Fluorine removal in renewable fuel production

Abstract

The present invention relates to the removal of fluorine in the processing of renewable feedstocks.

Description

[Technical Field]

[0001] Technical Field The present invention relates to the removal of fluorine in the processing of renewable feedstocks. [Background technology]

[0002] background Renewable feedstocks obtained from pyrolysis and hydrothermal liquefaction (HTL) of solid biomass waste (e.g., sludge, plastic waste, municipal solid waste) can contain significant amounts of fluorine. Some fluorine compounds have very high chemical and thermal stability and can be difficult to remove, which is why they are sometimes known as "forever chemicals."

[0003] The refinement of renewable feedstocks into transportation fuels such as jet fuel and diesel fuel requires the removal of sulfur, nitrogen, and oxygen to extremely low levels, while reducing other undesirable elements such as fluorine to meet relevant product specifications for transportation fuels. Producing jet fuel or its components with low fluorine content (e.g., 2 ppm by mass or less, or even 1 ppm by mass or less) has proven difficult. This has proven difficult to achieve by hydroprocessing alone, even under very rigorous reactor conditions. [Prior art documents] [Patent documents]

[0004] [Patent Document 1] WO21209555A1 [Non-patent literature]

[0005] [Non-Patent Document 1] “Heterodoxy in Fast Pyrolysis of Biomass” by Robert Brown [Non-patent document 2] Golakota et al., “A review of hydrothermal liquefaction of biomass”, Renewable and Sustainable Energy Reviews, vol. 81, Part 1, Jan. 2018, p. 1378-1392. Summary of the Invention [Problem to be solved by the invention]

[0006] During hydroprocessing of fossil fuels (upgrading), the process of separating sulfur and nitrogen from organic sulfur and nitrogen compounds to produce sulfur- and nitrogen-free compounds, it is known that heteroatom removal becomes increasingly difficult as the carbon number increases. Therefore, the most difficult heteroatom compounds to remove are expected to be present in the fractions with the highest carbon numbers. Surprisingly, the most difficult fluorine compounds to remove after hydroprocessing were found to be present in the naphtha and light jet fractions, rather than being concentrated with increasing carbon number. In fossil fuel-based refining processes, fluorine removal is less of a problem because the fluorine content in the feed is typically significantly lower.

[0007] summary Surprisingly, it was found that the fluorine content in the jet boiling range is higher than that in the diesel and higher boiling ranges. By separating and removing the lightest fraction of the jet boiling range product, the resulting jet boiling range heavy fraction has a significantly lower fluorine content than all other boiling ranges. Because the fluorine content of the upgraded product, which boils above the jet boiling range, is significantly lower, hydrocracking this material to convert it to a jet boiling range product yields a jet boiling range product with a lower fluorine content. This increases the production of jet fuel with reduced fluorine content. While the standard solution is hydroprocessing of renewable feedstocks, reducing the fluorine content of the jet fuel boiling range to below 2 ppm by mass has been considered extremely difficult, even under very harsh conditions (high activity catalysts, high pressure, and / or high temperature in the reactor). [Means for solving the problem]

[0008] Thus, a first aspect of the present invention relates to a process for obtaining a jet fuel fraction with a low fluorine content from a solid renewable feedstock, said process comprising the steps of: at least 5 ppm derived from said solid renewable feedstock wt of fluorine, 25 ppm wt of fluorine, or 50 ppm wt feeding the fluorine-containing liquid oil stream to a fractionation section and subjecting it to fractionation to provide at least a light jet fuel fraction and a heavy jet fuel fraction, wherein the fluorine content in the heavy fraction is lower than the fluorine content in the liquid oil stream.

[0009] Additional aspects of the present invention are set forth in the following description, drawings and claims. [Brief explanation of the drawings]

[0010] Text description of the illustration image022.gif. The technology is illustrated by the following schematic diagram. Figure 1 shows the fluorine content of the product in Experiment 1. Figure 2 shows the fluorine content of the product in Experiment 2. Figure 3 shows the fluorine content of the product in Run 4. 4 and 8 show prior art layouts. 5-7 and 9-11 show various layouts according to the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0011] Detailed Disclosure As used herein, "fluorine" refers to inorganic and organic molecules that contain F. "Low" fluorine content means a fluorine content of less than 5 ppm by weight. Fluorine content is measured according to ASTM D7359.

[0012] 1. A method for obtaining a jet fuel fraction with a low fluorine content from a solid renewable feedstock, the method comprising the steps of: at least 5 ppm derived from said solid renewable feedstock wt of fluorine, 25 ppm wt of fluorine, or 50 ppm wt feeding the fluorine-containing liquid oil stream to a fractionation section and subjecting it to fractionation to provide at least a light jet fuel fraction and a heavy jet fuel fraction, wherein the fluorine content in the heavy fraction is lower than the fluorine content in the liquid oil stream.

[0013] A novel feature is the distillation removal of the lightest fraction of the jet cut (jet fraction) derived from the hydroprocessing of renewable feedstocks. The resulting heavier jet cut has reduced fluorine content. When hydrocracking is used, the fluorine content is reduced in both the lightest and heavier jet fractions. As a result, an increased amount of light jet can be added to the heavier jet fraction.

[0014] renewable feedstock The process comprises a liquid oil stream derived from a solid renewable feedstock. In one embodiment, the renewable feedstock comprises one or more of the following: - lignocellulosic-based biomass, e.g. wood products, algae, grass, forestry waste and / or agricultural residues; recycled solid waste, in particular the organic fraction thereof, where recycled solid waste is defined as a feedstock containing materials from items discarded by the general public, for example mixed recycled solid waste as defined in EU Directive 2018 / 2001 (RED II), Annex IX, Part A; or - Nitrogen-rich renewable feedstocks, such as manure or sewage sludge.

[0015] In one embodiment, the proportion of solid renewable feedstock derived from renewable sources is between 5 and 60% by mass, for example 10 or 50% by mass, hi another embodiment, the proportion of feedstock derived from renewable sources is greater than 60% by mass, for example 70 to 90% by mass.

[0016] Liquid oil feed delivery The solid renewable feedstock must be cracked to produce a liquid oil stream. Thus, in one embodiment, the method further comprises pyrolysis of the renewable feedstock to produce the liquid oil stream, preferably comprising a pyrolysis step and / or a hydrothermal liquefaction step. While specific process conditions are mentioned below for specific processes, similar pyrolysis processes involving temperatures of 300°C to 700°C, pressures of 1 atm to 400 atm, and residence times of 1 second to 1 hour are feasible, each with its own advantages.

[0017] The pyrolysis step can include the use of a pyrolysis unit, such as a fluidized bed, transport bed, or circulating fluidized bed, as known in the art. Typically, it is carried out at about 1 atm and 350-650°C. For example, the pyrolysis step can include the use of a pyrolysis unit (also referred to herein as a pyrolysis reactor), a cyclone to remove particulate solids such as char, and a cooling unit, thereby producing an off-gas stream (i.e., pyrolysis off-gas) and a liquid oil stream, i.e., condensed pyrolysis oil. The off-gas stream can be concentrated into light hydrocarbons (e.g., C1-C4 hydrocarbons) and the like. ) , CO, and CO2. Liquid oil streams, also known as pyrolysis oils or bio-oils, are liquid materials resulting from the depolymerization of pyrolysis products and typically enriched in a mixture of over 200 different compounds (including aldehydes, ketones, and / or other compounds such as furfural with carbonyl groups). Thus, liquid oil feeds derived from renewable feedstocks can be pyrolysis oils or bio-oils.

[0018] In one embodiment, the pyrolysis step involves rapid pyrolysis (also known as flash pyrolysis). Rapid pyrolysis refers to the thermal decomposition of solid renewable feedstock in the absence of oxygen, with a temperature range of 350-650°C (e.g., about 500°C) and a reaction time of 10 seconds or less, e.g., less than 10 seconds, e.g., 5 seconds or less, e.g., about 2 seconds, i.e., a vapor residence time of 10 seconds or less, e.g., 2 seconds or less, e.g., about 2 seconds. The pressure is typically 1 atmosphere. This method provides sufficient heat to the reaction to at least partially decompose large organic compounds, such as polymers, present in the renewable feedstock. Because the reaction occurs under oxygen-deficient conditions, the high temperatures do not result in combustion of the renewable feedstock.

[0019] Conventionally, fast pyrolysis can also be carried out by autothermal operation (e.g., in a fluidized bed reactor). The latter, also referred to as autothermal pyrolysis, is characterized by using air as the fluidizing gas, optionally mixed with an inert gas or recycled gas, or a mixture of air and an inert gas or recycled gas. This allows the partial oxidation of pyrolysis compounds produced in the pyrolysis reactor (autothermal reactor) to serve as the energy source for pyrolysis and simultaneously improve heat transfer. For more details on autopyrolysis, see, for example, "Heterodoxy in Fast Pyrolysis of Biomass" by Robert Brown: https: / / dx.doi.org / 10.1021 / acs.energyfuels.0c03512. In one embodiment, the pyrolysis step comprises autopyrolysis.

[0020] In embodiments, the pyrolysis step comprises catalytic fast pyrolysis (CFP). Such catalytic fast pyrolysis steps involve the use of a catalyst, such as an acid catalyst, a zeolite catalyst, etc. Catalytic fast pyrolysis can be operated both in situ, where the catalyst is located within the pyrolysis unit, and ex situ, where the catalyst is located in a separate reactor.

[0021] The pyrolysis step can include in situ catalytic fast pyrolysis. In one embodiment, a catalyst is located within the pyrolysis unit, and deoxygenation (DO), e.g., decarboxylation, using an acid-based catalyst, e.g., a zeolite catalyst, occurs in the pyrolysis reactor immediately after pyrolysis vapor formation. Suitable catalysts for CFP include alumina and all types of zeolite catalysts, such as HZSM-5, typically used in hydrocracking (HCR) and cracking reactions in refinery processes. Alternatively, in one embodiment, hydrogen is added and a hydrotreating catalyst, e.g., a hydrodeoxygenation catalyst, is located within the pyrolysis unit, and hydrodeoxygenation occurs in the pyrolysis reactor immediately after pyrolysis vapor formation, typically achieving 50% to 99%, or even complete oxygen removal. This process is also referred to as in situ HDO (also referred to as reactive catalytic fast pyrolysis, RCFP, typically operated at 1.5 barg H2), although a combination of in situ and ex situ HDO can also be used, resulting in greater than 95%, or even complete oxygen removal. Suitable catalysts for HDO are metal-based catalysts, such as CoMo or NiMo catalysts, including reduced Ni, Mo, Co, Pt, Pd, Re, Ru, and Fe, and sulfide forms, such as CoMoS, NiS, NiMoS, NiWS, and RuS, are also suitable. The catalyst support is similar to that used in conventional HDO in oil refinery processes and is typically a refractory support such as alumina, silica, titania, or a combination thereof.

[0022] When operating in in situ mode, H2 is added to the pyrolysis reactor. When operating in ex situ mode, 、 H2 can be added to either the pyrolysis reactor or the HDO reactor. H2 pressures are typically in the range of 1 barg to 40 barg.

[0023] The use of a catalyst in the pyrolysis reactor can potentially reduce the temperature required to carry out the pyrolysis and can also increase the selectivity to the desired pyrolysis oil compounds.

[0024] In one example embodiment, the pyrolysis step is fast pyrolysis, and the vapor residence time is 10 seconds or less, e.g., less than 10 seconds, 5 seconds or less, e.g., about 2 seconds, or 1 second, or in the range of 1 to 5 seconds, and is selected from: simple fast pyrolysis; in-situ catalytic fast pyrolysis (in-situ CFP); ex-situ catalytic fast pyrolysis (ex-situ CFP); reactive catalytic fast pyrolysis (RCFP); hydrothermal cracking (HP); or catalytic fast hydrothermal cracking (CHP).

[0025] As an alternative to fast pyrolysis, intermediate and / or slow pyrolysis can also be used and may be preferred in some cases.

[0026] In one embodiment, the pyrolysis step is intermediate pyrolysis, with vapor residence times ranging from 10 seconds to 5 minutes, e.g., 11 seconds to 3 minutes. Similar to fast pyrolysis, temperatures range from 350 to 650°C, e.g., about 500°C. This pyrolysis is often carried out in a pyrolysis reactor for processing different types of waste, with the vapors being combusted after the pyrolysis reactor. Typical reactors include Herreshoff furnaces, rotary drums, Amaron, CHOREN paddle pyrolysis kilns, auger reactors, and vacuum pyrolysis reactors.

[0027] In another embodiment, the pyrolysis step is slow pyrolysis, with solids residence times ranging from 5 minutes to 2 hours, e.g., 10 minutes to 1 hour. A temperature of approximately 300°C is suitable. This pyrolysis results in a high char yield, which can be used as fertilizer or carbonized char. Pyrolysis still produces gas and bio-crude oil, and if the carbon is used as fertilizer, the greenhouse gas (GHG) emissions of the final bio-oil can exceed 100%, making it carbon negative. Representative reactors include auger reactors (which have different residence times than intermediate pyrolysis), fixed-bed reactors, kilns, Lambiot SIFIC / CISR retorts, Lurgi process, wagon reactors, and Carbotwin retorts.

[0028] Thus, the liquid oil feed includes compounds formed at moderately elevated temperatures (>80°C) but below temperatures that result in substantially complete hydrotreating. The liquid oil feed can include: i) feeds rich in conjugated diolefins or styrene and its homologues produced by the thermochemical decomposition of plastic waste, municipal solid waste, waste-derived fuels, and solid recovered fuels; ii) feeds rich in carbonyl compounds and sugars produced by the thermochemical decomposition of lignocellulosic biomass; and / or iii) nitrogen-rich feeds derived from the thermochemical decomposition of nitrogen-rich feeds (e.g., fertilizers, sewage sludge); and / or similar compositions from other sources. In one embodiment, the liquid oil feed can include larger compounds because the compounds produced by the thermochemical decomposition (e.g., compounds i)-iii) can subsequently react, i.e., between identical (e.g., diolefins with diolefins) or different (e.g., aldehydes with phenols) reactive functional groups to provide larger compounds. Such larger compounds can cause complete or partial blockage of reactors, tubes, heaters, heat exchangers, and catalysts involved in subsequent process steps.

[0029] Thus, the method of the present invention may further comprise the step of pyrolyzing a renewable feedstock to produce said liquid oil stream, preferably said pyrolysis comprising a pyrolysis step and / or a hydrothermal liquefaction step.

[0030] In one embodiment, the pyrolysis is hydrothermal liquefaction. Hydrothermal liquefaction refers to the thermochemical conversion of biomass into liquid fuels by treating it in a high-temperature, high-pressure aqueous environment for a sufficient time to decompose the solid polymer or biopolymer structure into primarily liquid components. Typical hydrothermal treatment conditions range from 250 to 400°C in temperature and 40 to 400 bar in operating pressure. This technology offers the advantages of lower temperature operation, higher energy efficiency, and lower tar yield compared to pyrolysis (e.g., fast pyrolysis). For more information on hydrothermal liquefaction of biomass, see, for example, Golakota et al., "A review of hydrothermal liquefaction of biomass," Renewable and Sustainable Energy Reviews, vol. 81, Part 1, January 2018, pp. 1378-1392.

[0031] In one embodiment, the pyrolysis is liquefaction. Liquefaction refers to the thermochemical conversion of biomass into liquid fuel by processing in the absence of water. Typical conditions are temperatures in the range of 250-375°C and operating pressures in the range of 40-220 bar. This is also described, for example, in WO21209555A1.

[0032] The liquid oil stream fed to the plant preferably contains more than 5 ppm fluorine by weight, such as more than 25 ppm, more than 50 ppm, or more than 75 ppm fluorine by weight.

[0033] stabilization The method, in one aspect, includes the step of subjecting the liquid oil stream to a stabilization step in a stabilization section prior to the fractionation step.

[0034] The purpose of the method step is to provide a stabilized liquid oil stream, characterized as a stream having a lower content of reactive compounds than the original liquid oil stream. This can be achieved by modifying the chemical composition of the liquid oil and / or removing destabilizing components from the liquid oil. The stabilized liquid oil stream can have a lower vapor pressure than the original liquid oil stream. In this way, the method step provides a less reactive, i.e., stabilized, liquid oil stream, which can be fed to a subsequent method step.

[0035] In one embodiment, the method includes reacting the liquid oil stream with hydrogen in the presence of a catalyst in a stabilization reactor, wherein the catalyst comprises at least one metal selected from Ni, Co, Mo, W, Cu, Pt, Pd, and Ru, e.g., nickel-molybdenum molybdenum (Ni-Mo), cobalt-molybdenum (Co-Mo), nickel-tungsten (NiW), nickel-copper (NiCu), Pt, Pd, or Ru, to provide at least one stabilized liquid oil stream. The catalyst may be S-passivated.

[0036] In one embodiment, the method includes operating the stabilization reactor at a temperature of 80 to 230°C and a pressure of 20 to 200 barg. The temperatures include the inlet temperature of the liquid oil stream and the outlet temperature of the stabilized liquid oil stream. The barg unit indicates pressures above atmospheric pressure (atmospheric pressure is approximately 1 bar), and the pressure may also be referred to as "hydrogen pressure." The method can be carried out at a hydrogen to liquid oil ratio of 500 to 10,000 NL / L, e.g., 2,000 to 5,000 NL / L, specifically 2,500, 3,000, 3,500, 4,000, or 4,500 NL / L. As used herein, "hydrogen-to-liquid oil ratio" or "H2 / oil ratio" refers to the volumetric ratio of hydrogen to the flow rate of the liquid oil stream. It will be understood that the unit NL refers to "standard" liters, i.e., the amount of gas that occupies this volume at 0°C and 1 atmosphere. Liquid volumes are standard volumes at 15°C and 1 atmosphere. When H2 / oil ratios are mentioned, the values ​​are illustrative; if hydrogen consumption is significantly higher or lower in a particular reaction step, the H2 / oil ratio can be adjusted accordingly. Typically, observed or theoretical hydrogen consumption is multiplied by a safety factor of 6, although in practice safety factors of 3 to 8 may be observed. When H2 / oil ratios are considered, an adjustment for the hydrogen concentration in the gas phase may also be included; for example, an 80% vol / vol hydrogen concentration would increase the required gas / oil ratio by 100 / 80 compared to the H2 / oil ratio requirement for 100% vol / vol hydrogen.

[0037] In this manner, the process steps can result in the modification of the liquid oil stream by hydrogenation to remove destabilizing components, thereby converting reactive compounds present in the liquid oil stream to less reactive compounds under low-temperature conditions. In one embodiment, the liquid oil stream at the stabilization section inlet contains at least 0.5% by mass of oxygen (O), e.g., at least 4% by mass, at least 20% by mass, at least 30% by mass, or at least 45% by mass of oxygen (O). Pyrolysis oils derived from recycled plastics typically contain 0.5-4% by mass of oxygen, while pyrolysis oils derived from biological materials typically contain 5-50% by mass of oxygen. Oxygen can exist as reactive compounds, such as furfural, furan, aldehydes, ketones, and acids, which can be converted to alcohols, for example, by efficiently converting carbonyl groups to alcohols. The conversion of carbonyls to alcohols occurs at reactor temperatures of approximately 100-200°C. The alcohols are further converted to saturated organic compounds in a stabilization step and / or in a subsequent hydroprocessing step such as hydrodeoxygenation (HDO).

[0038] In certain embodiments, the method steps include hydrotreating a liquid oil stream in a continuous fixed bed reactor, specifically hydrotreating the liquid oil stream in the presence of a nickel-molybdenum (Ni-Mo) based catalyst at an inlet temperature of 80-230°C, a pressure of 100-200 barg, and a liquid hourly space velocity (LHSV) of 0.1-1.1 h. -1 A stabilized liquid oil stream is formed by hydrotreating the liquid oil stream under conditions of a hydrogen-to-liquid oil ratio of 500-10,000 NL / L (e.g., 2,000-5,000 NL / L), defined as the volumetric ratio of hydrogen to the liquid oil stream. The amount of hydrogen is typically calculated by multiplying the theoretical hydrogen consumption by a factor. For example, for a feedstock containing 6.3 mass% O and 8.7 mass% N, the theoretical hydrogen consumption is approximately 300 NL / L (ignoring hydrogen consumption due to removal of other heteroatoms, saturation of double bonds, hydrocracking, etc.), and applying a safety factor of 6, the hydrogen-to-oil volumetric ratio is 1,800 NL / L.

[0039] The combination of the above mentioned features, i.e. low temperature, high pressure, low LHSV and high H2 / liquid oil ratio, allows for liquid oil stabilization, specifically converting carbonyl groups to alcohols, thereby extending the run time before plugging issues (if they occur) occur, while also reducing catalyst coking and subsequent catalyst deactivation and avoiding hydrogen starvation.

[0040] The temperature range of 80 to 230°C encompasses the inlet temperature of the liquid oil stream and the outlet temperature of the stabilized liquid oil stream. For example, the inlet temperature can be 80, 100, 110, 120, or 130°C. A higher inlet temperature (e.g., 130°C) facilitates ignition of the process and initiation of the exothermic reaction. The outlet temperature can be, for example, 200°C, 215°C, or 230°C. More generally, the temperature in a given step or reactor (unit) refers to the inlet temperature in an adiabatic step or the reaction temperature in an isothermal step. Thus, the temperature of 80 to 230°C appropriately refers to the inlet temperature. The term "continuous operation," as known to those skilled in the art, means that the flow of incoming liquid oil is constant during a given production cycle and that a stabilized liquid oil stream is withdrawn as the outgoing product. This contrasts with batch or discontinuous operation, also known in the art, in which the total amount of liquid oil and catalyst is introduced at the beginning of the process and the outgoing product is withdrawn after a certain time.

[0041] Therefore, operation at low temperatures (80-230 °C) not only results in stabilization of the liquid oil flow and avoids clogging problems, but also allows stabilization without deactivating the catalyst and without the risk of hydrogen starvation.

[0042] Guard Unit Optionally, the hydroprocessing section includes a guard unit. The guard unit is located upstream of the first hydroprocessing unit and traps one or more heteroatoms within the guard material. The trapped heteroatoms are typically selected from arsenic (As), phosphorus (P), silicon (Si), iron (Fe), nickel (Ni), vanadium (V), potassium (K), sodium (Na), zinc (Zn), magnesium (Mg), chromium (Cr), molybdenum (Mo), halides, or combinations thereof. These heteroatoms solidify as sulfides or other solid compounds within the guard material, making trapping advantageous.

[0043] Generally, guard conditions are similar to downstream hydroprocessing conditions, typically involving a temperature range of 250-420°C, a pressure range of 30-200 bar, and a liquid hourly space velocity (LHSV) range of 0.01 to 2. Hydrogen-to-oil ratios, including the hydrogen required for downstream hydroprocessing, typically range from 500-4500 NL / L.

[0044] The guard material can be a metal guard bed. By metal guard bed, we mean a bed, e.g., a fixed bed, containing material active in hydrometallation (HDM) and / or hydrodeoxygenation (HDO). The hydrodemetallation (HDM) process involves a pretreatment process that produces free metals and converts them to metal sulfides. Hydrodemetallation differs from, for example, hydrodesulfurization (HDS), in which heteroatoms (S) are removed in a gaseous state. In addition to the removal of heteroatoms as described above, the guard material can also be provided with deoxygenation activity.

[0045] A suitable guard bed may be a porous material comprising alumina, the alumina comprising α-alumina, which may further comprise θ-alumina, e.g., 0-50% by weight, and optionally a lesser amount, e.g., 0-10% by weight, of γ-alumina, as determined by XRD. The porous material may have a BET surface area of ​​1-110 m2, as measured according to ASTM D4567-19 (i.e., single point measurement of surface area by the BET equation). 2The porous material may have a pore size distribution (PSD) of 0.50 to 0.80 ml / g, preferably a total pore volume of 0.50 to 0.80 ml / g as measured by mercury penetration according to ASTM D4284. The pore size distribution (PSD) of the porous material desirably comprises at least 30% by volume of the total pore volume of pores with a radius of >400 Å, preferably >500 Å (e.g., pores with a radius of up to 5000 Å). It preferably includes pores with a radius of 500 Å, e.g., up to 5000 Å; for example, as described in the applicant's co-filed patent application PCT / EP2021 / 068656. The porous material may further comprise one or more metals selected from Co, Mo, Ni, W, and combinations thereof, preferably Ni, and may be combined with at least one other metal. The content of the one or more metals is 0.25 to 20% by weight, e.g., 0.25 to 15%, 0.25 to 10%, or 0.25 to 5% by weight. In one embodiment, at least one metal is in the form of an oxide or sulfide.

[0046] Catalytic Hydroprocessing In one embodiment, the method comprises, prior to the fractionation step, and preferably after the stabilization step, subjecting the liquid oil stream to a catalytic hydroprocessing step in a hydroprocessing section, which produces one or more hydroprocessed product streams. Thus, the method comprises at least one catalytic hydroprocessing step.

[0047] In one embodiment, the method comprises one or more catalytic hydroprocessing steps selected from hydrodeoxygenation (HDO), hydrotreating, hydrodenitrification (HDN), hydrodesulfurization (HDS), aromatic ring saturation (HDA), hydrocracking, and / or isomerization, carried out in one or more hydroprocessing reactors. Hydrodeoxygenation (HDO) refers to a process for removing oxygen from a liquid oil feed primarily as HO, but may also be removed as CO and CO. 。

[0048] In the following, reference may be made to a first and a second hydroprocessing step. Because oxygen compounds are typically more reactive than nitrogen compounds, the first hydroprocessing step may be referred to as the HDO step and the second hydroprocessing step as the HDN step, even when multiple hydroprocessing reactions are performed in parallel.

[0049] Catalytically active materials for hydrotreating typically include an active metal (a sulfide-based metal such as nickel, cobalt, tungsten, and / or molybdenum, or an elemental noble metal such as platinum and / or palladium) and a refractory support (alumina, silica, titania, or a combination thereof). Hydrotreating is typically carried out at temperatures ranging from 250 to 420°C or ~425°C, at pressures ranging from 30 to 200 bar, and for 0.1 to 2 or ~5 hours. -1 Liquid hourly space velocity (LHSV) in the range of 0.1 to 0.5 L / L, gas-to-oil ratio (GOR) of 300 to 5000 NL / L, optionally with intermediate cooling by cold hydrogen, feed, or product quenching.

[0050] Hydrodearomatization (HDA) is a hydrotreating process that uses heat, pressure, and catalysts to saturate aromatic hydrocarbons with hydrogen, reducing the aromatic hydrocarbon content of the product stream. Catalytically active materials in hydrodearomatization typically contain an active metal (typically an elemental precious metal such as platinum and / or palladium, or a sulfide-based metal such as nickel, cobalt, tungsten, and / or molybdenum) and a refractory support (such as amorphous silica-alumina, alumina, silica, titania, or a combination thereof). Dearomatization reaction conditions range from 200 to 350°C at a temperature of 20 to 200 bar, a liquid hourly space velocity (LHSV) of 0.5 to 8.0, and a gas-to-oil ratio (GOR) of 300 to 1500 nL / L.

[0051] Hydrocracking refers to a bifunctional catalytic process that combines catalytic cracking and hydrogenation, in which a liquid oil feed undergoes cracking in the presence of hydrogen. Catalytically active materials for hydrocracking have similar properties to those for isomerization, typically comprising an active metal (elemental precious metals such as platinum and / or palladium, or sulfide-based metals such as nickel, cobalt, tungsten, and / or molybdenum), an acidic support (typically a molecular sieve with a topology such as MFI, BEA, or FAU that exhibits high cracking activity), and a refractory support (such as alumina, silica, titania, or a combination thereof). The difference from catalytically active materials for isomerization typically lies in the nature of the acidic support, which may have a different structure (e.g., amorphous silica-alumina) or a different acidity, such as a silica:alumina ratio. Hydrocracking conditions range from 250-400°C in temperature, 30-200 bar in pressure, 0.5-8.0 in liquid hourly space velocity (LHSV), and 300-2500 NL / L in gas-to-oil ratio (GOR), optionally with intermediate cooling by cold hydrogen, feed, or product quenching.

[0052] Isomerization processes (including hydrodewaxing) aim to improve the flow index of liquid oil streams. Catalytically active materials in isomerization reactions typically include an active metal (either elemental precious metals such as platinum and / or palladium, or sulfide-based metals such as nickel, cobalt, tungsten, and / or molybdenum), an acidic support (usually a molecular sieve exhibiting high shape selectivity and having topologies such as MOR, FER, MRE, MWW, AEL, TON, or MTT), and a refractory support (such as alumina, silica, titania, or a combination thereof). Isomerization conditions include a temperature range of 250–400 °C, a pressure range of 20–200 bar, a liquid hourly space velocity (LHSV) of 0.5–8.0, and a gas-to-oil ratio (GOR) of 300–5000 nL / L.

[0053] sorting A liquid oil stream derived from a solid renewable feedstock is fed to a fractionation section and undergoes fractionation by distillation to produce at least a light jet fuel fraction and a heavy jet fuel fraction. After separating the jet fraction into light and heavy jet fractions, the fluorine content in the heavy fraction is lower than the fluorine content in the light jet fraction. Fractionation can be a one-stage (single-stage) or multi-stage process.

[0054] Typically, jet fuel has a boiling point range of 149-300°C. The fractional distillation temperatures (fractional cut points) for the light and heavy jet fractions are selected between 175-225°C depending on the fluorine distribution. At a given fractional distillation temperature, the light jet fuel fraction contains at least 75% of material boiling below the designated distillation temperature (as determined by simulated distillation), and the heavy jet fraction contains at least 75% of material boiling above the distillation temperature (as determined by simulated distillation).

[0055] The optimal distillation temperatures (cut points) for the light fluorine-rich and heavy fluorine-depleted jet fuel fractions may vary depending on the thermochemical cracking method and renewable feedstock, so it may be preferable to determine them experimentally rather than using predefined values. In a proposed determination method, a representative product sample is fractionated by boiling point (e.g., 10°C intervals), and the boiling point limit for light jet fuel is defined based on this distribution, e.g., excluding the range with a fluorine content greater than 5 ppm by mass.

[0056] Light jet fuel fractions can be distinguished from heavy jet fuel fractions by the boiling point of the fraction. The boiling point of the light jet fuel fraction is suitably in the range of 149-200°C, preferably in the range of 149-190°C. The boiling point of the heavy jet fuel fraction is suitably in the range of 175-300°C, preferably in the range of 200-300°C. A heavy jet fuel fraction is understood to be a fluid suitable for use as a jet fuel component, meeting jet fuel boiling point specifications, and having an initial boiling point greater than 175°C, although this term should not be construed to imply jet fuel specifications other than boiling point. Other specifications (such as cold flow properties, flash point, density, aromatic content, hydrogen content, smoke point, etc.) may be beneficially used, alone or in combination, to more precisely define the heavy fuel fraction to define a more suitable jet fuel component in accordance with ASTM D7566.

[0057] The heavy jet fuel fraction obtained by the present process suitably has a fluorine content of less than 2 ppm by mass (eg less than 1 ppm by mass), meeting the required specification.

[0058] In addition to the jet fuel fractionation step, one or more fluids selected from a gas stream, a naphtha stream, a diesel stream, and a fuel oil stream are further provided.

[0059] In one embodiment of the present invention, the hydroprocessing section comprises a guard unit, a first hydroprocessing unit, and a second hydroprocessing unit, and the liquid oil product stream passes through the guard unit, the first hydroprocessing unit, and the second hydroprocessing unit in sequence. Optionally, a stabilization unit is disposed upstream of the guard unit.

[0060] The first hydroprocessing unit preferably operates at a temperature of 250-420°C, a pressure of 30-200 bar, a liquid hourly space velocity (LHSV) of 0.1-2, and a hydrogen-to-oil ratio of 500-10,000 nl / L. Similar parameters are applicable to the second hydroprocessing unit. The second unit preferably operates at a lower LHSV and higher pressure than the first unit, for example. The second unit typically operates with a more hydrogen-rich treat gas.

[0061] The amount of jet fuel can be further increased by hydrocracking products boiling above the jet fuel boiling range to products within the jet fuel boiling range. Thus, in one embodiment, the method further comprises feeding at least a portion of the diesel stream and / or at least a portion of the fuel oil stream to a hydrocracking section to produce a cracked stream, and optionally feeding at least a portion of the cracked stream to a second hydroprocessing unit, e.g., a hydrodenitrogenation unit (HDN unit). In this case, the heavy products from the fractionation column (i.e., a mixture of diesel (gas oil) and fuel oil) are sent to a third reactor section, the hydrocracking reactor HC, where the heavy products are converted primarily to jet-boiling range materials with reduced fluorine content. One scenario is the complete recycle of the diesel and fuel streams. The reactor effluent from the HC reactor is sent to the HDN unit, but it can also be fed directly to the fractionation section, bypassing the HDN unit. This approach increases the output from the process by recycling and cracking the heavy products from the fractionation section.

[0062] In another scenario, the HC reactor can be located downstream of the second (HDN) unit. Thus, the hydroprocessing section comprises a hydrocracking section located downstream of said second hydroprocessing unit, and the method comprises cracking the liquid oil product stream from the second hydroprocessing unit.

[0063] In another application, the renewable feedstock can be distilled prior to the deep hydrotreating (i.e., second) stage to produce a heavy naphtha stream. This distillation is performed to remove naphtha and a portion of the light jet fuel, which contains a relatively high fluorine content. This reduces the fluorine content of the heavy product sent from the distillation process to the hydrotreating stage, thereby reducing the amount of "high" fluorine content light jet fuel material.

[0064] As noted above, the light jet fraction has a higher fluorine content than the heavy jet fraction. The resulting heavy jet fraction can be blended with an amount of the light jet fraction to obtain a composite jet fuel fraction having an acceptable fluorine content. Thus, the method according to the present invention can further comprise blending at least a portion of the heavy jet fuel fraction with at least a portion of the light jet fuel fraction to provide a composite jet fuel fraction.

[0065] Water washing of the liquid oil stream can remove halogens, ammonia, hydrogen sulfide, and salts. In one embodiment, the method further comprises washing the stabilized liquid oil stream with water between the first and second hydroprocessing units. Alternatively, or additionally, the method further comprises a hydroprocessing section in which the stabilized liquid oil stream is washed with water between the second hydroprocessing unit and the fractionation section.

[0066] In a further preferred embodiment, the hydroprocessing section includes a stripper column disposed between the first hydroprocessing unit and the second hydroprocessing unit. The stripper column is configured to receive and separate the liquid oil product stream from the first hydroprocessing unit into a first gas stream, a light oil product stream, and a partially hydrotreated bottoms product, with at least a portion of the partially hydrotreated bottoms product being fed to the second hydroprocessing unit. The stripper separates the liquid oil stream into an overhead gas stream and a light oil product stream comprising naphtha and a light jet cut. The bottoms product is then further hydroprocessed in the second hydroprocessing unit. The heavy products can be recycled to a hydrocracking reactor and converted to jet fuel range products.

[0067] Specific Embodiments of the Invention Figure 4 shows a simplified layout of a conventional system / process for renewable fuel production. A liquid oil feed (1) is mixed with a hydrogen-rich treat gas before being sent to a stabilization section (10) where the feedstock is stabilized, thereby providing a stabilized liquid oil stream (11). This stabilized liquid oil stream (11) is fed to a hydroprocessing section (30) comprising a guard unit (30a), a first hydroprocessing unit (30b), and a second hydroprocessing unit (30c). In the guard unit (30a), contaminants such as As, P, Si, and other metals are captured. After the guard unit (30a), the reactor effluent is sent to the first hydroprocessing unit (30b), where oxygen, sulfur, and nitrogen are removed.

[0068] The stabilized liquid oil stream (11) is water washed between the first hydroprocessing unit (30b) and the second hydroprocessing unit (30c). As shown, the effluent from the first unit (30b) is mixed with water before a high-pressure three-phase separator (30e), where a hydrogen-rich treat gas (39) is separated from the liquid oil and spent water phase. The treat gas (39) is recycled to the reactor system after adding make-up hydrogen. A portion of the hydrogen-rich treat gas (39) can be purged before adding make-up hydrogen. A portion of the liquid oil can optionally be recycled to the reactor system. The liquid oil from the first hydroprocessing unit (30b) is sent to the second hydroprocessing unit (30c) for additional nitrogen and sulfur removal.

[0069] The stabilized liquid oil stream (11) is subjected to at least one step of catalytic hydroprocessing to produce a hydroprocessed product stream (31). The hydroprocessed liquid oil stream (31) is fed to a fractionation section (40) where it undergoes fractionation to provide a gas stream (43), a naphtha stream (44), a diesel stream (45), a fuel oil stream (46), and a (single) jet fuel fraction (41 + 42). Figure 4 also shows a water wash step for the hydroprocessed liquid oil stream (31) between the second hydroprocessing unit (30c) and the fractionation section (40). This wash step is performed in a similar manner to that performed between the first and second hydroprocessing steps described above.

[0070] The layout of Figure 8 is a prior art layout similar to Figure 4. In this layout, the entire process is performed in a single stage configuration (compared to the two-stage configurations of Figures 4-7). A single stage layout can be used when the feedstock is relatively easy to upgrade. Therefore, the layout of Figure 8 shows the stabilization section (10), guard unit (30a), and first hydroprocessing unit (30b), but does not include a separate second hydroprocessing unit (30c). The hydroprocessed product stream (31) is fed to a fractionation section (40) where it undergoes fractionation to provide a gas stream (43), a naphtha stream (44), a diesel stream (45), a fuel oil stream (46), and a (single) jet fuel fraction (41 + 42).

[0071] When the nitrogen content in the feedstock exceeds about 0.5 wt. %, it is advantageous to employ a two-stage configuration (e.g., FIGS. 4-7), in which the amount of ammonia in the process gas in the second stage is significantly reduced compared to the process gas in the first stage.

[0072] Figure 5 is based on the layout of Figure 4. In fractionation section (40) of Figure 5, fractionation occurs to separate a light jet fuel fraction (41) and a heavy jet fuel fraction (42). The fluorine content in the heavy fraction is lower than the fluorine content in the light jet fraction. The layout of Figure 5 optionally blends at least a portion of the heavy jet fuel fraction (42) with at least a portion of the light jet fuel fraction (41) to provide a meet-specification composite jet fuel fraction (49).

[0073] Figure 6 is based on the layout of Figure 5. According to Figure 6, at least a portion of the fuel oil stream (46) is fed to a hydrocracking section (50) to obtain a cracked stream (51). Alternatively or additionally, at least a portion of the diesel stream (45) may be fed to the hydrocracking section (50). At least a portion of the cracked stream (51) output from the hydrocracking section (50) is fed to a hydrodenitrogenation (HDN) unit (30c).

[0074] In the embodiment of Figure 7, the high pressure separator is followed by a stripper column (30d). The stripper separates the liquid oil product into a first gas stream (35), a light oil product stream (36), and a partially hydrotreated bottoms product (37). The partially hydrotreated bottoms product (37) is fed to a hydrodenitrogenation (HDN) unit (30c).

[0075] The layout of Figure 9, like the layout of Figure 5, is a single stage layout that splits the jet fraction into light and heavy jet fractions, thereby reducing the fluorine content of the jet fractions produced.

[0076] The layout of Figure 10 adds a hydrocracking reactor (50) to the layout of Figure 9. The heavy products from the fractionation column (40) are sent to the hydrocracking reactor (50), located downstream of the second hydroprocessing reactor and upstream of the first hydroprocessing reactor, in a so-called "reverse stage" configuration, to crack the products into a range of products, including jet fuel with reduced fluorine content. The effluent from the hydrocracking reactor is returned to the guard unit (30a) or can be returned to any point before the water wash. Depending on the feedstock, it is also possible to place the hydrocracking reactor after unit 30b.

[0077] In the layout of Figure 11 (an extension of Figure 7), a deep HDF step (catalytic fluorine removal) is added. Its purpose is to treat stream 36 with a precious metal catalyst in reactor (60) to significantly reduce the fluorine compound content. The "deep HDF" step can also be located in other places. [Example]

[0078] example A pilot study was conducted to produce a first-stage product from pyrolysis oil derived from sewage sludge, which was further processed in a pilot plant using a commercially available hydrotreating catalyst with high HDN activity.

[0079] The properties of the first stage product are shown in Table 1.

[0080] [Table 1]

[0081] The feed was processed in a pilot unit with a single reactor followed by a gas-liquid separation section. The test was loaded with 20 ml of a commercially available, highly active Ni-Mo-based catalyst designed for nitrogen removal. The test was conducted at liquid feed flow rates of 0.52 to 0.61 h. -1 The experiments were carried out at a hydrogen to oil ratio of about 2500 Nl / l and pressures of 122 barg and 71 barg, respectively.

[0082] Liquid products were collected during the tests under stable reactor conditions at different reactor temperatures and pressures, as shown in Table 2. The amounts of nitrogen and fluorine in the liquid products collected in each experiment were measured.

[0083] [Table 2]

[0084] It was confirmed that the amount of nitrogen and fluorine decreased with increasing reactor temperature and reactor pressure.

[0085] The liquid products recovered in Runs 1, 2, and 4 were fractionated in a batch distillation unit to separate various boiling ranges representing naphtha, jet fuel, diesel fuel, and unconverted oil. Distillation was performed according to ASTM D 2892. The fluorine content of each boiling range was determined according to ASTM D 7359. The fractionation results are shown in Figures 1-3.

[0086] Surprisingly, it was found that the fluorine content in the low boiling range was significantly higher than in the high boiling range. The first cut (<150°C) represents the naphtha product, and the second cut represents the light jet fuel range product (150-175°C or 150-250°C). Jet fuel typically has a boiling range of 150-300°C, so removing the low boiling components from the jet fuel range allows for the production of jet fuel with a low fluorine content.

[0087] Jet fuel typically has a boiling range of 150-300° C. By converting very low fluorine content materials boiling above 300° C. into jet fuel range materials by hydrocracking, it is possible to produce jet fuel range materials with very low fluorine content and increase production of jet fuel with low fluorine content.

[0088] The present invention has been described with reference to several embodiments and examples. Those skilled in the art can combine these embodiments and examples within the scope of the invention as defined by the claims. All documents cited herein are incorporated by reference.

Claims

1. 1. A process for obtaining a jet fuel fraction with a low fluorine content from a solid renewable feedstock, the process comprising: - at least 5 ppm derived from said solid renewable feedstock ｗｔ of fluorine, 25 ppm ｗｔ of fluorine, or 50 ppm ｗｔ a liquid oil stream (31) containing fluorine of 0.01 to a fractionation section (40) and subjecting it to fractionation by distillation to provide at least a light jet fuel fraction (41) and a heavy jet fuel fraction (42), wherein the fluorine content in the heavy fraction is lower than the fluorine content in the liquid oil stream; The method comprising:

2. - subjecting the liquid oil stream (31) to a stabilization step in a stabilization section (10) before said fractionation step, The method of claim 1 further comprising:

3. - before said fractionation step and preferably after a stabilization step, subjecting the liquid oil stream (31) to a catalytic hydroprocessing step in a hydroprocessing section (30), 3. The method of claim 1 or 2, further comprising:

4. The renewable feedstocks include one or more of the following: - lignocellulose-based biomass, such as wood products, algae, grasses, forestry waste and / or agricultural residues; recycled solid waste, in particular the organic fraction thereof, where recycled solid waste is defined as a feedstock containing materials from items discarded by the general public, for example mixed recycled solid waste as defined in EU Directive 2018 / 2001 (RED II), Annex IX, Part A; or - nitrogen-rich renewable feedstocks, such as manure or sewage sludge; The method according to any one of claims 1 to 3.

5. 5. The method of claim 1, wherein the fractional distillation temperature between the light jet fuel fraction and the heavy jet fuel fraction is in the range of 175 to 225°C, and at a given fractional distillation temperature, the light jet fuel fraction contains at least 75% of material boiling below a particular distillation temperature, and the heavy jet fraction contains at least 75% of material boiling above said distillation temperature.

6. The method of any one of claims 1 to 5, wherein the heavy jet fuel fraction (42) contains less than 2 ppm by mass of fluorine, such as less than 1 ppm by mass.

7. 7. The method according to any one of claims 2 to 6, wherein the liquid oil stream (31) - at the inlet of the stabilisation section (10) - comprises more than 5 ppm by weight of fluorine, such as more than 25 ppm by weight of fluorine, more than 50 ppm by weight of fluorine or more than 75 ppm by weight of fluorine.

8. The hydroprocessing section (30) comprises: - Guard unit (30a) - a first hydroprocessing unit (30b) - a second hydroprocessing unit (30c) Including, the liquid oil product stream (31) passes through the guard unit (30a), the first hydroprocessing unit (30b) and the second hydroprocessing unit (30c) in this order; The method according to any one of claims 1 to 7.

9. 9. The method of claim 8, further comprising washing the liquid oil product stream (31) with water between the first (30b) and second (30c) hydroprocessing units.

10. 10. The method of any one of claims 8 to 9, further comprising washing the liquid oil product stream (31) with water between the second hydroprocessing unit (30c) and the fractionation section (40).

11. 11. The method of any one of claims 1 to 10, wherein the fractionation step further provides one or more streams selected from a gas stream (43), a naphtha stream (44), a diesel stream (45) and a fuel oil stream (46).

12. 12. The method of claim 11, further comprising feeding at least a portion of the diesel stream (45) and / or at least a portion of the fuel oil stream (46) to a hydrocracking section (50) to provide a cracked stream (51), and optionally feeding at least a portion of the cracked stream (51) to the second hydroprocessing unit (30c).

13. 13. The method according to any one of claims 8 to 12, wherein the hydroprocessing section (30) comprises a hydrocracking section downstream of the second hydroprocessing unit (30c), and the method comprises the step of cracking a liquid oil product stream (31) from the second hydroprocessing unit (30c).

14. 14. The method according to any one of claims 1 to 13, wherein the hydroprocessing section (30) comprises a stripper column (30d) arranged between the first hydroprocessing unit (30b) and the second hydroprocessing unit (30c), the stripper column (30d) being arranged to receive and fractionate the liquid oil product stream (31) from the first hydroprocessing unit (30b) into a first gas stream (35), a light oil product stream (36) and a partially hydrotreated bottoms product (37), wherein at least a portion of the partially hydrotreated bottoms product (37) is arranged to be supplied to the second hydroprocessing unit (30c).

15. The method of any one of claims 1 to 14, further comprising a step of thermal decomposition of said solid renewable feedstock to produce said liquid oil stream (31), preferably said thermal decomposition comprising a pyrolysis step and / or a hydrothermal liquefaction step.

16. 16. The method of any one of claims 1 to 15, further comprising blending at least a portion of the heavy jet fuel fraction (42) with at least a portion of the light jet fuel fraction (41) to provide a composite jet fuel fraction (49).

Images