Conversion of biomass to diesel

Abstract

The present invention relates to methods and systems for forming bio-based diesel fuel from biomass materials and the bio-based diesel fuel formed therefrom. The present invention also relates to methods and systems for forming bio-based diesel fuel from bio-based hydrocarbon feedstocks and the bio-based diesel fuel formed therefrom.

Description

[Technical field]

[0001] The present invention relates to methods and systems for forming bio-based diesel fuel from biomass materials and the bio-based diesel fuel formed therefrom. The present invention also relates to methods and systems for forming bio-based diesel fuel from bio-based hydrocarbon feedstocks and the bio-based diesel fuel formed therefrom. [Background technology]

[0002] The demand for energy has been increasing for many years due to an increased reliance on technology in both personal and commercial capacities, an expanding world population, and necessary technological advances being made in developing countries. Energy resources have traditionally been derived primarily from fossil fuels, however, as supplies of such resources are dwindling, there is greater significance in research to explore alternative ways of supplying energy. Furthermore, growing awareness of the environmental impact of burning fossil fuels and the responsibility to reduce greenhouse gas emissions have significantly increased the demand for greener energy resources.

[0003] Biofuels are considered to be a promising and more environmentally friendly alternative to fossil fuels, especially diesel, naphtha, gasoline and jet fuel. Currently, such materials are only partially replaced with bio-based fuels by blending. Due to the costs associated with the formation of some biofuels, it is not yet commercially feasible to produce fuels derived entirely from biomass materials. Even when bio-based fuels are combined with fossil fuels, the difficulty of blending some bio-based fuels can result in long processing times and high costs.

[0004] The term biomass is commonly used in reference to materials formed from plant-based sources such as corn, soybeans, linseed, rapeseed, sugarcane, and palm oil, but the term encompasses materials formed from any recently living organism or their metabolic by-products. Because biomass materials contain less nitrogen and sulfur compared to fossil fuels and do not result in a net increase in atmospheric CO2 levels, the formation of economically viable bio-derived fuels is considered to be beneficial to the environment.

[0005] High quality fossil fuels such as diesel and jet fuel are formed by refining crude oil. The diesel fuel produced contains primarily saturated paraffins, including n-, iso-, and cycloparaffins, but also contains aromatic hydrocarbons such as naphthalenes and alkylbenzenes. Typically, the diesel fuel is subjected to additional refining / upgrading processes, including hydrotreating processes to reduce the amount of sulfur present, catalytic cracking and / or hydrocracking to reduce the presence of larger hydrocarbon compounds, and optional blending with other streams, to produce a fuel that meets all of the required chemical, physical, economic, and inventory requirements of a diesel fuel product.

[0006] Fossil fuel-based diesel is formed from a complex mixture of hydrocarbon compounds, the majority of which contain carbon numbers between 10 and 22.

[0007] For a biofuel to be considered as a replacement for crude oil-based diesel fuel, it must meet the standardized chemical and physical properties of these materials as defined in the European Standards EN 590:2009 "Automotive fuels - Diesel - Requirements and test methods" and ASTM D975 "Standard specification for diesel fuel oil". These standards define the required specification properties for diesel fuel in Europe, for example, the required specifications for Euro 6 grade diesel oil are shown in Table 1.

[0008] [Table 1] JPEG2024503346000003.jpg107169

[0009] Particularly important requirements of any diesel fuel (or hydrocarbon feedstock used to form the diesel fuel) are i) the amount of sulfur present, and ii) the freezing point of the material. Combustion of sulfur containing hydrocarbons leads to the formation of sulfur oxides. Sulfur oxides are believed to contribute to the formation of aerosols and particulate matter (soot), which can cause flow degradation or clogging in filters and components of combustion engines. Furthermore, sulfur oxides are known to cause corrosion of turbine blades, so high sulfur content in fuels is highly undesirable. European standard EN590:2009 states that diesel fuel may contain up to 10 mg / kg sulfur, while in the US a maximum of 15 mg / kg sulfur is believed to be acceptable.

[0010] An essential property of any alternative diesel fuel is the flowability of the material at lower temperatures. The flowability of the fuel can be determined based on the cloud point and pour point of the material. Diesel fuel contains paraffin wax that melts at temperatures ranging from 40°C to 80°C, and therefore at lower temperatures the paraffin wax begins to solidify and paraffin wax crystals form. The temperature at which the wax begins to precipitate and the fuel becomes cloudy is called the cloud point. As the temperature of the fuel decreases below the cloud point, more paraffin wax precipitates out of solution. At approximately 3°C to 5°C below the cloud point (for fuels that do not contain pour point depressant additives), the fuel can no longer flow. The solid paraffin wax present in diesel fuel can cause poor flow or clogging in filters and components of combustion engines.

[0011] Diesel fuel contains a mixture of different hydrocarbon compounds, each with a unique freezing point, and unlike water, does not become solid at a particular temperature. As the fuel cools, the hydrocarbon components with the highest freezing points solidify first, forming wax crystals. With further cooling, the hydrocarbons with lower freezing points subsequently solidify. Thus, as the fuel cools, it changes from a homogeneous liquid to a liquid containing a small amount of hydrocarbon (wax) crystals, to a mixture of liquid fuel and hydrocarbon crystals, and finally to a nearly solid hydrocarbon wax. The pour point of a fuel is defined as the lowest temperature at which the oil can be poured from a beaker. Diesels formed from fossil fuels typically have pour points between -35°C and -15°C, and fuels with lower pour points within this range in diesel remain fluid at low temperatures and are therefore acceptable for use in a wider range of environments.

[0012] A further essential property of diesel fuel is the cetane number, which defines the ignition quality of the fuel. The cetane number is a measure of how easily the fuel burns under diesel engine conditions. A higher cetane number indicates a more volatile fuel and results in a shorter ignition delay time. Generally, diesel fuels have a cetane number between 40 and 55, but in Europe, the minimum cetane number allowed is 51. It has been found that fuels with a higher cetane number improve fuel combustion, reduce smoke generation, and produce lower NOx and particulate (soot) emissions.

[0013] It is well understood in the art that the physical properties of diesel fuel, such as freezing point, pour point, cetane number and viscosity, and therefore the performance of the fuel in an engine, are related to both the molecular weight or carbon number and the ratio of abundance of the different hydrocarbon compounds present. Typically, diesel fuels are based on paraffins (C 10 , C 14 , C 15 and C 20 ), naphthenes (C 10 , C 15 and C 20 ) or aromatic (C 10 , C15 and C 20 It is mainly composed of aryl groups (having a carbon number of 100 to 150).

[0014] However, many previously known methods for producing bio-based fuels result in a wide variety of hydrocarbon compounds and therefore cannot meet the requirements of alternative diesel fuel materials or require additional refining steps, thereby increasing the time and cost of producing such materials.

[0015] Bromine number or bromine index is a parameter used to estimate the amount of unsaturated hydrocarbon groups present in a material. The unsaturated hydrocarbon bonds present in bio-derived diesel fuels can adversely affect the physical properties and performance of the material. The unsaturated carbon bonds can crosslink or react with oxygen to form epoxides. Through crosslinking, the hydrocarbon compounds polymerize to form gums or varnishes. The gums and varnishes can form deposits in the fuel system or engine and clog filters and / or tubes that supply fuel to internal combustion engines. Reduced fuel flow results in reduced engine power and can even prevent the engine from starting. Although a specific bromine index range is not a standard requirement for diesel fuels, lower bromine index values ​​are clearly beneficial in such materials.

[0016] For a bio-based fuel to be considered suitable for diesel fuel purposes, it must meet the above standardization requirements. However, known methods for producing bio-based oils typically require extensive and costly refining steps to bring the oil to acceptable specifications. Thus, such methods cannot provide an economically competitive alternative to fossil fuels.

[0017] Research within the art has thus far focused on indirect methods of forming biofuels, including, for example, i) fractionation of biomass and fermentation of the cellulose and hemicellulose fractions to ethanol, or ii) gasification by decomposition of the entire biomass to form syngas, followed by subsequent upgrading to methanol or the Fischer-Tropsch process.

[0018] Currently, thermal conversion methods are considered to be the most promising technology for the conversion of biomass to biofuels. Thermochemical conversion includes the use of pyrolysis, gasification, liquefaction and supercritical fluid extraction. In particular, research has focused on pyrolysis and gasification to form biofuels.

[0019] Gasification involves heating biomass materials to temperatures above 430°C in the presence of oxygen or air to form carbon dioxide and hydrogen (also called synthesis gas or syngas). The syngas can then be converted to liquid fuels using catalyzed Fischer-Tropsch synthesis. Fischer-Tropsch reactions are usually carried out at 150-300°C under pressure with a catalyst. The catalysts used require clean syngas, so an additional step of cleaning the syngas is also required.

[0020] A typical gasification process involving biomass materials produces a H2:CO ratio of approximately 1, as shown in Equation 1 below: C6H 10 O5+H2O=6CO+6H2 (formula 1)

[0021] Thus, the reaction products are not formed at the CO to H ratio required for the subsequent Fischer-Tropsch synthesis to form biofuels (H2:CO ratio of ~2). To increase the H2 to CO ratio, the following additional steps are usually applied: An additional water-gas shift reaction is used; Hydrogen gas is added; · Carbon is extracted using gasification; Increased amounts of CO2 are produced by using excess steam: C6H 10 O5 + 7H2O = 6CO2 + 12H2. Carbon dioxide can be converted to carbon monoxide by the addition of carbon, which is called gasification with carbon dioxide rather than steam. · Unreacted CO is removed and used to generate heat and / or power.

[0022] Overall, the gasification reaction requires multiple reaction steps and additional reactants, making this method of producing biofuels less energy efficient. Furthermore, the increased time, energy requirements, reactants and catalysts required for the combined gasification and Fischer-Tropsch reactions significantly increase production costs.

[0023] Among thermal conversion processes, pyrolysis is considered to be the most efficient route to convert biomass to bio-based oils. Pyrolysis produces bio-oil, char and non-condensable gases by rapidly heating biomass materials in the absence of oxygen. The ratio of products produced depends on the reaction temperature, reaction pressure and residence time of the pyrolysis vapors formed.

[0024] At lower reaction temperatures and slower heating rates, larger amounts of biochar are formed; using lower reaction temperatures, faster heating rates and shorter residence times, larger amounts of liquid fuel are formed; at higher reaction temperatures, slower heating rates and longer residence times, fuel gas is preferentially formed. Pyrolysis reactions are divided into three main categories depending on the reaction conditions used: conventional pyrolysis, fast pyrolysis and flash pyrolysis.

[0025] In a conventional pyrolysis process, the heating rate is kept low (approximately 5-7°C / min) and the biomass is heated to a temperature of approximately 275-675°C with a residence time of 7-10 minutes. The slower increase in heating typically results in the formation of larger amounts of char compared to bio-oil and gas.

[0026] Fast pyrolysis involves the use of high reaction temperatures (575-975 °C) and high heating rates (approximately 300-550 °C / min) and shorter residence times of the pyrolysis vapors (typically up to 10 seconds) followed by rapid cooling. Fast pyrolysis increases the relative amount of bio-oil formed.

[0027] Flash pyrolysis involves rapid devolatilization in an inert atmosphere, high heating rates, high reaction temperatures (typically above 775°C) and very short vapor residence times (<1 second). In order to adequately transfer heat to the biomass material in these limited times, the biomass material must be present in particle form, typically with a diameter of about 1 mm. The reaction products formed are primarily gaseous fuels.

[0028] However, bio-oil produced by pyrolysis processes often contains a complex mixture of water and various organic compounds including acids, alcohols, ketones, aldehydes, phenols, esters, sugars, furans and hydrocarbons, as well as large amounts of oligomers. The presence of water, acids, aldehydes and oligomers is believed to be responsible for the poor fuel properties in the bio-oil formed.

[0029] Additionally, the resulting bio-oil may contain 300-400 different oxygenated compounds that may be corrosive, thermally and chemically unstable, and incompatible with petroleum fuels. The presence of these oxygenated compounds also increases the viscosity of the fuel and makes it more hygroscopic.

[0030] To address these issues, several upgrading techniques have been proposed, including catalytic (hydro)deoxygenation using hydrotreating catalysts, supported metallic materials, and more recently transition metals, however catalyst deactivation (via coking) and / or poor product yields mean that further research is needed.

[0031] Alternative upgrading techniques include emulsion catalytic hydrogenation, hydrocracking and / or catalytic esterification. However, previously known methods for producing biologically derived hydrocarbon feedstocks result in a wide range of hydrocarbon compounds containing significant amounts of contaminants and / or undesirable components, so that the biologically derived hydrocarbon feedstocks may not be stable enough to undergo upgrading cracking processes such as hydrocracking and may repolymerize, preventing or reducing flow in such reactor systems. Inevitably, additional purification steps and additional reactant materials are required, increasing both the time and costs associated with such processes in terms of both operating costs and capital investments.

[0032] Due to the insufficient quality of the biogenic hydrocarbon feedstock or biogenic fuel produced using previously known methods, it is often necessary to blend the hydrocarbon feedstock with a fossil fuel or a fraction thereof prior to catalytic cracking techniques, or alternatively prior to blending the formed biogenic fuel with a fossil fuel or a fraction thereof, in order to meet the chemical, physical and economic requirements discussed above. In some cases, the weight ratio of the fossil fuel or a fraction thereof to the biogenic hydrocarbon feed / biogenic fuel can be up to 99.9:0.1 in order to produce a fuel that meets the current standard requirements.

[0033] Thus, there remains a need in the art for simpler and more efficient methods of forming bio-derived diesel fuels that can meet at least some of the standardized chemical, physical and performance properties of fossil fuel-based materials. In particular, it would be desirable to provide a more cost-effective method of producing bio-derived fuels that are comparable to those produced from fossil fuels. Summary of the Invention [Means for solving the problem]

[0034] In a first embodiment, the present invention provides a method for forming a biodiesel fuel from a biomass feedstock, comprising: a. providing a biomass feedstock; b. ensuring that the moisture content of the biomass feedstock is 10% or less by weight of the biomass feedstock; c. pyrolyzing the low moisture biomass feedstock at a temperature of at least 950° C. to form a mixture of biochar, hydrocarbon feedstock, non-condensable light gases such as hydrogen, carbon monoxide, carbon dioxide and methane, and water; d. separating the hydrocarbon feedstock from the mixture formed in step c.; e. hydrocracking the hydrocarbon feedstock of step d. in the presence of a hydrocracking catalyst and a hydrogen-containing gas to produce a bio-oil; and f. fractionating the resulting bio-oil to obtain a bio-derived diesel fuel fraction. The present invention relates to a method comprising the steps of:

[0035] Preferably, the biomass feedstock comprises a cellulosic, hemicellulose or lignin based material.

[0036] Although it is possible to use food crops such as corn, sugarcane and vegetable oils as a source of biomass, it has been suggested that the use of such starting materials may result in other environmental and / or humanitarian problems. For example, if food crops are used as a biomass source, more land will need to be allocated to grow the additional crops required, or a portion of currently grown crops will have to be converted to this use, leading to further deforestation or increased costs of certain foods. Thus, in a preferred embodiment of the present invention, the biomass feedstock is selected from a non-crop biomass feedstock.

[0037] In particular, suitable biomass feedstocks may be preferably selected from Miscanthus, switchgrass, yard clippings, straw (e.g., rice straw or wheat straw), cotton gin waste, municipal solid waste, palm leaves / empty fruit bunches (EFB), palm seed shells, bagasse, wood (e.g., hickory, pine bark, Virginia pine, red oak, white oak, spruce, poplar, and cedar), pasture hay, mesquite, wood flour, nylon, lint, bamboo, paper, corn stalks, or combinations thereof.

[0038] During the combustion of a hydrocarbon feedstock or biofuel, the sulfur contained therein may be oxygenated and may further react with water to produce sulfuric acid (H2SO4). The sulfuric acid formed may condense on metal surfaces of the combustion engine and cause corrosion. Therefore, further or repeated processing steps are required to reduce the sulfur content of the bio-oil to a suitable level. This in turn increases the processing time to produce a viable biofuel and increases the costs associated with the production of these materials. Therefore, the biomass feedstock is selected from low-sulfur biomass feedstocks. In general, non-crop biomass feedstocks contain small amounts of sulfur, but particularly preferred low-sulfur biomass feedstocks include Miscanthus, grasses, and straw, such as rice straw or wheat straw.

[0039] The use of low sulfur biomass feedstocks reduces the extent to which the resulting hydrocarbon feedstock needs to undergo desulfurization to meet industrial requirements, and in some cases eliminates the need for a desulfurization step.

[0040] During the pyrolysis step, it has been found that the efficiency of heat transfer through the biomass material depends at least in part on the surface area and volume of the biomass material used. Thus, preferably, the biomass feedstock is ground, for example by use of a tube grinder, a mill, for example a hammer mill, a knife mill, a slurry milling, or sized to the required particle size by use of a chipper, to break down the biomass material and / or reduce its particle size. Preferably, the biomass feedstock is provided in the form of pellets, chips, particles or powder. More preferably, the pellets, chips, particles or powder have a diameter of 5 μm to 10 cm, for example 5 μm to 25 mm, preferably 50 μm to 18 mm, more preferably 100 μm to 10 mm. These sizes have been found to be particularly useful with regard to efficient heat transfer. The diameter of pellets, chips, particles and powders as defined herein relates to the maximum measurable width of the material.

[0041] It has also been found that at high temperatures, such as those required during high temperature pyrolysis reactions, the presence of smaller particles may increase the chance of dust explosions and fires. However, it has been found that by at least partially removing or preventing the formation of biomass pellets, chips, particles or powders having a diameter of less than about 1 mm, the likelihood of a dust explosion or fire occurring is significantly reduced. Thus, it is preferred that the biomass feedstock (generally in the form of pellets, chips, particles or powders) have a diameter of at least 1 mm, e.g., 1 mm to 25 mm, 1 mm to 18 mm, or 1 mm to 10 mm. The biomass feedstock may contain surface moisture. Preferably, such moisture is reduced prior to the step of pyrolyzing the biomass feedstock. The amount of moisture present in the biomass feedstock will vary depending on the type of biomass material, the transport and storage conditions of the material prior to use. For example, fresh wood may contain approximately 50-60% moisture. It has been found that the presence of increased amounts of moisture in the biomass feedstock reduces the efficiency of the pyrolysis step of the present invention because heat is lost through evaporation of the moisture without the biomass material itself being heated, thereby reducing the temperature to which the biomass material is heated or increasing the time to heat the biomass material to the required temperature, which in turn affects the desired ratio of pyrolysis products formed in the hydrocarbon feedstock product.

[0042] By way of example, the initial moisture content of the biomass feedstock may be between 10% and 50% by weight of the biomass feedstock, such as between 15% and 45% by weight of the biomass feedstock, or such as between 20% and 30% by weight of the biomass feedstock.

[0043] Preferably, the moisture content of the biomass feedstock is reduced to 7% or less, such as 5% or less by weight of the biomass feedstock.

[0044] Optionally, the moisture of the biomass feedstock is at least partially reduced before the biomass feedstock is ground.

[0045] Alternatively, the biomass feedstock may be formed into pellets, chips, particles or powder before the moisture content of the biomass feedstock is at least partially reduced to 10% or less by weight of the biomass feedstock, for example if the formation process is a "wet" process, or removal of at least some moisture from the biomass feedstock may be more efficiently achieved by increasing the surface area of ​​the raw biomass feedstock.

[0046] The amount of moisture present may be reduced by the use of a vacuum oven, rotary dryer, flash dryer, or heat exchanger, such as a continuous belt dryer. Preferably, the moisture is reduced by the use of an indirectly heated method, such as an indirectly heated belt dryer, an indirectly heated fluidized bed, or an indirectly heated contact rotary steam tube dryer.

[0047] Indirect heating methods have been found to improve the safety of the overall process since heat can be transferred in the absence of air or oxygen, thereby mitigating and / or reducing the occurrence of fire and / or dust explosions. Furthermore, it has been found that such indirect heating methods provide more precise temperature control, which in turn allows for better control of the ratio of pyrolysis products formed in the hydrocarbon feedstock product. In a preferred process, the indirect heating method comprises an indirectly heated contact rotary steam tube dryer, in which water vapor is used as the heat carrying medium.

[0048] The low moisture biomass feedstock may be pyrolyzed at at least 1000°C, more preferably at least 1100°C, for example 1120°C, 1150°C, or 1200°C.

[0049] In general, the biomass feedstock may be heated by convection heating, microwave heating, electrical heating, or supercritical heating. By way of example, the biomass feedstock may be heated by use of microwave assisted heating, a heating jacket, a solid heat carrier, a tubular furnace, or an electrical heater. Preferably, the heating source is a tubular furnace. The tubular furnace may be formed from any suitable material, for example, a nickel metal alloy.

[0050] As mentioned above, the use of indirect heating of the pyrolysis chamber is preferred as it reduces and / or mitigates the possibility of a dust explosion or fire occurring.

[0051] Alternatively or additionally, a heating source is disposed within the pyrolysis reactor to directly heat the low moisture biomass feedstock. The heating source may be selected from an electric heating source, for example, an electric spiral heater. It has been found to be beneficial to use two or more electric spiral heaters within the pyrolysis reactor. The use of multiple heaters can provide a more homogeneous distribution of heat throughout the reactor, ensuring a more uniform reaction temperature is applied to the low moisture biomass material.

[0052] It has been found to be beneficial for the biomass material from step b. to be transported continuously through the pyrolysis reactor. For example, the biomass material may be transported through the pyrolysis reactor using a conveyor, such as a screw conveyor or a rotating belt. Optionally, two or more conveyors may be used to transport the biomass material continuously through the pyrolysis reactor. A screw conveyor has been found to be particularly useful, since the speed of transporting the biomass material through the pyrolysis reactor, and therefore the residence time in the pyrolysis reactor, can be controlled by varying the pitch of the screw conveyor.

[0053] Alternatively, or in addition, the residence time of the biomass material within the reactor can be varied by varying the width or diameter of the pyrolysis reactor through which the biomass material is conveyed.

[0054] The biomass material may be pyrolyzed under atmospheric pressure (including essentially atmospheric conditions). Preferably, the biomass material is pyrolyzed in an oxygen-depleted environment to avoid the formation of undesirable oxygenated compounds, more preferably the biomass material is pyrolyzed in an inert atmosphere, for example the reactor is purged with an inert gas such as nitrogen or argon prior to the pyrolysis step. The biomass material may be pyrolyzed under atmospheric pressure (including essentially atmospheric conditions). Alternatively, the biomass material may be pyrolyzed under low pressure, for example 850-1,000 Pa, preferably 900-950 Pa. The resulting pyrolysis gases may then be separated by any method known within the art, for example condensation and distillation. The application of pressures such as 850-1,000 Pa during the pyrolysis step and subsequent condensation and distillation of the pyrolysis gases formed has been found to be beneficial in separating the pyrolysis gases from any residual solids formed during the pyrolysis reaction, such as biochar. Thus, in some embodiments, means are provided to apply the necessary vacuum pressure and / or remove the pyrolysis gases that are formed.

[0055] In certain examples, the biomass material is conveyed in a countercurrent direction to any pyrolysis gases that are formed, and any solid material, such as biochar, that is formed as a result of the pyrolysis step is removed separately from the pyrolysis gases that are formed. As the hot pyrolysis gases pass through the biomass material, heat is transferred from the pyrolysis gases to the biomass material, resulting in at least a small amount of low temperature pyrolysis of the biomass material.

[0056] Furthermore, the pyrolysis gases are at least partially cleaned as dust and heavy carbons present in the gases are captured by the biomass material.

[0057] If the pyrolysis step is carried out under low pressure conditions, a vacuum may be applied to assist in the flow of pyrolysis gases countercurrent to the biomass material being conveyed through the pyrolysis reactor, and, optionally, removal of the pyrolysis gases.

[0058] In some examples, the biomass feedstock from step b. is pyrolyzed for a time period between 10 seconds and 2 hours, preferably between 30 seconds and 1 hour, more preferably between 60 seconds and 30 minutes, for example, between 100 seconds and 10 minutes.

[0059] According to the present invention, step d. may further comprise a step of separating the biochar from the hydrocarbon feedstock product. In some cases, the separation of the biochar from the hydrocarbon feedstock product is carried out in the pyrolysis reactor. In other cases, the pyrolysis gases formed are first cooled, for example by use of a venturi, to condense the hydrocarbon feedstock product, and the biochar is subsequently separated from the liquid hydrocarbon feedstock product and non-condensable gases formed.

[0060] The amount of biochar formed in the pyrolysis step may be between 5% and 20% by weight of the biomass feedstock formed in step b., preferably the amount of biochar formed is between 10 and 15% by weight of the biomass feedstock formed in step b.

[0061] The hydrocarbon feedstock product may be at least partially separated from the formed biochar using filtration methods (e.g., using ceramic filters), centrifugation, cyclone, or gravity separation.

[0062] According to the present invention, step d. may or further comprises at least partially separating water from the hydrocarbon feedstock product. It has been found that the water at least partially separated from the hydrocarbon feedstock further comprises organic contaminants such as wood vinegar. Generally, wood vinegar is present in the water at least partially separated from the hydrocarbon feedstock product in an amount of 10% to 30% by weight of aqueous wood vinegar, preferably wood vinegar is present in an amount of 15% to 28% by weight of aqueous wood vinegar.

[0063] Aqueous pyrolignous acid (also called wood vinegar) contains primarily water, but also organic compounds such as acetic acid, acetone, and methanol. Pyrolignous acid is known to be used for agricultural purposes, such as as an antibacterial agent and insecticide. Additionally, pyrolignous acid can be used as a fertilizer to improve soil quality and can accelerate the growth of plant roots, stems, tubers, flowers, and fruits. Pyrolignous acid is also known to have medical applications, for example, in wood vinegar with antibacterial properties, can provide a positive effect on cholesterol, can aid in digestion, and can help relieve acid reflux, heartburn, and nausea. Thus, the present process has the added benefit of being able to isolate such product streams.

[0064] Water may be at least partially separated from the hydrocarbon feedstock by gravity oil separation, centrifugation, cyclone or microbubble separation.

[0065] According to the present invention, step d. may comprise or further comprise at least partially separating the non-condensable light gases from the product hydrocarbon feedstock. The non-condensable light gases may be separated from the product hydrocarbon feedstock by any method known in the art, for example by flash distillation or fractional distillation.

[0066] Generally, the non-condensable light gases may be at least partially recycled. Preferably, the non-condensable light gases separated from the hydrocarbon feedstock product are combined with the biomass feedstock that has been subjected to pyrolysis (step c.).

[0067] When the non-condensable light gas contains carbon monoxide, the carbon monoxide contained therein can be at least partially separated and further processed in a water gas shift (WGS) reaction. In particular, the carbon monoxide produced in the pyrolysis step can be combined with steam to produce carbon dioxide and hydrogen gas fuel. Since the feedstock used in the WSG reaction is derived from a biomass feedstock, the hydrogen gas produced is green bio-based hydrogen gas. Preferably, the carbon monoxide is contacted with steam at a temperature between 205°C and 482°C. Since the WGS reaction is exothermic, the carbon monoxide is more preferably contacted with steam at a temperature between 205°C and 260°C to increase the yield of bio-based hydrogen gas.

[0068] A shift catalyst may also be present in the WGS reaction, where the shift catalyst may be selected from a copper-zinc-aluminum catalyst or a chromium or copper promoted iron based catalyst. Preferably, the catalyst is selected from a copper-zinc-aluminum catalyst. To increase the contact between the carbon monoxide, steam and the selected shift catalyst and thus improve the efficiency of the WGS reaction, the catalyst may be contained in a fixed bed or trickle bed reactor.

[0069] The biogenic hydrogen gas produced by the WGS reaction may be at least partially recycled and used in downstream processing steps, such as hydrocracking steps. Alternatively, or in addition, the biogenic hydrogen gas produced may be at least partially used in downstream processing steps, such as desulfurization, deoxygenation and / or hydrotreating steps.

[0070] In some embodiments of the present invention, it has been found to be beneficial to further process the hydrocarbon feedstock product to at least partially remove contaminants contained therein, such as carbon, graphene, polyaromatic compounds and tars. The presence of impurities in biodiesel not only significantly affects its engine performance, but also complicates its handling and storage. Filters, such as membrane filters, may be used to remove larger amounts of contaminants.

[0071] Additionally or alternatively, microfiltration may be used to remove small amounts of contaminants that may be suspended in the hydrocarbon feedstock. For example, a Nutsche filter may be used to remove small amounts of contaminants.

[0072] The step of filtering the hydrocarbon feedstock may be repeated two or three or more times to reduce the contaminants present to a desired level (eg, until the hydrocarbon feedstock is straw colored).

[0073] Alternatively or additionally, contaminants such as polycyclic aromatic compounds may be removed by contacting the hydrocarbon feedstock with an activated carbon compound and / or a cross-linked organic hydrocarbon resin. The hydrocarbon feedstock may then be separated from the activated carbon and / or cross-linked organic resin by any suitable means, such as filtration. In particular, the activated carbon and / or cross-linked organic hydrocarbon resin may be in particulate or pellet form to increase contact between the adsorbent and the hydrocarbon feedstock, thereby reducing the time required to achieve a desired level of contaminant removal.

[0074] However, activated carbon can be costly to regenerate. Alternatively, for example, the biochar formed in the present method can be used as a more cost-effective and environmentally friendly alternative to activated carbon for removing contaminants from hydrocarbon feeds.

[0075] As discussed above, crosslinked organic hydrocarbon resins may also be used to remove contaminants from hydrocarbon feedstock products. In particular, crosslinked organic hydrocarbon resins are useful for removing organic contaminants through hydrophobic (i.e., van der Waals) or hydrophilic interactions (e.g., hydrogen bonding with functional groups such as carbonyl functional groups present on the surface of the resin material). The hydrophobicity / hydrophilicity of the resin adsorbent material depends on the chemical composition and structure of the selected resin material. Thus, a particular adsorbent resin can be tailored to remove the desired contaminants. Crosslinked organic hydrocarbon resins commonly used to remove contaminants present in biofuels include polysulfones, polyamides, polycarbonates, regenerated cellulose, aromatic polystyrene or polydivinylbenzene, and aliphatic methacrylates. In particular, aromatic polystyrene or polydivinylbenzene-based resin materials can be used to remove aromatic molecules such as phenols from hydrocarbon feeds.

[0076] Additionally, since the adsorption of contaminant materials can be increased by increasing the surface area and porosity of the crosslinked organic polymer resin, in a preferred embodiment the hydrocarbon feedstock is contacted with crosslinked organic hydrocarbon porous pellets or particles to further improve the purity of the treated hydrocarbon feedstock product and improve the efficiency of the purification step.

[0077] Preferably, the tar separated from the hydrocarbon feedstock product is at least partially recycled and combined with the biomass feedstock in step b. Tar obtained from pyrolysis of biomass material mainly comprises phenolic compositions and a range of additional oxygenated organic compounds. This pyrolysis tar can be further decomposed by the use of heat to at least partially form the hydrocarbon feedstock. Thus, by at least partially recycling the pyrolysis tar to the biomass feedstock in step b., the percentage yield of the hydrocarbon feedstock product obtained from the biomass source can be increased.

[0078] The hydrocarbon feedstock product may be contacted with the activated carbon, biochar, or crosslinked organic hydrocarbon resin at about atmospheric pressure (including essentially atmospheric conditions).

[0079] The activated carbon, biochar and / or crosslinked organic hydrocarbon resin may be contacted for any time necessary to sufficiently remove contaminants present in the hydrocarbon feedstock product. It is believed to be well within the knowledge of one of ordinary skill in the art to determine the appropriate contact time of the hydrocarbon feedstock and the adsorbent material. In some examples, the activated carbon, biochar and / or crosslinked organic hydrocarbon resin is contacted with the hydrocarbon feedstock for at least 15 minutes, preferably at least 20 minutes, and more preferably at least 25 minutes prior to separation.

[0080] The step of contacting the hydrocarbon feedstock product with activated carbon, biochar and / or crosslinked organic hydrocarbon resin may be repeated one or more times to reduce the contaminants present to a suitable level (e.g., until the hydrocarbon feedstock is straw colored).

[0081] The separated hydrocarbon feedstock formed in step d. preferably has at least 0.1 wt. % of one or more C compounds, at least 1 wt. % of one or more C 10 Compounds, at least 5% by weight of one or more of C 12 Compounds, at least 5% by weight of one or more of C 16 Compound, and at least 30% by weight of at least one or more C 18 Contains compounds.

[0082] More preferably, the separated hydrocarbon feedstock formed in step d. comprises at least 0.5 wt.% of one or more C compounds, at least 2 wt.% of one or more C 10 Compounds, at least 6% by weight of one or more C 12 Compounds; at least 6% by weight of one or more C 16 compound, and / or at least 33% by weight of one or more C 18Contains compounds.

[0083] The separated hydrocarbon feedstock preferably has a pour point of -10°C or less, preferably -15°C or less, such as -16°C or less.

[0084] The separated hydrocarbon feed preferably contains no more than 300 ppmw sulfur, preferably no more than 150 ppmw, more preferably no more than 70 ppmw sulfur.

[0085] A second embodiment is a method for forming a biodiesel fuel from a biologically derived hydrocarbon feedstock, comprising: i. at least 0.1% by weight of one or more C8 compounds, at least 1% by weight of one or more C 10 Compounds, at least 5% by weight of one or more of C 12 Compounds, at least 5% by weight of one or more of C 16 Compound, and at least 30% by weight of at least one or more C 18 providing a biologically derived hydrocarbon feedstock comprising the compound; ii. hydrocracking the hydrocarbon feedstock of step i. in the presence of a hydrocracking catalyst and a hydrogen-containing gas to produce a bio-oil; and iii. fractionating the resulting bio-oil to obtain a bio-derived diesel fuel fraction. The present invention provides a method comprising:

[0086] Preferably, the biologically derived hydrocarbon feedstock contains at least 0.5 wt. % of one or more C compounds, at least 2 wt. % of one or more C 10 Compounds, at least 6% by weight of one or more C 12 Compounds; at least 6% by weight of one or more C 16 compound, and / or at least 33% by weight of one or more C 18 Contains compounds.

[0087] The hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. may be contacted with the hydrocracking catalyst in an essentially liquid state, an essentially gaseous state, or a partially liquid-partially gaseous state. However, since the catalytic cracking reaction can only occur in the gas phase, in embodiments in which the hydrocarbon feedstock is present essentially or partially in a liquid state, the hydrocarbon feedstock or a portion thereof is preferably vaporized before or during contact with the hydrocracking catalyst.

[0088] It is understood that the reaction conditions of the hydrocracking process, including temperature and pressure, can vary the hydrocracking products produced.

[0089] Preferably, the hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. is contacted with a hydrocracking catalyst at a temperature between 200°C and 700°C, preferably at a temperature between 250°C and 550°C, more preferably at a temperature between 300°C and 300°C to produce a bio-oil comprising one or more cracked hydrocarbon products.

[0090] In some embodiments, the hydrocarbon feedstock is heated prior to contact with the hydrocracking catalyst, for example, the hydrocarbon feedstock may be heated to a temperature of at least 50° C., preferably at least 75° C., more preferably at least 100° C. prior to contact with the hydrocracking catalyst. Preferably, the hydrocarbon feedstock may be heated to a temperature of up to 200° C., preferably up to 175° C., more preferably up to 150° C. prior to contact with the hydrocracking catalyst. It has been found that if the hydrocarbon feedstock is maintained at a temperature below 50° C., coking of the hydrocarbons may occur in the pipelines or nozzles, leading to the hydrocracking catalyst reducing flow therein or clogging these structures. By maintaining the hydrocarbon feedstock at a temperature of at least 50° C., coking of the hydrocarbons may be significantly reduced or eliminated.

[0091] Preferably, the hydrocarbon feedstock in step d. or the hydrocarbon feedstock in step i. is contacted with the hydrocracking catalyst at a pressure of from 1 MPa to 28 MPa, preferably from 5 MPa to 20 MPa, more preferably from 10 MPa to 17 MPa.

[0092] The hydrocarbon feedstock in step d. or the hydrocarbon feedstock in step i. and / or the hydrogen-containing gas is mixed for 0.1 to 30 hours. -1 , preferably 0.2 to 10 hours -1 , more preferably 0.3 to 5 hours -1 The reactants may be contacted with the hydrocracking catalyst at a liquid hourly space velocity of 1000 rpm or less. As used herein, the term "liquid hourly space velocity" or "LHSV" refers to the ratio of the rate in barrels per hour at which the reactants are charged to a hydrocracking reaction zone at standard temperature and pressure (SIP), divided by the number of barrels of catalyst contained in the reaction zone at which the reactants are charged.

[0093] The above hydrocracking reaction conditions have been found to be particularly useful for efficiently producing hydrocracking products in shorter reaction times.

[0094] The hydrocracking step may be carried out in any suitable hydrocracking reactor known in the art. For example, the hydrocracking step may be carried out in a catalytic reactor, such as a fixed bed reactor, a trickle bed reactor, a fluidized bed reactor, or a tubular reactor, such as a coiled tube reactor, a U-tube reactor, or a straight tube reactor. The use of a fixed bed reactor, a trickle bed reactor, a fluidized bed reactor, or a tubular reactor increases the contact between the hydrocarbon feedstock and the hydrocracking catalyst, increasing the efficiency of the hydrocracking step. For the tubular reactor, any suitable tube diameter may be selected for the hydrocracking step defined herein, and as an example, a suitable tube diameter may range from 1.5 to 20 cm, preferably from 2 to 10 cm.

[0095] In some examples, the hydrocarbon feedstock may be passed through a single hydrocracking reactor. In other examples, the hydrocracking reactor may include a series of fluidly connected hydrocracking reactors, for example, two or more hydrocracking reactors. When a series of fluidly connected hydrocracking reactors is used, one or more quenching steps may further be present between the hydrocracking reactors to control the temperature of the hydrocracking step. The quenching step may include the addition of fresh hydrogen gas at reduced temperature or recycled hydrocarbon feedstock at reduced temperature.

[0096] The hydrocracking catalyst may be in the form of pellets, particles or powder. As discussed above, the hydrocracking process requires that the hydrocarbon feedstock is contacted with the hydrocracking catalyst in a gaseous state. Thus, the rate of catalytic cracking of the hydrocarbon feedstock depends at least in part on the surface area and volume of the hydrocracking catalyst. Thus, preferably, the hydrocracking catalyst is ground to reduce its particle size, for example, by using a tube grinder, a mill, such as a hammer mill, a knife mill, a slurry mill, or sized to the required particle size by using a chipper. Preferably, the hydrocracking catalyst is in the form of pellets, particles or powder with a diameter of 0.5 mm to 5 mm, preferably 0.8 mm to 3.5 mm. These particle sizes have been found to be particularly useful for increasing the efficiency of the hydrocracking reaction.

[0097] Additionally or alternatively, the hydrocracking catalyst may comprise 100 ml 2 / g~800m 2 / g surface area, preferably 150 m 2 / g~700m 2 / g, more preferably 200m 2 / g~600m 2 / g surface area.

[0098] The hydrocracking catalyst can be any catalyst known to those skilled in the art to be suitable for use in hydrocracking processes. Preferably, the hydrocracking catalyst is a bi-functional catalyst comprising one or more metals selected from Groups VB, VIB, VIIB and / or VIII of the Periodic Table, or salts thereof, on an acidic support material.

[0099] In particular, the one or more metals, or salts thereof, may be present on the acidic support material in an amount of 0.1 to 20 wt % based on the total weight of the hydrocracking catalyst, preferably 0.1 to 10 wt %, more preferably 0.5 to 5 wt % based on the total weight of the hydrocracking catalyst. The use of a support has been found to be beneficial because it allows the catalyst to be distributed more homogeneously throughout the hydrocarbon feedstock, increasing the amount of catalyst in contact with the hydrocarbon feedstock and thus improving the efficiency of the cracking reaction. Thus, the use of a supported catalyst can reduce the amount of catalyst required for the hydrocracking process and reduce the overall cost (operating and capital expenditures) of the process.

[0100] The hydrocracking catalyst may comprise a metal selected from the group consisting of iron, nickel, palladium, platinum, rhodium, iridium, cobalt, tungsten, molybdenum, vanadium, ruthenium, and mixtures thereof contained on a support material.

[0101] The acidic support material may favorably affect the particle strength, cost, porosity and overall performance of the hydrocracking catalyst. In particular, the acidic support material may be selected from zeolites, molecular sieves, silica-alumina, alumina, silica, silica nitride, silica borate, alumina oxide, boron nitride, zirconia, titania, ceria, carbon (such as activated carbon) boria, ferrierite and zirconia-alumina.

[0102] In particularly preferred examples, the acidic support material is selected from the group consisting of beta zeolite, Y zeolite, MFI zeolite, ALP0-31, SAP0-11, SAP0-31, SAP0-37, SAP0-41, SM-3, MgAPS0-31, FU-9, NU-10, NU-23, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, ZSM-50, ZSM-57, MeAP0-11, MeAP0-31, MeAP0-41, MeAP0-57, MeAP0-61, MeAP0-71, MeAP0-81, MeAP0-91, MeAP0-101, MeAP0-112, MeAP0-312, MeAP0-41, MeAP0-113, MeAP0-114, MeAP0-115, MeAP0-116, MeAP0-117, MeAP0-118, MeAP0-119 ... APS0-11, MeAPS0-31, MeAPS0-41, MeAPS0-46, ELAP0-11, ELAP0-31, ELAP0-41, ELAPS0-11, ELAPS0-31, ELAPS0-41, laumontite, cancrinite, offretite, the hydrogen form of stilbite, the magnesium or calcium form of mordenite, and the magnesium or calcium form of partite, or combinations thereof.

[0103] Alternatively, if no support is used, the hydrocracking catalyst may be used as a fine powder in the form of one or more sintered metals or metal foams, in which the one or more metals are as defined above. Preferably, the fine metal powder has a particle size of less than about 50 μm, preferably less than about 35 μm, more preferably less than about 25 μm.

[0104] Optionally, the hydrocarbon feedstock may be contacted with a hydrocracking catalyst prior to the addition of hydrogen gas. Alternatively, the hydrogen gas is contacted with the hydrocracking catalyst prior to contact with the hydrocarbon feedstock. In yet a further example, the hydrocarbon feedstock and hydrogen gas are contacted with the hydrocracking catalyst simultaneously.

[0105] The hydrocarbon feedstock may be preheated before contacting with the hydrocracking catalyst and, if present, hydrogen gas. The hydrocarbon feedstock may be preheated by use of a heat exchanger. In particular, the hydrocarbon feedstock may be preheated to a temperature between 150° C. and 650° C., more preferably between 200° C. and 500° C. Alternatively, the hydrocarbon feedstock may first be contacted with the hydrocracking catalyst and, if present, hydrogen gas, and subsequently heated to the desired temperature. The hydrocarbon feedstock and hydrogen gas may be heated to the desired temperature using any of the direct or indirect heating methods defined above.

[0106] Optionally, the method further comprises at least partially removing hydrogen gas and / or carbon dioxide in the bio-oil formed. Hydrogen gas and / or carbon dioxide may be separated from the bio-oil by any method known in the art, for example by partial vaporization, for example by use of a flash separator at about ambient pressure (including essentially atmospheric conditions). The vaporized hydrogen gas and / or carbon dioxide may be subsequently removed via a degassing step. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA. Alternatively, hydrogen gas and / or carbon dioxide may be removed from the bio-oil via fractional distillation.

[0107] Any unreacted hydrogen-rich gas and / or carbon dioxide removed from the bio-oil may be at least partially recycled and combined with the hydrocarbon feedstock in step d. or step i. By at least partially recycling the unreacted hydrogen gas, the amount of hydrogen gas required to hydrocrack the hydrocarbon feedstock is reduced and the overall costs (operations and capital expenditures) of the process may be reduced.

[0108] According to the invention, the method may further comprise the step of at least partially removing sulfur-containing components from the bio-oil formed in step e. or step ii.

[0109] Additionally or alternatively, the method may further comprise the step of at least partially removing sulfur-containing components from the bio-derived diesel fuel fraction formed in step e. or step ii.

[0110] The step of at least partially removing sulfur-containing components from the bio-oil and / or diesel fuel fraction may comprise at least partially removing one or more of the following present thiols, sulfides, disulfides, alkylated derivatives of thiophenes, benzothiophenes, dibenzothiophenes, 4-methyldibenzothiophenes, 4,6-dimethyldibenzothiophenes, benzonaphthothiophenes and benzo[def]dibenzothiophenes. Preferably, benzothiophenes, dibenzothiophenes are at least partially removed from the bio-oil and / or diesel fuel fraction.

[0111] The step of at least partially removing sulfur-containing components from the bio-oil and / or diesel fuel fraction may comprise a hydrodesulfurization step, preferably a catalytic hydrodesulfurization step.

[0112] The catalyst is preferably selected from nickel molybdenum sulfide (NiMoS), molybdenum, molybdenum disulfide (MoS2), cobalt / molybdenum, such as binary combinations of cobalt and molybdenum, cobalt molybdenum sulfide (CoMoS), ruthenium disulfide (RuS2), and / or nickel / molybdenum based catalysts. More preferably, the catalyst is selected from nickel molybdenum sulfide (NiMoS) based catalysts and / or cobalt molybdenum sulfide (CoMoS) based catalysts.

[0113] Alternatively, the catalyst may be selected from any known metal-organic framework (MOF) comprising a metal component and an organic ligand suitable for at least partially removing sulfur-containing components from bio-oil and / or diesel fuel fractions. In particular, the MOF material may be selected from copper-1,3,5-benzenetricarboxylic acid (Cu-BTC) and V / Cu-BTC. Preferably, the catalyst comprises V / Cu-BTC.

[0114] The catalyst may be a supported catalyst, and the support may be selected from natural or synthetic materials. In particular, the support is selected from activated carbon, silica, alumina, silica-alumina, molecular sieves and / or zeolites. The use of a support has been found to be beneficial, since it allows the catalyst to be distributed more homogeneously throughout the bio-oil and / or diesel fuel fraction, thus increasing the amount of catalyst in contact with the bio-oil and / or diesel fuel fraction. Thus, the use of a supported catalyst allows the amount of catalyst required for the hydrodesulfurization reaction to be reduced, reducing the overall process costs (operational and capital expenditures).

[0115] The hydrodesulfurization step may be carried out in a fixed bed or trickle bed reactor to increase the contact between the bio-oil and / or diesel fuel fraction and the catalyst present, thereby increasing the efficiency of the sulfur removal step.

[0116] The hydrodesulfurization step may be carried out at a temperature between 250°C and 400°C, preferably between 300°C and 350°C.

[0117] The bio-oil and / or diesel fuel fraction may be pre-heated prior to contact with hydrogen gas and, if present, the hydrodesulfurization catalyst. The bio-oil and / or diesel fuel fraction may be pre-heated by use of a heat exchanger. Alternatively, the bio-oil and / or diesel fuel fraction may be first contacted with hydrogen gas and, if present, the hydrodesulfurization catalyst, and subsequently heated to the desired temperature. The bio-oil and / or diesel fuel fraction and hydrogen gas may be heated to the desired temperature using any of the direct or indirect heating methods defined above.

[0118] The hydrodesulfurization step is carried out at a reaction pressure of 4 to 6 MPaG, preferably 4.5 to 5.5 MPaG, more preferably about 5 MPaG.

[0119] During the desulfurization reaction, the sulfur-containing components react with hydrogen gas to produce hydrogen sulfide gas (H2S). The hydrogen sulfide gas formed can be separated from the bio-oil and / or diesel fuel fraction by any method known in the art, such as by the use of a gas separator or by the application of a slight vacuum to the reactor vessel, for example a vacuum pressure of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA.

[0120] Optionally, the sulfur reduced bio-oil and / or diesel fuel fraction may then be cooled by any suitable means known in the art, for example by use of a heat exchanger, before further processing steps are carried out.

[0121] Trace amounts of hydrogen sulfide remaining in the sulfur-reduced bio-oil and / or diesel fuel fraction may subsequently be removed, for example by partial vaporization by use of a flash separator at about ambient pressure and removal of the vaporized hydrogen sulfide by degassing. Preferably, the bio-oil and / or diesel fuel fraction has a temperature between 60° C. and 120° C. during the degassing step, more preferably the bio-oil and / or diesel fuel fraction has a temperature between 80° C. and 100° C. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0122] Any unreacted hydrogen-rich gas removed during the degassing step may be separated from the hydrogen sulfide, for example, by use of an amine contactor. The separated gas may then be advantageously recycled and combined with the hydrocarbon feedstock of step d. or step i. By recycling the unreacted hydrogen gas, the amount of hydrogen gas required to remove sulfur-containing components from the bio-oil and / or diesel fuel fraction is reduced, thereby providing a more cost-effective process.

[0123] The hydrodesulfurization step may be repeated one or more times to achieve the desired sulfur reduction in the bio-oil and / or diesel fuel fraction, however, typically only one hydrodesulfurization step is necessary to sufficiently reduce the sulfur content of the bio-oil and / or diesel fuel fraction to the desired level, particularly when the hydrocarbon feedstock is produced according to the methods described herein.

[0124] The desulfurized bio-oil and / or diesel fuel fraction may contain a sulfur content of less than 5 ppmw, preferably less than 3 ppmw, more preferably less than 1 ppmw.

[0125] In some embodiments, a desulfurization step is not required. As discussed above, the biomass feedstock may be selected from non-crop biomass feedstocks. Non-crop biomass feedstocks such as Miscanthus, grasses, and straw, e.g., rice straw or wheat straw, contain small amounts of sulfur, so that the hydrocarbon feedstocks, bio-oil and diesel fuel fractions obtained therefrom also contain smaller amounts of sulfur-containing components and may essentially meet the limits stated above. Furthermore, sulfur-containing components present in non-crop biomass feeds mainly include benzothiophenes, which are easily decomposed at temperatures of approximately 500° C. to form benzene and hydrogen sulfide (H2S). Thus, such sulfur-containing components decompose during the pyrolysis process defined herein, further reducing the sulfur content of the resulting bio-oil. As a result, the use of such biomass feedstocks can reduce the time and costs associated with the method.

[0126] The method may further include hydrotreating the biooil formed in step e. or step ii.

[0127] The hydrotreating step of the present invention is used to reduce the number of unsaturated hydrocarbon functional groups present in the bio-oil and advantageously convert the bio-oil into a more stable fuel with a higher energy density.

[0128] The hydrotreating step may be carried out at a temperature between 250°C and 350°C, preferably between 270°C and 330°C, more preferably between 280°C and 320°C. Preferably, the bio-oil is heated prior to contact with hydrogen gas and, if present, the hydrotreating catalyst. The bio-oil may be pre-heated by use of a heat exchanger. Alternatively, the bio-oil may first be contacted with hydrogen gas and, if present, the hydrotreating catalyst, and subsequently heated to the desired temperature. The bio-oil and hydrogen gas may be heated to the desired temperature using any of the direct or indirect heating methods defined above.

[0129] The hydrotreating step may be carried out at a reaction pressure of 4 MPaG to 6 MPaG, preferably 4.5 MPaG to 5.5 MPaG, more preferably about 5 MPaG.

[0130] Typically, the hydrotreating step further comprises a catalyst. Preferably, the catalyst comprises a metal catalyst selected from groups IIIB, IVB, VB, VIB, VIIB and VIII of the periodic table. In particular, the metal catalyst is selected from group VIII of the periodic table, for example, the catalyst may be selected from Fe, Co, Ni, Ru, Rh, Pd, Os, Ir and / or Pt, such as catalysts containing Ni, Co, Mo, W, Cu, Pd, Ru, Pt. Preferably, the catalyst is selected from CoMo, NiMo or Ni catalysts.

[0131] When the hydrotreating catalyst is selected from platinum-based catalysts, the hydrodesulfurization step is preferably carried out before the hydrotreating step, since the sulfur contained in the hydrocarbon feedstock may poison the platinum-based catalyst and thus reduce the efficiency of the hydrotreating step.

[0132] The catalyst may be a supported catalyst, the support may optionally be selected from natural or synthetic materials. In particular, the support may be selected from activated carbon, silica, alumina, silica-alumina, molecular sieves and / or zeolites. The use of a support has been found to be beneficial, since the catalyst may be distributed more homogeneously throughout the bio-oil, increasing the amount of catalyst in contact with the bio-oil. Thus, the use of a supported catalyst may reduce the amount of catalyst required for the hydrotreating reaction, reducing the overall cost of the process (operational and capital expenditures).

[0133] The hydrotreating step may be carried out in a fixed bed or trickle bed reactor to increase the contact between the bio-oil and the catalyst present, thereby improving the efficiency of the hydrotreating reaction.

[0134] Optionally, the hydrotreated bio-oil is subsequently cooled, for example by use of a heat exchanger, before any further processing steps are carried out.

[0135] Prior to fractionating the formed bio-oil, the LPG gas may optionally be at least partially separated from the bio-oil by any method known in the art, for example by use of a gas condenser and / or a gas separator. Alternatively or additionally, the LPG gas may be separated from the bio-oil by application of a slight vacuum, for example using a vacuum pressure of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA to separate the LPG from the remaining bio-oil. Alternatively, the LPG may be separated from the bio-oil by condensation and flash distillation methods.

[0136] The fractionation step of the present invention can separate the refined bio-oil into respective naphtha, jet fuel and / or heavy diesel fractions. The fractionation process may be carried out using any standard method known in the art, for example, by use of a fractionation column.

[0137] The fractionation step may comprise isolating a first fractionation cut of the refined bio-oil having a cut point between 30°C and 220°C, preferably between 50°C and 210°C, for example between 70°C and 200°C, at atmospheric pressure (including essentially atmospheric conditions). Alternatively, the fractionation step may be carried out at a pressure between 850 and 1000 Pa, preferably between 900 and 950 Pa. The hydrocarbons in the first fractionation cut may be subsequently cooled and condensed. The first cut fraction is a bio-derived gasoline fuel fraction.

[0138] The method may further include performing a second fractional cut of the refined bio-oil having a cut point between 280° C. and 320° C., preferably between 290° C. and 310° C., more preferably about 300° C. The second fractional cut generally comprises bio-derived jet fuel. The hydrocarbons in the second fractional cut may be cooled and condensed, for example, using a condenser.

[0139] The second fraction cut is a bio-based jet fuel, preferably an A1 grade jet fuel. Preferably, the physical and chemical properties of the second fraction cut meet at least a portion of the standardization requirements for jet fuel.

[0140] The remaining bio-oil in the underflow is bio-derived diesel fuel.

[0141] A third embodiment includes a bio-based LPG fuel produced according to the method defined herein.

[0142] A fourth embodiment includes a bio-based gasoline fuel produced according to the methods defined herein.

[0143] A fifth embodiment includes a bio-based jet fuel produced according to the methods defined herein.

[0144] A sixth embodiment includes a bio-based diesel fuel produced according to the methods defined herein. Preferably, the bio-based diesel fuel is formed entirely from biomass feedstock.

[0145] Surprisingly, it has been found that the bio-based diesel fuel produced according to the method of the present invention meets the standards for D-2 grade diesel fuel. Preferably, the pour point of the bio-based diesel fuel is -40°C or less, preferably -42°C or less, more preferably -45°C or less.

[0146] The bio-derived diesel fuel may have a cetane number of at least 60, preferably at least 65, and more preferably at least 70.

[0147] The bio-derived diesel fuel preferably contains no more than 10 ppmw sulfur, preferably no more than 5 ppmw sulfur, more preferably no more than 1 ppmw sulfur.

[0148] Preferably, the bio-derived diesel fuel has no measurable Bromine Index.

[0149] It is recognized that, although not technically necessary, the bio-derived diesel fuel of the present invention may be blended with other materials (e.g., fossil-derived fuel materials) to meet current fuel specifications. By way of example, such blends may be up to 50%. However, the surprising quality of the fuel of the present invention makes it feasible for the first time to make such processes avoidable.

[0150] A seventh embodiment is a system for forming a biodiesel fuel from a biomass feedstock, comprising: means for ensuring that the moisture content of the biomass feedstock is less than 10% by weight of the biomass feedstock; a reactor comprising a heating body configured to heat the biomass feedstock to a temperature of at least 950° C. to form a mixture of biochar, hydrocarbon feedstock, hydrogen, carbon monoxide, carbon dioxide and non-condensable light gases such as methane, and water; a separator configured to separate the formed hydrocarbon feedstock from the reaction mixture produced in the reactor; a hydrocracking reactor suitable for cracking a hydrocarbon feedstock in the presence of hydrogen gas to produce a bio-oil; and Separator configured to separate a diesel fuel fraction from a bio-oil The present invention provides a system including:

[0151] According to the invention, the system may further include means for grinding the biomass feedstock prior to entering the reactor to reduce the particle size of the material, for example the biomass feedstock may be formed into pellets, chips, particles or powder with a maximum particle diameter of 1 mm to 25 mm, 1 mm to 18 mm, or 1 mm to 10 mm. Preferably the system includes a tube grinder, mill, such as a hammer mill, knife mill, slurry mill or chipper, for reducing the particle size of the biomass feedstock.

[0152] In some examples, the system may further include a heating means for reducing the moisture content of the biomass feedstock to less than 10% by weight. The heating means may be selected from a vacuum oven, a rotary dryer, a flash dryer, or a heat exchanger, e.g., a continuous belt dryer. Preferably, the heating means is configured to indirectly heat the biomass feedstock, e.g., the heating means may be selected from an indirectly heated belt dryer, an indirectly heated fluidized bed, or an indirectly heated contact rotary steam tube dryer.

[0153] According to the present invention, the heating element may be configured to heat the biomass feedstock to a temperature of at least 1000°C, more preferably at least 1100°C, such as 1120°C, 1150°C, or 1200°C.

[0154] The heating element may comprise microwave assisted heating, a heating jacket, a solid heat carrier, a tubular furnace or an electric heater, preferably the heating element comprises a tubular furnace.

[0155] Alternatively or additionally, a heating element may be disposed within the reactor and configured to directly heat the biomass feedstock. By way of example, the heating element may be selected from an electric heating element, such as an electric spiral heater. Preferably, two or more electric spiral heaters may be disposed within the reactor.

[0156] The biomass feedstock may be transported continuously through the reactor, for example, the biomass material may be contained on / in a conveyor, such as a screw conveyor or a rotating belt. Optionally, two conveyors may be configured to transport the biomass material continuously through the reactor.

[0157] The reactor may be arranged such that the biomass material is heated under atmospheric pressure. Alternatively, the reactor may be arranged to create low pressure conditions, e.g., 850-1,000 Pa, preferably 900-950 Pa. The reactor may be configured such that the reactor is maintained under vacuum to aid in the removal of pyrolysis gases that are formed. Preferably, the reactor is configured to use the application of vacuum to continuously transport the biomass material in a countercurrent direction to any pyrolysis gases that are removed from the reactor. In this way, any solid material that is formed as a result of heating, such as biochar, is removed separately from the pyrolysis gases that are formed.

[0158] According to the present invention, the system may further comprise cooling means for condensing the pyrolysis gases formed in the reactor to produce the hydrocarbon feedstock product and non-condensable light gases.

[0159] The system may further comprise means for separating the pyrolysis gases formed, for example by distillation.

[0160] The separator may be configured to separate the biochar from the hydrocarbon feedstock product. For example, the separator may include a filtration means (e.g., using a ceramic filter), a centrifuge, or a cyclone or gravimetric separation.

[0161] Additionally or alternatively, the separator may include means for at least partially separating water from the hydrocarbon feedstock product. For example, the separator may include a gravity oil separator, a centrifuge, a cyclone, or a microbubble separation means.

[0162] Additionally or alternatively, the separator may include means for at least partially separating non-condensable light gases from the hydrocarbon feedstock product, for example the separator may be arranged so that the hydrocarbon feedstock product undergoes flash distillation or fractionation.

[0163] The separator may be configured such that any non-condensable light gases separated from the hydrocarbon feedstock product are recycled to the biomass feedstock before entering the reactor.

[0164] Alternatively or additionally, where the separator may be arranged to at least partially separate the carbon monoxide from the non-condensable gases formed. The system may further comprise means for converting the at least partially separated carbon monoxide to hydrogen gas and carbon dioxide via a water-gas shift reaction. In particular, the reactor may be configured to contact the separated carbon monoxide with steam. The reactor further comprises a heating element configured to heat the carbon monoxide and steam to a temperature between 205°C and 482°C, more preferably between 205°C and 260°C. In some examples, the reactor comprises a shift catalyst selected from a copper-zinc-aluminum catalyst or a chromium or copper promoted iron-based catalyst. Preferably, the catalyst is selected from a copper-zinc-aluminum catalyst.

[0165] The separator may be configured to recycle any hydrogen gas that is formed to the hydrocracking reactor.

[0166] According to the present invention, the system may include means for further processing the formed hydrocarbon feedstock product. By way of example, the system may be arranged to remove contaminants present in the hydrocarbon feedstock, such as carbon, graphene and tar. Preferably, the system further includes a filter, such as a membrane filter, which can be used to remove larger contaminants present. Additionally or alternatively, the system may further include a microfiltration means, such as a Nutsche filter, for removing small contaminants suspended in the hydrocarbon feedstock. Alternatively or additionally, the system may be arranged to contact the hydrocarbon feedstock with an activated carbon compound and / or a cross-linked organic hydrocarbon resin for further processing the generated hydrocarbon feedstock product. The activated carbon and / or cross-linked organic hydrocarbon resin may be in particulate or pellet form to increase contact between the adsorbent and the hydrocarbon feedstock, thereby reducing the time required to achieve a desired level of contaminant removal. The hydrocarbon feedstock product may be contacted with the activated carbon and / or cross-linked organic hydrocarbon resin at about atmospheric pressure (including essentially atmospheric conditions).

[0167] In some examples, the system may be configured so that the hydrocarbon feedstock product is passed through the further processing means two or more times.

[0168] The hydrocracking reactor may be configured to heat the hydrocarbon feedstock and hydrogen gas to a temperature between 200°C and 700°C, preferably between 250°C and 550°C, and more preferably between 300°C and 300°C to produce a bio-oil comprising one or more cracked hydrocarbon products.

[0169] Furthermore, the hydrocracking reactor may be configured to create pressure conditions of 1 MPa to 28 MPa, preferably 5 MPa to 20 MPa, and more preferably 10 MPa to 17 MPa.

[0170] Additionally or alternatively, the hydrocracking reactor may be configured to react with the hydrogen-containing gas and / or the hydrocarbon feedstock for 0.1 to 30 hours. -1 , preferably 0.2 to 10 hours -1 , more preferably 0.3 to 5 hours -1 The mixture may be arranged so that it can be contacted with the hydrocracking catalyst at a liquid hourly space velocity of at least about 1000 rpm.

[0171] In some embodiments, the hydrocracking reactor is selected from catalytic reactors such as fixed bed reactors, trickle bed reactors, fluidized bed reactors, or tubular reactors such as coiled tube reactors, U-tube reactors, or straight tube reactors. The hydrocracking catalyst is preferably as defined above. When the hydrocracking reactor is a tubular reactor, the tube may have a diameter in the range of 1.5 to 20 cm, preferably 2 to 10 cm.

[0172] In some embodiments, the system may include a single hydrocracking reactor, or the system may include a series of fluidly connected hydrocracking reactors, e.g., two or more fluidly connected hydrocracking reactors. In embodiments where the system includes a series of fluidly connected hydrocracking reactors, the hydrocracking reactor may further include a means for quenching the temperature of the hydrocarbon feed between one or more of the series of fluidly connected hydrocracking reactors. For example, the quenching means may include an inlet suitable for introducing fresh hydrogen and / or recycled hydrocarbon feedstock having a reduced temperature.

[0173] Optionally, the system may be configured to at least partially remove hydrogen gas and / or carbon dioxide in the bio-oil formed. The means for at least partially removing hydrogen gas and / or carbon dioxide may be selected from any means known in the art, and by way of example, the means for at least partially removing hydrogen gas and / or carbon dioxide may be a flash separator configured to function at about ambient pressure (including essentially atmospheric conditions). In some embodiments, the means for at least partially removing hydrogen gas and / or carbon dioxide includes a vacuum, and preferably the vacuum is configured to apply a vacuum pressure of less than 6 KPaA, more preferably a vacuum pressure of less than 5 KPaA, and even more preferably a vacuum pressure of less than 4 KPaA. Alternatively, the means for at least partially removing hydrogen gas and / or carbon dioxide may be a fractionation device.

[0174] The system may further comprise a means for at least partially removing sulfur-containing components from the bio-oil or bio-derived diesel fuel fraction formed. The means for at least partially removing sulfur-containing components from the hydrocarbon feedstock may comprise an inlet for feeding hydrogen gas to the reactor. The reactor may also comprise a hydrodesulfurization catalyst, preferably a hydrodesulfurization catalyst as defined above. In some examples, the means for at least partially removing sulfur components from the hydrocarbon feedstock may comprise a heating body arranged to heat the hydrocarbon feedstock to a temperature between 250°C and 400°C, preferably between 300°C and 350°C. Optionally, the heating body may be arranged to heat the hydrocarbon feedstock to the required temperature before entering the reactor, for example the heating body may be selected from a heat exchanger. Alternatively, the heating body may be arranged to heat the hydrocarbon feedstock to the required temperature after contact with the hydrogen gas and, if present, the hydrodesulfurization catalyst. If the hydrocarbon feed is heated after entering the reactor, the heating body may be selected from any of the direct or indirect heating methods defined above. In some examples, the means for at least partially removing sulfur-containing components from the hydrocarbon feedstock may be maintained under a pressure of from 4 to 6 MPaG, preferably from 4.5 to 5.5 MPaG, and more preferably about 5 MPaG.

[0175] The reactor may further include means for removing hydrogen sulfide gas formed during the desulfurization process, for example, the reactor may further include a gas separator configured to provide a slight vacuum, for example a vacuum pressure of less than 6 KPaA, more preferably a vacuum pressure of less than 5 KPaA, even more preferably a vacuum pressure of less than 4 KPaA, to assist in the removal of hydrogen sulfide gas present.

[0176] The system may further include cooling means, for example a heat exchanger, for cooling the sulfur-reduced hydrocarbon feed before further processing steps are carried out.

[0177] Optionally, the system may further comprise means for partially vaporizing the sulfur-reduced hydrocarbon feedstock to remove traces of hydrogen sulfide present. By way of example, the means for partially vaporizing may comprise a flash separator maintained at ambient pressure, and a degasser for removing vaporized hydrogen sulfide. The means for partially vaporizing may comprise a heater configured to heat the hydrocarbon feedstock to a temperature between 60° C. and 120° C., more preferably to a temperature between 80° C. and 100° C., during the degassing step. Optionally, the degasser may be maintained under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0178] Preferably, the reactor is configured to recycle any unreacted hydrogen gas present after the desulfurization step back into the biogenic hydrocarbon feedstock entering the reactor, thus reducing the amount of hydrogen gas required to remove sulfur-containing components in the biogenic hydrocarbon feedstock and providing a more cost-effective system.

[0179] In some examples, the reactor is configured so that the hydrocarbon feedstock flows through the means for at least partially removing sulfur-containing components two or more times.

[0180] Additionally or alternatively, the system may further comprise a means for hydrotreating the bio-oil formed. The means for hydrotreating the hydrocarbon feedstock may comprise a hydrotreating catalyst, for example a hydrotreating catalyst as defined above. The means for hydrotreating may further comprise a heating element arranged to heat the hydrocarbon feedstock to a temperature between 250°C and 350°C, preferably between 270°C and 330°C, more preferably between 280°C and 320°C. Optionally, the heating element may be arranged to heat the hydrocarbon feedstock to the required temperature before contacting the means for hydrotreating the hydrocarbon feedstock, for example the heating element may be selected from a heat exchanger. Alternatively, the heating element may be arranged to heat the hydrocarbon feedstock to the required temperature after contacting with the hydrogen gas and, if present, the hydrotreating catalyst. If the hydrocarbon feed is heated subsequent to contacting the hydrotreating means, the heating element may be selected from any of the direct or indirect heating methods defined above. In some examples, when used to carry out a hydrotreating step, the reactor may be maintained under a pressure of 4 to 6 MPaG, preferably 4.5 to 5.5 MPaG, and more preferably about 5 MPaG.

[0181] The system may further include cooling means, e.g., a heat exchanger, for cooling the reduced hydrotreated hydrocarbon feed before further processing steps are carried out.

[0182] Optionally, the system may include means for at least partially separating the LPG gas from the bio-oil. In particular, the system may further include degassing means, such as a gas condenser and / or a gas separator. In some examples, the degassing means is configured to apply a vacuum pressure to the bio-oil. More preferably, the degassing means is configured to apply a vacuum pressure of less than 6 KPaA, more preferably less than 5 KPaA, even more preferably less than 4 KPaA to at least partially remove the LPG gas.

[0183] The separator may be configured to separate a first fractional cut of the refined bio-oil at atmospheric pressure (i.e., approximately 101.3 KPa) and having a cut point between 30° C. and 220° C., preferably between 50° C. and 210° C., for example between 70° C. and 200° C. Alternatively, the separator may be configured and arranged such that the first fractional cut is separated at a pressure between 850 and 1000 Pa, preferably between 900 and 950 Pa.

[0184] The separator may further comprise means for cooling the first fraction cut, for example the cooling means may be selected from a heat exchanger.

[0185] Optionally, the separator may also be configured to separate a second fractional cut having a cut point between 280° C. and 320° C., preferably between 290° C. and 310° C., and more preferably about 300° C. The second fractional cut generally comprises bio-derived jet fuel.

[0186] The separator may be configured to verify that any remaining bio-oil in the underflow is bio-diesel.

[0187] In some embodiments, the separator is selected from a fractionation column.

[0188] The present invention as defined herein is illustrated in the accompanying drawings, in which: [Brief description of the drawings]

[0189] [Figure 1] FIG. 1 is a flow diagram of a process for forming biodiesel fuel from a biomass feedstock in accordance with the present invention. [Diagram 2] FIG. 1 is a flow diagram of a process for forming biodiesel fuel from a biologically derived hydrocarbon feedstock in accordance with the present invention. [Figure 3-1] ~ [Figure 3-2] FIG. 1 is a flow diagram of a known method for forming fuels based on a hydrocracking process. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0190] 1 shows a simplified process (10) for forming biodiesel fuel from a biomass feedstock via a hydrocracking reactor. Process steps shown in dashed lines should be understood to be optional process steps.

[0191] The biomass feed stream (12) is fed to a feed oven or dryer (14) to ensure that the moisture content of the biomass feedstock is 10% or less by weight of the biomass feedstock. The feed oven or dryer may further include an outlet (16) for separating any water vapor removed from the biomass material. The low moisture biomass material may then be fed to a pyrolysis reactor (18) where the low moisture biomass material is heated to a temperature of at least 1000°C, more preferably at least 1100°C, e.g., 1120°C, 1150°C, or 1200°C. The biomass material may be pyrolyzed under low pressure, e.g., 850-1,000 Pa, preferably 900-950 Pa. The pyrolysis reactor further includes an inlet (20) for supplying an inert gas, such as nitrogen or argon, to the pyrolysis reactor before the pyrolysis step is carried out. The resulting pyrolysis gases may then be removed from the pyrolysis reactor via outlet (22). The pyrolysis reactor includes a further outlet (24) for removing any residual solids formed during the pyrolysis reaction, such as biochar. The hydrocarbon feedstock products may be at least partially separated from the formed biochar using filtration methods (e.g., using ceramic filters), centrifugation, cyclones or gravity separation.

[0192] The pyrolysis gases extracted from the pyrolysis reactor (22) are transferred to a cooling means (26) for condensing the pyrolysis gases formed to produce a hydrocarbon feedstock product and non-condensable light gases, which are then fed to a distillation column (28), where the non-condensable light gases are removed from the top of the distillation column (30) and the hydrocarbon feedstock is removed from the bottom of the distillation column (32). The non-condensable light gases (30) separated from the hydrocarbon feedstock product may be at least partially recycled to the low moisture biomass feed stream (18). The separated hydrocarbon feedstock (32) is fed to a separator (34) to at least partially separate water from the hydrocarbon feedstock product (32). For example, the separator may comprise a gravity oil separator, a centrifuge, a cyclone or a microbubble separation means. The separator comprises a first outlet (36) through which water may be removed from the hydrocarbon feedstock and a second outlet (38) through which a water-reduced hydrocarbon feedstock may be obtained.

[0193] The water-reduced hydrocarbon feedstock may be fed to a reactor (40) for at least partial removal of contaminants contained therein, such as carbon, graphene, polyaromatic compounds and tars. The reactor may include filters, such as membranes or nutsches, for removing larger and smaller contaminants, respectively. Alternatively or additionally, activated carbon compounds and / or cross-linked organic hydrocarbon resins for removing contaminants, such as polycyclic aromatic compounds. As an alternative to activated carbon, the reactor may include biochar for removing contaminants from the low moisture hydrocarbon feed. The reactor includes an outlet (42) for separating contaminants from the hydrocarbon feedstock. If the contaminants separated from the hydrocarbon feedstock include tars, the separated tars may be at least partially recycled and combined with the low moisture biomass feed stream (18).

[0194] The treated hydrocarbon feedstock (44) is then fed to a hydrocracking reactor (46). An example of a hydrocracking system is also shown in FIG. 3. FIG. 1 shows that the hydrocracking reactor includes a hydrocracking catalyst and an inlet (48) for feeding a hydrogen-containing gas to the hydrocracking reactor (46). The reactor heats the treated hydrocarbon feedstock (44), the hydrocracking catalyst, and the hydrogen-containing gas (48) to a temperature between 200° C. and 700° C., preferably between 250° C. and 550° C., and more preferably between 300° C. and 300° C., to produce a bio-oil containing one or more cracked hydrocarbon products.

[0195] The hydrocracking process may be carried out at a pressure of from 1 MPa to 28 MPa, preferably from 5 MPa to 20 MPa, more preferably from 10 MPa to 17 MPa.

[0196] Additionally or alternatively, the hydrogen-containing gas and / or the hydrocarbon feedstock may be subjected to a process for producing a hydrogen-containing gas having a hydrogen permeability of 0.1 to 30 h. -1 , preferably 0.2 to 10 hours -1 , more preferably 0.3 to 5 hours -1 The mixture may be contacted with the hydrocracking catalyst at a liquid hourly space velocity of

[0197] The formed bio-oil (50) may be further processed using a separator (52), such as a flash separator, to at least partially remove hydrogen gas and / or carbon dioxide present in the bio-oil. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0198] The separated hydrogen gas and / or carbon dioxide gas (54) is then at least partially recycled to the treated hydrocarbon feedstock (44).

[0199] The degassed bio-oil (56) is fed to a desulfurization reactor (58) containing a hydrodesulfurization catalyst, where the desulfurization reactor further includes an inlet (60) for feeding a hydrogen-containing gas to the reactor. The desulfurization reactor heats the bio-oil, hydrogen-containing gas and hydrodesulfurization catalyst to a temperature between 250°C and 400°C, preferably between 300°C and 350°C.

[0200] The desulfurization step may be carried out at a pressure of 4-6 MPaG, preferably 4.5-5.5 MPaG, more preferably about 5 MPaG.

[0201] The desulfurization reactor may further comprise a gas separator for at least partially removing hydrogen sulfide formed from the bio-oil. Optionally, the sulfur-reduced bio-oil may then be cooled by any suitable means known in the art, for example by use of a heat exchanger. Traces of hydrogen sulfide remaining in the sulfur-reduced bio-oil may then be at least partially removed, for example by partial vaporization by use of a flash separator at about ambient pressure, and removal of the vaporized hydrogen sulfide by degassing. Preferably, the bio-oil has a temperature between 60°C and 120°C during the degassing step, more preferably the bio-oil has a temperature between 80°C and 100°C. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0202] Any unreacted hydrogen-rich gas (62) removed during the degassing step may be separated from the hydrogen sulfide, for example, by use of an amine contactor. The separated gas is then at least partially recycled and combined with the treated hydrocarbon feedstock (44).

[0203] The sulfur-reduced bio-oil is then fed to a hydrotreating reactor (64) containing a hydrotreating catalyst to reduce the number of unsaturated hydrocarbon functional groups present in the bio-oil and to favorably convert the bio-oil into more stable fuels having higher energy density.

[0204] The hydrotreating reactor further comprises an inlet (66) for supplying a hydrogen-containing gas to the reactor. The hydrotreating reactor heats the bio-oil, the hydrogen-containing gas and the hydrotreating catalyst to a temperature of 250°C to 350°C, preferably 270°C to 330°C, more preferably 280°C to 320°C.

[0205] The hydrotreating step may be carried out at a reaction pressure of 4 MPaG to 6 MPaG, preferably 4.5 MPaG to 5.5 MPaG, more preferably about 5 MPaG.

[0206] The hydrotreated bio-oil (68) is then transferred to a fractionation column (70) which separates a first fractional cut of the refined bio-oil (72) at atmospheric pressure (including essentially atmospheric conditions) and with a cut point between 30° C. and 220° C., preferably between 50° C. and 210° C., for example between 70° C. and 200° C. In some examples, the separator further comprises cooling means for cooling and condensing the separated first fractional cut.

[0207] The fractionation column forms a second fractional cut (74) of the refined bio-oil with a cut point between 280°C and 320°C, preferably between 290°C and 310°C, more preferably about 300°C. Again, the separator may further include means for cooling and condensing the second fractional cut, e.g., a condenser. The produced second fractional cut (74) is bio-based jet fuel, preferably A1 grade bio-based jet fuel. The fractionation column further includes an outlet (76) for collecting a bottom stream after the second fractional cut, the bottom stream being bio-based diesel fuel.

[0208] Either via the desulfurization reactor (58) or instead of this desulfurization step, the bio-derived diesel fuel (76) may be fed to a desulfurization reactor (78) as defined above, in order to at least partially remove sulfur-containing components in the biofuel, in addition to reducing the sulfur-containing compounds in the bio-oil.

[0209] 2 shows an alternative simplified process (110) for forming a biodiesel fuel from a biologically derived hydrocarbon feedstock. Process steps shown in dashed lines should be understood to be optional process steps.

[0210] At least 0.1% by weight of one or more C8 compounds, at least 1% by weight of one or more C 10 Compounds, at least 5% by weight of one or more of C 12 Compounds, at least 5% by weight of one or more of C 16 Compound, and at least 30% by weight of at least one or more C 18 A bio-based hydrocarbon feedstock (144) containing compounds is fed to a hydrocracking reactor (146). An example of a hydrocracking system is also shown in FIG. 3. FIG. 2 shows that the hydrocracking reactor includes a hydrocracking catalyst and an inlet (148) for feeding a hydrogen-containing gas to the hydrocracking reactor (146). The reactor heats the bio-based hydrocarbon feedstock (144), the hydrocracking catalyst, and the hydrogen-containing gas (148) to a temperature between 200° C. and 700° C., preferably between 250° C. and 550° C., and more preferably between 300° C. and 300° C., to produce a bio-oil containing one or more cracked hydrocarbon products.

[0211] The hydrocracking process may be carried out at a pressure of from 1 MPa to 28 MPa, preferably from 5 MPa to 20 MPa, more preferably from 10 MPa to 17 MPa.

[0212] Additionally or alternatively, the hydrogen-containing gas and / or the hydrocarbon feedstock may be subjected to a process for producing a hydrogen-containing gas having a hydrogen permeability of 0.1 to 30 h. -1 , preferably 0.2 to 10 hours -1 , more preferably 0.3 to 5 hours -1 The mixture may be contacted with the hydrocracking catalyst at a liquid hourly space velocity of

[0213] The formed bio-oil (150) may be further processed using a separator (152), such as a flash separator, to at least partially remove hydrogen gas and / or carbon dioxide present in the bio-oil. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0214] The separated hydrogen gas and / or carbon dioxide gas (154) may then be at least partially recycled to the treated hydrocarbon feedstock (144).

[0215] The degassed bio-oil (156) is fed to a desulfurization reactor (158) containing a hydrodesulfurization catalyst, where the desulfurization reactor further includes an inlet (160) for feeding a hydrogen-containing gas to the reactor. The desulfurization reactor heats the bio-oil, hydrogen-containing gas, and hydrodesulfurization catalyst to a temperature between 250°C and 400°C, preferably between 300°C and 350°C.

[0216] The desulfurization step may be carried out at a pressure of 4-6 MPaG, preferably 4.5-5.5 MPaG, more preferably about 5 MPaG.

[0217] The desulfurization reactor may further comprise a gas separator for at least partially removing hydrogen sulfide formed from the bio-oil. Optionally, the sulfur-reduced bio-oil may then be cooled by any suitable means known in the art, for example by use of a heat exchanger. Traces of hydrogen sulfide remaining in the sulfur-reduced bio-oil may then be at least partially removed by partial vaporization, for example by use of a flash separator at about ambient pressure, and removal of the vaporized hydrogen sulfide by degassing. Preferably, the bio-oil has a temperature between 60°C and 120°C during the degassing step, more preferably the bio-oil has a temperature between 80°C and 100°C. The degassing step may be carried out under vacuum, preferably under a vacuum pressure of less than 6 KPaA, more preferably under a vacuum pressure of less than 5 KPaA, even more preferably under a vacuum pressure of less than 4 KPaA.

[0218] Any unreacted hydrogen-rich gas (162) removed during the degassing step may be separated from the hydrogen sulfide, for example, by use of an amine contactor. The separated gas is then at least partially recycled and combined with the treated hydrocarbon feedstock (144).

[0219] The sulfur-reduced bio-oil is then fed to a hydrotreating reactor (164) containing a hydrotreating catalyst to reduce the number of unsaturated hydrocarbon functional groups present in the bio-oil and to favorably convert the bio-oil into more stable fuels having higher energy density.

[0220] The hydrotreating reactor further comprises an inlet (166) for supplying a hydrogen-containing gas to the reactor. The hydrotreating reactor heats the bio-oil, the hydrogen-containing gas and the hydrotreating catalyst to a temperature of 250°C to 350°C, preferably 270°C to 330°C, and more preferably 280°C to 320°C.

[0221] The hydrotreating step may be carried out at a reaction pressure of 4 MPaG to 6 MPaG, preferably 4.5 MPaG to 5.5 MPaG, more preferably about 5 MPaG.

[0222] The hydrotreated bio-oil (168) is then fed to a fractionation column (170) which separates a first fractional cut of the refined bio-oil (172) at atmospheric pressure (essentially including atmospheric pressure) and a cut point between 30° C. and 220° C., preferably between 50° C. and 210° C., for example between 70° C. and 200° C. In some examples, the separator further comprises cooling means for cooling and condensing the separated first fractional cut.

[0223] The fractionation column forms a second fractional cut (174) of the refined bio-oil with a cut point between 280°C and 320°C, preferably between 290°C and 310°C, and more preferably about 300°C. Again, the separator may further include means for cooling and condensing the second fractional cut, e.g., a condenser. The produced second fractional cut (174) is bio-based jet fuel, preferably A1 grade bio-based jet fuel. The fractionation column further includes an outlet (176) for collecting a bottom stream after the second fractional cut, the bottom stream being bio-based diesel fuel.

[0224] Either via the desulfurization reactor (158) or instead of this desulfurization step, the bio-derived diesel fuel (176) may be fed to a desulfurization reactor (178) as defined above, in order to at least partially remove sulfur-containing components in the biofuel, in addition to reducing the sulfur-containing compounds in the bio-oil.

Claims

1. 1. A method for forming a biodiesel fuel from a biomass feedstock, comprising: a. providing a biomass feedstock; b. ensuring that the moisture content of the biomass feedstock is less than or equal to 10% by weight of the biomass feedstock; c. pyrolyzing the low moisture biomass feedstock at a temperature of at least 950° C. to form a mixture of biochar, hydrocarbon feedstock, non-condensable light gases such as hydrogen, carbon monoxide, carbon dioxide and methane, and water; d. separating said hydrocarbon feedstock from said mixture formed in step c.; e. hydrocracking the hydrocarbon feedstock of step d. in the presence of a hydrocracking catalyst and a hydrogen-containing gas to produce a bio-oil; and f. fractionating the resulting bio-oil to obtain a bio-derived diesel fuel fraction. The method comprising:

2. the biomass feedstock comprises a cellulosic, hemicellulose or lignin based feedstock; and / or The biomass feedstock is a non-food crop biomass feedstock, preferably the non-crop biomass feedstock is selected from Miscanthus, switchgrass, yard clippings, straw (e.g., rice straw or wheat straw), cotton gin waste, municipal solid waste, palm leaves / empty fruit bunches (EFB), palm seed shells, bagasse, wood (e.g., hickory, pine bark, Virginia pine, red oak, white oak, spruce, poplar, and cedar), pasture hay, mesquite, wood flour, nylon, lint, bamboo, paper, corn stalks, or combinations thereof; The method of claim 1.

3. The biomass feedstock is in the form of pellets, chips, particles or powder, preferably said pellets, chips, particles or powder have a diameter of from 5 μm to 10 cm, such as from 5 μm to 25 mm, preferably from 50 μm to 18 mm, more preferably from 100 μm to 10 mm, e.g. The pellets, chips, particles or powder have a diameter of at least 1 mm, e.g., from 1 mm to 25 mm, from 1 mm to 18 mm, or from 1 mm to 10 mm; The method according to claim 1 or 2.

4. the initial moisture content of the biomass feedstock is at most 50% by weight of said biomass feedstock, such as at most 45% by weight of said biomass feedstock, or such as at most 30% by weight of said biomass feedstock; and / or The moisture content of the biomass feedstock is reduced to 7% or less, such as 5% or less, by weight of the biomass feedstock; The method according to any one of claims 1 to 3.

5. Ensuring a moisture content of the biomass feedstock is 10% or less by weight of the biomass feedstock may comprise reducing the moisture content of the biomass feedstock, e.g. by: The moisture content of the biomass feedstock is reduced by the use of a vacuum oven, a rotary dryer, a flash dryer, or a heat exchanger, such as a continuous belt dryer, preferably the moisture content of the biomass feedstock is reduced by the use of indirect heating, such as by using an indirectly heated belt dryer, an indirectly heated fluidized bed, or an indirectly heated contact rotary steam tube dryer; The method according to any one of claims 1 to 4.

6. A method according to any preceding claim, wherein the low moisture biomass feedstock is pyrolysed at a temperature of at least 1000°C, more preferably at least 1100°C.

7. Heat can be provided to the pyrolysis step by convection heating, microwave heating, electrical heating or supercritical heating, e.g. The heat source includes microwave assisted heating, a heating jacket, a solid heat carrier, a tubular furnace or an electric heater, preferably the heat source is a tubular furnace, e.g. the heat source is disposed inside the reactor, preferably the heat source comprises one or more electric spiral heaters, e.g., a plurality of electric spiral heaters; The method according to any one of claims 1 to 6.

8. The low-moisture biomass is pyrolyzed at atmospheric pressure, or the low-moisture biomass is pyrolyzed under a pressure of 850 to 1000 Pa, preferably 900 to 950 Pa, optionally separating the pyrolysis gases formed by distillation, and / or The low moisture biomass feedstock is pyrolyzed for a time period of from 10 seconds to 2 hours, preferably from 30 seconds to 1 hour, more preferably from 60 seconds to 30 minutes, for example from 100 seconds to 10 minutes; The method according to any one of claims 1 to 7.

9. The pyrolysis reactor may be arranged such that the low moisture biomass is conveyed in a countercurrent direction to any pyrolysis gases formed, and optionally biochar formed as a result of the pyrolysis step leaves the pyrolysis reactor separately from said pyrolysis gases, e.g. The pyrolysis gas is then cooled, for example by use of a venturi, to condense the hydrocarbon feedstock products. The method according to any one of claims 1 to 8.

10. and / or step d. comprises at least partially separating the biochar from the hydrocarbon feedstock product, preferably by filtration (e.g., by use of a ceramic filter), centrifugation, or cyclone or gravity separation; and / or step d. comprises at least partially separating water from the hydrocarbon feedstock product, preferably said at least partially separated water further comprises organic contaminants, more preferably said water is at least partially separated from said hydrocarbon feedstock product by gravity oil separation, centrifugation, cyclone or microbubble separation; and / or Step d. comprises at least partially separating non-condensable light gases from the hydrocarbon feedstock product, preferably said non-condensable light gases are at least partially separated by use of flash distillation or fractional distillation, preferably In step c., the separated non-condensable light gases are recycled and, optionally, combined with the low moisture biomass feedstock; or Carbon monoxide present in the non-condensable light gases is contacted with steam in a water gas shift reaction to produce carbon dioxide and biogenic hydrogen gas, preferably the water gas shift reaction is carried out at a temperature of from 205°C to 482°C, more preferably at a temperature of from 205°C to 260°C, e.g. The water gas shift reaction further comprises a shift catalyst, preferably the shift catalyst is selected from a copper-zinc-aluminum catalyst or a chromium or copper promoted iron based catalyst, more preferably the shift catalyst is a copper-zinc-aluminum catalyst. The method according to any one of claims 1 to 9.

11. The method further comprises a step of filtering the hydrocarbon feedstock product to at least partially remove contaminants such as carbon, graphene, polyaromatic compounds and / or tars contained therein, preferably said filtering step comprising the use of a membrane filter to remove larger contaminants and / or microfiltration to remove smaller contaminants, for example by using a Nutsche filter, e.g. The filtering step may include contacting the hydrocarbon feedstock product with an activated carbon compound and / or a cross-linked organic hydrocarbon resin, followed by separating the hydrocarbon feedstock product from the activated carbon and / or cross-linked organic hydrocarbon resin compound by filtering, e.g. contacting the activated carbon compound and / or crosslinked organic hydrocarbon resin with a hydrocarbon feedstock product under ambient conditions; and / or The activated carbon compound and / or crosslinked organic hydrocarbon resin is contacted with the hydrocarbon feedstock product for at least 15 minutes, preferably at least 20 minutes, more preferably at least 25 minutes, prior to separation; and / or The step of filtering the hydrocarbon feedstock is carried out once or repeated one or more times; The method according to any one of claims 1 to 10.

12. 12. The method of claim 11, wherein in step c., tar removed from the hydrocarbon feedstock is recycled and optionally combined with the low moisture biomass feedstock.

13. 1. A method for forming a biodiesel fuel from a biologically derived hydrocarbon feedstock, comprising: i. providing a biologically derived hydrocarbon feedstock obtained by the method of steps a. to d. of claim 1; ii. hydrocracking the hydrocarbon feedstock of step i. in the presence of a hydrocracking catalyst and a hydrogen-containing gas to produce a bio-oil; and iii. fractionating the resulting bio-oil to obtain a bio-derived diesel fuel fraction. The method comprising:

14. the hydrocracking step is carried out at a temperature of from 200° C. to 700° C., preferably from 250° C. to 550° C., more preferably from 300° C. to 500° C., and / or under a pressure of from 1 MPa to 28 MPa, preferably from 5 MPa to 20 MPa, more preferably from 10 MPa to 17 MPa; and / or contacting the hydrocarbon feedstock and the hydrogen-containing gas with the hydrocracking catalyst at a liquid hourly space velocity of from 0.1 to 30 hr −1 , preferably from 0.2 to 10 hr −1 , more preferably from 0.3 to 5 hr −1 ; The method according to any one of claims 1 to 13.

15. The hydrocracking catalyst is contained in a catalytic reactor, such as a fixed bed reactor, a trickle bed reactor, a fluidized bed reactor, or a tubular reactor, such as a coiled tube reactor, a U-tube reactor, or a straight tube reactor; and / or the hydrocracking catalyst is in the form of pellets, particles or powder, preferably the pellets, particles or powder have a diameter of 0.5 to 5 mm, preferably 0.8 to 3.5 mm; and / or the hydrocracking catalyst has a surface area of ​​100 m 2 / g to 800 m 2 / g, preferably 150 m 2 / g to 700 m 2 / g, more preferably 200 m 2 / g to 600 m 2 / g; The method according to any one of claims 1 to 14.

16. The hydrocracking catalyst is a bifunctional catalyst comprising one or more metals selected from Groups VB, VIB, VIIB and / or VIII of the Periodic Table on an acidic support material, such as The metal is present in an amount of 0.1 to 20 wt %, preferably 0.1 to 10 wt %, more preferably 0.5 to 5 wt %, based on the total weight of the hydrocracking catalyst, and preferably The hydrocracking catalyst comprises a metal selected from the group consisting of iron, nickel, palladium, platinum, rhodium, iridium, cobalt, tungsten, molybdenum, vanadium, ruthenium, and mixtures thereof contained on a support material, e.g. The acidic support material is selected from zeolites, molecular sieves, silica-alumina, alumina, silica, silica nitride, silica borate, alumina oxide, boron nitride, zirconia, titania, ceria, carbon (such as activated carbon), boria, ferrierite and zirconia-alumina, preferably the acidic support material is selected from beta zeolite, Y zeolite, MFI zeolite, ALP0-31, SAP0-11, SAP0-31, SAP0-37, SAP0-41, SM-3, MgAPS0-31, FU-9, NU-10, NU-23, ZSM-12, ZSM-22, ZSM-2 3, ZSM-35, ZSM-48, ZSM-50, ZSM-57, MeAP0-11, MeAP0-31, MeAP0-41, MeAPS0-11, MeAPS0-31, MeAPS0-41, MeAPS0-46, ELAP0-11, ELAP0-31, ELAP0-41, ELAPS0-11, ELAPS0-31, ELAPS0-41, laumontite, cancrinite, offretite, hydrogen form of stilbite, magnesium or calcium form of mordenite, and magnesium or calcium form of partite, or combinations thereof; The method according to any one of claims 1 to 15.

17. contacting the hydrocarbon feedstock and the hydrogen-containing gas simultaneously with a hydrocracking catalyst; and / or the hydrocarbon feedstock is preheated before contacting the hydrocracking catalyst, preferably the hydrocarbon feedstock is preheated to a temperature of from 150° C. to 650° C., more preferably from 200° C. to 500° C.; The method according to any one of claims 1 to 16.

18. The method further comprises at least partially removing the hydrogen gas and / or carbon dioxide contained in the bio-oil formed, preferably by using flash distillation or fractional distillation, and preferably The separated hydrogen gas is at least partially recycled to the hydrocracking process step. The method according to any one of claims 1 to 17.

19. Further comprising at least partially removing sulfur-containing components from the formed bio-oil and / or the formed bio-derived diesel fuel fraction, e.g. The sulfur removal step includes a catalytic hydrodesulfurization step, for example The catalyst is part of a fixed bed or trickle bed reactor, and preferably the catalyst is selected from nickel molybdenum sulfide (NiMoS), molybdenum, molybdenum disulfide (MoS 2 ), cobalt / molybdenum, cobalt molybdenum sulfide (CoMoS) and / or nickel / molybdenum based catalysts, preferably the catalyst is selected from nickel molybdenum sulfide (NiMoS) based catalysts, preferably the catalyst is a supported catalyst such as with a support selected from activated carbon, silica, alumina, silica-alumina, molecular sieves and / or zeolites; The method according to any one of claims 1 to 18.

20. 20. The method according to any of claims 19, wherein the hydrodesulfurization step is carried out at a temperature of from 250°C to 400°C, preferably from 300°C to 350°C; and / or the hydrodesulfurization step is carried out at a reaction pressure of from 4 to 6 MPaG, preferably from 4.5 to 5.5 MPaG, more preferably about 5 MPaG.

21. The catalytic hydrodesulfurization process further comprises the step of degassing the sulfur-reduced bio-oil and / or diesel fuel fraction to remove hydrogen sulfide gas, for example by cooling the sulfur-reduced bio-oil and / or diesel fuel fraction to a temperature of 60-120° C., preferably 80-100° C., and optionally applying a vacuum pressure of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA, and optionally The degassing step removes hydrogen formed during the catalytic hydrodesulfurization process, and optionally the removed hydrogen is recycled to the hydrocracking process step.

21. The method of claim 19 or 20.

22. The method further comprises hydrotreating the bio-oil formed, for example by the hydrotreating step is carried out at a temperature of from 250°C to 350°C, preferably from 270°C to 330°C, more preferably from 280°C to 320°C; and / or the hydrotreating step is carried out under a pressure of from 4 MPaG to 6 MPaG, preferably from 4.5 MPaG to 5.5 MPaG; The method according to any one of claims 1 to 21.

23. The hydrotreating process further comprises a catalyst, for example as part of a fixed bed or trickle bed reactor, preferably The catalyst comprises a metal selected from groups IIIB, IVB, VB, VIB, VIIIB and VIII of the periodic table, preferably a metal selected from group VIII of the periodic table, more preferably the catalyst comprises a catalyst comprising Fe, Co, Ni, Ru, Rh, Pd, Os, Ir and / or Pt, such as Ni, Co, Mo, W, Cu, Pd, Ru, Pt, preferably the catalyst is selected from CoMo, NiMo or Ni, and preferably The catalyst is a supported catalyst, such as a support selected from activated carbon, silica, alumina, silica-alumina, molecular sieves and / or zeolites; 23. The method of claim 22.

24. and optionally further comprising at least partially removing the LPG from the bio-oil by condensation and / or flash distillation. applying a vacuum pressure of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA to the bio-oil to separate LPG from the remaining bio-oil; The method according to any one of claims 1 to 23.

25. The fractionation step comprises isolating a first fractionation cut of the bio-oil having a cut point between 30°C and 220°C, preferably between 50°C and 210°C, more preferably between 70°C and 200°C under atmospheric pressure, the separated fraction being recovered as a bio-derived gasoline fuel, and optionally The method further comprises the step of performing a second fraction cut of the boiled oil under atmospheric pressure, the second fraction cut having a cut point of 280°C to 320°C, preferably 290°C to 310°C, more preferably about 300°C, wherein the separated fraction is recovered as a biogenic jet fuel, and further optionally, recovering the bio-oil underflow as a bio-derived diesel fuel. The method according to any one of claims 1 to 24.

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