Conversion of biomass to gasoline

Abstract

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

Description

[Technical field]

[0001] The present invention relates to methods and systems for forming bio-based gasoline fuels from biomass feedstocks and the bio-based gasoline fuels formed therefrom. The present invention also relates to methods and systems for forming bio-based gasoline fuels from bio-based hydrocarbon feedstocks and the bio-based gasoline fuels 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 gasoline are formed by refining crude oil. The gasoline fuel produced contains primarily paraffins (alkanes), olefins (alkenes) and cycloalkanes (naphthenes). Typically, the refining process includes 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 gasoline product.

[0006] Fossil-based gasoline is formed from a complex mixture of hydrocarbon compounds, the majority of which contain carbon numbers between 4 and 12. For a biofuel to be considered as a substitute for crude oil-based gasoline fuel, it must meet the standardized chemical and physical properties of these materials as defined in Directive 2009 / 30 / EC.

[0007] In Europe, standard requirements for gasoline-based fuels are becoming more stringent to meet lower target emission requirements and improve fuel efficiency. The latest requirements for gasoline fuels are defined by EURO VI (Euro 6dTEMP (from 2017), Euro 6d (from 2020)). The requirements for category VI unleaded gasoline fuels are defined in the "Worldwide Fuel Charter: Sixth Edition - Gasoline and Diesel Fuel" and some of the standard requirements for Euro 6 grade unleaded gasoline fuels are shown in Table 1 below.

[0008] [Table 1]

[0009] Particularly important requirements for any gasoline fuel (or hydrocarbon feedstock used to form the gasoline fuel) are i) the amount of sulfur present, and ii) the amount of diene-containing compounds present. 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.

[0010] 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-based gasoline 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. Crosslinking causes the hydrocarbon compounds to polymerize to form gums or varnishes that can form deposits in the fuel system or engine and plug 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. EURO V and EURO VI require that gasoline fuels have an olefin content of 18% or less.

[0011] Since gasoline fuels are highly flammable at ambient temperatures, the octane number can indicate the viability of such fuels in a combustion engine. Octane number is a measure of the resistance of hydrocarbons to ignition when compressed in a standard spark-ignited internal combustion engine. As the octane number increases, the likelihood of the hydrocarbons "knocking," i.e., causing an explosion due to premature ignition in a combustion engine, decreases. The octane number of a gasoline fuel is determined by calculating the average of the Research Octane Number (RON) and the Motor Octane Number (MON). RON is determined by analyzing the performance of a gasoline fuel under research test conditions (using a 600 rpm test engine with a variable compression ratio) and comparing the results with those of a mixture of iso-octane and n-heptane (as defined in ASTM D2699). MON is determined by analyzing the performance of a gasoline fuel under more strenuous driving conditions (using a 900 rpm engine as defined in ASTM D 2700). Additives such as butanes and aromatics can be used to increase the octane number of gasoline fuels, but such additives have undesirable environmental effects. For example, butanes are known to increase the loss of unburned hydrocarbons through evaporation, and aromatics can reduce engine cleanliness and increase engine deposits. The use of aromatic additives can also increase the amount of carcinogenic compounds, such as benzene and polyaromatic compounds, present in the exhaust gases.

[0012] It is well understood in the art that the physical properties of gasoline fuel, such as octane number, corrosivity and vapor pressure, as well as the performance of the fuel in a turbine engine, are related to both the molecular weight or carbon number and ratio of the different hydrocarbon compounds present.

[0013] For a bio-derived fuel to be considered suitable for gasoline fuel purposes, it must meet the above standardization requirements. However, known methods for producing bio-derived oils typically produce a wide range of hydrocarbon compounds and therefore require extensive and costly refining steps to bring the oil to acceptable specifications. Such methods cannot provide an economically competitive alternative to fossil fuels.

[0014] 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.

[0015] 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.

[0016] 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.

[0017] 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)

[0018] 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.

[0019] 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.

[0020] 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.

[0021] 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.

[0022] 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.

[0023] 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.

[0024] 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.

[0025] 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.

[0026] 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.

[0027] 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.

[0028] Alternative upgrading techniques include emulsion catalytic hydrogenation, fluid catalytic cracking 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 fluid catalytic cracking, 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.

[0029] 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 biogenic feedstock with a fossil fuel or a fraction thereof prior to the fluid catalytic cracking technology, 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.

[0030] Thus, there remains a need in the art for simpler and more efficient methods of forming bio-derived gasoline 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 more cost-effective methods of producing bio-derived fuels that are comparable to those produced from fossil fuels. Summary of the Invention [Means for solving the problem]

[0031] In a first embodiment, the present invention provides a method for forming a biogasoline 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. cracking the hydrocarbon feedstock of step d. using a fluid catalytic cracking (FCC) process to produce a bio-oil; and f. fractionating the resulting bio-oil to obtain a bio-derived gasoline fuel fraction. The present invention relates to a method comprising the steps of:

[0032] Preferably, the biomass feedstock comprises a cellulosic, hemicellulose or lignin based material.

[0033] 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.

[0034] 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 such as 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.

[0035] 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 an appropriate 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 may be 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.

[0036] 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.

[0037] 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.

[0038] 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 feedstock, 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.

[0039] 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.

[0040] 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.

[0041] Optionally, the moisture of the biomass feedstock is at least partially reduced before the biomass feedstock is ground.

[0042] 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.

[0043] 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.

[0044] 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.

[0045] 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.

[0046] 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.

[0047] 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.

[0048] 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.

[0049] 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.

[0050] 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.

[0051] 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.

[0052] 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.

[0053] Furthermore, the pyrolysis gases are at least partially cleaned as dust and heavy carbons present in the gases are captured by the biomass material.

[0054] 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 conveyed through the pyrolysis reactor, and, optionally, removal of the pyrolysis gases.

[0055] 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.

[0056] According to the present invention, step d. may further comprise a step of separating the biochar from the hydrocarbon feedstock product. In some examples, the separation of the biochar from the hydrocarbon feedstock product is carried out in the pyrolysis reactor. In other examples, 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.

[0057] 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.

[0058] 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.

[0059] 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.

[0060] 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.

[0061] Water may be at least partially separated from the hydrocarbon feedstock by gravity oil separation, centrifugation, cyclone or microbubble separation.

[0062] 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.

[0063] 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.).

[0064] 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.

[0065] 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.

[0066] The biogenic hydrogen gas produced by the WGS reaction may be at least partially recycled and used in further downstream processing or "upgrading" steps. For example, the biogenic hydrogen gas produced may be at least partially used in downstream processing steps such as desulfurization, deoxygenation and / or hydrotreating steps.

[0067] It may 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 biogasoline 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.

[0068] 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.

[0069] 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).

[0070] 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.

[0071] 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.

[0072] 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.

[0073] 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.

[0074] 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.

[0075] 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).

[0076] 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.

[0077] 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).

[0078] 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.

[0079] 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.

[0080] 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.

[0081] The separated hydrocarbon feedstock preferably contains no more than 300 ppmw sulfur, preferably no more than 150 ppmw, more preferably no more than 70 ppmw sulfur.

[0082] A second embodiment is a method for forming a biogasoline 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. cracking the hydrocarbon feedstock of step i. using a fluid catalytic cracking (FCC) process to produce a bio-oil; and iii. fractionating the resulting bio-oil to obtain a bio-derived gasoline fuel fraction. The present invention provides a method comprising:

[0083] 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.

[0084] The hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. may be contacted with the fluid catalytic cracking catalyst in an essentially liquid state, an essentially gaseous state, or a partially liquid-partially gaseous state. However, since catalytic cracking reactions 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 fluid catalytic cracking catalyst.

[0085] Preferably, the hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. is contacted with a fluid catalytic cracking catalyst at a temperature of at least 400°C, preferably at a temperature between 400°C and 800°C, more preferably at a temperature between 450°C and 750°C, more preferably at a temperature between 500°C and 700°C to produce a bio-oil comprising one or more cracked hydrocarbon products.

[0086] In some embodiments, the hydrocarbon feedstock is heated prior to contact with the fluid catalytic cracking 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 fluid catalytic cracking 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 fluid catalytic cracking 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 fluid catalytic cracking 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.

[0087] The hydrocarbon feedstock in step d. or the hydrocarbon feedstock in step i. may be subjected to fluid catalytic cracking at a pressure of from 0.05 MPa to 10 MPa, preferably from 0.1 MPa to 8 MPa, more preferably from 0.5 MPa to 6 MPa.

[0088] The weight ratio of the hydrocarbon feedstock to the fluid catalytic cracking catalyst may be 1:1 to 1:150, preferably 1:2 to 1:100, more preferably 1:5 to 1:50. It has been found that the above weight ratio of the hydrocarbon feedstock to the FCC catalyst can effectively crack the hydrocarbon feedstock with a short residence time.

[0089] The fluid catalytic cracking step may be carried out in any suitable fluid catalytic cracking reactor known in the art. For example, the fluid catalytic cracking reactor may be selected from a fluidized dense bed reactor or a riser reactor. Preferably, the catalytic cracking reactor is a riser reactor.

[0090] Examples of suitable riser reactors are described in the handbook entitled "Fluid Catalytic Cracking technology and operations" by Joseph W. Wilson, published by Penn Well Publishing Company (1997), chapter 3, pages 101 to 112. For example, the riser reactor may be an internal riser reactor or an external riser reactor as described therein. In particular, the riser reactor may include an essentially vertical upstream end located outside the vessel and an essentially vertical downstream end located inside the vessel, or an essentially vertical downstream end located outside the vessel and an essentially vertical upstream end located inside the vessel. Internal riser reactors may be particularly advantageous for use according to the present invention, as they are less prone to clogging, which may increase safety and hardware integrity.

[0091] A riser reactor as defined herein should be understood to mean an elongated essentially tubular reactor suitable for carrying out a fluid catalytic cracking reaction. The elongated essentially tubular reactor is preferably oriented essentially vertically.

[0092] The length of the riser reactor may be any length suitable for carrying out the fluid catalytic cracking reaction and may depend on the required residence time of the hydrocarbon feedstock in the reactor. It is believed to be well within the knowledge of a person skilled in the art to select a riser length suitable for carrying out the fluid catalytic cracking step as defined herein. However, for example, the FCC reactor may have a length of 10 to 65 meters, preferably 15 to 55 meters, more preferably 20 to 45 meters.

[0093] The fluid catalytic cracking reactor may include an inlet at or near the base of the fluid catalytic cracking reactor for feeding the hydrocarbon feedstock and / or the fluid catalytic cracking catalyst to the reactor, and an outlet at or near the top of the fluid catalytic cracking reactor, where the formed bio-oil and deactivated catalyst are extracted from the fluid catalytic cracking reactor.

[0094] By feeding the hydrocarbon feedstock at or near the base of the fluid catalytic cracking reactor, in-situ formed water is generated in the bottom of the reactor, which can lower the hydrocarbon partial pressure, reduce secondary hydrogen transfer reactions, and result in higher olefin yields.

[0095] Preferably, the hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. is atomized before or when it enters the fluid catalytic cracking reactor. The term atomising is understood herein to mean that the hydrocarbon feedstock is formed into a dispersion of droplets in a gas. Preferably, the droplets have an average diameter of 10 μm to 60 μm, more preferably an average diameter of 20 μm to 50 μm. In some embodiments, the hydrocarbon feedstock may be atomised in a feed nozzle by applying shear energy. Preferably, the feed nozzle is a bottom entry feed nozzle or a side entry feed nozzle. By bottom entry feed nozzle, it is understood herein that the feed nozzle protrudes from the bottom of the fluid catalytic cracking reactor. By side entry feed nozzle, it is understood herein that the feed nozzle protrudes from the side wall of the fluid catalytic cracking reactor. The nozzle may be configured to atomise the hydrocarbon feedstock as it enters the fluid catalytic cracking reactor, preferably the nozzle is configured to produce a cone-shaped spray, a fan-shaped spray or a mist.

[0096] By atomizing the hydrocarbon feed prior to or as it enters the fluid catalytic cracking reactor, the increased surface area of ​​the hydrocarbon feed can transfer heat to it more efficiently, improving the efficiency of conversion of the liquid or partially liquid hydrocarbon feed to a gaseous state.

[0097] Generally, fluid catalytic cracking occurs when the gaseous hydrocarbon feedstock carries the fluid catalytic cracking catalyst along the reactor length. When the hydrocarbon feedstock is fed to or near the base of the fluid catalytic cracking reactor, it may also be advantageous to feed a lift gas to or near the base of the riser reactor. The velocity of the lift gas fed to the reactor can be advantageously used to control the residence time of the hydrocarbon feedstock and / or the FCC catalyst. The term residence time as used herein is considered to indicate the time that the fluid catalytic cracking reactor contacts the gaseous hydrocarbon feedstock in the fluid catalytic cracking reactor, and of course the residence time includes not only the residence time of the hydrocarbon feedstock but also the residence time of its conversion products. Examples of suitable lift gases include steam, nitrogen, vaporized oil or mixtures thereof. Preferably, the lift gas is steam. In a preferred embodiment, the lift gas and the hydrocarbon feedstock may be combined before entering the fluid catalytic cracking reactor.

[0098] The hydrocarbon feedstock of step d. or the hydrocarbon feedstock of step i. may have a residence time of from 0.5 seconds to 15 seconds, preferably from 1 second to 10 seconds, more preferably from 2 seconds to 5 seconds.

[0099] The fluid cracking catalyst may be in the form of particles or powder, preferably the fluid cracking catalyst is in the form of a fine powder. As discussed above, the fluid catalytic cracking process requires that the hydrocarbon feedstock is contacted with the fluid catalytic cracking 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 fluid catalytic cracking catalyst available at its disposal. Therefore, preferably, the fluid catalytic cracking catalyst is ground to reduce its particle size, for example by using a tube grinder, a mill, for example a hammer mill, a knife mill, a slurry mill, or sized to the required particle size by using a chipper. In particular, the fluid cracking catalyst may be in the form of particles or powder having a diameter of 10 μm to 300 μm, preferably 15 μm to 200 μm, more preferably 20 μm to 150 μm. Catalysts having particle sizes within these ranges have been found to be particularly useful for increasing the efficiency of the catalytic cracking reaction.

[0100] The fluid catalytic cracking catalyst can be any catalyst known to those skilled in the art to be suitable for use in a fluid catalytic cracking process. Preferably, the fluid catalytic cracking catalyst comprises a zeolite or a highly active crystalline alumina silicate. The fluid catalytic cracking catalyst may further comprise an amorphous binder compound and / or a filler. Examples of amorphous binder components include silica, alumina, titania, zirconia and magnesium oxide, or combinations thereof. Examples of fillers include clays, such as kaolin. The use of binder and / or filler materials has been found to be beneficial because it allows the catalyst to be more homogeneously distributed throughout the hydrocarbon feed, thus increasing the amount of catalyst in contact with the hydrocarbon feed. Thus, the use of catalyst in combination with binder and / or filler materials can reduce the amount of catalyst required for the fluid catalytic cracking reaction, reducing the overall process cost (operational and capital expenditures).

[0101] When the fluid catalytic cracking catalyst comprises a zeolite, the zeolite may be selected from a large pore zeolite, a medium pore zeolite, or a combination thereof.

[0102] The large pore zeolite is preferably selected from FAU or faujasite, such as synthetic faujasite, e.g. zeolite Y or X, ultrastable zeolite Y (USY), rare earth zeolite Y (REY) and rare earth USY (REUSY), more preferably the large pore zeolite is selected from ultrastable zeolite Y (USY).

[0103] In particular, the large pore zeolite may be selected from natural large pore zeolites such as gmelinite, chabazite, dachyardite, clinoptilolite, faujasite, heulandite, analcite, levinite, erionite, sodalite, cancrinite, nepheline, lazurite, scolecite, natrolite, offretite, mesolite, mordenite, brewsterite and ferrierite, and / or synthetic large pore zeolites such as zeolites X, Y, A, L. ZK-4, ZK-5, B, E, F, H, J, M, Q, T, W, Z, alpha and beta, omega, REY and USY zeolites, preferably the natural large pore zeolites are selected from faujasite, in particular zeolites Y, USY and REY.

[0104] Large pore zeolites may contain internal pores with pore diameters between 0.62 nm and 0.8 nm, where the pore diameter is measured along the long axis of the pore. Zeolite axes are described in 'Atlas of Zeolite Structure Types' by W. M. Meier, D. H. Olson, and Ch. Baerlocher, Fourth Revised Edition 1996, Elsevier, ISBN 0-444-10015-6.

[0105] The medium pore zeolite may be selected from MFI type zeolites, such as ZSM-5, MFS type zeolites, MEL type zeolites, MTW type zeolites, such as ZSM-12, MTW type zeolites, EUO type zeolites, MTT type zeolites, HEU type zeolites, TON type zeolites, such as Theta-1, and / or FER type zeolites, such as Ferrierite. Preferably, the medium pore zeolites are selected from ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-34, ZSM-35, ZSM-38, ZSM-48, ZSM-50, silicalite and silicalite 2, more preferably the medium pore zeolite is ZSM-5.

[0106] Medium pore zeolites may contain internal pores with diameters between 0.45 nm and 0.62 nm, where the pore diameter is measured along the long axis of the pore. Zeolite axes are described in 'Atlas of Zeolite Structure Types' by W. M. Meier, D. H. Olson, and Ch. Baerlocher, Fourth Revised Edition 1996, Elsevier, ISBN 0-444-10015-6.

[0107] It is known that the type and range of cracked olefins produced by catalytic cracking reactions can vary depending on the type and therefore selectivity of the zeolite catalyst used. As discussed above, more stringent requirements, such as the minimum octane value of the fuel produced, are applied to modern fuels. If the FCC process produces a range of cracked olefin products, the resulting fuel may not be of sufficient quality to meet these requirements. Therefore, in some cases, further processing or upgrading techniques may be used to improve the quality of the fuel product. However, such additional processing steps increase both the time and expenditure required to produce a marketable product. Alternatively, or in addition, catalysts containing medium pore zeolites are known to increase the yield of light olefins (C2-C4), mainly propylene and butylene, in the cracked hydrocarbon product.

[0108] Light olefins are known to be high octane compounds and may increase the volatility of the resulting fuel. Thus, the inclusion of medium pore zeolites in the fluid catalytic cracking process may improve the quality of the bio-oil formed and reduce the need for subsequent treatment or upgrading steps. In addition to improving the volatility and octane of the bio-oil formed, the increased amount of light olefins may also reduce the emissions of the resulting fuel. Ethylene, which may also be increased, is valuable as a chemical feedstock.

[0109] In particular, ZSM-5 has been shown to provide significantly higher yields of lighter olefins (C2-C4), including increased yields of propylene.

[0110] As discussed above, the fluid catalytic cracking catalyst may comprise a blend of one or more large pore zeolites and one or more medium pore zeolites, preferably the one or more large pore zeolites are as defined above and / or the one or more medium pore zeolites are as defined above. In some embodiments, the weight ratio of the large pore zeolites to the medium pore zeolites is in the range of 99:1 to 70:30, preferably 98:2 to 85:15.

[0111] Preferably, when a fluid catalytic cracking catalyst blend is selected comprising one or more large pore zeolites and one or more medium pore zeolites, at least one of the medium pore zeolites is selected from ZSM-5. More preferably, the ZSM-5 zeolite is present in an amount of 1-20 wt%, preferably 2-15 wt%, more preferably 2-8 wt%, based on the total weight of the catalyst.

[0112] The total amount of large pore zeolite and / or medium pore zeolite present in the fluid catalytic cracking catalyst is preferably in the range of 5 wt% to 40 wt%, more preferably in the range of 10 wt% to 30 wt%, and even more preferably in the range of 10 wt% to 25 wt%, based on the total mass of the fluid catalytic cracking catalyst.

[0113] The fluid catalytic cracking catalyst may be contacted with the hydrocarbon fluid feed in a countercurrent flow, cocurrent flow or crossflow configuration, preferably the fluid catalytic cracking catalyst is contacted with the hydrocarbon fluid feed in a cocurrent configuration.

[0114] After the fluid catalytic cracking process, the deactivated catalyst may be at least partially separated from the bio-oil that is formed. The separation step is preferably carried out using one or more cyclone separators and / or one or more vortex tubes.

[0115] In some embodiments, the method further comprises at least partially removing sulfur-containing components from the bio-oil formed in step d. or step ii. Additionally or alternatively, the method may further comprise at least partially removing sulfur-containing components from the bio-derived gasoline fuel fraction formed in step e. or step iii.

[0116] At least partially removing sulfur-containing components from the bio-oil and / or gasoline fuel fraction may comprise at least partially removing one or more of thiols, sulfides, disulfides, alkylated derivatives of thiophenes, benzothiophene, dibenzothiophene, 4-methyldibenzothiophene, 4,6-dimethyldibenzothiophene, benzonaphthothiophene, and benzo[def]dibenzothiophene present in the hydrocarbon feedstock. Preferably, benzothiophene, dibenzothiophene are at least partially removed from the bio-oil and / or gasoline fuel fraction.

[0117] The step of at least partially removing sulfur-containing components from the bio-oil and / or the gasoline fuel fraction may comprise a hydrodesulfurization step, preferably a catalytic hydrodesulfurization step.

[0118] 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.

[0119] 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 gasoline 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.

[0120] 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 hydrocarbon feed, thus increasing the amount of catalyst that comes into contact with the bio-oil and / or gasoline fuel fraction. Thus, the use of a supported catalyst can reduce the amount of catalyst required for the hydrodesulfurization reaction, reducing the overall process costs (operational and capital expenditures).

[0121] 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 gasoline fuel fraction and the catalyst present, thereby increasing the efficiency of the sulfur removal step.

[0122] The hydrodesulfurization step may be carried out at a temperature between 250°C and 400°C, preferably between 300°C and 350°C.

[0123] The bio-oil and / or gasoline fuel fraction may be pre-heated prior to contact with hydrogen gas and, if present, the hydrodesulfurization catalyst. The bio-oil and / or gasoline fuel fraction may be pre-heated by use of a heat exchanger. Alternatively, the bio-oil and / or gasoline 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 gasoline fuel fraction and hydrogen gas may be heated to the desired temperature using any of the direct or indirect heating methods defined above.

[0124] 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.

[0125] 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 hydrocarbon feed by any method known in the art, such as by the use of a gas separator or by 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.

[0126] Optionally, the sulfur reduced bio-oil and / or gasoline 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.

[0127] Trace amounts of hydrogen sulfide remaining in the sulfur-reduced bio-oil and / or gasoline 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 gasoline fuel fraction has a temperature between 60° C. and 120° C. during the degassing step, more preferably the bio-oil and / or gasoline 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.

[0128] 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 gasoline fuel fraction is reduced, thereby providing a more cost-effective process.

[0129] The hydrodesulfurization step may be repeated one or more times to achieve the desired sulfur reduction in the bio-oil and / or gasoline fuel fraction, however, typically only one hydrodesulfurization step is necessary to sufficiently reduce the sulfur content of the bio-oil and / or gasoline fuel fraction to the desired level, particularly when the hydrocarbon feedstock is produced according to the methods described herein above.

[0130] The desulfurized bio-oil and / or gasoline fuel fraction may contain a sulfur content of less than 5 ppmw, preferably less than 3 ppmw, more preferably less than 1 ppmw.

[0131] 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 resulting hydrocarbon feedstocks, bio-oils, and gasoline fuel fractions essentially fall within the sulfur 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 and / or fluid catalytic cracking process as 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.

[0132] According to the present invention, the method may further comprise a step of deoxygenating the hydrocarbon feedstock prior to the fluid catalytic cracking step in order to at least partially remove oxygen-containing compounds (oxygenates) from the hydrocarbon feedstock. Unlike crude oil-based hydrocarbon feedstocks, biologically derived hydrocarbon feedstocks contain oxygen-containing components that are not easily converted into forms that can be easily integrated into existing hydrocarbon-based infrastructure. For example, these oxygen-containing components can poison catalysts commonly used in traditional fuel production processes. Furthermore, hydrocarbon feedstocks containing oxygen-containing components are not easily processed using fluid catalytic cracking methods. The presence of oxygen-containing hydrocarbons in biofuels or traditionally formed fossil fuels can result in high acidity and low energy conversion. These oxygenated hydrocarbons can also undergo secondary reactions during storage or when heated to produce undesirable compounds, such as oligomers, polymers, and other compounds that cause clogging and inhibit liquid transport operations.

[0133] The term oxygenate refers to a compound that contains at least one or more carbon atoms, one or more hydrogen atoms, and one or more oxygen atoms. Oxygenates may include, for example, aldehydes, carboxylic acids, alkanols, phenols, and / or ketones.

[0134] Preferably, the deoxygenation step is a hydrodeoxygenation step carried out at a temperature between 200°C and 450°C, preferably between 250°C and 400°C, more preferably between 280°C and 350°C.

[0135] The hydrocarbon feedstock may be preheated before contacting with hydrogen gas and, if present, the hydrodeoxygenation catalyst. The hydrocarbon feedstock may be preheated by use of a heat exchanger. Alternatively, the hydrocarbon feedstock may first be contacted with hydrogen gas and, if present, the hydrodeoxygenation catalyst, 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.

[0136] The water vapor formed may be separated from the hydrocarbon feedstock by any method known in the art, for example by the use of a gas separator or by 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.

[0137] Preferably, the hydrodeoxygenation step further comprises a hydrodeoxygenation catalyst. The hydrodeoxygenation step may be carried out in a fixed bed or trickle bed reactor in order to increase the contact between the hydrocarbon feedstock and the catalyst present, thereby increasing the efficiency of the oxygen removal step.

[0138] The catalyst preferably comprises a metal selected from group VIII and / or group VIB of the periodic table, in particular the catalyst comprises a metal selected from Ni, Cr, Mo, W, Co, Pt, Pd, Rh, Ru, Ir, Os, Cu, Fe, Zn, Ga, In, V, and mixtures thereof.

[0139] 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 alumina, amorphous silica-alumina, titania, silica, ceria, zirconia, carbon, silicon carbide, or zeolites, such as zeolite Y, zeolite beta, ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-48, SAP0-11, SAP0-41, and ferrierite. The use of a support has been found to be beneficial, since it allows the catalyst to be distributed more homogeneously throughout the hydrocarbon feedstock, thus increasing the amount of catalyst contacted with the hydrocarbon feedstock. Thus, the use of a supported catalyst can reduce the amount of catalyst required for the hydrodeoxygenation reaction, reducing the overall process cost (operational and capital investment).

[0140] Optionally, the oxygen-reduced hydrocarbon feedstock 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.

[0141] Trace amounts of hydrogen remaining in the oxygen-reduced hydrocarbon feedstock may subsequently be removed, for example, by partial vaporization by use of a flash separator at about ambient pressure (including essentially atmospheric conditions) and removing the vaporized hydrogen by degassing. 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.

[0142] Any unreacted hydrogen-rich gas removed during the degassing step may be advantageously recycled and combined with the hydrocarbon feedstock in step d. or step ii. By at least partially recycling the unreacted hydrogen gas, the amount of hydrogen gas required to remove oxygen-containing components from the hydrocarbon feedstock is reduced, thereby providing a more cost-effective process.

[0143] The hydrodeoxygenation step may be repeated one or more times to achieve the desired oxygen reduction in the hydrocarbon feedstock, however, typically only one hydrodeoxygenation step is necessary to sufficiently reduce the oxygen content of the hydrocarbon feedstock to the desired level, particularly when the hydrocarbon feedstock is produced according to the methods described herein above.

[0144] The method may further include hydrotreating the biooil formed in step e. or step ii.

[0145] 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.

[0146] 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.

[0147] 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.

[0148] 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.

[0149] 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.

[0150] 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).

[0151] 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.

[0152] Optionally, the hydrotreated bio-oil is subsequently cooled, for example by use of a heat exchanger, before any further processing steps are carried out.

[0153] 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.

[0154] The fractionation step of the present invention can separate the refined bio-oil into respective naphtha, gasoline, 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.

[0155] 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.

[0156] 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.

[0157] 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.

[0158] The remaining bio-oil in the underflow is bio-derived diesel fuel.

[0159] During the fluid catalytic cracking step, coke and hydrocarbonaceous materials are deposited on the surface of the catalyst, resulting in loss of catalytic activity and selectivity. Therefore, the method may further comprise a step of regenerating the at least partially removed deactivated fluid catalytic cracking catalyst. In particular, the at least partially removed deactivated fluid catalytic cracking catalyst may be regenerated by: a. stripping the deactivated catalyst to bio-oil absorbed on the surface of the catalyst; and b. Regenerating the catalyst may be played back via

[0160] The stripping step removes hydrocarbonaceous reaction products adsorbed on the deactivated catalyst prior to the regenerating step. The products removed during the stripping step may be at least partially recycled and combined with the bio-oil produced in step e. or step ii.

[0161] Preferably, the stripping step comprises contacting the deactivated catalyst with a gas comprising steam at a temperature between 400°C and 800°C, preferably between 400°C and 700°C, more preferably between 450°C and 650°C. Preferably, the gas comprising steam is heated prior to contact with the deactivated catalyst. The gas may be preheated by use of a heat exchanger. Alternatively, the deactivated catalyst may first be contacted with a gas comprising steam and subsequently heated to the desired temperature. The deactivated catalyst and the gas comprising steam may be heated to the desired temperature using any of the direct or indirect heating methods defined above.

[0162] The deactivated catalyst may be contacted with the gas containing steam for any period of time necessary to sufficiently remove the hydrocracking products adsorbed on the surface of the deactivated catalyst, in particular for a period of 1 to 10 minutes, preferably 2 to 8 minutes, more preferably 3 to 6 minutes.

[0163] In a preferred embodiment, the deactivated catalyst is contacted with a gas comprising steam in a weight ratio of from 10:1 to 100:1, preferably from 20:1 to 60:1.

[0164] The regenerating step preferably comprises contacting the stripped fluid catalytic cracking catalyst with air or a mixture of air and oxygen in a regenerator at a temperature of 550°C or higher to produce regenerated catalytic cracking catalyst, heat and carbon dioxide. Preferably, the stripped fluid catalytic cracking catalyst is contacted with air or a mixture of air and oxygen in the regenerator at a temperature of 550°C to 950°C, preferably 575°C to 900°C, more preferably 600°C to 850°C.

[0165] During the regenerating step, the coke deposited on the catalyst as a result of the fluid catalytic cracking step is burned off to restore the catalytic activity. The combustion of the coke on the surface of the catalyst is a highly exothermic reaction. Thus, the regenerating step not only serves to remove the coke from the surface of the catalyst, but also heats the catalyst to a temperature suitable for endothermic fluid catalytic cracking. Thus, the heated regenerated fluid catalytic cracking catalyst can be at least partially recycled to the fluid catalytic cracking step. Preferably, the catalyst is continuously circulated from the fluid catalytic cracking step to the stripping step and the regenerating step, and back to the fluid catalytic cracking step. The circulation rate of the catalyst is adjusted relative to the feed rate of the hydrocarbon feedstock so that the heat generated in the regenerating step is sufficient to sustain the fluid catalytic cracking reaction and maintain a heat balance operation in which the circulating regenerated catalyst is used as a heat transfer medium.

[0166] Alternatively or additionally, the heat generated during the exothermic regeneration step may be at least partially used to heat water and / or generate steam. The generated steam may be used as lift gas in the riser reactor. Alternatively or additionally, the heat generated during the exothermic regeneration step may be at least partially used to preheat the hydrocarbon feedstock before the hydrodeoxygenation step, and / or to preheat the bio-oil before the hydrotreating step, and / or to preheat the bio-oil and / or the gasoline fuel fraction before the desulfurization step. Thus, by at least partially recycling the heat generated during the exothermic regeneration step, the overall cost (operating and capital expenditures) of the process may be reduced.

[0167] The regeneration step may be carried out at a pressure between 0.05 MPa and 1 MPa, preferably between 0.1 MPa and 0.6 MPa.

[0168] A third embodiment includes a bio-based LPG fuel produced according to the method defined herein.

[0169] A fourth embodiment includes a bio-based gasoline fuel produced according to the methods defined herein. Preferably, the bio-based gasoline fuel is formed entirely from a biomass feedstock.

[0170] Surprisingly, it has been found that the bio-based gasoline fuel produced according to the method of the present invention meets the standards for EURO VI gasoline fuel.

[0171] The bio-derived gasoline fuel may have a research octane number of at least 98, preferably at least 102, more preferably at least 105. The bio-derived gasoline fuel may have a motor octane number of at least 88, preferably at least 90, more preferably at least 95.

[0172] The bio-derived gasoline fuel preferably contains no more than 10 ppmw sulfur, preferably no more than 5 ppmw sulfur, more preferably no more than 1 ppmw sulfur.

[0173] Preferably, the bio-derived gasoline fuel has no measurable Bromine Index.

[0174] A fifth embodiment includes a bio-based jet fuel produced according to the methods defined herein.

[0175] A sixth embodiment includes a bio-based diesel fuel produced according to the methods defined herein.

[0176] Although not technically necessary, it is recognized that the bio-derived 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 to make such processes avoidable.

[0177] A seventh embodiment is a system for forming a biogasoline fuel from a biomass feedstock, comprising: a 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 fluid catalytic cracking reactor suitable for cracking a hydrocarbon feedstock to produce a bio-oil; and A separator configured to separate a gasoline fuel fraction from the bio-oil. The present invention provides a system including:

[0178] 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.

[0179] 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.

[0180] 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.

[0181] 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.

[0182] 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.

[0183] 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.

[0184] The reactor may be arranged such that the biomass material is heated under atmospheric pressure (including essentially atmospheric conditions). Alternatively, the reactor may be arranged to form 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 manner, any solid material that is formed as a result of heating, such as biochar, is removed separately from the pyrolysis gases that are formed.

[0185] 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.

[0186] The system may further comprise means for separating the pyrolysis gases formed, for example by distillation.

[0187] 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.

[0188] Additionally or alternatively, the separator may include means for at least partially separating water from the hydrocarbon feed product. For example, the separator may include a gravity oil separator, a centrifuge, a cyclone, or a microbubble separation means.

[0189] 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.

[0190] 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.

[0191] 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.

[0192] 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 large 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). 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.

[0193] According to the present invention, the fluid catalytic cracking reactor may comprise a heating element configured to heat the hydrocarbon feedstock and the fluid catalytic cracking catalyst to a temperature of at least 400°C, preferably a temperature between 400°C and 800°C, more preferably a temperature between 450°C and 750°C, more preferably a temperature between 500°C and 700°C to produce a bio-oil comprising one or more cracked hydrocarbon products.

[0194] Furthermore, the fluid catalytic cracking reactor may be configured to create a pressure condition of 0.05 MPa to 10 MPa, preferably 0.1 MPa to 8 MPa, and more preferably 0.5 MPa to 6 MPa.

[0195] The fluidized catalytic cracking reactor may be selected from a fluidized dense bed reactor or a riser reactor. Preferably, the catalytic cracking reactor is a riser reactor. For example, the riser reactor may be a so-called internal riser reactor or a so-called external riser reactor.

[0196] The riser reactor may be configured to include an elongated essentially tubular shaped reactor, preferably oriented essentially vertically.

[0197] The length of the riser reactor may be a length suitable for carrying out a fluid catalytic cracking reaction. For example, the fluid catalytic cracking reactor may have a length of 10 to 65 meters, preferably 15 to 55 meters, more preferably 20 to 45 meters.

[0198] The fluid catalytic cracking reactor may be configured to include an inlet at or near the base for feeding the hydrocarbon feedstock and / or the fluid catalytic cracking catalyst into the reactor, and an outlet at or near the top of the fluid catalytic cracking reactor, where the formed bio-oil and deactivated catalyst are extracted from the fluid catalytic cracking reactor.

[0199] Preferably, the fluid catalytic cracking reactor is configured to atomize the hydrocarbon feedstock prior to or upon entering the fluid catalytic cracking reactor. The reactor may be configured to disperse the hydrocarbon feedstock to form droplets having an average diameter of 10 μm to 60 μm, more preferably an average diameter of 20 μm to 50 μm. In some examples, the reactor includes a feed nozzle configured to apply shear energy to the hydrocarbon feedstock to form the dispersion. The nozzle may be configured to atomize the hydrocarbon feedstock as it enters the fluid catalytic cracking reactor, preferably the nozzle is configured to generate a cone-shaped spray, a fan-shaped spray or a mist.

[0200] The fluid catalytic cracking reactor is configured so that the fluid catalytic cracking catalyst contacts the hydrocarbon fluid feed in a countercurrent flow, cocurrent flow, or crossflow configuration, preferably the fluid catalytic cracking reactor is configured so that the fluid catalytic cracking catalyst contacts the hydrocarbon fluid feed in a cocurrent configuration.

[0201] Additionally, the system may further comprise means for at least partially separating the deactivated catalyst from the bio-oil formed. Preferably, the separating means is selected from one or more cyclone separators and / or one or more vortex tubes.

[0202] The system may further comprise a means for at least partially removing sulfur-containing components from the bio-oil or bio-derived gasoline 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 element 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 element may be arranged to heat the hydrocarbon feedstock to the required temperature before entering the reactor, 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 contact with the hydrogen gas and, if present, the hydrodesulfurization catalyst. If the hydrocarbon feed is heated after entering the reactor, the heating element 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.

[0203] 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.

[0204] 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.

[0205] 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.

[0206] 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.

[0207] 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.

[0208] Additionally or alternatively, the system may be configured to at least partially remove oxygen-containing compounds from the hydrocarbon feedstock prior to entering the fluid catalytic cracking reactor. Preferably, a means for at least partially removing oxygen-containing compounds from the hydrocarbon feedstock. In some examples, the means comprises a reactor having an inlet for feeding the hydrocarbon feed and hydrogen gas to the reactor. In some examples, the reactor may be a fixed bed or trickle bed reactor. The reactor may further comprise a hydrodeoxygenation catalyst as defined above. The reactor may further comprise a heating element configured to heat the hydrocarbon feed to a temperature of between 200°C and 450°C, preferably between 250°C and 400°C, more preferably between 280°C and 350°C, for example using any of the direct or indirect heating methods defined above.

[0209] The means for at least partially reducing oxygen-containing compounds from the hydrocarbon feed may further comprise means for at least partially separating water vapor formed from the hydrocarbon feedstock, for example the means for at least partially removing water vapor formed may comprise a vacuum configured to apply a vacuum pressure to the reactor vessel of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA.

[0210] Optionally, the system may further comprise a cooling means for reducing the temperature of the oxygen-reduced hydrocarbon feedstock before further processing steps are carried out. By way of example, the cooling means may comprise a heat exchanger.

[0211] Additionally or alternatively, the system may further comprise a degassing means for at least partially removing trace amounts of hydrogen remaining in the oxygen-reduced hydrocarbon feedstock. In particular, the degassing means comprises a flash separator at about ambient pressure (including essentially atmospheric pressure). Preferably, the degassing means is configured to apply a vacuum pressure to the oxygen-reduced hydrocarbon feedstock. 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.

[0212] Preferably, the reactor is configured to recycle any unreacted hydrogen gas present after the deoxygenation step back into the biogenic hydrocarbon feedstock entering the reactor, thus reducing the amount of hydrogen gas required to remove oxygen-containing components in the biogenic hydrocarbon feedstock and providing a more cost-effective system.

[0213] Additionally or alternatively, the system may further comprise a means for hydrotreating the bio-oil formed. The means for hydrotreating the bio-oil 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 bio-oil 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 bio-oil 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 bio-oil 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.

[0214] The system may further include cooling means, e.g., a heat exchanger, for cooling the hydrotreated bio-oil before further processing steps are carried out.

[0215] 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.

[0216] 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.

[0217] The separator may further comprise means for cooling the first fraction cut, for example the cooling means may be selected from a heat exchanger.

[0218] 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.

[0219] As a further option, the separator may be configured to verify that any remaining bio-oil in the underflow is bio-diesel.

[0220] In some embodiments, the separator is selected from a fractionation column.

[0221] The present invention as defined herein is illustrated in the accompanying drawings, in which: [Brief description of the drawings]

[0222] [Figure 1] FIG. 1 is a flow diagram of a process for forming biogasoline fuel from a biomass feedstock in accordance with the present invention. [Diagram 2] FIG. 1 is a flow diagram of a process for forming biogasoline 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 a fuel based on a standard FFC process. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0223] 1 shows a simplified process (10) for forming biogasoline fuel from a biomass feedstock via a fluid catalytic cracking reactor. Process steps shown in dashed lines should be understood to be optional process steps.

[0224] 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 feeding 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 an outlet (22). The pyrolysis reactor further includes an additional outlet (24) for removing any residual solids formed during the pyrolysis reaction, such as biochar. 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.

[0225] The pyrolysis gases extracted from the pyrolysis reactor (22) are fed to a cooling means (26) to condense the pyrolysis gases formed to produce a hydrocarbon feedstock product and non-condensable light gases, which may then be transferred 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 feedstock stream (18). The separated hydrocarbon feedstock (32) is fed to a separator (34) to at least partially remove 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) where water may be removed from the hydrocarbon feedstock and a second outlet (38) where a water-reduced hydrocarbon feedstock may be obtained.

[0226] 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 feedstock stream (18).

[0227] The treated hydrocarbon feedstock (44) may then be fed to a deoxygenation reactor (48) containing a hydrodeoxygenation catalyst, where the reactor further comprises an inlet (50) for feeding a hydrogen-containing gas to the deoxygenation reactor (48). The deoxygenation reactor heats the hydrocarbon feedstock (44), the hydrogen-containing gas and the hydrodeoxygenation catalyst to a temperature between 200°C and 450°C, preferably between 250°C and 400°C, and more preferably between 280°C and 350°C.

[0228] The reduced oxygen-containing hydrocarbon feedstock (52) is then fed to a fluid catalytic cracking reactor (54). An example of a fluid catalytic cracking system is also shown in FIG. 3. FIG. 1 shows that the fluid catalytic cracking reactor includes an inlet (56) at or near the bottom of the fluid catalytic cracking reactor (54) for feeding the hydrocarbon feedstock and / or the fluid catalytic cracking catalyst to the reactor, and an outlet (58) at or near the top of the fluid catalytic cracking reactor (54), where the formed bio-oil and deactivated catalyst are extracted from the fluid catalytic cracking reactor (54). The fluid catalytic cracking reactor heats the hydrocarbon feedstock and the fluid catalytic cracking catalyst to a temperature of at least 400° C., preferably at a temperature between 400° C. and 800° C., more preferably at a temperature between 450° C. and 750° C., more preferably at a temperature between 500° C. and 700° C. The fluid catalytic cracking process may be carried out at a pressure between 0.05 MPa and 10 MPa, preferably between 0.1 MPa and 8 MPa, more preferably between 0.5 MPa and 6 MPa.

[0229] The deactivated catalyst (60) is at least partially separated from the bio-oil that is formed. The separation step is preferably carried out using one or more cyclone separators and / or one or more vortex tubes.

[0230] The separated bio-oil (62) is fed to a desulfurization reactor (64) containing a hydrodesulfurization catalyst, where the desulfurization reactor further includes an inlet (66) for feeding a hydrogen-containing gas to the reactor. The desulfurization reactor heats the bio-oil, the hydrogen-containing gas, and the hydrodesulfurization catalyst to a temperature between 250°C and 400°C, preferably between 300°C and 350°C.

[0231] 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.

[0232] The desulfurization reactor may further comprise a gas separator for removing hydrogen sulfide formed from the bio-oil. Optionally, the sulfur-reduced bio-oil and / or the gasoline fuel fraction 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 and / or the sulfur-reduced gasoline fuel fraction may then 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 the gasoline fuel fraction has a temperature between 60° C. and 120° C. during the degassing step, more preferably the bio-oil and / or the gasoline 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.

[0233] Any unreacted hydrogen-rich gas (68) 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 reduced oxygen-containing hydrocarbon feedstock (52).

[0234] The sulfur-reduced bio-oil is then fed to a hydrotreating reactor (70) containing a hydrotreating catalyst to reduce the number of unsaturated hydrocarbon functional groups present in the bio-oil and advantageously convert the bio-oil into more stable fuels having higher energy density.

[0235] The hydrotreating reactor further comprises an inlet (72) 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.

[0236] 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.

[0237] The hydrotreated bio-oil (74) is then transferred to a fractionation column (76) which separates 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 first fractionation cut may be removed from the fractionation column via an outlet (78). The first cut fraction is a bio-derived gasoline fuel fraction.

[0238] Either via the desulfurization reactor (64) or instead of this desulfurization step, the bio-derived gasoline fuel (78) may be fed to a desulfurization reactor (80) to at least partially remove sulfur-containing components in the biofuel in addition to reducing the sulfur-containing compounds in the bio-oil. The desulfurization reactor (80) is as defined above.

[0239] The process (10) may further include a catalyst regenerator (82) comprising a catalyst strip reactor and a catalyst regeneration reactor. The deactivated catalyst (60) separated from the bio-oil is at least partially recycled to the catalyst strip reactor to remove catalyst decomposition products absorbed thereon. The stripping step includes contacting the deactivated catalyst with a gas comprising steam at a temperature between 400° C. and 800° C., preferably between 400° C. and 700° C., more preferably between 450° C. and 650° C. Alternatively, the deactivated catalyst may first be contacted with a gas comprising steam and subsequently heated to the desired temperature.

[0240] Products (84) removed during the stripping step may be at least partially recycled and combined with the bio-oil (62).

[0241] The stripped fluid catalytic cracking catalyst is then contacted with air or a mixture of air and oxygen in a regenerator at a temperature of 550°C or higher to produce regenerated catalytic cracking catalyst, heat and carbon dioxide. Preferably, the stripped fluid catalytic cracking catalyst is contacted with air or a mixture of air and oxygen in the regenerator at a temperature of 550°C to 950°C, preferably 575°C to 900°C, more preferably 600°C to 850°C.

[0242] The regeneration step may be carried out at a pressure between 0.05 MPa and 1 MPa, preferably between 0.1 MPa and 0.6 MPa.

[0243] The regenerated fluid catalytic cracking catalyst (86) is then at least partially recycled to the fluid catalytic cracking reactor (54).

[0244] 2 shows an alternative simplified process (110) for forming a biogasoline fuel from a biologically derived hydrocarbon feedstock. Process steps shown in dashed lines should be understood to be optional process steps.

[0245] 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 deoxygenation reactor (148) containing a hydrodeoxygenation catalyst, where the reactor further comprises an inlet (150) for feeding a hydrogen-containing gas to the deoxygenation reactor (148). The deoxygenation reactor heats the bio-based hydrocarbon feedstock (144), the hydrogen-containing gas and the hydrodeoxygenation catalyst to a temperature between 200°C and 450°C, preferably between 250°C and 400°C, more preferably between 280°C and 350°C.

[0246] The reduced oxygen containing hydrocarbon feedstock (152) is then fed to a fluidized catalytic cracking reactor (154). An example of a fluidized catalytic cracking system is also shown in FIG. 3. FIG. 2 shows that the fluidized catalytic cracking reactor includes an inlet (156) at or near the bottom of the fluidized catalytic cracking reactor (154) for feeding the hydrocarbon feedstock and / or the fluidized catalytic cracking catalyst to the reactor, and an outlet (158) at or near the top of the fluidized catalytic cracking reactor (154), where the formed bio-oil and deactivated catalyst are extracted from the fluidized catalytic cracking reactor (154). The fluidized catalytic cracking reactor heats the hydrocarbon feedstock and the fluidized catalytic cracking catalyst to a temperature of at least 400° C., preferably at a temperature between 400° C. and 800° C., more preferably at a temperature between 450° C. and 750° C., more preferably at a temperature between 500° C. and 700° C. The fluid catalytic cracking process may be carried out at a pressure of from 0.05 MPa to 10 MPa, preferably from 0.1 MPa to 8 MPa, more preferably from 0.5 MPa to 6 MPa.

[0247] The deactivated catalyst (160) is at least partially separated from the bio-oil that is formed. The separation step is preferably performed using one or more cyclone separators and / or one or more vortex tubes.

[0248] The separated bio-oil (162) is fed to a desulfurization reactor (164) containing a hydrodesulfurization catalyst, where the desulfurization reactor further includes an inlet (166) 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.

[0249] 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.

[0250] The desulfurization reactor may further comprise a gas separator for removing hydrogen sulfide formed from the bio-oil. Optionally, the sulfur-reduced bio-oil and / or the gasoline fuel fraction 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 and / or the sulfur-reduced gasoline fuel fraction may then 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 the gasoline fuel fraction has a temperature between 60° C. and 120° C. during the degassing step, more preferably the bio-oil and / or the gasoline 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.

[0251] Any unreacted hydrogen-rich gas (168) 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 reduced oxygen-containing hydrocarbon feedstock (152).

[0252] The sulfur-reduced bio-oil is then fed to a hydrotreating reactor (170) containing a hydrotreating catalyst 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 higher energy density.

[0253] The hydrotreating reactor further comprises an inlet (172) 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.

[0254] 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.

[0255] The hydrotreated bio-oil (174) is then fed to a fractionation column (176) which separates 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 first fractionation cut may be removed from the fractionation column via an outlet (178). The first cut fraction is a bio-derived gasoline fuel fraction.

[0256] Either via the desulfurization reactor (164) or instead of this desulfurization step, the bio-derived gasoline fuel (178) may be fed to a desulfurization reactor (180) to at least partially remove sulfur-containing components in the biofuel in addition to reducing the sulfur-containing compounds in the bio-oil. The desulfurization reactor (180) is as defined above.

[0257] The process (110) may further include a catalyst regenerator (182) comprising a catalyst strip reactor and a catalyst regeneration reactor. The deactivated catalyst (160) separated from the bio-oil is fed to the catalyst strip reactor to remove absorbed catalyst decomposition products. The stripping step includes contacting the deactivated catalyst with a gas comprising steam at a temperature between 400° C. and 800° C., preferably between 400° C. and 700° C., more preferably between 450° C. and 650° C. Alternatively, the deactivated catalyst may be first contacted with a gas comprising steam and subsequently heated to the desired temperature.

[0258] Products (184) removed during the stripping step may be at least partially recycled and combined with the bio-oil (162).

[0259] The stripped fluid catalytic cracking catalyst is then contacted with an oxygen-containing gas in a regeneration reactor at a temperature of 550°C or higher to produce regenerated catalytic cracking catalyst, heat and carbon dioxide. Preferably, the stripped fluid catalytic cracking catalyst with the oxygen-containing gas in the regenerator at a temperature of 550°C to 950°C, preferably 575°C to 900°C, more preferably 600°C to 850°C.

[0260] The regeneration step may be carried out at a pressure between 0.05 MPa and 1 MPa, preferably between 0.1 MPa and 0.6 MPa.

[0261] The regenerated fluid catalytic cracking catalyst (186) is then at least partially recycled to the fluid catalytic cracking reactor (154).

Claims

1. 1. A method for forming a biogasoline 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. cracking the hydrocarbon feedstock of step d. using a fluid catalytic cracking (FCC) process to produce bio-oil; and f. fractionating the resulting bio-oil to obtain a bio-derived gasoline fuel fraction. The method comprising:

2. the biomass feedstock comprises a cellulosic, hemicellulose or lignin based feedstock; and / or wherein 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 comprises 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; and / or 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 is arranged such that the low moisture biomass is conveyed in a countercurrent direction to any pyrolysis gases that are formed, and optionally, biochar formed as a result of the pyrolysis step leaves the pyrolysis reactor separately from said pyrolysis gases, and further optionally The pyrolysis gas is then cooled, for example by use of a venturi, to condense the hydrocarbon feed products. The method according to any one of claims 1 to 8.

10. step d. comprises at least partially separating the biochar from the hydrocarbon feedstock product, preferably the biochar is at least partially separated 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 comprising 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 from said hydrocarbon feedstock product 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; and / or Carbon monoxide present in said non-condensable light gases is contacted with steam in a water gas shift reaction to produce carbon dioxide and biogenic hydrogen gas, preferably said water gas shift reaction is carried out at a temperature between 205°C and 482°C, more preferably at a temperature between 205°C and 260°C, and optionally 10. The method according to any of claims 1 to 9, wherein the water gas shift reaction further comprises a shift catalyst, preferably the shift catalyst is selected from a copper-zinc-aluminium catalyst or a chromium or copper promoted iron based catalyst, more preferably the shift catalyst is a copper-zinc-aluminium catalyst.

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, for example 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 at about atmospheric pressure; and / or contacting the activated carbon compound and / or crosslinked organic hydrocarbon resin with said 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 any of claims 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 biogasoline 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. cracking the hydrocarbon feedstock of step i. using a fluid catalytic cracking (FCC) process to produce bio-oil; and iii. fractionating the resulting bio-oil to obtain a bio-derived gasoline fuel fraction. The method comprising:

14. The hydrocarbon feedstock is subjected to FCC at a temperature of from 400°C to 800°C, preferably from 450°C to 750°C, more preferably from 500°C to 700°C; and / or said hydrocarbon feedstock undergoes FCC at a pressure of from 0.05 MPa to 10 MPa, preferably from 0.1 MPa to 8 MPa, more preferably from 0.5 MPa to 6 MPa; The method according to any one of claims 1 to 13.

15. A process according to any preceding claim, wherein the hydrocarbon feedstock is contacted with the fluid cracking catalyst in a weight ratio of from 1:1 to 1:150, preferably from 1:2 to 1:100, more preferably from 1:5 to 1:

50.

16. The FCC process is carried out in a fluid catalytic cracking reactor, such as a fluidized dense bed reactor or a riser reactor, preferably said FCC reactor is a riser reactor, more preferably said riser reactor is selected from an internal riser reactor or an external riser reactor; optionally, The hydrocarbon feedstock and the fluid cracking catalyst are fed into an inlet at or near the base of an FCC reactor, and the resulting bio-oil and deactivated catalyst are extracted from an outlet at or near the top of the FCC reactor; and / or The hydrocarbon feedstock is atomized before or upon entering the FCC reactor, preferably the hydrocarbon feedstock is atomized to a droplet size of from 10 μm to 60 μm, more preferably to a droplet size of from 20 μm to 50 μm; The method according to any one of claims 1 to 15.

17. A lift gas is supplied to the FCC reactor through an inlet at or near the base of the reactor, preferably the lift gas being selected from steam, nitrogen, or vaporized oil; and / or The hydrocarbon feedstock is contacted with the fluid cracking catalyst in the FCC reactor for a time period of from 0.5 seconds to 15 seconds, preferably from 1 second to 10 seconds, more preferably from 2 seconds to 5 seconds; 17. The method of claim 16.

18. The fluid cracking catalyst is in the form of particles or powder, preferably the fluid cracking catalyst is in the form of a fine powder, for example The particles or powder have a diameter of 10 μm to 300 μm, preferably 15 μm to 200 μm, more preferably 20 μm to 150 μm; The method according to any one of claims 1 to 17.

19. The fluid cracking catalyst comprises a zeolite or a highly active crystalline alumina silicate, and optionally further comprises an amorphous binder compound and / or a filler, preferably the amorphous binder compound is selected from silica, alumina, titania, zirconia and magnesium oxide, or a combination thereof, and / or the filler is selected from a clay, e.g. kaolin, e.g. The zeolite is a large pore zeolite, preferably the large pore zeolite is selected from FAU or faujasite, preferably synthetic faujasite, such as zeolite Y or X, ultrastable zeolite Y (USY), rare earth zeolite Y (REY) and rare earth USY (REUSY), more preferably the large pore zeolite is selected from ultrastable zeolite Y (USY), and / or the zeolite is a large pore zeolite, preferably natural large pore zeolites, such as gmelinite, chabazite, dathialdite, clinoptilolite, faujasite, heulandite, analcite, levinite, erionite, sodalite, cancrinite, nepheline, lazurite, scolecite, natrolite, offretite, mesolite, mordenite, brewsterite and ferrierite, and / or synthetic large pore zeolites, such as zeolites X, Y, A, L. and / or selected from ZK-4, ZK-5, B, E, F, H, J, M, Q, T, W, Z, alpha and beta, omega, REY and USY zeolites, preferably said large pore zeolites being preferably selected from faujasites, in particular zeolites Y, USY and REY; and / or The large pore zeolite comprises internal pores having a pore diameter of 0.62 nm to 0.8 nm. The method according to any one of claims 1 to 18.

20. The zeolite is a medium pore zeolite, preferably the medium pore zeolite is an MFI type zeolite, such as ZSM-5, MFS type zeolite, MEL type zeolite, MTW type zeolite, such as ZSM-12, MTW type zeolite, EUO type zeolite, MTT type zeolite, HEU type zeolite, TON type zeolite, such as theta-1, and / or FER type zeolite, such as ferrierite, for example the medium pore zeolite is selected from ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-34, ZSM-35, ZSM-38, ZSM-48, ZSM-50, silicalite and silicalite 2, preferably the medium pore zeolite is ZSM-5; and / or The medium pore zeolite has internal pores with diameters between 0.45 nm and 0.62 nm; 20. The method of claim 19.

21. The zeolite catalyst comprises a blend of one or more large pore zeolites as defined in claim 19 and one or more medium pore zeolites as defined in claim 20, e.g. the weight ratio of the large pore zeolite to the medium pore zeolite is in the range of 99:1 to 70:30, preferably 98:2 to 85:15; 21. The method according to claim 19 or 20.

22. The process of any of claims 1 to 21, wherein the fluid cracking catalyst is configured to contact the hydrocarbon feedstock in a countercurrent flow, cocurrent flow or crossflow configuration.

23. 23. The method according to any of the preceding claims, further comprising the step of at least partially removing deactivated catalyst from the bio-oil formed, preferably said deactivated catalyst being at least partially removed from said bio-oil using one or more cyclones and / or one or more vortex tubes.

24. The method further comprises at least partially removing sulfur-containing components from the formed bio-oil and / or bio-derived gasoline fuel fraction, preferably wherein the sulfur removal step comprises a catalytic hydrodesulfurization step, e.g. 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 23.

25. 25. The process according to claim 24, 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.

26. The catalytic hydrodesulfurization process further comprises the steps of, for example, cooling the sulfur reduced bio-oil and / or gasoline fuel fraction to a temperature of 60-120° C., preferably 80-100° C., and optionally degassing the sulfur reduced bio-oil and / or gasoline fuel fraction to remove hydrogen sulfide gas, by applying a vacuum pressure of less than 6 KPaA, preferably less than 5 KPaA, more preferably less than 4 KPaA, and optionally The method further comprises the step of deoxygenating the hydrocarbon feedstock, for example by said deoxidation step is a hydrodeoxidation step carried out at a temperature of from 200° C. to 450° C., preferably from 250° C. to 400° C., more preferably from 280° C. to 350° C. and / or said hydrodeoxidation step is carried out at a pressure of from 1 MPa to 30 MPa, preferably from 5 MPa to 30 MPa, and optionally The hydrodeoxygenation step further comprises a catalyst, for example a catalyst as part of a fixed bed or trickle bed reactor, preferably the catalyst comprises a metal selected from group VIII and / or group VIB of the periodic table, preferably the catalyst comprises a metal selected from Ni, Cr, Mo, W, Co, Pt, Pd, Rh, Ru, Ir, Os, Cu, Fe, Zn, Ga, In, V and mixtures thereof, more preferably the catalyst is a supported catalyst such as a support selected from alumina, amorphous silica-alumina, titania, silica, ceria, zirconia, carbon, silicon carbide or a zeolite, e.g. zeolite Y, zeolite beta, ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-48, SAP0-11, SAP0-41 and ferrierite, 26. The method of claim 24 or 25.

27. Further comprising a step of hydrotreating the formed bio-oil, e.g. the hydrotreating step is carried out at a temperature of 250°C to 350°C, preferably 270°C to 330°C, more preferably 280°C to 320°C; and / or the hydrotreating step is 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, and optionally 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 the catalyst comprises a metal selected from group VIII of the periodic table, 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, more preferably the catalyst is a supported catalyst, such as 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 26.

28. 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 27.

29. 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 28.

30. The at least partially removed catalyst is subjected to regeneration; a. stripping the deactivated catalyst to remove bio-oil absorbed on the surface of the catalyst; and b. Regenerating the catalyst and optionally, wherein the stripping step comprises contacting the deactivated catalyst with a gas comprising steam at a temperature of from 400° C. to 800° C., preferably from 400° C. to 700° C., more preferably from 450° C. to 650° C., preferably contacting the deactivated catalyst with the gas comprising steam for a period of from 1 to 10 minutes, preferably from 2 to 8 minutes, more preferably from 3 to 6 minutes, and preferably contacting the deactivated catalyst with a gas comprising steam in a weight ratio of from 10:1 to 100:1, preferably from 20:1 to 60:1; and / or the catalyst is regenerated by contacting the stripped catalyst with an oxygen-containing gas at a temperature of from 550° C. to 950° C., preferably from 575° C. to 900° C., more preferably from 600° C. to 850° C., and / or the regeneration step is carried out at a pressure of from 0.05 MPa to 1 MPa, preferably from 0.1 MPa to 0.6 MPa; 30. The method according to any one of claims 23 to 29.

31. 31. The method of claim 30, wherein the regenerated catalyst is at least partially recycled to the FCC process.

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