Gas phase upgrading with slurry hydroconversion for processing renewable feedstock

Abstract

A process includes obtaining, from a slurry hydroconversion reactor processing a renewable feedstock, a slurry hydroconversion effluent comprising a gas phase having an oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase, and a slurry phase, separating the gas phase from the slurry phase thereby producing a first gas stream, and processing the first gas stream in the presence of a gas phase upgrading catalyst, thereby producing a second gas stream having a reduced content of oxygen based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream. The separation unit and the gas phase upgrading reactor operate in a same pressure loop as the slurry hydroconversion reactor.

Description

T-12558-WO01 (538-370 PCT)GAS PHASE UPGRADING WITH SLURRY HYDROCONVERSION FOR PROCESSING RENEWABLE FEEDSTOCKPRIORITY CLAIM

[0001] The present application claims priority to U.S. Provisional Patent Application No.63 / 745,530, entitled “Gas Phase Upgrading with Slurry Hydroconversion for Processing Renewable Feedstock,” filed January 15, 2025, the content of which is incorporated by reference herein in its entirety.BACKGROUND

[0002] Slurry hydrocracking has been used for the upgrading of heavy hydrocarbon feedstocks to produce distillate products. In slurry hydrocracking, these feedstocks are converted in the presence of hydrogen and solid catalyst particles in a slurry phase.

[0003] The distillate products produced using slurry hydrocracking include, for example, naphtha, jet fuel, diesel, and vacuum gas oil range materials containing high level of contaminants. In order to meet product specifications, the distillate products can be further upgraded by hydrotreating in a hydrotreater. The hydrotreater is typically a stand-alone distillate hydrotreater to upgrade liquid products.

[0004] The ongoing search for alternatives to crude is increasingly driven by a number of factors. These include diminishing petroleum reserves, higher anticipated energy demands, and emissions from sources of non-renewable carbon. As a result, there is growing interest in transitioning away from solely conventional carbon-based fossil fuel energy carriers. For example, energy conservation such as improvements in energy efficiency and electrification, may play a role, but efforts to use renewable resources for the production of fuels and fuel components and / or chemical feedstocks are also a focus. Thus, there is increasing interest in alternative feedstocks such as biomass feedstocks for at least partially replacing crude oil, in the production of hydrocarbons, suitable as fuels or fuel components such as, for example, transportation fuels, or compatible with fuels.T-12558-WO01 (538-370 PCT)SUMMARY

[0005] In accordance with an illustrative embodiment, a process comprises:

[0006] obtaining, from a slurry hydroconversion reactor processing a renewable feedstock, a slurry hydroconversion effluent comprising a gas phase having an oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase, and a slurry phase,

[0007] separating, in a separation unit, the gas phase having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase from the slurry hydroconversion effluent, thereby producing a first gas stream having an oxygen content of at least about 3 wt. %, based on the total content of the organic compounds in the first gas stream, and

[0008] processing, in a gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the first gas stream, in the presence of a gas phase upgrading catalyst and under gas phase upgrading conditions to reduce the oxygen content from the first gas stream, thereby producing a second gas stream having a reduced content of oxygen based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream,

[0009] wherein the separation unit and the gas phase upgrading reactor operate in a same pressure loop as the slurry hydroconversion reactor.BRIEF DESCRIPTION OF THE DRAWING

[0010] In combination with the accompanying drawing and with reference to the following detailed description, the features, advantages, and other aspects of the implementations of the present disclosure will become more apparent, and several implementations of the present disclosure are illustrated herein by way of example but not limitation. The principles illustrated in the example embodiments of the drawing can be applied to alternate processes and apparatus. Additionally, the elements and features shown in the drawing are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. In the accompanying drawing:T-12558-WO01 (538-370 PCT)

[0011] FIG. 1 illustrates a system utilizing gas phase upgrading and slurry hydroconversion for processing a solid biomass feedstock, according to an illustrative embodiment.DETAILED DESCRIPTION

[0012] Various illustrative embodiments described herein are directed to processes and systems utilizing gas phase upgrading with slurry hydroconversion for processing a renewable feedstock to produce, for example, a gas stream, a water stream having a reduced chemical oxygen demand and one or more oil streams.

[0013] DEFINITIONS

[0014] To define more clearly the terms used herein, the following definitions are provided. Unless otherwise indicated, the following definitions are applicable to this disclosure. If a term is used in this disclosure but is not specifically defined herein, the definition from the IUPAC Compendium of Chemical Terminology can be applied, as long as that definition does not conflict with any other disclosure or definition applied herein or render indefinite or non-enabled any claim to which that definition is applied. To the extent that any definition or usage provided by any document incorporated herein by reference conflicts with the definition or usage provided herein, the definition or usage provided herein controls.

[0015] While systems and processes are described in terms of “comprising” various components or steps, the systems and processes can also “consist essentially of’ or “consist of’ the various components or steps, unless stated otherwise.

[0016] The terms “a,” “an,” and “the” are intended to include plural alternatives, e.g., at least one. The terms “including,” “with,” and “having,” as used herein, are defined as comprising (i.e., open language), unless specified otherwise.

[0017] Various numerical ranges are disclosed herein. When Applicant discloses or claims a range of any type, Applicant’s intent is to disclose or claim individually each possible number that such a range could reasonably encompass, including end points of the range as well as any sub-ranges and combinations of sub-ranges encompassed therein, unless otherwise specified. For example, all numerical end points of ranges disclosed herein are approximate, unless excluded by proviso.T-12558-WO01 (538-370 PCT)

[0018] Values or ranges may be expressed herein as “about,” from “about” one particular value, and / or to “about” another particular value. When such values or ranges are expressed, other embodiments disclosed include the specific value recited, from the one particular value, and / or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another embodiment. It will be further understood that there are a number of values disclosed therein, and that each value is also herein disclosed as “about” that particular value in addition to the value itself. In another aspect, use of the term “about” means ±20% of the stated value, ±15% of the stated value, ±10% of the stated value, ±5% of the stated value, ±3% of the stated value, or ±1% of the stated value.

[0019] Applicant reserves the right to proviso out or exclude any individual members of any such group of values or ranges, including any sub-ranges or combinations of sub-ranges within the group, that can be claimed according to a range or in any similar manner, if for any reason Applicant chooses to claim less than the full measure of the disclosure, for example, to account for a reference that Applicant may be unaware of at the time of the filing of the application. Further, Applicant reserves the right to proviso out or exclude any members of a claimed group.

[0020] The term “hydroconverting” or “hydroconversion” as used herein refers to any process in which a hydrocarbon or biomass feedstock are processed or treated in the presence of a hydrogen stream and a catalyst under hydroconverting conditions, typically, at elevated temperature and elevated pressure. Hydroconverting includes, for example, hydrocracking, hydrotreating, hydrogenation, deoxygenation, desulfurization, denitrogenation, demetallization, dechlorination, decarboxylation, decarbonylation, dearomatization or a combination thereof. Depending on the type of hydroconversion and the reaction conditions, products of hydroconversion processes may have improved specific gravity, acidity, aromatic content, viscosities, viscosity indices, saturates content, low temperature properties, volatilities and depolarization, for example.

[0021] The term “renewable” refers to a material that is produced from a renewable resource, which is a resource produced via a natural process at a rate comparable to its rate of consumption (e.g., within a 100-year time frame). The renewable resource can be replenished naturally or via agricultural techniques. Non-limiting examples of renewable resources include plants, animals, fish, bacteria, fungi, and forestry products. These resources can be naturallyT-12558-WO01 (538-370 PCT)occurring, hybrids, or genetically engineered organisms. Natural resources such as crude oil (petroleum), natural gas, coal, peat, etc. take longer than 100 years to form and thus they are not considered renewable resources.

[0022] The terms “upgrade,” “upgrading” and “upgraded,” when used to describe a reactor, or a feedstock that is being or has been subjected to hydroprocessing, or a resulting material or product, refer to one or more of a reduction in molecular weight of the feedstock, a reduction in boiling point range of the feedstock, a reduction in concentration of hydrocarbon free radicals, and / or a reduction in quantity of impurities, such as sulfur, nitrogen, oxygen, halides, and metals.

[0023] The term “Cn hydrocarbons” or “Cn,” is used herein having its well-known meaning, that is, wherein “n” is an integer value, and means hydrocarbons having that value of carbon atoms. The term “Cn+ hydrocarbons” or “Cn+” refers to hydrocarbons having that value or more carbon atoms. The term “Cn- hydrocarbons” or “Cn-” refers to hydrocarbons having that value or less carbon atoms.

[0024] The term “hydrocarbon” is used in the conventional sense to refer to a compound containing only carbon and hydrogen atoms.

[0025] The term “continuous” means a system that operates without interruption or cessation for a period of time, such as where reactants are continually fed into a reaction zone and products are continually or regularly withdrawn without stopping the reaction in the reaction zone.

[0026] The term “biomass” or “biomass feedstock” refers to, without limitation, organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae).

[0027] The term “zone” can refer to an area including one or more equipment items and / or one or more sub-zones. Equipment items can include one or more reactors or reactor vessels, separation vessels, distillation towers, heaters, exchangers, pipes, pumps, compressors, and controllers. Additionally, an equipment item, such as a reactor, dryer, or vessel, can further include one or more zones or sub-zones.

[0028] The term “effluent” refers to a stream that is passed out of a reactor, a reaction zone, or a separation unit following a particular reaction or separation. Generally, an effluent has a different composition than the stream that entered the reactor, reaction zone, or separator. It shouldT-12558-WO01 (538-370 PCT)be understood that when an effluent is passed to another component or system, only a portion of that effluent may be passed. For example, a slipstream may carry some of the effluent away, meaning that only a portion of the effluent may enter the downstream component or system.

[0029] The term “catalyst precursor” refers to a compound containing one or more catalytically active metals, from which compound the slurry catalyst is eventually formed, and which compound may be catalytically active as a hydroprocessing catalyst. An example is a waterbased catalyst prior to a transformation step with a hydrocarbon diluent, another example is a sulfided metal precursor. Catalyst precursors and the preparation of slurry catalysts are described in various patents, e.g., U.S. Patent No. 8,802,586, WO 2012 / 092006, and the like.

[0030] It should further be understood that streams may be named for the components of the stream, and the component for which the stream is named may be the major component of the stream (such as comprising from 50 wt. %, from 70 wt. %, from 90 wt. %, from 95 wt. %, from 99 wt. %, from 99.5 wt. %, or from 99.9 wt. % of the contents of the stream to 100 wt. % of the contents of the stream). It should also be understood that components of a stream are disclosed as passing from one system component to another when a stream comprising that component is disclosed as passing from that system component to another. For example, a disclosed “hydrogen stream” passing to a first system component or from a first system component to a second system component should be understood to equivalently disclose “hydrogen” passing to the first system component or passing from a first system component to a second system component.

[0031] The term “boiling point” means atmospheric equivalent boiling point (AEBP) as calculated from the observed boiling temperature and the distillation pressure using the equations furnished in ASTM DI 160 appendix A7 entitled “Practice for Converting Observed Vapor Temperatures to Atmospheric Equivalent Temperatures”.

[0032] The term “T5” or “T95” means the temperature at which 5 volume percent or 95 volume percent, as the case may be, respectively, of the sample boils using ASTM D86.

[0033] The term “initial boiling point” (IBP) means the temperature at which the sample begins to boil using ASTM D86.

[0034] The term “end point” (EBP) means the temperature at which the sample has all boiled off using ASTM D86.T-12558-WO01 (538-370 PCT)

[0035] The term “True Boiling Point” (TBP) means a test method for determining the boiling point of a material which corresponds to ASTM D2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5: 1 reflux ratio.

[0036] The term “naphtha” or “naphtha boiling range” means hydrocarbons boiling in the range of an IBP between about 0°C and 100°C or a T5 between 15°C and 100°C and the “naphtha cut point” comprising a T95 between 150°C and 200°C using the TBP distillation method.

[0037] The term “kerosene” or “kerosene boiling range” means hydrocarbons boiling in the range of from 132°C to 300°C, using the TBP distillation method. Further, a kerosene stream may be defined as having T5 boiling point from 120°C to 200°C and T95 boiling point from 270°C to 300°C or a T10 boiling of no more than 205°C and a final boiling point of no greater than 300°C using ASTM D86. Furthermore, the flash point must be greater than about 100°F (about 38°C) using ASTM D56.

[0038] The term “diesel” or “diesel boiling range” means hydrocarbons having a T5 boiling point between about 302°F and about 392°F (about 150°C and about 200°C) and a T95 boiling point between about 649°F and about 800°F (about 343°C and about 399°C) using the TBP distillation method.

[0039] The term “vacuum gas oil” (VGO) as used herein refer to hydrocarbons boiling in the range of about 649°F and about 1022°F (about 343°C to about 550°C).

[0040] The term “light vacuum gas oil” (LVGO) refers to hydrocarbons boiling in the range of about 649°F and about 797°F (about 343°C to about 425°C).

[0041] The term “heavy vacuum gas oil” (HVGO) refers to hydrocarbons boiling in the range of about 797°F and about 1022°F (about 425°C to about 550°C).

[0042] The terms “wt. %,” “vol. %” or “mol. %” refers to a weight, volume, or molar percentage of a component, respectively, based on the total weight, the total volume, or the total moles of material that includes the component. In a non-limiting example, 10 moles of component in 100 moles of the material are 10 mol. % of component.T-12558-WO01 (538-370 PCT)

[0043] As mentioned above, slurry hydrocracking has been used for the upgrading of heavy hydrocarbon feedstocks to produce a slurry reactor effluent containing distillate products. In order to meet product specifications such as, for example, low sulfur, low nitrogen, and cetane, the distillate products are further upgraded by hydrotreating in a hydrotreater.

[0044] A major challenge in slurry hydroconversion of biomass feedstocks is the separation of the distillate products from the wastewater byproducts, because many of the distillate products are oxygen-containing organic compounds (oxygenates) resulting in the slurry reactor effluent containing a high level of oxygenates. Since oxygenates are highly soluble in water, the separation of the distillate products (i.e. oil phase) and the wastewater (i.e., water phase) is more difficult. In addition, the wastewater has a high organic matter content, making it difficult to process in wastewater treatment plants. Further, the presence of oxygenates as well as olefins can increase the fouling tendency. Another problem is separating any carbon monoxide produced during the slurry hydroconversion in an off-gas separation process. Yet another problem is that phenolic compounds produced during processing of biomass feedstocks are challenging to hydrotreat as traditional trickle bed hydrotreaters are unable to achieve full oxygen conversion.

[0045] The non-limiting illustrative embodiments described herein overcome the drawbacks discussed above by providing systems and processes utilizing gas phase upgrading with slurry hydroconversion for converting a renewable feedstock to produce, for example, a gas stream, a water stream having a reduced chemical oxygen demand and one or more oil streams. Several advantages from the systems and processes of the non-limiting illustrative embodiments described herein include:

[0046] Energy Efficiency. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor eliminates the need to cool and repressurize the effluent for offline hydrotreating. This significantly reduces the number of pressure vessels, pumps, heat exchangers and associated equipment, leading to lower energy consumption and operational costs. Thus, by maintaining a continuous process, the system becomes more efficient and less complex.

[0047] Enhanced Separation. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor improves oil-water separation, thereby allowing for the use of a simpler separation system such as a three-phase separation unit. This can save space as well as reduce the capital and maintenance costs associated with larger and more complex separation systems. TheT-12558-WO01 (538-370 PCT)improved separation efficiency ensures that the oil and water phases are more distinct, leading to better overall process performance.

[0048] Improved Water Quality. By improving the quality of the water produced after processing in the gas phase upgrading reactor, the use of a gas phase upgrading reactor with a slurry hydroconversion reactor reduces the burden on wastewater treatment facilities. The cleaner water output results in fewer contaminants that have to be removed, which can lower treatment costs and environmental impact. This improvement may also facilitate compliance with environmental regulatory requirements.

[0049] Stability Improvement. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor also removes olefins and other unstable components from the gas phase of the effluent. This reduction in reactive species decreases the fouling tendency in downstream equipment, such as heat exchangers and reactors. As a result, the equipment operates more efficiently and requires less frequent cleaning and maintenance, leading to improved reliability and lower operational costs.

[0050] Oil Quality Improvement. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor improves the overall quality of the oil by removing impurities and enhancing its properties. This can lead to higher-value end products and better performance in subsequent processing steps. The improved oil quality can also extend the lifespan of downstream catalysts and equipment.

[0051] Water-Gas Shift Reaction. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor can include a water-gas shift reaction in the gas phase upgrading reactor that converts carbon monoxide (CO) to carbon dioxide (CO2). This conversion reduces the CO content without hydrogen consumption as well as the load on off-gas treatment systems, making them more efficient and less costly to operate. The water-gas shift reaction also helps in managing the hydrogen balance within the process, which is particularly useful for maintaining optimal upgrading conditions.

[0052] Methanation. The use of a gas phase upgrading reactor with a slurry hydroconversion reactor can reduce the CO content through methanation, which converts CO into methane (CH4) and water. This conversion reduces the CO content as well as decreases theT-12558-WO01 (538-370 PCT)demand on gas separation processes, making the process more efficient. Methanation also assists in producing a cleaner off-gas stream, which can be more easily managed and utilized.

[0053] Gas Phase Hydrotreating to Reduce Acidic Attack on Catalyst. Most hydrotreating is operated in a fixed bed reactor such as a trickle bed reactor, with a liquid phase in the feed. The acidic components in the liquid phase of the feed can attack the fixed bed catalyst, leading to its disintegration. This results in catalyst loss and plugging of the fixed bed. The continuous process described herein involves gas phase upgrading only. Thus, highly acidic components do not significantly impact the catalyst in the gas phase upgrading reactor.

[0054] The non-limiting illustrative embodiments of the present disclosure will be specifically described below with reference to the accompanying drawing. For the purpose of clarity, some steps leading up to the production of a gas phase, a water phase having a reduced chemical oxygen demand and an oil phase illustrated in FIG. 1 may be omitted. In other words, one or more well-known processing steps which are not illustrated but are well-known to those of ordinary skill in the art have not been included in the figure. This is not intended to be interpreted as a limitation of any particular embodiment, or illustration, or scope of the claims.

[0055] Referring to FIG. 1, a system 100 includes at least a slurry hydroconversion reactor 102, a separation unit 112 and a gas phase upgrading reactor 118. It is to be understood that system 100 including at least slurry hydroconversion reactor 102, separation unit 112 and gas phase upgrading reactor 118 is not limited to the configuration of the embodiments shown in FIG. 1, and other configurations are contemplated herein.

[0056] Slurry Hydroconversion Reactor

[0057] FIG. 1 shows system 100 including slurry hydroconversion reactor 102 for receiving a renewable feedstock 101, an optional renewable liquid carrier 104, a slurry hydroconversion catalyst 106, a hydrogen stream 108 and an optional sulfiding agent stream (not shown). Although renewable feedstock 101, optional renewable liquid carrier 104, slurry hydroconversion catalyst 106 and hydrogen stream 108 are shown entering slurry hydroconversion reactor 102 separately, this is merely illustrative and any points of entry into slurry hydroconversion reactor 102 are contemplated herein. For example, in some embodiments, hydrogen stream 108 may be mixed with renewable feedstock 101 and / or optional renewable liquid carrier 104 upstream of the feed inlet to slurry hydroconversion reactor 102. Alternatively,T-12558-WO01 (538-370 PCT)hydrogen stream 108 may be added to slurry hydroconversion reactor 102 independently, but concurrently, with renewable feedstock 101, and / or optional renewable liquid carrier 104 and / or slurry hydroconversion catalyst 106. Likewise, slurry hydroconversion catalyst 106 may be added to slurry hydroconversion reactor 102 independently, but concurrently, with renewable feedstock 101, and / or optional renewable liquid carrier 104 and / or hydrogen stream 108. Alternatively, slurry hydroconversion catalyst 106 may be mixed with renewable feedstock 101, optional renewable liquid carrier 104 and hydrogen stream 108 upstream of the feed inlet to slurry hydroconversion reactor 102.

[0058] In some embodiments, suitable slurry hydroconversion reactors for slurry hydroconversion reactor 102 include, for example, continuous stirred tank reactors, fluidized bed reactors, spouted bed reactors, spray reactors, bubble column reactors, liquid recirculation reactors, slurry recirculation reactors, and combinations thereof. Slurry hydroconversion reactor 102 may be a single-stage or multi-stage and may be comprised of a single reactor or multiple reactors. In some embodiments, slurry hydroconversion reactor 102 may be utilized in parallel or in series. In one embodiment, slurry hydroconversion reactor 102 is an up-flow reactor. In another embodiment, slurry hydroconversion reactor 102 is a down-flow reactor.

[0059] In some embodiments, slurry hydroconversion reactor 102 is configured for sufficient backmixing of renewable feedstock 101, optional renewable liquid carrier 104, slurry hydroconversion catalyst 106 and hydrogen stream 108. In non-limiting illustrative embodiments, backmixing is provided by, for example, mechanical mixers such as top-mounted, side-mounted, or bottom-mounted agitators; for rapid movement of renewable feedstock 101, optional renewable liquid carrier 104, slurry hydroconversion catalyst 106 and hydrogen stream 108 pumped into or through slurry hydroconversion reactor 102; and / or introducing or generating gases or vapors such as gas bubbles from one or more gas spargers in slurry hydroconversion reactor 102.

[0060] The feeds to slurry hydroconversion reactor 102 generally comprise at least about 10 wt. %, or about 20 wt. %, or about 30 wt. %, or about 40 wt. %, or about 50 wt. %, or about 60 wt. % and up to about 99 wt. % renewable feedstock 101, about 0 to about 90 wt. % optional renewable liquid carrier 104 and from about 0.5 wt. % and up to about 5 wt.%, slurry hydroconversion catalyst 106 or a precursor thereof. In some embodiments, slurry hydroconversion catalyst 106 is present in an amount of from 0.005% to 3% on a metal basis. One or more liquidT-12558-WO01 (538-370 PCT)hydrocarbon products and / or slurry hydroconversion catalyst may also be recycled to slurry hydroconversion reactor 102.

[0061] Renewable Feedstock

[0062] The process is capable of processing a wide range of renewable feedstocks. In some embodiments, renewable feedstock 101 is a renewable liquid feedstock. In some embodiments, the renewable liquid feedstock can be any type of biologically derived liquid feedstock that can be usefully processed in slurry hydroconversion reactor 102. Examples of such biologically derived liquid feedstocks include lipids (e.g., fats, oils, grease), tall oil products (e.g., crude tall oil, tall oil fatty acid, distilled tall oil, rosin acid, tall oil pitch), pyrolysis oils from biomass, hydrothermal liquefication oils from biomass, biodiesel, hydroprocessed esters and fatty acids (HEFA), bio-alcohols (e.g., bio-ethanol, bio-isobutanol, bio-glycerol).

[0063] In some embodiments, renewable feedstock 101 is a solid biomass feedstock. Suitable solid biomass feedstocks for renewable feedstock 101 include, for example, (1) agricultural residues, such as corn stalks, straw, seed hulls, sugarcane leavings, bagasse, nutshells, and manure from cattle, poultry, and hogs; (2) wood materials, such as wood or bark, sawdust, timber slash, and mill scrap; (3) municipal waste, such as waste paper and yard clippings; (4) algae-derived biomass, including carbohydrates and lipids from microalgae (e.g., Botryococcus braunii, Chlorella, Dunaliella tertiolecta Gracilaria Pleurochyrsis carterae, and Sargassum) and macroalgae (e.g., seaweed); and (5) energy crops, such as poplars, willows, switch grass, miscanthus, sorghum, alfalfa, prairie bluestream, corn, soybean, and the like.

[0064] In some embodiments, renewable feedstock 101 may comprise a solid biomass component selected from wood or wood mill byproduct, tree leaves, grass, algae, crop byproduct, municipal solid waste, or a combination thereof, optionally, wherein the solid biomass component is ground, pulverized, chipped or in a particulate, pellet, powder, shaving, chip, dust, or pulverized form, or a combination thereof.

[0065] In some embodiments, renewable feedstock 101 is provided as a raw solid biomass feedstock containing biomass components that have not been chemically processed or modified prior to being directly fed to slurry hydroconversion reactor 102.

[0066] In some embodiments, renewable feedstock 101 includes a solid biomass feedstock containing lignocellulosic material. Lignocellulosic material includes three main components,T-12558-WO01 (538-370 PCT)namely, cellulose, hemicellulose and lignin. In some embodiments, cellulose is the primary structural component of lignocellulose and provides rigidity and forms the framework of plant cell walls. Cellulose can consist of a beta (l-4)-linked chain of glucose molecules. Hydrogen bonds between different layers of cellulose contribute to its resistance to degradation. In some embodiments, hemicellulose is usually the second most abundant component in lignocellulose and contributes to the overall structure and flexibility of the plant cell wall. Hemicelluloses are polysaccharides made up of various sugars. For example, hemicellulose can be composed of various 5- and 6-carbon sugars, including arabinose, galactose, glucose, mannose and xylose. In some embodiments, lignin is the most complex constituent and provides additional strength, protection, and resistance to decay. Lignin is a polymer structure of three major phenolic components, including p-coumaryl alcohol (H), coniferyl alcohol (G) and sinapyl alcohol (S).

[0067] Lignocellulosic material may include a mixture of lignin, cellulose and hemicelluloses in any proportion. Such material can be more difficult to convert into fungible liquid hydrocarbon products than cellulosic and hemicellulosic material. Suitable lignocellulosecontaining biomass includes woody biomass and agricultural and forestry products and residues (e.g., whole harvest energy crops, round wood, forest slash, bamboo, sawdust, bagasse, sugarcane tops and trash, cotton stalks, com stover, com cobs, castor stalks, Jatropha whole harvest, Jatropha trimmings, de-oiled cakes of palm, castor and Jatropha, coconut shells, residues derived from edible nut production and mixtures thereof), and municipal solid wastes containing lignocellulosic material. The municipal solid waste may include, for example, any combination of lignocellulosic material (yard trimmings, pressure- treated wood such as fence posts, plywood), discarded paper and cardboard and waste plastics, along with refractories such as glass, and metal.

[0068] In some embodiments, a solid form of the solid biomass feedstock for renewable feedstock 101 includes, for example, particles, pellets, shavings, fibers, needles and / or other geometries. The solid form does not necessarily have to have a homogeneous configuration. Instead, the configuration may be regular or irregular. For example, in the case of the solid form comprising particles, the particles can be, for example, virtually spherical particles, and likewise particles having an irregular and / or angular outward shape. In addition, the surface of the particles may be smooth, but it is also possible that the surface of the material is rough and / or has unevenness and / or depressions and / or elevations. In an illustrative embodiment, a solid form canT-12558-WO01 (538-370 PCT)contain particles of the solid biomass feedstock having a particle size of about 1 millimeter (mm) to about 3.5 mm.

[0069] The solid biomass material may be washed, dried, roasted, torrefied and / or reduced in particle size before it is used as a feedstock in slurry hydroconversion reactor 102.

[0070] Transfer of renewable feedstock 101 to slurry hydroconversion reactor 102 may be through a variety of single or combined means, including, e g., the use of a pressure transfer vessel, extruders, a rotatory valve, or a lock hopper. Raw biomass materials can be crushed or otherwise treated to any desired size or size range, e.g., in the range of about 50 microns to about 10 mm, or into wood chips up to about 3 cm in length, and the like. The raw biomass may be dried or in an undried condition.

[0071] In some embodiments, renewable feedstock 101 will include the renewable liquid feedstock as the only feedstock to slurry hydroconversion reactor 102. In some embodiments, renewable feedstock 101 will include the solid biomass feedstock as the only feedstock to slurry hydroconversion reactor 102.

[0072] In some embodiments, when renewable feedstock 101 is a solid biomass feedstock, it can be dispersed in optional renewable liquid carrier 104 to make a slurry which can be fed to a slurry hydroconversion zone in slurry hydroconversion reactor 102. Optional renewable liquid carrier 104 can be any type of the biologically derived liquid feedstocks discussed above that can be usefully processed in slurry hydroconversion reactor 102. Optional renewable liquid carrier 104 may be or include a recycled feedstock from the slurry hydroconversion process. Examples of recycled feedstocks include heavy and / or partially converted liquid fractions from the slurry hydroconversion process. Optional renewable liquid carrier 104 may further comprise water. In some embodiments, optional renewable liquid carrier 104 may be a slurry stream 116 recycled back to slurry hydroconversion reactor 102 as discussed below. In some embodiments, optional renewable liquid carrier 104 may be the renewable liquid phase of slurry stream 116 following removing the solid from slurry stream 116 by, for example, filtration, centrifuge, setting, electrostatic separation, magnetic separation, etc. as discussed below.

[0073] In some embodiment, when renewable feedstock 101 is a solid biomass feedstock then renewable feedstock 101 and optional renewable liquid carrier 104 in slurry hydroconversionT-12558-WO01 (538-370 PCT)reactor 102 can include, for example, from about 6 wt. % to about 50 wt. % of the solid biomass feedstock and from about 50 wt. % to about 94 wt. % of optional renewable liquid carrier 104.

[0074] Slurry Hydroconversion Catalyst

[0075] In some embodiments, the hydroconversion process uses a dispersed catalyst which is continuously doped into the feed. In some embodiments, slurry hydroconversion catalyst 106 can correspond to one or more catalytically active metals in particulate form and may be a supported catalyst, an unsupported catalyst, or a combination thereof. Catalytically active metals for use in the hydrotreating process can include those from Groups 4-12 of the IUPAC Periodic Table of Elements. Suitable metals include, for example, iron, nickel, molybdenum, zinc, vanadium, tungsten, cobalt, ruthenium, and any combination thereof. The catalytically active metal may be present as a solid particulate in elemental form or as an organic compound or an inorganic compound such as a sulfide or other ionic compound. Metal or metal compound nanoaggregates may also be used to form the solid particulates.

[0076] A catalyst in the form of a solid particulate is generally a compound of a catalytically active metal, or a metal sulfide, either alone or supported on a refractory material such as an inorganic metal oxide (e.g., alumina, silica, titania, zirconia, and any combination thereof). Other suitable refractory materials can include carbon, coal, and clays. Zeolites and non-zeolitic molecular sieves are also useful as solid supports. Generally, supported catalyst can have from about 0.01 wt. % to about 30 wt. % of the catalytic active metal based on the total weight of the catalyst.

[0077] In some embodiments, it can be desirable to form slurry hydroconversion catalyst 106 for the hydroconversion process in situ, such as forming a catalyst from a metal sulfate (e.g., iron sulfate monohydrate) catalyst precursor or another type of catalyst precursor that decomposes or reacts in the hydroconversion reaction zone environment, or in a pretreatment step, to form a desired, well -dispersed and catalytically active solid particulate (e.g., as iron sulfide). Precursors also include oil-soluble organometallic compounds containing the catalytically active metal of interest that thermally decompose to form the solid particulate (e.g., iron sulfide) having catalytic activity. Other suitable precursors include metal oxides that may be converted to catalytically active (or more catalytically active) compounds such as metal sulfides. In a particular embodiment, a metal oxide containing mineral may be used as a precursor of a solid particulateT-12558-WO01 (538-370 PCT)comprising the catalytically active metal (e.g., iron sulfide) on an inorganic refractory metal oxide support (e.g., alumina).

[0078] In some embodiments, slurry hydroconversion catalyst 106 includes sulfided catalytically active metals. Examples of suitable catalytically active metals include, without limitation, sulfided nickel, sulfided cobalt, sulfided molybdenum, sulfided tungsten, sulfided CoMo, sulfided NiMo, sulfided MoW, sulfided NiW, and combinations thereof.

[0079] A catalyst bed / zone may have a mixture of two types of catalysts and / or successive beds / zones, including stacked beds, and may have the same or different catalysts and / or catalyst mixtures. In case of such sulfided hydrotreating catalyst, a sulfur source will typically be supplied to the catalyst to keep the catalyst in sulfided form during the hydroconversion process.

[0080] Slurry hydroconversion catalyst 106 used in conjunction with the processes described herein may have an average particle size of up to about 300 microns. In some embodiments, slurry hydroconversion catalyst 106 used in conjunction with the processes described herein may have an average particle size of about 100 microns or less, or about 10 microns or less. The particle size is the length of the largest orthogonal axis through the particle. Average particle size is the average particle diameter of all the catalyst particles fed to the reactor which may be determined by a representative sampling.

[0081] Hydrogen Stream

[0082] Hydrogen stream 108 includes hydrogen, which is contained in a hydrogen “treat gas,” for injecting into slurry hydroconversion reactor 102. The treat gas can be either pure hydrogen or a hydrogen-containing gas, which is a gas stream containing hydrogen in an amount that is sufficient for the intended reaction(s), optionally including one or more other gases (e.g., nitrogen and carbon monoxide). The treat gas stream introduced into a reaction stage can contain at least about 50 vol. % or at least about 75 vol. % hydrogen and up to 100 vol. %. Optionally, the hydrogen treat gas can be substantially free (less than about 1 vol. %) of impurities such as H2S and NH3 and / or such impurities can be substantially removed from a treat gas prior to use. Hydrogen can be supplied co-currently with the input feed to slurry hydroconversion reactor 102 or separately via a separate gas conduit.

[0083] Slurry Hydroconversion ProcessT-12558-WO01 (538-370 PCT)

[0084] The slurry hydroconversion process generally involves passing renewable feedstock 101 and optional renewable liquid carrier 104 through a slurry hydroconversion reaction zone in the presence of slurry hydroconversion catalyst 106 and hydrogen stream 108 under slurry hydroconversion conditions to provide a slurry hydroconversion effluent 110 including a gas phase and a slurry phase.

[0085] The conversion of renewable feedstock 101 in slurry hydroconversion reactor 102 can depend on a variety of factors, including feedstock composition, temperature and pressure, reactor space velocity, hydrogen partial pressure and catalyst type and performance. In some embodiments, slurry hydroconversion reactor 102 hydroconverts at least about 50%, or at least about 70%, or at least about 80% or at least about 90% or at least about 95%, or at least about 99.5%, and up to 100% of renewable feedstock 101 to slurry hydroconversion effluent 110.

[0086] The slurry hydroconversion process can be operated under slurry hydroconversion conditions including, for example, a pressure in a range of from about 300 psig to about 2500 psig, a reactor temperature in a range from about 500°F to about 950°F, an average residence time of about 10 minutes to about 5 hours, and a space velocity of about 0.1 to 5.0 h or 0.5 to 5.0 h ', or 0.5 to 2.0 h '. The amount of the hydrogen stream fed to the reactor for slurry hydroconverting can be up to about 2000 scf / B, or up to about 15000 scf / B fresh feed or from about 3,000 SCF / bbl to about 10,000 SCF / bbl fresh feed.

[0087] Hydroconverting includes, for example, hydrocracking, hydrotreating, hydrogenation, deoxygenation, desulfurization, denitrogenation, demetallization, dechlorination, decarboxylation, decarbonylation, dearomatization or a combination thereof. The hydroconversion reaction in the slurry hydroconversion zone results in the formation of slurry hydroconversion effluent 110. Slurry hydroconversion effluent 110 is in the form of a gas-liquid-solid mixture. For example, slurry hydroconversion effluent 110 includes a gas phase and a slurry phase comprising catalyst particles / or uniquified solid feeds and a liquid product.

[0088] In some embodiments, the gas phase can include organic compounds and a hydroconversion product. In non-limiting illustrative embodiments, the organic compounds include, for example, oxygen-free organic compounds, oxygen-containing organic compounds, and the like. In some embodiment, the oxygen-free organic compounds include, for example, Ci to C40 hydrocarbons. In some embodiment, the oxygen-containing organic compounds canT-12558-WO01 (538-370 PCT)include, for example, organic acids such as aliphatic acids and aromatic acids, aldehydes, aliphatic / cyclic ketones, aliphatic / aromatic alcohols, diols, esters, ethers, furans, phenolic compound, or combinations thereof. Representative examples of such oxygen-containing organic compounds include acetone, 2-butanone, 2-pentanone, 2-heptadecanone, cyclopentanone, heptanoic acid, butanoic, methyl ester, ethyl acetate, 2-cyclopentenol, 1 -butanol, benzoic acid, 2-methyl furan, 2,5-dimethyl furan and combinations thereof.

[0089] In some embodiments, the gas phase can contain an oxygen content of from at least about 3 wt. %, and from about 3 wt. % to about 20 wt. %, based on the total amount of the organic compounds in the gas phase.

[0090] In some embodiments, the gas phase further includes hydrogen, carbon monoxide, carbon dioxide, steam, H2S, and NH3, in various concentrations.

[0091] In some embodiments, the liquid product of the slurry phase can be composed of, for example, unconverted renewable feedstock, partially converted renewable feedstock, unvaporized hydroconversion product, etc.

[0092] Separation Unit

[0093] System 100 further includes separation unit 112 for receiving slurry hydroconversion effluent 110. Separation unit 112 can include one or more separators as well as one or more heat exchangers. The terms “separation unit” and “separator” refer to any separation device(s) that at least partially separates one or more chemical constituents in different physical phases in a mixture from one another. For example, a separation system may selectively separate different chemical constituents from one another, forming one or more chemical fractions. Suitable separation systems include, for example, a slurry-vapor two phase separation device. In some embodiments, separation unit 112 separates the gas phase from the slurry phase in slurry hydroconversion effluent 110, thereby producing a gas stream 114 and slurry stream 116.

[0094] In some embodiments, separation unit 112 can include a first separator downstream of slurry hydroconversion reactor 102 for separating the gas phase from the slurry phase in slurry hydroconversion effluent 110. The separation of the gas phase from the slurry phase can be based upon, for example, slurry -vapor two phase separation. In a non-limiting illustrative embodiment, the first separator can be a high temperature high pressure separator where slurry hydroconversion effluent 110 is separated into gas stream 114 and slurry stream 116.T-12558-WO01 (538-370 PCT)

[0095] Separation unit 112 such as the high temperature high pressure separator will operate in the same pressure loop as in slurry hydroconversion reactor 102, i.e., at a pressure of from about 300 psig to about 2500 psig. As one skilled in the art will appreciate, the use of the same pressure loop shall be understood to mean that there is no pressure reduction or control device between slurry hydroconversion reactor 102 and separation unit 112 and gas phase upgrading reactor 118. Any pressure drop from slurry hydroconversion reactor 102 to separation unit 112 is only from the pressure drop to drive the flow of slurry hydroconversion effluent 110. Thus, the pressure in separation unit 112 such as the high temperature high pressure separator is relatively the same as in slurry hydroconversion reactor 102, with a slight pressure drop to drive the process flow from slurry hydroconversion reactor 102 to separation unit 112. For example, separation unit 112 such as the high temperature high pressure separator can operate at a pressure difference of less than about 20%, or less than about 15%, or less than about 10%, or less than about 5%, or less than about 1%, of the pressure in the pressure loop of slurry hydroconversion reactor 102. However, it is to be understood that the lower limit of the pressure in separation unit 112 will be about 300 psig. In some embodiments, the high temperature high pressure separator can operate at a temperature in the range of about 500°F to about 780°F.

[0096] Following separation of the gas phase from the slurry phase, slurry stream 116 can be sent to one or more solid-liquid separation devices such as fdtration and centrifuge devices (not shown) to separate the catalyst particles from the liquid product. Suitable filtration processes generally include, for example, using a mesh, screen, cross-flow filtration, backwash filtration, pressure filtration or a combination thereof. The separated liquid product can be recycled back to slurry hydroconversion reactor 102 while the spent catalyst particles can be collected. In some embodiments, slurry stream 116 can be recycled back to slurry hydroconversion reactor 102.

[0097] In some embodiments, gas stream 114 will exit the high temperature high pressure separator at a first temperature, e g., a temperature of about 500°F to about 780°F and sent to one or more heat exchangers. Suitable heat exchangers include, for example, a shell-and-tube, plate-fin, microchannel, spiral wound, or any other suitable heat exchanger. In some embodiments, when slurry hydroconversion reactor 102 and the high temperature high pressure separator operate at a lower temperature than gas phase upgrading reactor 118, it will be necessary to increase the temperature of gas stream 114. Accordingly, gas stream 114 can be sent to one or more heatT-12558-WO01 (538-370 PCT)exchangers to transfer heat to the gas stream to produce a heated gas stream having a temperature sufficient to enter gas phase upgrading reactor 118.

[0098] In some embodiments, the one or more heat exchangers can remove heat from gas stream 114 having a first temperature, thereby producing a mixture comprising a cooled gas phase and a liquid phase, the mixture having a second temperature less than the first temperature. For example, in some embodiments, gas stream 114 will enter the one or more heat exchangers and be condensed thereby forming a mixture comprising the cooled gas phase and the liquid phase including heavy components such as hydrocarbon components having boiling points of greater than about 680°F. In some embodiments, the liquid phase includes heavy components such as hydrocarbon components having boiling points of greater than about 750°F. In some embodiments, the liquid phase includes heavy components such as hydrocarbon components having boiling points of greater than about 800°F. In some embodiments, the liquid phase includes heavy components such as hydrocarbon components having a 95% boiling point of greater than about 680°F. In some embodiments, the liquid phase includes heavy components such as hydrocarbon components having a 95% boiling point of greater than about 750°F. In some embodiments, the liquid phase includes heavy components such as hydrocarbon components having a 95% boiling point of greater than about 800°F.

[0099] In some embodiments, separation unit 112 can further include a second separator downstream of the first separator and the heat exchanger for receiving the mixture and separating the liquid phase from the cooled gas phase. In a non-limiting illustrative embodiment, the second separator can be a medium temperature high pressure separator for separating the liquid phase from the cooled gas phase, thereby producing a liquid stream and a liquid free gas stream. In some embodiments, the medium temperature high pressure separator can operate at a temperature of at least about 50°F less than the temperature of the high temperature high pressure separator. In some embodiments, the medium temperature high pressure separator can operate at a temperature in the range of about 300°F to about 700°F. In some embodiments, the medium temperature high pressure separator can operate at a pressure in the same pressure loop as slurry hydroconversion reactor 102 as discussed above.

[0100] In some embodiments, the liquid free gas stream can exit the medium temperature high pressure separator and passed to another heat exchanger prior to the processing the liquid freeT-12558-WO01 (538-370 PCT)gas stream in gas phase upgrading reactor 118. In some embodiments, the liquid free gas stream exits the medium temperature high pressure separator and is passed to gas phase upgrading reactor 118 as gas stream 114.

[0101] Gas Phase Upgrading Reactor

[0102] System 100 further includes gas phase upgrading reactor 118 for receiving gas stream 114 from separation unit 112 and an optional hydrogen stream 120 for carrying out one or more upgrading processes in the presence of a gas phase upgrading catalyst. In gas phase upgrading reactor 118, gas stream 114 is received from separation unit 112 and upgraded in the presence of a gas phase upgrading catalyst, and optionally hydrogen, to reduce the oxygen content of the total content of the organic compounds in gas stream 114 thereby producing a gas stream 122 having a reduced oxygen content based on the total content of the organic compounds in gas stream 122 relative to the oxygen content based on the total content of the organic compounds in gas stream 114. For example, the oxygen content based on the total content of the organic compounds in gas stream 122 can be reduced by at least 90%, or at least 95%, or at least about 99% relative to the oxygen content based on the total content of the organic compounds in gas stream 114. In some embodiments, gas phase upgrading reactor 118 contains the gas phase upgrading catalyst active for upgrading, and this catalyst catalyzes conversion of the oxygen present in the organic compounds of gas stream 114 to, for example, water, CO and CO2, as well as other reactions such as, for example, saturation of olefins to paraffins, conversion of nitrogen to ammonia and conversion of sulfur to hydrogen sulfide.

[0103] In some embodiments, the gas phase upgrading processes can be carried out in a fixed-bed reactor. In some embodiments, gas phase upgrading reactor 118 may be a single-stage or multi-stage and may be comprised of a single reactor or multiple reactors. In some embodiments, gas phase upgrading reactor 118 includes two or more gas phase upgrading reactors utilized in parallel or in series.

[0104] In some embodiments, the gas phase upgrading catalyst can be any base metal catalyst or noble metal catalyst that is used in typical upgrading processes. In some embodiments, the gas phase upgrading catalyst can be any base metal catalyst or noble metal catalyst in which the active sites are metal sulfides. For example, catalytically active metals for use in the upgrading processes can include those from Groups 4 to 12 of the IUPAC Periodic Table of Elements.T-12558-WO01 (538-370 PCT)

[0105] In some embodiment, the upgrading catalysts used for upgrading can include conventional upgrading catalysts, such as those that comprise at least one Group 8-10 non-noble metal, such as Fe, Co, and / or Ni, such as Co and / or Ni; and / or at least one Group 6 metal, such as Mo and / or W. Such upgrading catalysts optionally include transition metal sulfides that are impregnated or dispersed on a refractory support or carrier.

[0106] The inorganic oxide support is prepared by any of the suitable methods known to those skilled in the art for preparing shaped porous catalyst supports used to carry catalytically active metals. The inorganic oxide support or shaped inorganic oxide support comprises a porous refractory oxide or inorganic oxide component such as alumina (AI2O3), silica (SiCh), titania (TiCh), zirconia (ZrO2), and physical mixtures or chemical combinations thereof. In some embodiments, an inorganic oxide for the shaped inorganic oxide support of the catalyst is includes low acidic oxides such as silica, alumina, silica-alumina, silica-titania, and titania-alumina. Suitable aluminas include porous aluminas such as gamma or eta having average pore sizes from 50 A to 200 A, or 75 A to 150 A; a surface area from 100 m2 / g to 300 m2 / g, or 150 m2 / g to 250 m2 / g; and a pore volume of from 0.25 cm3 / g to 1.0 cm3 / g, or 0.35 cm3 / g to 0.8 cm3 / g. The supports are preferably not promoted with a halogen such as fluorine as this generally increases the acidity of the support.

[0107] In some embodiments, the upgrading catalyst can be a bulk metal catalyst, or a combination of stacked beds of supported and bulk metal catalyst. By “bulk metal”, it is meant that the catalysts are unsupported wherein the bulk catalyst comprise of at least one Group 8-10 non-noble metal and / or at least one Group 6 metal.

[0108] In some embodiments, a noble metal catalyst can include those from Groups 8-10 of the IUPAC Periodic Table of Elements including, for example, palladium, platinum and iridium.

[0109] In some embodiments, the gas phase upgrading catalyst includes sulfided catalytically active metals. Examples of suitable catalytically active metals include, without limitation, sulfided nickel, sulfided cobalt, sulfided molybdenum, sulfided tungsten, sulfided C0M0, sulfided NiMo, sulfided MoW, sulfided NiW, and combinations thereof.

[0110] In some embodiments, the gas phase upgrading catalyst can include (a) an inorganic oxide support, and (b) a bimetallic component. The bimetallic component can include any of the metals discussed above. For example, the bimetallic component can include at least one Group 8-T-12558-WO01 (538-370 PCT)10 non-noble metal, such as Fe, Co, and / or Ni and at least one Group 6 metal, such as Mo and / or W. These metals or mixtures of metals are typically present as oxides or sulfides on the inorganic oxide supports. In some embodiments, the at least one Group 8-10 non-noble metal, in oxide form, can be present in an amount ranging from about 2 wt. % to about 40 wt. % (e.g., about 4 wt. % to about 15 wt. %). The at least one Group 6 metal, in oxide form, can typically be present in an amount ranging from about 2 wt. % to about 70 wt. % (e g., about 6 wt. % to about 40 wt. %, or about 10 wt. % to about 30 wt. %). These weight percents are based on the total weight of the catalyst. Suitable metal catalysts include cobalt / molybdenum (about 1 to about 10 wt. % Co as oxide, about 10 to about 40 wt. % Mo as oxide), nickel / molybdenum (about 1 to about 10 wt. % Ni as oxide, about 3 to about 40 wt. % Mo as oxide), or nickel / tungsten (about 1 to about 10 wt. % Ni as oxide, about 10 to about 40 wt. % W as oxide) on an inorganic oxide support such as alumina, silica, silica-alumina, or titania.

[0111] A gas phase upgrading catalyst composed of (a) an inorganic oxide support, and (b) a catalytically active metal such as a bimetallic component can be prepared by methods known in the art. For example, for a gas phase upgrading catalyst composed of nickel and molybdenum as the active metals, supported on a porous alumina base, the gas phase upgrading catalyst can be prepared by impregnating the alumina support with solutions of nickel and molybdenum metal salts, followed by drying and calcination. The gas phase upgrading catalyst can then be sulfided in situ before use, to form the active sulfide phases of nickel and molybdenum.

[0112] In some embodiments, a sulfiding agent such as, for example, H2S and dimethyl disulfide, can be added to gas phase upgrading reactor 118 to maintain the catalyst activity during the upgrading process.

[0113] In some embodiments, the upgrading reaction is operated at conditions sufficient to produce gas stream 122 having a reduced content of oxygen based on the total content of the organic compounds in gas stream 122 relative to the oxygen content based on the total content of the organic compounds in gas stream 114. Gas phase upgrading reactor 118 will operate in the same pressure loop as in slurry hydroconversion reactor 102, i.e., at a pressure of from about 300 psig to about 2500 psig. As one skilled in the art will appreciate, any pressure drop from slurry hydroconversion reactor 102 to separation unit 112 to gas phase upgrading reactor 118 is only from the pressure drop to drive the flow of gas stream 114. Thus, the pressure in gas phaseT-12558-WO01 (538-370 PCT)upgrading reactor 118 is relatively the same as in slurry hydroconversion reactor 102, with a slight pressure drop to drive the process flow from separation unit 112 to gas phase upgrading reactor 118. For example, gas phase upgrading reactor 118 can operate at a pressure difference of less than about 20%, or less than about 15%, or less than about 10%, or less than about 5%, or less than about 1%, of the pressure in the pressure loop of slurry hydroconversion reactor 102. However, it is to be understood that the lower limit of the pressure in gas phase upgrading reactor 118 will be about 300 psig.

[0114] The operating temperature may vary depending on the type and activity of the catalyst and the desired degree of hydrodeoxygenation. In some embodiments, a reactor temperature can range from about 500°F to about 800°F. In some embodiments, the upgrading conditions can further include a weight hourly space velocity (WHSV) of from about 0.2 h-1to about 5 h'1. In some embodiments, gas phase upgrading reactor 118 can be operated at temperatures below typical hydrotreating conditions (i.e., temperatures of at least about 530°F). In some embodiments, gas stream 114 can contain at least about 50% of hydrogen, or at least 60% of hydrogen, or at least 70% of hydrogen.

[0115] If needed, additional hydrogen may be provided to the upgrading reaction via optional hydrogen stream 120. Optional hydrogen stream 120 includes hydrogen, as discussed above for hydrogen stream 108. The upgrading process generally involves passing gas stream 114, through one or more upgrading reaction zones and fixed catalyst beds in the presence of a gas phase upgrading catalyst under upgrading conditions to provide gas stream 122. In some embodiments, optional hydrogen stream 120 may be mixed with gas stream 114 upstream of the feed inlet to gas phase upgrading reactor 118. Alternatively, optional hydrogen stream 120 may be added to gas phase upgrading reactor 118 independently, but concurrently, with gas stream 114. Alternatively, optional hydrogen stream 120 may be added to gas phase upgrading reactor 118 independently, such as between fixed catalyst beds.

[0116] In some embodiments, the upgrading process in gas phase upgrading reactor 118 further includes a water gas shift reaction, which involves the reaction of carbon monoxide (CO) present in gas stream 114 with steam in the presence of a gas phase upgrading catalyst to form carbon dioxide (CO2) and hydrogen (H2).T-12558-WO01 (538-370 PCT)

[0117] In some embodiments, the upgrading process in gas phase upgrading reactor 118 further includes a methanation reaction, which involves the reaction of carbon monoxide present in gas stream 114 with hydrogen in the presence of gas phase upgrading catalyst to form methane (CH4) and water (H2O).

[0118] In some embodiments, at least about 20% of the carbon monoxide in gas stream 114 is converted via the water gas shift reaction or the methanation reaction. In some embodiments, at least about 30% of the carbon monoxide in gas stream 114 is converted via the water gas shift reaction or the methanation reaction. In some embodiments, at least about 40% of the carbon monoxide in gas stream 114 is converted via the water gas shift reaction or the methanation reaction. In some embodiments, at least about 50% of the carbon monoxide in gas stream 114 is converted via the water gas shift reaction or the methanation reaction.

[0119] Following completion of the upgrading process, gas stream 122 can be sent for further processing. In some embodiments, gas stream 122 will exit gas phase upgrading reactor 118 and sent to one or more separation units for separating gas stream 122 into three distinct streams represented by a gas stream, a water stream and one or more oil streams.

[0120] In some embodiments, the gas stream can include, for example, hydrogen and Ci to C4 light gases. When passing the cooled product effluent through the three-phase separator, the water stream and the one or more oil streams can undergo a phase separation in about 10 seconds or less.

[0121] The water stream obtained from the phase separation will be a water stream having a reduced chemical oxygen demand (COD). For example, in some embodiments, the COD of the water stream can be less than about 5000 mg / L. In some embodiments, the COD of the water stream can be less than about 4000 mg / L. In some embodiments, the chemical oxygen demand (COD) of the water stream can be less than about 2000 mg / L. In some embodiments, the COD of the water stream can be less than about 1000 mg / L. In some embodiments, the COD of the water stream can be less than about 750 mg / L. In some embodiments, the COD of the water stream can be less than about 500 mg / L. In some embodiments, the COD of the water stream can be less than about 250 mg / L.

[0122] In some embodiments, the COD of the water stream obtained from the phase separation can be reduced by at least 95% relative to the COD of a water phase from a liquidT-12558-WO01 (538-370 PCT)product of gas stream 114. In some embodiments, the COD of the water stream obtained from the phase separation can be reduced by at least 99% relative to the COD of a water phase from a liquid product of gas stream 114.

[0123] In some embodiments, the one or more oil streams can be sent to a hydrotreater for further upgrading. For example, the one or more oil streams can be sent for further processing to produce, for example, products such as kerosene, diesel and naphtha components.

[0124] The non-limiting illustrative embodiments described herein will now be illustrated by the following examples, which are not intended to limit the invention.Example 1

[0125] Feed to Gas Phase Upgrading Reactor.

[0126] The gas phase feed to a gas phase upgrading reactor was derived from a slurry hydroconversion reaction of a solid biomass of lignocellulose in a slurry hydroconverion reactor. To show the gas phase feed composition and characteristics, the gas phase feed was cooled down to room temperature and separated into a gas phase and a liquid portion composed of a water phase and an oil phase. The properties of each phase prior to being sent to the gas phase upgrading reactor are listed below. The oxygen content in the total organic compounds of the gas phase feed (i.e., from the gas and liquid portion) was about 9.1 wt. %. The gas phase composition was determined by gas chromatography with a thermal conductivity detector (TCD) and flame-ionization detector (FID)T-12558-WO01 (538-370 PCT)Gas phase

[0127] A small concentration of oxygenates were also found in the gas phase as measured by gas chromatography (GC) and mass spectrometry (MS) (GC-MS). The top ten oxygenates in concentration are listed below.Oxygenates

[0128] The liquid portion is listed below. There was more water than oil in the liquid portion and the water phase contained a high level of organic compounds as indicated by 7% carbon, and the oil phase contained a high level of oxygenates as indicated by 10% oxygen. TheT-12558-WO01 (538-370 PCT)carbon and hydrogen were measured by ASTM D5373 Combustion Analysis with Thermal Conductivity Detection. The oxygen content was calculated by mass balance.Liquid PortionExample 2

[0129] Processing the Gas Phase Feed in a Gas Phase Upgrading Reactor.

[0130] The gas phase feed of Example 1 was passed through a gas phase upgrading reactor. The gas phase upgrading reactor was operated at 550°F and at a pressure of 1300 psig. The gas phase upgrading catalyst used in the gas phase upgrading reactor was commercially available and obtained from ART (Advanced Refining Technology), ICR catalyst family. The upgrading catalyst was a base metal catalyst on an alumina support.

[0131] The gas analysis by gas chromatography with a thermal conductivity detector (TCD) and flame-ionization detector (FID) for alkenes and GC-MS for oxygenates showed that all alkenes and oxygenates in the gas phase feed had been fully removed as their related concentration dropped below the detection limit.Example 3

[0132] Water Quality without and with Upgrading.

[0133] The water phase from a liquid product of a gas phase feed derived from a slurry hydroconversion reaction of a solid biomass of lignocellulose in a slurry hydroconverion reactor was analyzed without upgrading and with upgrading at 572°F and a pressure of 1300 psig using the catalyst of Example 2. The COD (chemical oxygen demand) was measured by Flach Method 8000 and showed a reduction of about 99.5% by using the upgrading. In addition, the carbon content in the upgraded water dropped below the detection of ASTM D5373, i.e., 1 wt. %.T-12558-WO01 (538-370 PCT)<Example 4

[0134] Improvement of Oil-Water Separation.

[0135] The liquid product of Example 1 was then shaken vigorously in a vessel to mix the water and the oil product into a well-mixed mixture to observe the phase separation between the water phase and the oil phase.

[0136] Without Upgrading

[0137] It was observed that at least 6 hours was required to achieve a clear interface between the water phase and the oil phase of the liquid product of Example 1 without upgrading, resulting in an oil-water separation.

[0138] With Upgrading

[0139] It was observed that a clear interface between the water phase and the oil phase of the liquid product of Example 1 with upgrading was achieved within a few seconds, resulting in an oil-water separation.Example 5

[0140] Carbon Monoxide Reduction.

[0141] Carbon monoxide (CO) can be converted to methane in the upgrading reactor through a methanation reaction, similar to those in typical hydrotreaters. In addition, CO is converted to carbon dioxide (CO2) via a water-gas shift reaction. As shown in the table below, the reduction of CO results in an increase in both methane and CO2. Based on the ratio of methane and CO2 increase, approximately 40% of CO conversion occurs through the water-gas shift reaction. This behavior is different from traditional hydrotreating reactors, where hydrogenation is the exclusive reaction.T-12558-WO01 (538-370 PCT)

[0142] According to an aspect of the present disclosure, a process comprises:

[0143] obtaining, from a slurry hydroconversion reactor processing a renewable feedstock, a slurry hydroconversion effluent comprising a gas phase having an oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase, and a slurry phase,

[0144] separating, in a separation unit, the gas phase having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase from the slurry hydroconversion effluent, thereby producing a first gas stream having an oxygen content of at least about 3 wt. %, based on the total content of the organic compounds in the first gas stream, and

[0145] processing, in a gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the first gas stream, in the presence of a gas phase upgrading catalyst and under gas phase upgrading conditions to reduce the oxygen content from the first gas stream, thereby producing a second gas stream having a reduced content of oxygen based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream,

[0146] wherein the separation unit and the gas phase upgrading reactor operate in a same pressure loop as the slurry hydroconversion reactor.

[0147] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the renewable feedstock comprises a renewable liquid feedstock.

[0148] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the renewable liquid feedstock comprises a lipid, a tall oil product, a pyrolysis oil from biomass, a hydrothermal liquefication oil from biomass, a biodiesel, a hydroprocessed ester and fatty acid, a bio-alcohol, or a combination thereof.

[0149] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the renewable feedstock comprises a solid biomass feedstock.T-12558-WO01 (538-370 PCT)

[0150] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the solid biomass feedstock comprises an agricultural residue, a wood material, a municipal waste, an algae-derived biomass, an energy crop, and any combination thereof, optionally, wherein the solid biomass feedstock is ground, pulverized, chipped or in a particulate, pellet, powder, shaving, chip, dust, or pulverized form, or a combination thereof.

[0151] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the solid biomass feedstock comprises a lignocellulosic material.

[0152] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the renewable feedstock further comprises a renewable liquid carrier.

[0153] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the slurry hydroconversion reactor operates at a pressure in a range of about 300 psig to about 2500 psig and a reactor temperature of about 500°F to about 950°F.

[0154] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the process further comprises:

[0155] passing the first gas stream to a heat exchanger prior to the processing the first gas stream in the gas phase upgrading reactor.

[0156] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the first gas stream is obtained by passing the slurry hydroconversion effluent to a first separator to separate the gas phase from the slurry hydroconversion effluent, thereby producing the first gas stream having a first temperature, and the process further comprises:

[0157] passing the first gas stream having the first temperature to a heat exchanger, thereby producing a mixture comprising a cooled gas phase and a liquid phase, the mixture having a second temperature less than the first temperature,

[0158] passing the mixture comprising the cooled gas phase and the liquid phase to a second separator, thereby producing a liquid stream and a liquid free gas stream, and

[0159] passing the liquid free gas stream to the gas phase upgrading reactor.

[0160] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the separation unit and the gas phase upgrading reactor operating in the same pressure loop as the slurry hydroconversion reactor comprises operating the gas phaseT-12558-WO01 (538-370 PCT)upgrading reactor at a pressure difference of about 20% or less than the pressure loop of the slurry hydroconversion reactor, and wherein the gas phase upgrading reactor operates at a pressure not less than about 300 psig.

[0161] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the gas phase upgrading catalyst comprises one or more of a Group 8-10 non-noble metal catalyst, a Group 6 metal and a Group 8-10 noble metal catalyst, optionally on a support.

[0162] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the processing, in the gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on the total content of organic compounds in the first gas stream, in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises adding hydrogen into the gas phase upgrading reactor.

[0163] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the processing, in the gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on the total content of organic compounds in the first gas stream, in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises passing a sulfiding agent into the gas phase upgrading reactor.

[0164] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the first gas stream comprises carbon monoxide, and the processing, in the gas phase upgrading reactor, the first gas stream in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises converting, in the gas phase upgrading reactor, one of (i) the carbon monoxide and steam to carbon dioxide and hydrogen via a water gas shift reaction or (ii) the carbon monoxide and hydrogen to methane and water via a methanation reaction.

[0165] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, at least about 20% of the carbon monoxide in the first gas stream is converted via the water gas shift reaction or the methanation reaction.T-12558-WO01 (538-370 PCT)

[0166] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the second gas stream has a reduced content of oxygen of at least about 90% based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream.

[0167] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, the process further comprises passing the second gas stream to one or more additional separation units, thereby producing a third gas stream, a water stream and one or more oil streams.

[0168] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, a chemical oxygen demand (COD) of the water stream is less than about 5000 mg / L.

[0169] In non-limiting illustrative embodiments, as may be combined with one or more of the preceding paragraphs, a chemical oxygen demand (COD) of the water stream is reduced by at least 95% relative to the COD of a water phase from a liquid product of the first gas stream.

[0170] Various features disclosed herein are, for brevity, described in the context of a single embodiment, but may also be provided separately or in any suitable sub-combination. All combinations of the embodiments are specifically embraced by the illustrative embodiments disclosed herein just as if each and every combination was individually and explicitly disclosed. In addition, all sub-combinations listed in the embodiments describing such variables are also specifically embraced by the present disclosure and are disclosed herein just as if each and every such sub-combination was individually and explicitly disclosed herein.

[0171] While the above description contains many specifics, these specifics should not be construed as limitations of the invention, but merely as exemplifications of preferred embodiments thereof. Those skilled in the art will envision many other embodiments within the scope and spirit of the invention as defined by the claims appended hereto.

Claims

T-12558-WO01 (538-370 PCT)CLAIMS WHAT IS CLAIMED IS:

1. A process, comprising:obtaining, from a slurry hydroconversion reactor processing a renewable feedstock, a slurry hydroconversion effluent comprising a gas phase having an oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase, and a slurry phase;separating, in a separation unit, the gas phase having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the gas phase from the slurry hydroconversion effluent, thereby producing a first gas stream having an oxygen content of at least about 3 wt. %, based on the total content of the organic compounds in the first gas stream; and processing, in a gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on a total content of organic compounds in the first gas stream, in the presence of a gas phase upgrading catalyst and under gas phase upgrading conditions to reduce the oxygen content from the first gas stream, thereby producing a second gas stream having a reduced content of oxygen based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream;wherein the separation unit and the gas phase upgrading reactor operate in a same pressure loop as the slurry hydroconversion reactor.

2. The process according to claim 1, wherein the renewable feedstock comprises a renewable liquid feedstock.

3. The process according to claim 2, wherein the renewable liquid feedstock comprises a lipid, a tall oil product, a pyrolysis oil from biomass, a hydrothermal liquefication oil from biomass, a biodiesel, a hydroprocessed ester and fatty acid, a bio-alcohol, or a combination thereof.

4. The process according to claim 1, wherein the renewable feedstock comprises a solid biomass feedstock.T-12558-WO01 (538-370 PCT)5. The process according to claim 4, wherein the solid biomass feedstock comprises an agricultural residue, a wood material, a municipal waste, an algae-derived biomass, an energy crop, and any combination thereof, optionally, wherein the solid biomass feedstock is ground, pulverized, chipped or in a particulate, pellet, powder, shaving, chip, dust, or pulverized form, or a combination thereof.

6. The process according to claim 4, wherein the solid biomass feedstock comprises a lignocellulosic material.

7. The process according to claim 4, wherein the renewable feedstock further comprises a renewable liquid carrier.

8. The process according to any one of claims 1-7, wherein the slurry hydroconversion reactor operates at a pressure in a range of about 300 psig to about 2500 psig and a reactor temperature of about 500°F to about 950°F.

9. The process according to any one of claims 1-8, further comprising:passing the first gas stream to a heat exchanger prior to the processing the first gas stream in the gas phase upgrading reactor.

10. The process according to any one of claims 1-8, wherein the first gas stream is obtained by passing the slurry hydroconversion effluent to a first separator to separate the gas phase from the slurry hydroconversion effluent, thereby producing the first gas stream having a first temperature; and the process further comprises:passing the first gas stream having the first temperature to a heat exchanger, thereby producing a mixture comprising a cooled gas phase and a liquid phase, the mixture having a second temperature less than the first temperature;passing the mixture comprising the cooled gas phase and the liquid phase to a second separator, thereby producing a liquid stream and a liquid free gas stream; andpassing the liquid free gas stream to the gas phase upgrading reactor.T-12558-WO01 (538-370 PCT)11. The process according to any one of claims 1-10, wherein the separation unit and the gas phase upgrading reactor operating in the same pressure loop as the slurry hydroconversion reactor comprises operating the gas phase upgrading reactor at a pressure difference of about 20% or less than the pressure loop of the slurry hydroconversion reactor, and wherein the gas phase upgrading reactor operates at a pressure not less than about 300 psig.

12. The process according to any one of claims 1-11, wherein the gas phase upgrading catalyst comprises one or more of a Group 8-10 non-noble metal catalyst, a Group 6 metal and a Group 8-10 noble metal catalyst, optionally on a support.

13. The process according to any one of claims 1-12, wherein the processing, in the gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on the total content of organic compounds in the first gas stream, in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises adding hydrogen into the gas phase upgrading reactor.

14. The process according to any one of claims 1-13, wherein the processing, in the gas phase upgrading reactor, the first gas stream having the oxygen content of at least about 3 wt. %, based on the total content of organic compounds in the first gas stream, in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises passing a sulfiding agent into the gas phase upgrading reactor.

15. The process according to any one of claims 1-14, wherein the first gas stream comprises carbon monoxide, and the processing, in the gas phase upgrading reactor, the first gas stream in the presence of the gas phase upgrading catalyst and under gas phase upgrading conditions further comprises converting, in the gas phase upgrading reactor, one of (i) the carbon monoxide and steam to carbon dioxide and hydrogen via a water gas shift reaction or (ii) the carbon monoxide and hydrogen to methane and water via a methanation reaction.T-12558-WO01 (538-370 PCT)16. The process according to claim 15, wherein at least about 20% of the carbon monoxide in the first gas stream is converted via the water gas shift reaction or the methanation reaction.

17. The process according to any one of claims 1-16, wherein the second gas stream has a reduced content of oxygen of at least about 90% based on the total content of the organic compounds in the second gas stream relative to the oxygen content based on the total content of the organic compounds in the first gas stream.

18. The process according to any one of claims 1-17, further comprising:passing the second gas stream to one or more additional separation units, thereby producing a third gas stream, a water stream and one or more oil streams.

19. The process according to claim 18, wherein a chemical oxygen demand (COD) of the water stream is less than about 5000 mg / L.

20. The process according to claim 18, wherein a chemical oxygen demand (COD) of the water stream is reduced by at least 95% relative to the COD of a water phase from a liquid product of the first gas stream.

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