Particle removal system for hydroprocessing

Abstract

A process for producing a liquid hydrocarbon product from a solid feedstock, the process comprising feeding the solid feedstock and hydrogen to a first stage hydropyrolysis reactor. The first stage hydropyrolysis reactor has one or more deoxygenation catalysts, and the solid feedstock comprises biomass, waste plastic, or a combination thereof. The method further includes hydropyrolyzing the solid feedstock in the first stage hydropyrolysis reactor to produce a process gas stream having partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines, and feeding the process gas stream to a solids separation system having a hot gas filtration unit, the hot gas filtration unit has a plurality of filtration elements that can separate the char and catalyst fines from the process gas to produce a gas phase product and a dust filter cake. The gas phase product comprises the partially deoxygenated hydropyrolysis product, H2O, H2, CO2, CO, and C1-C3 gases, and the dust filter cake is disposed on an outer surface of the plurality of filter elements and comprises the char and catalyst fines.

Description

[0001] The present disclosure generally relates to systems and methods for removing particulates. More specifically, the present disclosure relates to a solids removal system integrated into a hydroprocessing system. Background Art

[0002] Due to the worldwide economic growth and development, the demand for energy is increasing. This increase in energy demand has led to the increase of greenhouse gas volume and overall carbon footprint. In addition, with the increase in the demand for liquid transportation fuels, the reduction of the reserves of crude oil that can be easily obtained and recovered, and the restriction of the carbon footprint of such fuels are increasing, it may be necessary to develop an approach to produce liquid transportation fuels from renewable resources in an effective manner. Such liquid transportation fuels produced by biomass are sometimes also referred to as biofuels. Biomass provides a renewable carbon source. The example of suitable biomass includes vegetable oil, oil obtained from algae and animal fat, deconstructed materials such as pyrolyzed recyclable materials and wood, straw, forestry residues, etc. Therefore, when using a fuel derived from renewable resources, it is possible to achieve a more sustainable CO2 emission than petroleum-derived fuels. For the biofuel that replaces all or at least a portion of carbon-based fossil fuels, biofuels should meet the required performance and emission specifications of carbon-based fossil fuels.

[0003] Currently, systems for removing particles (e.g., biochar, ash, catalyst fines) from a product gas stream generated in a hydroprocessing reactor include cyclone separators. For example, existing systems may include one or more continuous cyclone separators that receive a product gas stream and remove entrained particles from the product gas stream. However, the efficiency of cyclone separators in removing entrained particles from the product gas stream is in the range of about 99.95%, which is undesirable. Therefore, hydroprocessing systems that use cyclone separators alone to remove entrained particles also include guard beds downstream of the solids removal system, which capture and remove particles that are not removed by the cyclone separators. Adding guard beds downstream of the solids removal system increases the overall cost of the hydroprocessing system. In addition, although multiple cyclone separators can be used in series or in combination with a three-stage separator, this increases the complexity and overall cost of the hydroprocessing system due to the need for additional equipment, maintenance, and installation space. Therefore, it is very advantageous to provide a solids removal system with improved particle removal efficiency that can be integrated into a hydroprocessing system without the use of guard beds or other solids removal systems. Summary of the invention

[0004] In one embodiment, a method for producing a liquid hydrocarbon product from a solid feedstock, the method comprising feeding the solid feedstock and hydrogen to a first-stage hydropyrolysis reactor. The first-stage hydropyrolysis reactor has one or more deoxygenation catalysts, and the solid feedstock comprises biomass, waste plastics, or a combination thereof. The method also includes hydropyrolyzing the solid feedstock in the first-stage hydropyrolysis reactor to produce a process gas stream having partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines, and feeding the process gas stream to a solid separation system having a hot gas filtration unit, the hot gas filtration unit having a plurality of filter elements, the plurality of filter elements being capable of separating the char and catalyst fines from the process gas to produce a gas phase product and a dust filter cake. The gas phase product comprises the partially deoxygenated hydropyrolysis product, H2O, H2, CO2, CO, and C1-C3 gases, and the dust filter cake is disposed on the outer surface of the plurality of filter elements and comprises char and catalyst fines.

[0005] In another embodiment, a system for producing liquid hydrocarbon products from solid feedstocks includes a hydropyrolysis reactor having one or more deoxygenation catalysts that can produce a process gas stream having partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines. The solid feedstock comprises biomass, waste plastics, or a combination thereof. The system also includes a solid separation system disposed downstream of the hydropyrolysis reactor and fluidly coupled to the hydropyrolysis reactor. The solid separation system can receive the process gas stream and include a hot gas filtration unit having a plurality of filter elements that can remove the char and catalyst fines from the process gas stream to produce a gas phase product having the partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, and C1-C3 gases. The system also includes a hydroconversion reactor disposed downstream of the solid separation system and fluidly coupled to the solid separation system, and comprising one or more hydroconversion catalysts. The hydroconversion reactor can receive the gaseous product from the solid separation system and produce hydrocarbon products from the gaseous product. The hydrocarbon products include substantially completely deoxygenated hydrocarbon products, H2O, CO, CO2 and C1-C3 gases.

[0006] In another embodiment, a method for producing a liquid hydrocarbon product from a solid feedstock includes hydropyrolyzing the solid feedstock in a hydropyrolysis reactor to produce a process gas stream having partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines, and feeding the process gas stream to a solid separation system disposed downstream of the hydropyrolysis reactor and fluidly coupled to the hydropyrolysis reactor. The solid separation system includes a hot gas filtration unit having a plurality of filter elements, each filter element including a conduit having a plurality of holes. The method also includes filtering the process gas stream through the respective conduits of the plurality of filter elements to separate the char and catalyst fines from the process gas and produce a gas phase product and a dust filter cake. The gas phase product includes the partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, and C1-C3 gases, the dust filter cake is disposed on the outer surface of the respective conduits of the plurality of filter elements, and the dust filter cake includes the char and catalyst fines.

[0007] Additional features and advantages of exemplary embodiments of the present disclosure will be set forth in the description that follows, and in part will be apparent from the description, or may be learned by practice of such exemplary embodiments. The features and advantages of such embodiments may be realized and obtained by the instruments and combinations particularly pointed out in the appended claims. These and other features will become more apparent from the following description and the appended claims, or may be learned by practice of such exemplary embodiments set forth below. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] Advantages of the present disclosure will become apparent by reading the following detailed description and referring to the accompanying drawings, in which:

[0009] Figure 1 is a block diagram of a hydroprocessing system having a first stage and a second stage for producing hydrocarbons from biomass according to one embodiment of the present disclosure, wherein the system includes a solids separation system having a hot gas filtration unit;

[0010] Figure 2 According to one embodiment of the present disclosure Figure 1 A schematic diagram of a solid separation system of the invention, wherein the hot gas filtration unit comprises one or more candle filters, and the solid separation system comprises a solids container downstream of the hot gas filtration unit arranged in series;

[0011] Figure 3 According to one embodiment of the present disclosure Figure 1 A schematic diagram of a solid separation system, wherein the hot gas filtration unit comprises one or more candle filters, and the solid separation system comprises solid containers downstream of the hot gas filtration unit arranged in series and in parallel;

[0012] Figure 4 According to one embodiment of the present disclosure, using Figure 1 A flow chart of a method for removing entrained solids from a process gas stream using a solids separation system; and

[0013] Figure 5 According to one embodiment of the present disclosure Figures 1 to 3 Schematic diagram of a hot gas filtration unit. DETAILED DESCRIPTION

[0014] One or more specific embodiments of the present disclosure will be described below. These described embodiments are examples of currently disclosed technologies. In addition, in order to provide a concise description of these embodiments, not all features of the actual specific implementation may be described in the specification. It should be understood that in the development of any such actual specific implementation, as in any engineering or design project, many specific implementation-specific decisions will be made to achieve the specific goals of the developer, such as meeting system-related and business-related constraints, which may vary from one implementation to another. In addition, it should be understood that such development efforts may be complex and time-consuming, but are still routine tasks of design, production and manufacturing for those of ordinary skill who benefit from the present disclosure.

[0015] When introducing elements of various embodiments of the present disclosure, the articles "a," "an," and "the" are intended to indicate that there are one or more elements. The terms "comprising," "including," and "having" are intended to be inclusive, and mean that additional elements may be present in addition to the listed elements. Additionally, it should be understood that reference to "one embodiment" or "an embodiment" of the present disclosure is not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the described features.

[0016] As used herein, the terms "approximately," "about," and "substantially" refer to an amount that is close to a specified amount but still performs a desired function or achieves a desired result. For example, the terms "approximately," "about," and "substantially" may refer to an amount that is less than 10% of the stated amount, less than 5% of the stated amount, less than 1% of the stated amount, less than 0.1% of the stated amount, and less than 0.01% of the stated amount.

[0017] The disclosed embodiments include a solid separation system having a hot gas filtration unit that can be used to remove entrained solids / particles from a process gas produced in a hydroprocessing reactor (e.g., a hydropyrolysis reactor). Hydroprocessing is a catalytic process that includes hydropyrolysis, hydroconversion, and / or hydrotreating certain carbonaceous materials to produce hydrocarbon fuels. During hydropyrolysis, carbonaceous materials (e.g., biomass, waste plastics, and other solid feedstocks from renewable resources) undergo partial deoxygenation in the presence of hydrogen and under hydropyrolysis conditions. Hydropyrolysis of the solid feedstock produces a process gas having partially deoxygenated hydrocarbons and solids (such as char and fine particles (e.g., ash, catalyst fine particles, etc.)). When the process gas leaves the hydropyrolysis reactor, solids may be entrained in the process gas and removed in a solid separation system downstream of the hydropyrolysis reactor. Existing solid separation systems used in hydroprocessing systems include cyclone separators that separate entrained solids from process gases. However, the separation efficiency of the cyclone separator is such that a portion of the undesirable entrained solids remain in the process gas after passing through the cyclone separator. For example, the cyclone separator typically removes about 99.95% or less of the entrained solids. Even when multiple cyclone separators are used (e.g., in series), an undesirable amount of residual solids is still entrained in the process gas downstream of the solids separation system. The entrained solids remaining in the process gas can cause blockage and / or fouling of downstream equipment and affect the overall efficiency of the hydroprocessing. Therefore, in order to reduce the blockage and / or fouling of downstream equipment, a guard bed is located downstream of the solids separation system to remove the entrained solids remaining in the process gas. The undesirable solids separation efficiency of the cyclone separator and the addition of the guard bed increase the overall cost and complexity of the hydroprocessing system. Therefore, compared with existing systems that use cyclone separators for solids separation, it is necessary to develop a solids separation system with improved separation efficiency and reduced total operating costs.

[0018] As discussed in further detail below, the use of a hot gas filter (e.g., a candle filter) to remove entrained solids from the process gas produced in the hydropyrolysis reactor improves the separation efficiency of the solid separation system and also reduces the overall operating cost of the hydroprocessing process compared to existing systems. For example, the use of a hot gas filter can improve the separation efficiency of the solid separation system disclosed herein to greater than 99.99%, compared to the 99.95% separation efficiency of a cyclone separator. Compared to a system using a cyclone separator to separate entrained solids, the separation efficiency is improved by about 0.04% or more, thereby ideally reducing the overall operating cost of the hydroprocessing system. In addition, by using hot gas filtration in the solid separation system disclosed herein, the guard bed commonly used in existing systems downstream of the solid separation system can be omitted. However, although hot gas filtration can ideally improve the removal efficiency of the solid separation system, the process gas produced in the hydropyrolysis reactor does not undergo complete combustion and therefore contains oxygenates and other reactive species that may continue to react in the solid separation system. For example, oxygenates and / or reactive species in the process gas can form condensates and tars, thereby blocking the pores of the hot gas filter. However, as disclosed herein, by controlling the temperature of the process gas, in combination with the use of blowback gas through a hot gas filter, the formation of condensates and tars can be reduced. Thus, a hot gas filter can be integrated into a hydroprocessing system and used to remove entrained solids from the process gas produced in a hydropyrolysis reactor, thereby improving the separation efficiency of the solids separation system and reducing the overall operating cost of the hydroprocessing system compared to those systems that use cyclones in the solids separation system.

[0019] In view of the above, Figure 1 is a block diagram of an embodiment of a system 10 including a hot gas filter disclosed in a solids separation system for providing a process gas substantially free of entrained solids. As used herein, the phrase “substantially free of entrained solids” is intended to mean less than or equal to 0.009% (or less than 1 milligram (mg) / Nm3 (Nm 3)) of entrained solids. It should be understood that the process gases and other hydroprocessing products disclosed herein can be produced by any suitable hydroprocessing technology, such as those disclosed in U.S. Patent No. 9,447,328, which is hereby incorporated by reference in its entirety. In the illustrated embodiment, the system 10 includes a solid feedstock feed system 12, a hydropyrolysis reactor 14 located downstream of the solid feedstock feed system 12 and connected to the solid feedstock feed system fluid, and a hydroconversion reactor 16 located downstream of the hydropyrolysis reactor 14 and connected to the hydropyrolysis reactor fluid. As discussed in further detail below, the reactors 14, 16 are used to convert the solid feedstock 18 into an intermediate hydrocarbon fuel fraction (e.g., GO / diesel fraction), which can be used to generate commercially viable biodiesel. As shown, the reactors 14, 16 are arranged in one of the two stages. For example, the system 10 includes a first stage 20 and a second stage 24. The first stage 20 includes the hydropyrolysis reactor 14, and the second stage 24 includes the hydroconversion reactor 16. The reaction pressure in the first stage 20 and the second stage 22 can be changed to adjust the boiling point distribution and composition of the resulting hydrocarbon products generated by the second stage 24. The ability to adjust the boiling point distribution and / or composition of the resulting hydrocarbon products by changing the reaction pressure can provide an effective method for generating commercially viable hydrocarbon biofuels, which meets the different requirements of the location and / or market using hydrocarbon biofuels. For example, compared with a reaction pressure higher than 2.0MPa, when the reaction pressure is less than about 0.6 MPa, the occurrence of undesirable olefins and / or aromatic saturation reactions can be reduced, and the cetane number of biodiesel and / or gasoline fractions can be increased. However, the cetane number may still not reach the desired level that meets the specifications proposed for commercial biodiesel fuel. Therefore, the biodiesel fraction may need to undergo additional processing (e.g., hydrofining) to upgrade biodiesel and increase the cetane number to more than about 50. Therefore, in certain embodiments, the hydroprocessing system may include a third stage downstream of the second stage 24, wherein one or more biodiesel fractions undergo additional processing.

[0020] First level

[0021] In the illustrated embodiment, a solid feedstock 18 having biomass (e.g., lignocellulose) and / or waste plastic and molecular hydrogen (H2) 28 are introduced into the hydropyrolysis reactor 14. For example, the solid feedstock 18 is fed to the feeder 30 of the solid feedstock feeding system 12. The feeder 30 may be any feeder suitable for feeding solids, such as a screw conveyor, a piston feeder, and the like. The solid feedstock feeding system 12 also includes a metering tank 32 located downstream of the feeder 30 and the hydropyrolysis reactor 14 and fluidly coupled to the feeder and the hydropyrolysis reactor. In certain embodiments, the solid feedstock feeding system 12 does not include a metering tank 32. Although in the illustrated embodiment, the system 10 has a single hydropyrolysis reactor 14, it should be understood that the system 10 may have a plurality of hydropyrolysis reactors 14. In an embodiment in which the system 10 includes a plurality of hydropyrolysis reactors 14, the solid feedstock feeding system 12 is fluidly coupled to each of the reactors 14 and provides the solid feedstock 18 to each of the reactors.

[0022] The hydropyrolysis reactor 14 contains a deoxygenation catalyst that promotes partial deoxygenation of the solid feedstock 18. For example, in the hydropyrolysis reactor 14, the solid feedstock 18 undergoes hydropyrolysis to produce a process gas 34 having char, partially deoxygenated products of the hydropyrolysis, light gases (C1-C3 gases, carbon monoxide (CO), carbon dioxide (CO2), and H2), water (H2O) vapor, and catalyst fines. As described above, the partially deoxygenated products of the hydropyrolysis are not fully converted and may continue to react with other components in the process gas 34 to form condensates and tars, which can accumulate on equipment surfaces downstream of the hydropyrolysis reactor 14. As discussed in further detail below, controlling the temperature of the process gas 34 so that it is above the condensation temperature can reduce the formation of condensates and tars, thereby facilitating the separation of entrained solids (e.g., catalyst fines, char, ash) in the process gas 34.

[0023] The hydropyrolysis reactor 14 can be a fluidized bed reactor (e.g., a fluidized bubbling bed reactor), a fixed bed reactor, or any other suitable reactor. In embodiments where the hydropyrolysis reactor 14 is a fluidized bed reactor, the fluidization velocity, catalyst particle size and bulk density, and solid feedstock particle size and bulk density are selected so that the deoxygenation catalyst is retained in the bubbling fluidized bed, and the produced char is entrained with a portion of the deoxygenated product (e.g., process gas 34) leaving the hydropyrolysis reactor 14. It should be understood that, although most of the deoxygenation catalyst is retained in the bubbling fluidized bed, over time, the catalyst particles may wear away and produce catalyst fines. The catalyst fines may be entrained in the process gas 34 along with the char and other fine solids (e.g., ash). The hydropyrolysis step in the first stage 20 employs rapid heating of the solid feedstock 18, so that the residence time of the pyrolysis vapor in the hydropyrolysis reactor 14 is preferably less than about 1 minute, more preferably less than about 30 seconds, and most preferably less than about 10 seconds.

[0024] The solid raw material 18 used in the disclosed method may include residual waste raw materials and / or biomass raw materials containing lignin, lignocellulose, cellulose, hemicellulose materials or any combination thereof. Lignocellulosic materials may include a mixture of lignin, cellulose and hemicellulose in any proportion, and also contain ash and moisture. Such materials are more difficult to convert into alternative liquid hydrocarbon products than cellulose and hemicellulose materials. The advantage of the present method is that it can be used for biomass containing lignocellulose. Suitable biomass containing lignocellulose includes woody biomass and agricultural and forestry products and residues (full harvest energy crops; roundwood; forest fellings; bamboo; sawdust; bagasse; sugarcane leaves and residual stems; cotton stalks; corn stalks; corn cobs; castor stalks; whole harvests of jatropha; jatropha waste; de-oiled cakes of palm, castor and jatropha; coconut shells; residues from edible nuts; rice husks; rice stalk products and mixtures thereof), animal waste and municipal solid waste containing lignocellulosic materials. Municipal solid waste (MSW) can include any combination of lignocellulosic materials (yard waste, pressure treated wood such as fence posts, plywood), waste paper and cardboard and waste plastics and refractory materials such as glass, metals. Before being used in the method disclosed herein, municipal solid waste can be optionally converted into pellets or briquettes. Pellets or briquettes are commonly referred to as refuse derived fuels in the industry. Certain raw materials (such as algae and duckweed) may also contain proteins and lipids in addition to lignocellulose. Residual waste raw materials are those raw materials that mainly have waste plastics. In certain embodiments, solid raw materials 18 can be coal of different grades, peat or any other suitable solid raw materials that can be fed to a pressurized reactor.

[0025] The solid feedstock 18 can be provided to the hydropyrolysis reactor 14 in the form of loose biomass particles or in the form of a biomass / liquid slurry, and the loose biomass particles have a majority of particles preferably less than about 3.5 millimeters (mm) in size. However, as will be appreciated by those skilled in the art, the solid feedstock 18 can be pretreated or otherwise treated so that a larger particle size can be accommodated. Suitable means for introducing the solid feedstock 18 into the hydropyrolysis reactor 14 include, but are not limited to, an auger, a fast moving (greater than about 5 minutes (m) / second (sec)) flow of a carrier gas (such as an inert gas and H2) and a constant displacement pump, an impeller, a turbo pump, and the like. In one embodiment of the present disclosure, the solid feedstock feed system 12 includes a twin screw system for dosing, the twin screw system having a slow screw for metering the solid feedstock 18, followed by a fast screw that pushes the solid feedstock 18 into the reactor without causing roasting in the screw housing. An inert gas or hydrogen flow is maintained on the fast screw to further reduce the residence time of the solid feedstock 18 in the fast screw housing.

[0026] The hydropyrolysis step is carried out in the hydropyrolysis reactor 14 at a temperature in the range of about 300 degrees Celsius (° C.) to 650° C., preferably in the range of about 330° C. to about 500° C., more preferably in the range of about 350° C. to about 480° C., and at a pressure of about 0.50 megapascals (MPa) to about 7.5 MPa (about 5 bar to 75 bar). The heating rate of the solid feedstock 18 is preferably greater than about 100 watts / meter. 2 (W / m 2 The weight hourly space velocity (WHSV) in grams (g) of biomass / g of catalyst / hour (h) for the hydropyrolysis step is about 0.2 h -1 About 10 hours -1 In the range of about 0.3h -1 Until 3h -1 within the range.

[0027] The temperature used in the hydropyrolysis allows the solid feedstock 18 to rapidly devolatilize. Therefore, in a preferred embodiment, the hydropyrolysis step includes the use of an active catalyst (e.g., a deoxygenation catalyst) to stabilize the hydropyrolysis vapor. The activity of the catalyst used herein remains high and stable over a long period of time so that it does not rapidly coke. The catalyst particle size used in the hydropyrolysis reactor 14 is preferably in the range of about 0.3 millimeters (mm) to about 4.0 mm, more preferably in the range of about 0.6 mm to about 3.0 mm, and most preferably in the range of about 1 mm to about 2.4 mm.

[0028] Any deoxygenation catalyst within the temperature range suitable for hydropyrolysis process can be used. Preferably, the deoxygenation catalyst is selected from a sulfided catalyst with one or more metals, and the one or more metals are selected from the group consisting of nickel (Ni), cobalt (Co), molybdenum (Mo) or tungsten (W) supported on a metal oxide. Suitable metal combinations include sulfided NiMo, sulfided CoMo, sulfided NiW, sulfided CoW and sulfided ternary metal systems with any 3 metals from the family consisting of Ni, Co, Mo and W. Monometallic catalysts such as sulfided Mo, sulfided Ni and sulfided W are also applicable. The metal combination of the deoxygenation catalyst used according to certain embodiments of the present disclosure includes sulfided NiMo and sulfided CoMo. The carrier for the sulfided metal catalyst includes metal oxides, such as but not limited to aluminum oxide, silicon dioxide, titanium dioxide, ceria and zirconium oxide. Binary oxides such as silicon dioxide-aluminum oxide, silicon dioxide-titania and ceria-zirconium oxide can also be used. Preferably, the carrier includes aluminum oxide, silicon dioxide and titanium dioxide. In certain embodiments, the support contains fines of recycled, regenerated, and reactivated spent hydrotreating catalysts (e.g., fines of CoMo on an oxide support, fines of NiMo on an oxide support, and fines of a hydrocracking catalyst comprising NiW on a mixture of an oxide support and a zeolite). The total metal loading on the deoxygenated catalyst is preferably in the range of about 1.5 weight percent (wt%) to about 50 wt%, expressed as weight percent of the calcined deoxygenated catalyst in oxidized form (e.g., weight percent of Ni (as NiO) and Mo (as MoO3) on calcined oxidized NiMo on an alumina support). Additional elements such as phosphorus (P) may be incorporated into the deoxygenated catalyst to improve the dispersion of the metals.

[0029] The first stage 20 of the process disclosed herein produces a process gas 34 having a partially deoxygenated hydropyrolysis product and entrained solids (e.g., char, ash, catalyst fines). As used herein, the term "partially deoxygenated" refers to a material in which at least 30 weight percent (wt%), preferably at least 50 weight percent, and more preferably at least 70 weight percent of the oxygen present in the original solid feedstock 18 has been removed. The degree of oxygen removal refers to the percentage of oxygen in the solid feedstock 18 (e.g., biomass), excluding oxygen contained in free moisture in the solid feedstock 18. The oxygen is removed in the hydropyrolysis step in the form of water (H2O), carbon monoxide (CO), and carbon dioxide (CO2). Although almost 100 weight percent of the oxygen present in the solid feedstock 18 may be removed, typically up to 99 weight percent, suitably up to 95 weight percent, will be removed in the hydropyrolysis step.

[0030] Carbon removal

[0031] As described above, the process gas 34 produced by the hydropyrolysis step in the hydropyrolysis reactor 14 includes mixed solid and vapor products, including char, ash, catalyst fines, partially deoxygenated hydropyrolysis products, light gases (C1-C3 gases, CO, CO2, hydrogen sulfide (H2S), ammonia (NH3), and H2), H2O vapor, C 4+ Hydrocarbon vapors and oxygenated hydrocarbons. Char, ash, and catalyst fines are entrained in the gas phase products. Thus, between the hydropyrolysis and hydroconversion steps, between the first stage 20 and the second stage 24, respectively, char and catalyst fines are removed from the gas phase products (e.g., partially deoxygenated hydropyrolysis products) in the solids separation system 42. Any ash present may also be removed at this stage.

[0032] Typically, entrained carbon, ash, and catalyst fines are removed from the process gas 34 via one or more cyclone separators. However, cyclone separation does not provide the desired separation efficiency. For example, the separation efficiency of a cyclone separator is such that after passing through the cyclone separator, about 0.05% of residual solids are still entrained in the process gas. This amount of entrained solids may have an undesirable effect on the overall efficiency of the hydroprocessing process. For example, the residual entrained solids may cause plugging and / or fouling of downstream equipment. Therefore, a hydroprocessing system that utilizes a cyclone separator to remove entrained solids also includes a guard bed downstream of the cyclone separator to capture and remove the residual solids from the process gas. Due to the inefficiency of separating solids from the process gas using a cyclone separator and the addition of a guard bed, the overall cost of hydroprocessing is increased. Unlike cyclone separators, hot gas filters (e.g., candle filters) are known to have solid separation efficiencies exceeding 99.99%. The separation efficiency of hot gas filters is improved compared to cyclone separators, thereby reducing the operating and capital costs of the hydroprocessing system. Thus, the disclosed solids separation system 12 includes one or more hot gas filtration units 46 that remove char and other solids from the process gas 34 to produce a gas phase product 48. For example, Figure 1 As shown, the process gas 34 is fed to a solids separation system 42 , wherein a hot gas filtration unit 46 separates / removes solids (eg, char, ash, and catalyst fines 44 ) from the process gas 34 .

[0033] For example, refer to Figure 2 and Figure 3 , the solid separation system 12 includes a hot gas filtration unit 46 and containers 50a, 50b, and 50c. The containers 50 may be arranged in series ( Figure 2 ), parallel arrangement, or a combination of series and parallel arrangement ( Figure 3). Although three containers 50 are shown in the illustrated embodiment, it should be understood that any number of containers may be used. For example, the solid separation system may have 1, 2, 3, 4 or more containers 50. The hot gas filtration unit 46 includes a plurality of filter elements 52 (e.g., filter candles) that separate solids from the gas phase product 48. The filter element 52 includes a cylindrical conduit 54, typically made of a porous ceramic or metal material, having a closed upstream end 56 and an open end 58 on the downstream side. Each conduit 54 may be between 1 meter (m) and 3 meters in length and have a diameter of approximately 60 millimeters (mm) to 150 mm. The filter element 52 has a diameter of between 15 and 65×10 13 Square meter (m 2 ) range, with a pore size ranging from about 5 microns (μm) to 15 microns.

[0034] During operation, the process gas 34 flows into the hot gas filter unit 46 via the inlet 60 and is blown in a direction 62 toward the filter element 52. The process gas 34 flows through the holes into the conduit 54, where entrained solids in the process gas 34 cannot pass through the holes and are separated from the process gas 34. The separated solids accumulate on the outer surface of the conduit 54, forming a dust filter cake. The resulting gas phase product 48 flows within the conduit 54 toward the open end 58 and is released from the hot gas filter unit 46 via the outlet 64. The dust cake can be removed from the outer surface of the conduit 54 by using a reverse pulse of a fluid (e.g., hydrogen, carbon dioxide, air, steam, clean process gas and / or inert gas) and collected in one or more containers 50. For example, returned to Figure 1 , a blowback gas 70 is provided to the hot gas filter unit 46 of the filter element 52 (e.g., through the open end 58), so that the blowback gas flows through the conduit 54 toward the closed end and flows out through the holes to remove the dust filter cake (e.g., char and fine particles 44) accumulated on the filter element 52. The blowback gas 70 can be hydrogen 28, carbon dioxide (CO2), air, steam, or any other suitable fluid and combinations thereof. Using hydrogen 28 as the blowback gas 70 may be advantageous because dilution of the hydrotreating process is avoided. The hydrogen 28 can also stabilize free radicals and saturate the olefins in the gas phase product 48. In addition, by using hydrogen 28, it may not be necessary to incorporate additional equipment or cleaning processes to remove blowback gases that are not hydrogen.

[0035] As described above, process gas 34 comprises partially deoxygenated hydropyrolysis products and catalyst fines. Partially deoxygenated hydropyrolysis products may continue to react in solid separation system 42, resulting in coking and the formation of tar and condensate. Tar and condensate can gather on filter element (e.g., filter element 52) ​​and block the pores of the filter element. Therefore, the temperature of blowback gas 70 is kept higher than the condensation temperature of gas phase product 48 to avoid coking and the formation of condensate and tar. In addition, in certain embodiments, the temperature of blowback gas 70 is kept higher than the desublimation temperature of salt (e.g., ammonium chloride (NH4Cl)) present in gas phase product 48 to reduce the degradation of hot gas filter unit 46 and reduce the overall performance of filter element 52. For example, if the temperature of the gas-phase product 48 is below the desublimation temperature, the corrosive salts may sublime and accumulate on portions of the hot gas filter unit 46 and / or the filter element 52, thereby degrading the material of the hot gas filter unit 46 and / or the filter element 52, preventing the blowback gas 70 from flowing through the filter element 52, and reducing the overall performance of the hot gas filter unit 46 in separating particles (e.g., char, ash) from the gas-phase product 48. Therefore, the temperature of the blowback gas 70 may be about 10° C. to 30° C. higher than the condensation / desublimation temperature of the gas-phase product 48. Therefore, the temperature of the blowback gas 70 is higher than about 250° C. In particular, between about 300° C. and 450° C., preferably between about 350° C. and 400° C.

[0036] Level 2

[0037] After removal of the char and catalyst fines 44, the gas phase product 48 (e.g., partially deoxygenated hydropyrolysis product) is fed to the hydroconversion reactor 16 in the second stage 24 together with H2, CO, CO2, H2O and C1-C3 gases from the hydropyrolysis step (e.g., the first stage 20) and undergoes a hydroconversion step. The hydroconversion step is carried out at a temperature in the range of about 300°C to about 600°C and a pressure in the range of about 0.1 MPa to about 5 MPa. It should be noted that, based on the desired specifications of the hydrocarbon fuel produced by the hydroprocessing, a pressure higher than 0.6 MPa can be used to adjust the boiling point distribution and composition of the resulting hydrocarbon product. The weight hourly space velocity (WHSV) of this step is about 0.1 h -1 About 2 hours -1range. The hydroconversion reactor 16 is a fixed bed reactor. However, in certain embodiments, the hydroconversion reactor 16 may be a fluidized bed reactor. The gas phase product 48 undergoes hydroconversion in the presence of a hydroconversion catalyst to produce a fully deoxygenated hydrocarbon product 74. As used herein, the term "fully deoxygenated" means a material in which at least 98% by weight, preferably at least 99% by weight, and more preferably at least 99.9% by weight of the oxygen present in the original solid feedstock 18 (e.g., lignocellulose-containing biomass) has been removed. The hydrocarbon product 74 contains light gaseous hydrocarbons (such as methane, ethane, ethylene, propane and propylene, hydrocarbons in the naphtha range, hydrocarbons in the middle distillate range, hydrocarbons with a boiling point higher than 370°C (based on ASTM D86)), hydrogen and by-products of the hydroconversion reaction such as H2O, H2S, NH3, CO and CO2.

[0038] The solid feedstock 18 used in the disclosed process may contain metals, such as, but not limited to, sodium (Na), potassium (K), calcium (Ca), and phosphorus (P). These metals may degrade the hydroconversion catalyst used in the second stage 24. However, these metals may be removed in the first stage 20 along with the char and ash products (e.g., char and catalyst fines 44). Thus, the hydroconversion catalyst used in the hydroconversion step is protected from the presence of Na, K, Ca, P, and other metals in the solid feedstock 18, which may otherwise degrade the hydroconversion catalyst. In addition, by hydropyrolyzing the solid feedstock 18 in the first stage 20, the hydroconversion catalyst is advantageously protected from olefins and free radicals. The conditions under which the hydropyrolysis occurs in the first stage 20 stabilize the free radicals generated during the high temperature devolatilization of the solid feedstock 18 (e.g., biomass) by the presence of hydrogen and the catalyst, thereby generating stable hydrocarbon molecules that are less prone to, for example, coke-forming reactions that may deactivate the catalyst.

[0039] The hydroconversion catalyst used in the hydroconversion step includes any suitable hydroconversion catalyst with desired activity within the temperature range of the disclosed hydroconversion method. For example, the hydroconversion catalyst is selected from a sulfided catalyst with one or more metals from a group consisting of Ni, Co, Mo or W supported on a metal oxide. Suitable metal combinations include sulfided NiMo, sulfided CoMo, sulfided NiW, sulfided CoW and sulfided ternary metal systems with any three metals from a family consisting of Ni, Co, Mo and W. Catalysts such as sulfided Mo, sulfided Ni and sulfided W are also applicable. Metal oxide carriers for sulfided metal catalysts include but are not limited to aluminum oxide, silicon dioxide, titanium dioxide, ceria, zirconium oxide and binary oxides such as silicon dioxide-aluminum oxide, silicon dioxide-titania and ceria-zirconium oxide. Preferred carriers include aluminum oxide, silicon dioxide and titanium dioxide. The support may optionally comprise fine particles of regenerated and reactivated spent hydrotreating catalyst (e.g., fine particles of CoMo on an oxide support, fine particles of NiMo on an oxide support, and fine particles of a hydrocracking catalyst comprising NiW on a mixture of an oxide support and a zeolite). The total metal loading on the catalyst is in the range of about 5 wt % to about 35 wt % (expressed as weight percentage of the calcined catalyst in oxidized form, e.g., weight percentage of nickel (as NiO) and molybdenum (as MoO3) on calcined oxidized NiMo on an alumina catalyst). Additional elements such as phosphorus (P) may be incorporated into the catalyst to improve the dispersion of the metals. The metals may be introduced onto the support by impregnation or co-grinding or a combination of these two techniques. The hydroconversion catalyst used in the hydroconversion step may be the same or different in composition from the deoxygenation catalyst used in the hydropyrolysis step (e.g., the first stage 20). In one embodiment of the present disclosure, the hydropyrolysis catalyst comprises sulfided CoMo on an alumina support, and the hydroconversion catalyst comprises sulfided NiMo on an alumina support.

[0040] After the hydroconversion step, the fully deoxygenated hydrocarbon product 74 is fed to one or more condensers which condense the hydrocarbon product 74. The condensed hydrocarbon product 74 is fed to a gas-liquid separator 78 to provide a substantially fully deoxygenated hydrocarbon product. 4+ The term "substantially fully deoxygenated" is used herein to refer to a material in which at least 90% to 99% by weight of the oxygen present in the initial lignocellulose-containing biomass (e.g., solid feedstock 18) has been removed. Thus, the resulting liquid product 80 (e.g., substantially fully deoxygenated hydrocarbon C 4+Liquid) contains less than 2 wt %, preferably less than 1 wt % and most preferably less than 0.1 wt % oxygen. Substantially completely deoxygenated C4+ hydrocarbon liquids are different in composition from bio-oils produced using other low pressure hydrogenation processes. For example, compared with the oxygen content of liquid product 80 (e.g., less than 2 wt %), the oxygen content of bio-oil is greater (e.g., between about 5 wt % and 15 wt %). Therefore, partly due to the lower oxygen content of liquid product 80, the amount of acid components (measured by total acid number) and polar compounds compared with bio-oil is reduced. As a non-limiting example, acid components include carboxylic acids, phenols and mixtures thereof.

[0041] The hydrocarbon product 74 undergoes a separation process in a gas-liquid separator 78, which is used to separate the substantially completely deoxygenated C 4+ The aqueous material is separated from the hydrocarbon liquid and removed. Any suitable phase separation technique can be used to separate the aqueous material from the substantially completely deoxygenated C 4+ The aqueous material is separated from the hydrocarbon liquid and removed, thereby producing a C 4+ The liquid product 80 is a hydrocarbon and non-condensable gas 82. The non-condensable gas 82 mainly includes H2, CO, CO2 and light hydrocarbon gas (usually C1 to C3, and may also contain some C 4+ hydrocarbon).

[0042] In certain embodiments, the non-condensable gas 82 is fed to a gas purification system 60. The gas purification system 86 removes H2S, NH3 and trace amounts of organic sulfur compounds (if present) as byproducts of the process, thereby producing a hydrocarbon stream 90 having CO, CO2, H2 and light hydrocarbon gas. The gas purification system 86 includes one or more processing units that remove H2S92 and NH3 94 as byproducts of the process from the non-condensable gas 82. The hydrocarbon stream 90 can be sent to a separation, reforming and water-gas shift section 98, in which hydrogen 28 is produced from the light hydrocarbon gas in the hydrocarbon stream 90, and renewable CO2 100 is discharged as a byproduct of the process. The fuel gas stream can be recovered as a byproduct of the process. The generated hydrogen 28 can be reused in the process. For example, the hydrogen 28 can be recycled to the hydropyrolysis reactor 14 in the first stage 20. Enough hydrogen is generated for the entire process disclosed herein. That is, the amount of hydrogen 28 produced by the separation, reforming and water gas shift stage 98 is equal to or greater than the hydrogen required to maintain fluidization and sustain chemical consumption of hydrogen in the process.

[0043] The liquid phase product 80 recovered from the gas-liquid separator 78 is fed to the product recovery section 102. In the product recovery section 102, the aqueous product 104 is removed from the liquid phase product 80 to produce an intermediate liquid phase product 108. The intermediate liquid phase product 108 may be subjected to distillation to separate substantially completely deoxygenated C 4+ The hydrocarbon liquid is separated into fractions. For example, the substantially completely deoxygenated C 4+ Hydrocarbon liquids include naphtha range hydrocarbons, middle distillate range hydrocarbons (eg, gas oil, diesel), and vacuum gas oil (VGO) range hydrocarbons.

[0044] For the purpose of clarity, "middle distillates" as used herein are hydrocarbons or oxygenated hydrocarbons recovered by distillation between the atmospheric equivalent initial boiling point (IBP) and the final boiling point (FBP) measured according to the standard ASTM distillation method. The ASTM D86 initial boiling point of the middle distillate may vary between about 150° C. and about 220° C. According to ASTM D86 distillation, the final boiling point of the middle distillate may vary between about 350° C. and about 380° C. As used herein, "naphtha" is one or more hydrocarbons or oxygenated hydrocarbons having four or more carbon atoms and having an atmospheric equivalent final boiling point greater than about 90° C. but less than about 200° C. A small amount of hydrocarbons (less than about the total C 200° C.) produced in the process 4+ 3 wt % of total C 4+ 1 wt % of hydrocarbons) boil at a temperature higher than the above middle distillates. That is, the boiling range of these hydrocarbons is similar to that of vacuum gas oil produced by distilling petroleum. Gasoline is primarily a hydrocarbon in the naphtha range and is used in spark-ignited internal combustion engines. In the United States, the ASTM D4814 standard establishes the requirements for gasoline for ground vehicles with spark-ignited internal combustion engines. Gas oil (GO) / diesel is primarily a hydrocarbon in the middle distillate range and is used in compression-ignition internal combustion engines. In the United States, the ASTM D975 standard covers the requirements for several grades of diesel fuel suitable for various types of diesel engines.

[0045] Therefore, in the illustrated embodiment, the intermediate liquid product 108 is fed to the distillation unit 110 to recover the gasoline product 112 and the distillate product 114 (e.g., middle distillate). In certain embodiments, kerosene / jet fuel 116 is recovered from the distillation unit 110 as an independent stream. The distillate product 114 (e.g., middle distillate) contains gas oil (GO), such as biodiesel, and is substantially completely free of oxygen, sulfur, and nitrogen. In certain embodiments, the oxygen content of the distillate product 114 is less than about 1.50 wt %. For example, the oxygen content can be about 1.40 wt %, 1.25 wt %, 0.50 wt %, 0.25 wt %, or 0.10 wt % or less. In one embodiment, the sulfur content is less than 100 ppmw. For example, the sulfur content can be about 75 ppmw, 50 ppmw, 25 ppmw, 10 ppmw, 5 ppmw, 1 ppmw or less. Thus, the biodiesel obtained from the distillate product 114 is considered to be ultra-low sulfur diesel (ULSD), which generally has less than 10 ppmw sulfur. With respect to nitrogen content, in certain embodiments, the substantially fully deoxygenated C 4+ The nitrogen content of the hydrocarbon liquid is less than 1000 ppmw. For example, the nitrogen content may be about 750 ppmw, 500 ppmw, 250 ppmw, 100 ppmw, 75 ppmw, 50 ppmw, 25 ppmw, 10 ppmw or 1 ppmw or less.

[0046] As described above, hydrocarbon liquid products (such as distillate products 114) produced by hydroprocessing of solid biomass feedstocks (e.g., solid feedstock 18) typically require additional processing in the third stage to upgrade and improve product characteristics, such as cetane number, reduced density, reduced sulfur and / or nitrogen content, reduced benzene content (e.g., due to selective saturation), etc., and are conducive to tailoring the overall hydrocarbon product to specific site and market specifications, as well as other benefits. In certain embodiments, the distillate product 114 can be blended with hydroprocessed esters and / or fatty acids (HEFA) to upgrade and improve characteristics such as cetane number and density.

[0047] The present embodiment also includes a method of removing entrained solids (e.g., char and fines 44) from a process gas (e.g., process gas 34) in a solids separation system (e.g., solids separation system 42). For example, Figure 4 2 is a flow chart of a method 200 that can be used to remove entrained solids (e.g., char and fines 44) from a process gas using a disclosed hot gas filtration unit (e.g., hot gas filtration unit 46). For ease of discussion of the actions of method 200, reference will be made to Figure 5The method 200 includes providing a process gas produced in the hydropyrolysis reactor to a solids separation system (block 204). The method 200 also includes removing entrained solids from the process gas to produce a gas phase product (e.g., gas phase product 48) and a dust filter cake (block 208). For example, go to Figure 5 , the hot gas filter unit 46 receives the process gas 34 through the inlet 60, where the process gas is introduced into the space 210. The inlet 60 and the space 210 are located below the filter element 52 so that the process gas 34 (e.g., process gas) flows toward the filter element 52 in an upward direction (e.g., direction 62). The upward flow of the process gas 34 helps to separate high-density heavy particles in the process gas 34 that cannot be transported in the direction 62. The solids / particles fall toward the solids outlet 210 of the hot gas filter unit 46, where they are introduced into one or more containers (e.g., container 50) of the solid separation system. However, fine particles (e.g., catalyst fines, char, and ash) are still entrained in the process gas 34. Thus, once the process gas 34 reaches the filter element 52, the remaining entrained particles are captured on the outer surface of the conduit 54, and the gaseous product 48 flows through the pores of the conduit 54, into the filtered gas outlet 214 (e.g., a venturi outlet), and into the second space 216, after which the gaseous product 48 is released from the hot gas filter unit 42 through the outlet 64. The gaseous product 48 is substantially free of solids / particles. For example, the gaseous product 48 may contain less than about 1 mg / Nm 3 of solids / particles.

[0048] Return to Figure 4 , method 200 also includes providing (e.g., blowback gas 70) to the solids separation system and removing the dust cake (block 220). As described above, entrained solids / particles (e.g., catalyst fines, char, and ash 44) in the outlet (e.g., process gas 34) are captured on the conduit (e.g., conduit 54) of the filter element (e.g., filter element 52). Therefore, in order to remove the particles (e.g., dust cake) accumulated on the conduit, blowback gas (e.g., blowback gas 70) is provided to the conduit to blow the dust cake from the outer surface of the conduit and remove it. For example, returning to Figure 5 , a blowback gas 70 is injected into the gas inlet 226 associated with each respective filter element 52. The gas inlet 226 is fluidly coupled to the filtered gas outlet 214 and the conduit 54. During the removal of the dust filter cake from the outer surface of the conduit 54, the flow of the process gas 34 entering the hot gas filter unit 46 is temporarily interrupted. For example, the flow of the process gas 34 is interrupted for about 20 microseconds (ms) to about 800 ms. When the flow of the process gas 34 is interrupted, the blowback gas 70 is injected into the gas inlet 226 and discharged through the holes of the conduit 54, thereby loosening the dust filter cake and removing it from the outer surface.

[0049] As described above, the process gas 34 contains partially deoxygenated hydropyrolysis products and catalyst fines. The partially deoxygenated hydropyrolysis products may continue to react in the hot gas filtration unit 46 and form tar and condensate, which may clog the holes of the conduit 54. However, by controlling the temperature of the process gas 34 and the blowback gas 70, the formation of tar and condensate can be reduced. For example, the temperature of the process gas 34 and the blowback gas 70 is maintained at a temperature higher than the condensation temperature of the process gas 34. In certain embodiments, the blowback gas 70 may be preheated to a temperature higher than the condensation temperature of the process gas 34. For example, the blowback gas 70 may be preheated to a temperature higher than the condensation (i.e., dew point) temperature of water and / or hydrocarbons present in the process gas 34. In certain embodiments, the blowback gas 70 may be preheated to a temperature higher than the desublimation temperature of the salt (e.g., ammonium chloride (NH4Cl)) present in the process gas 34. In one embodiment, the filter element 52 may also be preheated to a temperature higher than the temperature of the process gas 34 before the process gas 34 is injected into the hot gas filter unit 46 to reduce the formation of tar and condensate on the surface of the conduit 54. This may be accomplished by injecting preheated blowback gas 70 or any other suitable particulate-free gas into the conduit 54 and / or the hot gas filter unit 46. As a non-limiting example, the temperature of the process gas 34 and the blowback gas 70 may be about 10°C to 30°C higher than the condensation temperature of the process gas 34. For example, between about 250°C and 400°C.

[0050] In addition to the temperature of the process gas 34 and the blowback gas 70, the formation of tar and condensate and coking can be reduced by the frequency of providing the blowback gas to the conduit 54 (e.g., the frequency of dust cake removal) and the type of gas used as the blowback gas 70. When a low molecular weight gas (e.g., hydrogen) is used, the amount of blowback gas injected into the conduit 54 can be higher than the amount of a high molecular weight blowback gas (e.g., carbon dioxide (CO2)). Although hydrogen is expected to be used as the blowback gas 70 in part due to its production and use in the hydroprocessing process, other blowback gases can also be used. For example, the blowback gas can be hydrogen, carbon dioxide, air, or any other suitable gas and combinations thereof. Depending on the composition of the blowback gas 70 used to remove the dust cake from the conduit 54, the frequency of the blowback gas injection into the conduit 54 will vary.

[0051] Return to Figure 4 , the dust filter cake is then removed from the conduit 54 according to the action of frame 220. The method 200 includes collecting particles from the removed dust filter cake (frame 228). As described above, with reference to Figure 2 and Figure 3, the solids separation system 12 includes a vessel 50 downstream of the hot filtration unit 46. One or more vessels 50 may receive the particles 44 removed from the conduit 54 for disposal.

[0052] As described above, the solids separation system disclosed herein includes a hot gas filtration unit having a filter element that can remove entrained solids / particles from process gases produced in a hydropyrolysis process in a highly efficient manner without the use of a cyclone separator, as compared to existing hydroprocessing systems. The disclosed system and method can also reduce the formation of tar and condensate and coking on the outer surface of the filter element, thereby reducing fouling of the hot gas filtration unit. By replacing the cyclone separator used in the existing hydroprocessing system with hot gas filtration, the solids removal efficiency of the solids separation system can be improved, and the overall cost of the hydroprocessing system and process can be reduced, as compared to existing hydroprocessing systems that use cyclones.

[0053] Without departing from the essence or essential features of the present disclosure, the present disclosure may be embodied in other specific forms. The described embodiments should be considered in all respects to be merely illustrative and not restrictive. Therefore, the scope of the present disclosure is indicated by the appended claims rather than by the foregoing description. All changes falling within the equivalent meaning and scope of the claims will be included within the scope of the claims.

Claims

1. A method for producing a liquid hydrocarbon product from a solid feedstock, the method comprising: feeding the solid feedstock and hydrogen to a first-stage hydropyrolysis reactor, wherein the first-stage hydropyrolysis reactor comprises one or more deoxygenation catalysts, and wherein the solid feedstock comprises biomass, waste plastic, or a combination thereof; hydropyrolyzing the solid feedstock in the first stage hydropyrolysis reactor to produce a process gas stream comprising partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines; as well as The process gas stream is fed to a solid separation system comprising a hot gas filtration unit having a plurality of filter elements, the plurality of filter elements being configured to separate the char and catalyst fines from the process gas to produce a gas phase product and a dust cake, wherein the gas phase product comprises the partially deoxygenated hydropyrolysis product, H2O, H2, CO2, CO, and C1-C3 gases, and wherein the dust cake is disposed on outer surfaces of the plurality of filter elements and comprises the char and catalyst fines.

2. The method of claim 1 , comprising injecting a blowback gas into a gas inlet fluidly coupled to an outlet of the plurality of filter elements, wherein the blowback gas is configured to remove the dust cake from the outer surfaces of the plurality of filter elements, and wherein the blowback gas comprises the hydrogen, carbon dioxide (CO 2 ), air, steam, or a combination thereof.

3. The method of claim 2, comprising preheating the blowback gas to a temperature higher than the condensation temperature of the process gas stream or the desublimation temperature of the salt in the process gas, wherein the condensation temperature of the process gas stream is the condensation temperature of the H2O, the partially deoxygenated hydropyrolysis product or the C1-C3 gas present in the process gas stream.

4. The method of claim 3, wherein the temperature is between about 250°C and about 400°C.

5. The method of claim 2, comprising interrupting the flow of the process gas stream into the hot gas filter unit prior to injecting the purge gas.

6. The method of claim 2, comprising collecting the dust filter cake removed from the outer surfaces of the plurality of filter elements in one or more containers, wherein the one or more containers are disposed within the solid separation system, downstream of the hot gas filter unit and fluidically coupled to the hot gas filter unit.

7. The method of claim 1, comprising preheating the plurality of filter elements to a temperature above a condensation temperature of the process gas stream prior to feeding the process gas stream to the hot gas filtration unit.

8. The method of claim 6, wherein the temperature is about 10°C to about 30°C higher than the condensation temperature of the process gas stream.

9. The method of claim 1, wherein the gas phase product comprises less than about 1 mg / Nm3. 3 ) wt % solids.

10. The process of claim 1, comprising feeding at least a portion of the process gas stream to a second hydroconversion reactor comprising one or more hydroconversion catalysts; hydroconverting the partially deoxygenated hydropyrolysis product in the gas phase product to produce a hydrocarbon product comprising substantially fully deoxygenated hydrocarbon products, H2O, CO, CO2, and C1-C3 gases; and The hydrocarbon product is condensed to produce a substantially completely deoxygenated C 4+ Deoxygenated hydrocarbon liquids.

11. A system for producing a liquid hydrocarbon product from a solid feedstock, the system comprising: a hydropyrolysis reactor comprising one or more deoxygenation catalysts and configured to produce a process gas stream comprising partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines, wherein the solid feedstock comprises biomass, waste plastic, or a combination thereof; a solids separation system disposed downstream of the hydropyrolysis reactor and fluidly coupled to the hydropyrolysis reactor, wherein the solids separation system is configured to receive the process gas stream and includes a hot gas filtration unit having a plurality of filter elements configured to remove the char and catalyst fines from the process gas stream to produce a gas phase product comprising the partially deoxygenated hydropyrolysis product, H2O, H2, CO2, CO, and C1-C3 gases; and a hydroconversion reactor disposed downstream of and fluidly coupled to the solids separation system and comprising one or more hydroconversion catalysts; wherein the hydroconversion reactor is configured to receive the gas phase product from the solid separation system and produce a hydrocarbon product from the gas phase product, wherein the hydrocarbon product comprises a substantially fully deoxygenated hydrocarbon product, H2O, CO, CO2, and C1-C3 gas.

12. The system of claim 11, wherein the hot gas filter unit comprises a gas inlet extending between a blowback gas source and outlets of the plurality of filter elements, wherein the gas inlet is configured to inject the blowback gas into the outlets of the plurality of filter elements, and wherein the blowback gas is configured to remove the char and catalyst fines from exterior surfaces of the plurality of filter elements.

13. The system of claim 11, wherein the blowback gas comprises the hydrogen, carbon dioxide (CO2), air, nitrogen (N2), steam, or a combination thereof.

14. The system of claim 11, comprising one or more containers disposed within the solid separation system, downstream of the hot gas filtration unit and fluidically coupled to the hot gas filtration unit, wherein the one or more containers are configured to collect the char and catalyst fines removed from the gas phase product.

15. The system of claim 11, wherein the gas phase product comprises less than about 1 mg / Nm 3 of solid.

16. A method for producing a liquid hydrocarbon product from a solid feedstock, the method comprising: hydropyrolyzing the solid feedstock in a hydropyrolysis reactor to produce a process gas stream comprising partially deoxygenated hydropyrolysis products, H2O, H2, CO2, CO, C1-C3 gases, and char and catalyst fines; and feeding the process gas stream to a solids separation system disposed downstream of and fluidly coupled to the hydropyrolysis reactor, wherein the solids separation system comprises a hot gas filtration unit having a plurality of filter elements, each filter element comprising a conduit having a plurality of apertures; The process gas stream is filtered through the respective conduits of the plurality of filter elements to separate the char and catalyst fines from the process gas and produce a gas-phase product and a dust cake, wherein the gas-phase product comprises the partially deoxygenated hydropyrolysis product, H2O, H2, CO2, CO, and C1-C3 gases, wherein the dust cake is disposed on outer surfaces of the respective conduits of the plurality of filter elements, and wherein the dust cake comprises the char and catalyst fines.

17. The method of claim 16, comprising injecting a blowback gas into a gas inlet fluidly coupled to outlets of the plurality of filter elements, wherein the blowback gas is configured to remove the dust filter cake from the outer surface of the conduit, and wherein the blowback gas comprises the hydrogen, carbon dioxide (CO2), air, steam, or a combination thereof.

18. The method of claim 17, comprising preheating the blowback gas, the plurality of filter elements, or both to a temperature greater than the condensation temperature of the process gas stream.

19. The method of claim 18, wherein the temperature is about 10°C to about 30°C higher than the condensation temperature of the blowback gas.

20. The method of claim 18, wherein the temperature is between about 350°C and about 400°C.

21. The method of claim 16, wherein the gas phase product comprises less than about 1 mg / Nm 3 of solid.

22. The method of claim 16, comprising feeding at least a portion of the process gas stream to a second hydroconversion reactor comprising one or more hydroconversion catalysts; hydroconverting the partially deoxygenated hydropyrolysis product in the gas phase product to produce a hydrocarbon product comprising substantially fully deoxygenated hydrocarbon products, H2O, CO, CO2, and C1-C3 gases; and The hydrocarbon product is condensed to produce a substantially completely deoxygenated C 4+ Deoxygenated hydrocarbon liquids.

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