tar from the syngas.

[0036] In various embodiments, the syngas generation system 222 includes a syngas cooler 70 configured to cool the syngas and waste fines associated therewith to about 575° C., about 550° C., about 534° C., about 525° C., about 550° C., about 475° C., about 450° C., or less than 450° C. The syngas cooler includes a boiler, a superheater, and a steam drum. In some cases, the syngas cooler also includes an economizer. The recovered heat from the syngas cooler can be used to generate superheated high-pressure steam (e.g., a temperature of about 250°C to about 350°C, 275°C to about 350°C, 285°C to about 350°C, 290°C to about 350°C, 300°C to about 350°C, 325°C to about 350°C, e.g., about 288°C, and a pressure of about 35 bar to about 45 bar, 36 bar to about 45 bar gauge, 37 bar to about 45 bar gauge, 38 bar to about 45 bar gauge, 39 bar to about 45 bar gauge, 40 bar to about 45 bar gauge, 41 bar to about 45 bar gauge, 42 bar to about 45 bar gauge, 43 bar to about 45 bar gauge, 44 bar to about 45 bar gauge, e.g., about 41.4 bar gauge). Steam from the syngas cooler may be used in the gasifier 30, in the post-gasification process 108, and in other process units such as an air separation unit or a steam turbine.

[0037] In various embodiments, boiler feed water is fed into the steam drum of the syngas cooler 70 and preheated therein. The steam drum associated with the syngas cooling has at least one blowdown stream. Waste fines are separated from the gas stream and fall into the water bath by gravity. The cooled wet waste fines are then fed into the wet waste fines removal system 50 of the syngas generation system 222. The water bath at the bottom of the syngas cooler 70 has a blowdown stream. In some cases, the syngas and remaining waste fines leaving the syngas cooler 70 are further cooled by adding a quench water stream before entering the syngas filter 80 to about 250°C to about 350°C, 260°C to about 350°C, 270°C to about 350°C, 280°C to about 350°C, 290°C to about 350°C, 300°C to about 350°C, 310°C to about 350°C, 320°C to about 350°C, 330°C to about 350°C, 340°C to about 350°C, including values ​​and subranges therebetween, e.g., about 295°C, 300°C, 305°C, etc.

[0038] In various embodiments, the syngas generation system 222 includes a syngas filter 80 configured to receive syngas and waste fines from the syngas cooler 70. The syngas filter is a candle filter unit that includes metal candle filter elements arranged in clusters and mounted on a tube sheet. The filter candles are cleaned with carbon dioxide by a reverse pulse from a backflush tank. The filter unit operates at system pressure, and the pulse gas is injected at a higher temperature.

[0039] In various embodiments, the syngas generation system 222 includes a syngas scrubber 90 configured to receive syngas from the syngas filter 80 and further cool it to about 40°C, 41°C, 42°C, 43°C, 44°C, 45°C, 46°C, 47°C, 48°C, 49°C or 50°C, including values ​​and sub-ranges therebetween. The syngas scrubber 90 can remove part of the water vapor and remaining pollutants from the syngas, and prevent the syngas compression system 112 and downstream processes from being contaminated by solid pollutants when the tar removal burner or the syngas filter 80 fails. In some cases, the scrubber has an inlet quench system in which water is pumped into the syngas feed stream before entering the scrubber through a nozzle by a cooling pump (e.g., 2×100%). The gas is then further cooled by the first stage bed. In some cases, the washing water is circulated by a circulating pump (e.g., 2×100%) and flows to the top of the first stage bed through a heat recovery heat exchanger. In the second stage, the gas is cooled by circulating water in the second stage bed. In some cases, a process condensate stream is injected at the top of the syngas scrubber 90 to allow additional chlorides to be removed.

[0040] Chemicals may be added to the scrubber water to adjust its pH or to enhance chloride removal and neutralize ammonia from the syngas. The raw cooled saturated syngas from the syngas scrubber 90 is sent to a post-gasification process 108 .

[0041] In various embodiments, the syngas generation system 222 includes a solid removal system 40, 100 configured to process and store waste bed material and dry waste fines, etc. For example, the solid removal system 40, 100 may include two independent solid removal systems including lock hoppers, conveyor hoppers, and storage silos for processing solid materials from the gasifier 30 and the syngas filter 80.

[0042] In some cases, a water-cooled screw is used to remove the waste bed material from the bottom of the gasifier 30 into a nitrogen-pressurized lock hopper. The waste bed material is pneumatically conveyed to a common gasification waste bed material silo through a gasification waste bed material conveying hopper using nitrogen or any other available inert gas.

[0043] Similar to the waste bed material, the dry waste fines from the syngas filter 80 are also removed using a water-cooled screw and transferred through a lock hopper and a conveyor hopper. A surge hopper located after the cooling screw allows the screw to operate continuously. The dry waste fines from the syngas filter 80 are then charged to a dry waste fines storage silo with nitrogen or any other available inert gas.

[0044] In various embodiments, the syngas generation system 222 also includes a wet waste removal system 50 configured to receive wet waste fines that fall from the water bath of the syngas cooler. Water from the system is circulated back to the syngas cooler via a pump. The accumulated wet waste fines are then cooled, depressurized, and removed from the wet waste removal system 50.

[0045] In various embodiments, the nitrogen, carbon dioxide, water, etc. used by the synthesis gas generation system 222 to generate synthesis gas can be supplied by an auxiliary system coupled to the synthesis gas generation system 222. For example, the auxiliary system may include a nitrogen supply system, a carbon dioxide supply system, a water supply system, etc. The auxiliary system may also include a heat exchange system. For example, the nitrogen supply system can supply nitrogen from the device boundary line, which can be used as an inert gas in the synthesis gas generation system 222 and as a fuel diluent for the hot oxygen burner during startup. Nitrogen is supplied to the project at high pressure and low pressure. A buffer drum is set at each pressure to ensure that there is sufficient nitrogen available for the device to operate safely, start up and shut down. The nitrogen from the buffer drum can flow into the low-pressure and high-pressure nitrogen headers, which distribute nitrogen to the nitrogen consuming device.

[0046] The carbon dioxide supply system provides sulfur-free CO from the acid gas removal unit of the downstream process to the synthesis gas generation system 222. 2 The CO 2 The flow is fed into the high-pressure and low-pressure buffer tanks of the carbon dioxide supply system. 2 From these tanks it is distributed to the various consumers.

[0047] The water supply system includes a high-pressure cooling water system and a high-pressure sealing water system. The high-pressure cooling water system is used to cool the waste bed material at the bottom of the gasifier, the dry waste fines and the three biomass feed screws. The cooling water system is a closed loop system operating at high pressure. The closed loop includes a circulation pump, a storage tank and a cooling heat exchanger. The high-pressure sealing water system is used to supply water to the mechanical seal of the solid removal system and the biomass feed screw shaft. The closed loop includes a circulation pump, a storage tank and a cooling heat exchanger.

[0048] The heat exchange system of the auxiliary system is a hot process heat exchange system including a hot process cooling water system. The cooling water system is a closed loop system that uses a series of pumps, storage tanks and heat exchangers to exchange heat between various parts of the equipment. The hot treated water supplies the cooling scrubber bottom flow and high pressure cooling water circulation water, and the hot treated water can then be used as a heat source for drying biomass feed as needed.

[0049] Back to Figure 1 In various embodiments, the tar removal system 60 can use the tail gas produced as a by-product of the post-gasification process 108 as a fuel for removing tar from the syngas. In a process model in which the tar removal system is configured to use tail gas instead of syngas as a fuel source, the amount of hydrogen at the outlet of the H2 separation system (PSA) increases by 8% to 11%. In various embodiments, the washed syngas from the gasifier 30 enters the syngas compressor inlet dehydrator (KOD) to separate the liquid entrained in the gas flow. A multi-stage compressor with an interstage air cooler may be included. The water and condensate formed after each stage are removed by the KOD downstream of the interstage cooler and sent to the sour water stripper unit. The syngas circulation stream is extracted after the second interstage KOD and circulated back to the gasifier 30. The compressed syngas is sent to a water-gas shift (e.g., a two-stage water-gas shift) and a gas cooling unit.

[0050] In various embodiments, the washed compressed synthesis gas undergoes a water shift process (e.g., a multi-stage water shift process). For example, the washed compressed synthesis gas is sent to a water-gas shift and gas cooling unit. A two-stage sour shift reactor can be used to maximize hydrogen production. The raw synthesis gas feed can have applied high-pressure steam to maintain an optimal steam / CO ratio. Then, before being sent to the first-stage shift reactor, it is preheated in a reactor feed / effluent heat exchanger. The synthesis gas from the first-stage shift reactor outlet is first cooled in a process steam generator before entering the second-stage shift reactor, and then cooled in a feed / effluent exchanger. The gas at the outlet of the second-stage shift reactor is further cooled in a plurality of (e.g., four) exchangers.

[0051] The cooled and shifted syngas is then fed to the syngas KOD and then to the H2O2 for syngas purification. 2 S removal unit. In some cases, the process condensate from the bottom of the syngas KOD is pumped, mixed with recycle water from the process wastewater treatment unit, and used as process steam in the water gas shift unit by recovering heat from the shifted syngas. The process steam is separated from any condensate in the process steam drum, and the final hot process condensate stream is discharged and sent to the condensate steam distributor, from which it is sent to the process wastewater treatment unit.

[0052] The syngas is further processed to separate H 2 S, CO 2 and H 2 (e.g., by pressure swing adsorption). To remove H 2 S, can use H 2 S Removal Unit Cleaner Pack (H 2 The cooled synthesis gas from the second stage shift reactor is fed into the H 2 S removal unit scavenger package. This package can have two adsorption beds that use granular solids containing iron and other metal oxides to remove H 2 S. As the gas passes through the bed, H 2 S is absorbed to purify the synthesis gas. H 2 The S analyzer measures the H 2 S concentration. 2 S scavenger and H 2Target H at the clean syngas outlet of the S removal unit 2 The S content is less than about 0.3 ppmv, 0.2 ppmv, 0.1 ppmv, 0.05 ppmv (parts per million by volume), or less than 0.05 ppmv. The manual valve and piping configuration between the dual adsorbent beds allows operation in a lead-lag design layout, including but not limited to single bed operation when maintaining or replacing the other adsorbent bed, operation of the first bed as the lead bed and the second bed as the lag bed, or operation of the second bed as the lead bed and the first bed as the lag bed.

[0053] For CO 2 Removal of CO 2 The removal unit can use an amine-based CO 2 Removal system that uses activated MDEA (methyldiethanolamine) solvent and / or physical solvent using propylene carbonate to remove CO from hydrogen-rich syngas 2 To achieve its recovery. The captured CO 2 The stream is of sufficient purity for carbon sequestration. 2 After the S removal unit, the syngas enters the CO 2 removal unit. In some cases, the wet syngas is first dehydrated using a triethylene glycol (TEG) dehydration pack. Using the treated gas, the dehydrated feed gas from the TEG absorber is cooled in a feed / process gas heat exchanger. The cooled gas (e.g., fed from the bottom) is then contacted with a cold lean solvent in a physical solvent absorber (e.g., fed from the top) to remove CO. 2 Lower operating temperatures increase the solvent loading capacity, thereby reducing the solvent circulation rate.

[0054] The rich solvent leaving the bottom of the absorber is regenerated by a series of reduced pressure flashes. The first pressure reduction is done by a hydraulic turbine. The flash gas from the high pressure (HP) flash drum contains a large amount of hydrogen which is recycled back to the CO 2removal unit to improve the overall recovery. The HP flash gas is compressed by a recycle compressor and cooled by a recycle cooler. The rich solvent from the HP flash tank flows into a low pressure (LP) flash tank under liquid level control, where the pressure is further reduced. The solvent from the LP flash tank flows into a vacuum flash tank under liquid level control. The lean solvent from the vacuum flash tank is pumped first by a booster pump under flow control, then by a recycle pump, through a lean solvent cooler (and a refrigeration / cooling package), and then returned to the absorber. The flash gas from the LP flash tank is combined with the flash gas from the vacuum flash tank and then compressed by a vacuum compressor. The resulting purity is approximately 95 mol%, 96 mol%, 97 mol%, 98 mol%, 99 mol%, 99.6 mol%, 99.7 mol%, 99.8 mol%, 99.9 mol% dry CO 2 Products delivered to CO 2 Compression unit.

[0055] About CO 2 Compression, from CO 2 Dry CO removal unit 2 Sent to CO 2 Compression unit, in CO 2 Before being sent to the pipeline for storage, the gas is compressed to the desired pressure using a four-stage compressor in this compression unit. 2 CO removal unit 2 It is expected to be completely dry, but it is still considered to arrange an inlet suction KOD upstream of the first compressor to remove any potential moisture that may be brought in under abnormal conditions. Interstage air coolers and aftercoolers (for example, at the 4th stage outlet) are installed to maintain the correct temperature. Two intermediate circulation streams are extracted after the second and third stages and recycled back to the gasification system. 2 Before being sent to the pipeline for storage, CO 2 The metering system is installed at the compressor outlet.

[0056] From CO 2 The clean syngas from the removal unit is sent to H 2 Pressure swing adsorption (PSA) unit. The purpose of setting up a PSA unit is to obtain high-purity hydrogen products from a hydrogen-rich synthesis gas stream. The PSA unit can selectively adsorb impurities (CH 4 , N 2 ,CO,CO 2 ). Impurities are desorbed by reducing the adsorbent pressure from the feed pressure to the tail gas pressure. Hydrogen is not adsorbed and can therefore be recovered at a purity of about 99.6 mol%, 99.7 mol%, 99.8 mol%, 99.9 mol%, 99.95 mol%, 99.96 mol%, 99.97 mol%, 99.98 mol%, 99.99 mol%, or greater than 99.99 mol%. The generated hydrogen is sent to H2 Compression or liquefaction unit, while producing low-pressure tail gas as a by-product.

[0057] In some embodiments, the tail gas contains some H 2 , CH 4 , N 2 , CO and trace amounts of CO generated during the process 2 , sent to the PSA tail gas boiler of the power generation and boiler unit. In some embodiments, the tail gas byproduct can be recycled or provided to the tar removal system for use as fuel for the tar removal process of gasification 106. The PSA tail gas can have a lower CO 2 content, because before the clean syngas enters the PSA unit, the upstream CO 2 The removal unit removes CO from 2 Therefore, its calorific value is relatively high for use as a fuel for the tar removal unit or system 60. In some embodiments, the tail gas may be compressed before being fed into the tar removal system. That is, in addition to or in lieu of using the tail gas to generate electricity and fuel the boiler, the tail gas may be fed to the tar removal system 60 ( Figure 2 ) so that the tar removal system 60 can use the tail gas byproduct as a fuel to operate, thereby removing or reducing tar in the syngas generated from the syngas generation system 222. In some embodiments, the recycled syngas and / or natural gas can be used as a fuel to drive the tar removal system 60. In some embodiments, no recycled syngas or natural gas can be used as a fuel, but instead, the recycled tail gas can be used as a fuel for the tar removal system 60 to remove tar from the syngas.

[0058] In various embodiments, the tail gas provided to the tar removal system 60 as a fuel for removing tar can have a temperature of about 20° C. to about 60° C., 25° C. to about 60° C., 30° C. to about 60° C., 35° C. to about 60° C., 40° C. to about 60° C., 45° C. to about 60° C., 50° C. to about 60° C., 55° C. to about 60° C., including values ​​and sub-ranges therebetween. In some aspects, the temperature can be about 25° C. to about 50° C., including values ​​and sub-ranges therebetween. In addition, the pressure can be about 0.5 bar to about 10 bar gauge, 1 bar to about 10 bar gauge, 2 bar to about 10 bar gauge, 3 bar to about 10 bar gauge, 4 bar to about 10 bar gauge, 5 bar to about 10 bar gauge, 6 bar to about 10 bar gauge, 7 bar to about 10 bar gauge, 8 bar to about 10 bar gauge, 9 bar to about 10 bar gauge, including values ​​and sub-ranges therebetween, for example, about 2 bar gauge, about 3 bar gauge, about 5 bar gauge. In some embodiments, the mass rate can be about 100 kg / h to about 2500 kg / h, including values ​​and sub-ranges therebetween. Example

[0059] Tables 1 to 7 provide examples of the advantages of recycling tail gas as a byproduct of a synthesis gas (e.g., hydrogen) generation process as a fuel for removing tar gas from synthesis gas, i.e., as a fuel for a tar removal system of a synthesis gas generation system that performs the synthesis gas generation process. Table 1 compares exemplary experimental values ​​of various parameters related to synthesis gas generation in the "tail gas recycle" and "base" schemes, wherein the "tail gas recycle" scheme in which the tail gas is recycled as a fuel for the tar removal system in the synthesis gas generation system, and the "base" scheme in which the tail gas is not recycled for use as the fuel. Table 2 shows the percentage of each value in the "tail gas recycle" scheme relative to each value in the "base" scheme. Tables 1 and 2 show that, in some embodiments, using the tail gas recycle as a fuel for removing tar from synthesis gas can produce more hydrogen (e.g., an increase of about 8.7%), demonstrating the benefits of recycling tail gas. Carbon dioxide capture is also increased (e.g., an increase of about 2.2%). In addition, although energy consumption is increased, because more CO 2 The carbon intensity is reduced by trapping, and the recycling of tail gas also improves the thermal efficiency by about 7.1%.

[0060] Tables 3 and 4 show the energy balances of the “basic” scheme and the “exhaust gas recycle” scheme, respectively.

[0061] Table 1 - Exemplary experimental values ​​for various parameters related to syngas generation in the "Tail Gas Recycle" and "Base" schemes.

[0062]

[0063] Table 2 - Example values ​​in the "Exhaust Gas Recirculation" scenario as a percentage of the corresponding example values ​​in the "Base" scenario.

[0064]

[0065] Table 3 - Energy balance for an exemplary "base" scenario.

[0066]

[0067] Table 4 - Energy balance for an exemplary "tail gas recycle" scheme.

[0068]

[0069] In accordance with the present disclosure, all methods disclosed and claimed herein can be implemented or performed without undue experimentation. Although the compositions and methods of the present invention have been described in accordance with preferred embodiments, changes to the methods and steps or the order of steps thereof are apparent to those skilled in the art without departing from the concept, spirit and scope of the present invention. More specifically, it is apparent that certain reagents related to chemistry or physiology can be substituted for the reagents described herein to achieve the same or similar results. All such similar substitutions or modifications apparent to those skilled in the art are defined as being within the spirit, scope and concept defined by the appended claims.

Claims

1. A method comprising: receiving a biomass feed at a biomass feed inlet of a synthesis gas (syngas) generation system; gasifying the biomass feed to produce syngas using a gasifier of a syngas generation system under conditions that result in the production of a tar by-product, the syngas generation system including a tar removal system configured to remove the tar by-product from the syngas, post-gasification producing a tail gas by-product; providing at least a portion of the tail gas by-product to a tar removal system of the syngas generation system; and The tar removal system is operated using the at least a portion of the tail gas by-product as a fuel to remove or reduce tar in the syngas.

2. The method of claim 1, further comprising increasing the concentration of at least one tail gas by-product component by a separation process before providing at least a portion of the tail gas by-product to a tar removal system of the syngas generation system.

3. The method of claim 2, wherein increasing the concentration of at least one tail gas by-product component comprises using a separation technique selected from the group consisting of pressure swing adsorption (PSA), cryogenic distillation, and membrane separation.

4. The method of claim 2, wherein the component whose concentration is increased is an oxidizable component.

5. The method of claim 2, wherein the oxidizable component is selected from the group consisting of hydrogen, carbon monoxide, and combinations thereof.

6. The method of claim 1, wherein the tail gas by-product provided to the tar removal system of the syngas generation system does not undergo a component concentration increasing step.

7. The method of claim 1, wherein providing at least a portion of the tail gas by-product to a tar removal system of a syngas generation system increases the net amount of syngas available for post-gasification processes.

8. A synthesis gas (syngas) generation system comprising: a biomass feed port configured to receive a biomass feed; a gasifier in communication with the biomass feed port and configured to receive and gasify the biomass feed under conditions that result in the generation of a tar by-product to generate a synthesis gas, and a post-gasification process to generate a tail gas by-product; a transport system configured to transport tail gas byproducts of the post-gasification process to a tar removal system; and A tar removal system is configured to use the tail gas by-product received via the delivery system as a fuel to remove tar by-products from the synthesis gas.

9. The system of claim 8, wherein the delivery system includes a component separation device that increases the concentration of at least one tail gas byproduct component through a separation process.

10. The system of claim 9, wherein the component separation device increases the concentration of at least one tail gas by-product component by using a separation technology selected from the group consisting of pressure swing adsorption (PSA), cryogenic distillation and membrane separation.

11. The system of claim 9, wherein the component whose concentration is increased is an oxidizable component.

12. The system of claim 11, wherein the oxidizable component is selected from the group consisting of hydrogen, carbon monoxide, and combinations thereof.

13. The system of claim 8, wherein the system does not include a component separation device for increasing the concentration of at least one tail gas by-product component.

14. The system of claim 8, wherein the delivery system enables the syngas generation system to generate an increased net amount of syngas compared to a comparable syngas generation system lacking a tail gas delivery system.

Images