A PROCESS FOR PRODUCING SYNTHETIC JET FUEL

Abstract

A process is described for producing a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination of both, by converting raw materials into hydrocarbons.

Description

A PROCESS FOR PRODUCING SYNTHETIC JET FUEL Cross Reference to Related Request

[001] This application claims priority to United States Provisional Patent Application number US 62 / 798,636, filed on January 30, 2019; the full contents of which are incorporated herein by reference. Field of Invention [OO1] This description refers generally to processes for producing jet fuel. More specifically, this description refers to a process for producing synthetic jet fuel. Background of the Invention

[002] A process for producing aviation turbine fuel, also referred to as jet fuel, from feedstocks such as renewable biomass and / or waste materials is valuable. Jet fuel is at least likely among the transportation fuels that are being replaced by non-hydrocarbon-based fuels, such as electricity.

[003] There are problems in designing a process for producing jet fuel from feedstocks such as renewable and / or waste materials.

[004] One problem is that of feed logistics related to the conversion of biomass to liquids; for example, as described in the literature (Zwart, RWR; Boerrigter, H.; Van der Drift, A. Energy Fuels 2006, 20, 2192-2197). Biomass, as a representative feedstock, is composed mainly of lignocellulosic material and is a feedstock that has been collected over a wide area. Biomass has a low physical density, i.e., low mass per volume, and a low energy density, i.e., low combustion energy per volume. It is typically preferred to have a centralized processing facility to convert biomass into jet fuel, but transporting such a low-density feedstock over long distances can be costly (e.g., both financially and energetically), and densification of the biomass before transport is generally required.Food logistics can be less of a problem with residual raw materials, where waste collection is normally provided as a service to residents in a community through the sewer system and the municipal waste (garbage) collection system.

[005] Another problem, related to feed logistics, is the high water content of raw materials, such as biomass and waste materials. Although methods for drying and other ways of removing water are known (e.g., Allardice, DJ; Caffee, AL; Jackson, WR; Marshall, M. In Advances in the Science of Victorian brown coal\ Li, CZ. Ed. Elsevier, 2004, p.85-133), reducing water content to increase energy density can add cost.

[006] Another problem is feed heterogeneity. With raw materials that are primarily solid in nature, heterogeneity generally refers to both physical and chemical diversity. When a process is sensitive to feed variation, an effort must be made to homogenize the raw material, which adds jci «nn / 1 ζηζ / κ / γίΛΐ κ c ι\ cost. DC <X

[007] Another problem relates to the molar ratios of hydrogen, carbon, and oxygen in feedstocks such as biomass and waste feedstocks. Biomass and waste feedstocks contain oxygen-containing compounds where more than 1 / 3 of the total mass can be oxygen. This is in contrast to fossil raw materials, which contain little oxygen. When these oxygen-containing feedstocks are converted to jet fuel, the oxygen is generally removed with either the loss of hydrogen as water or the loss of carbon as carbon monoxide or carbon dioxide. Jet fuel specifications, however, generally require almost complete deoxygenation. In general, biomass and biowaste feedstocks typically have a hydrogen-to-carbon molar ratio of approximately 1.4 to 1, whereas jet fuel generally requires a higher hydrogen-to-carbon molar ratio of approximately 2 to 1, a consequence of jet fuel specifications such as smoke point and gravimetric energy density.

[008] Another problem relates to techniques for refining a biocrude product containing oxygen-containing compounds (oxygenated compounds); for example, when they are present in the <350°C boiling fraction of the product. Experimental investigations evaluating the operation of petroleum refining technology with oxygenated products indicated that modification of the petroleum refining technology is frequently required, even for hydroprocessing; for example, Leckel, DO Energy Fuels 2007, 21, 662-667; Cowley, M. Energy Fuels 2006, 20, 1771-1776; Smook, D.; De Klerk, A. Ind. Eng. Chem. Res. 2006, 45, 467-471. The impact of oxygenated compounds on catalysts and catalysis for refining has been reviewed (e.g., De Klerk, A.; Furimsky, E. Catalysis in the refining of Fischer-Tropsch syncrude', Royal Society of Chemistry, 2010).Conventional refineries would likely have to undergo changes in order to use biocrude as a feedstock for jet fuel. Brief Description of the Invention

[009] In one aspect of the present description, a process for producing synthetic jet fuel is provided, comprising converting the feedstock to synthesis gas; converting the synthesis gas into a mixture comprising liquid hydrocarbons; refining the mixture comprising liquid hydrocarbons to isolate a kerosene product; and hydrotreating the kerosene product to form synthetic jet fuel.

[0010] In one embodiment of the present description, a process is provided wherein converting feedstock to synthesis gas comprises: pyrolyzing the feedstock under aqueous conditions to form a mixture comprising biocrude.

[0011] In another modality, a process is provided in which the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a high water content.

[0012] In another embodiment, a process is provided in which converting the raw material to synthesis gas comprises: pyrolyzing the raw material to form a mixture comprising biocrude.

[0013] In another modality, a process is provided in which the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a low water content.

[0014] In another modality, a process is provided in which converting the raw material to synthesis gas also comprises: gasifying the mixture comprising biocrude to form synthesis gas.

[0015] In another embodiment, a process is provided in which gasifying the mixture comprising biocrude comprises: supercritical water gasification of the mixture comprising biocrude to form a mixture comprising CH4, CO, CO2, and H2; and reforming the mixture comprising CH4, CO, CO2, and H2 to form synthesis gas.

[0016] In another embodiment, a process is provided in which the reforming comprises dry reforming and steam reforming.

[0017] In another modality, a process is provided in which, when the raw material is converted to synthesis gas, the process further comprises: adding an oil raw material, a sugar raw material and / or an alcohol raw material to the mixture comprising biocrude before gasification.

[0018] In another embodiment, a process is provided in which the synthesis gas comprises an H2 to CO ratio that is less than 2 to 1.

[0019] In another embodiment, a process is provided in which the synthesis gas comprises a stoichiometric ratio of (H2- CO2) / (CO + CO2) that is less than 2 to 1.

[0020] In another embodiment, a process is provided in which the synthesis gas comprises a Ribblet ratio of (H2) / (2CO +3CO2), which is less than 1 to 1.

[0021] In another embodiment, a process is provided in which the conversion of synthesis gas into a mixture comprising liquid hydrocarbons comprises: carrying out a Fischer-Tropsch synthesis to convert the synthesis gas into a mixture comprising liquid hydrocarbons.

[0022] In another embodiment, a process is provided in which the Fischer-Tropsch synthesis is carried out with an iron-based catalyst.

[0023] In another embodiment, a process is provided wherein when the FischerTropsch synthesis is carried out to convert the synthesis gas into a mixture comprising liquid hydrocarbons, the process further comprises: a water-gas exchange reaction to increase the concentration of H2.

[0024] In another embodiment, a process is provided wherein the Fischer-Tropsch synthesis is carried out at a pressure of approximately 2 MPa; at a pressure greater than 2 MPa; or approximately 2.5 MPa; or approximately 2.8 MPa.

[0025] In another embodiment, a process is provided wherein the Fischer-Tropsch synthesis is carried out at a pressure in a range of approximately 1.5 MPa to 5 MPa; or in a range of approximately 2 MPa to approximately 4 MPa; or in a range of approximately 2 MPa to approximately 3 MPa; or in a range of approximately 1.5 to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0026] In another embodiment, a process is provided in which the Fischer-Tropsch synthesis is carried out at a pressure greater than 2 MPa.

[0027] In another embodiment, a process is provided wherein the mixture comprising liquid hydrocarbons comprises an alkene to alkane ratio greater than 1 to 1.

[0028] In another embodiment, a process is provided in which refining the mixture comprising liquid hydrocarbons to isolate a kerosene product comprises: carrying out a vapor-liquid equilibrium separation in the mixture comprising liquid hydrocarbons; and separating the mixture into the kerosene product and at least one of an aqueous product, a naphtha and gas product, or a gas oil and a heavier product.

[0029] In another embodiment, a process is provided in which the vapor-liquid equilibrium separation is carried out as a single-stage separation and / or a multi-stage separation.

[0030] In another embodiment, a process is provided in which, when an aqueous product is separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: adding the separated aqueous product to the mixture comprising biocrude before gasifying the mixture comprising biocrude when converting the feedstock to synthesis gas.

[0031] In another embodiment, a process is provided in which, when a naphtha and gas product is separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: oligomerizing the naphtha and gas product to form a mixture comprising a first additional kerosene product.

[0032] In another embodiment, a process is provided in which the oligomerization of the naphtha and gas product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

[0033] In another embodiment, a process is provided wherein the oligomerization of the naphtha and gas product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0034] In another embodiment, a process is provided in which the oligomerization of the naphtha and gas product is carried out with a non-sulfured catalyst.

[0035] In another embodiment, a process is provided in which the oligomerization of the naphtha and gas product is carried out with an acidic ZSM-5 zeolite catalyst.

[0036] In another embodiment, a process is provided wherein the first additional kerosene product comprises alkene and aromatic compounds.

[0037] In another embodiment, a process is provided wherein the first additional kerosene product comprises approximately 0% to approximately 60% aromatic compounds; approximately 1% to approximately 60% aromatic compounds; or approximately 1% to approximately 50% aromatic compounds; or approximately 1% to approximately 40% aromatic compounds; or approximately 1% to approximately 30% aromatic compounds; or approximately 0% to approximately 1% aromatic compounds; or approximately 1% to approximately 7% aromatic compounds; or approximately 8% to approximately 25% aromatic compounds; or approximately 8% aromatic compounds. tci «nn / 1 ζηζ / E / γίΛΐ

[0038] In another embodiment, a process is provided in which, when a gas oil and a heavier product are separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: hydrocracking the gas oil and the heavier product to form a mixture comprising an additional second kerosene product.

[0039] In another embodiment, a process is provided in which hydrocracking of the gas oil and the heavier product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

[0040] In another embodiment, a process is provided wherein hydrocracking of the gas oil and heavier product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0041] In another modality, a process is provided in which the hydrocracking of the gas oil and the heavier product is carried out with a non-sulfured catalyst.

[0042] In another embodiment, a process is provided in which hydrocracking is carried out with a noble metal catalyst supported on an amorphous silica-alumina. In another embodiment, the catalyst is Pt / SiO2-Al2O3.

[0043] In another embodiment, a process is provided in which hydrotreating the kerosene product to form synthetic jet fuel comprises: hydrotreating the kerosene product, and wherein a naphtha and gas product is separated; hydrotreating the first additional kerosene product to form a mixture comprising paraffinic hydrocarbons; and fractionating the mixture comprising paraffinic hydrocarbons, and when a gas oil and a heavier product are separated, fractionating the mixture comprising the second additional kerosene product to isolate the synthetic jet fuel.

[0044] In another embodiment, a process is provided in which, when fractionating the mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising the second additional kerosene product, the process further comprises: adding the mixture comprising the second additional kerosene product to the mixture comprising paraffinic hydrocarbons prior to fractionation.

[0045] In another embodiment, a process is provided wherein each of the kerosene product, the first additional kerosene product, and the second additional kerosene product have a normal boiling point temperature range of approximately 140°C to approximately 300°C.

[0046] In another modality, a process is provided in which the hydrotreating is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

[0047] In another embodiment, a process is provided in which the hydrotreating is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0048] In another modality, a process is provided in which hydrotreatment is carried out with a non-sulfur catalyst.

[0049] In another embodiment, a process is provided in which hydrotreatment is carried out with a reduced base metal catalyst supported on alumina or silica. In another embodiment, the catalyst is reduced Ni / AhOs. [ 0050 ] In another embodiment, a process is provided wherein the synthetic jet fuel is a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination thereof. Brief Description of the Figures

[0051] The modalities of the present description will now be described, by way of example only, with reference to the attached figures.

[0052] Figure 1 represents a block flow diagram of the process described herein. The steps are indicated by dashed blocks and are numbered 1 through 5. Each dashed block provides the next level of process detail. Each major unit is numbered. Only streams where differentiation is necessary for clarity are numbered.

[0053] Figure 2 represents a detailed block flow diagram of the third and fourth steps of Figure 1, with main streams identified.

[0054] Figure 3 represents the oligomerization unit, unit 5.1 in Figure 1, in more detail with the main streams identified.

[0055] Figure 4 represents an expansion of Figure 3 showing how the lighter product fraction from the oligomerization unit, which includes the synthesis gas compounds, is further processed.

[0056] Figure 5 represents an expansion of Figure 3 showing how the performance of synthetic jet fuel can be increased.

[0057] Figure 6 represents the hydrocracking unit, unit 5.2 in Figure 1, in more detail with the main streams identified where hydrogen feed and hydrogen recycling are not shown.

[0058] Figure 7 represents the hydrotreating unit, unit 5.3 in Figure 1, in more detail with the main streams identified, where hydrogen feed and hydrogen recycling are not shown.

[0059] Figure 8 represents an expansion of Figure 7 showing how the hydrotreater product is separated. [0060 ] Figures 9A-9C represent an example of a system for producing synthetic synthesis gas, where 9A features a hydrothermal liquefaction unit; 9B represents a supercritical water gasification unit; 9C represents a reforming unit; and XX” indicates feed flow between 9A and 9B, and ZZ” indicates feed flow between 9B and 9C. Detailed Description of the Invention

[0061] In general, the present description provides a process for producing synthetic jet fuel, comprising converting feedstock to synthesis gas; converting the synthesis gas into a mixture comprising liquid hydrocarbons; refining the mixture comprising liquid hydrocarbons to isolate a kerosene product; and hydrotreating the kerosene product to form synthetic jet fuel.

[0062] In an example of the present description, a process is provided in which converting raw material tci «nn / 1 ζηζ / E / γίΛΐ to synthesis gas comprises: pyrolyzing the raw material under aqueous conditions to form a mixture comprising biocrude.

[0063] In another example, a process is provided in which the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a high water content.

[0064] In another example, a process is provided wherein converting the raw material to synthesis gas comprises: pyrolyzing the raw material to form a mixture comprising biocrude.

[0065] In another example, a process is provided in which the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a low water content.

[0066] In another example, a process is provided in which converting raw material to synthesis gas further comprises: gasifying the mixture comprising biocrude to form synthesis gas.

[0067] In another example, a process is provided wherein gasifying the mixture comprising biocrude comprises: supercritical water gasification of the mixture comprising biocrude to form a mixture comprising CH4, CO, CO2 and H2; and reforming the mixture comprising CH4, CO, CO2 and H2 to form synthesis gas.

[0068] In another example, a process is provided in which reforming comprises dry reforming and steam reforming.

[0069] In another example, a process is provided in which, when converting the raw material to synthesis gas, the process further comprises: adding an oil raw material, a sugar raw material and / or an alcohol raw material to the mixture comprising biocrude prior to gasification. [0070 ] In another example, a process is provided in which the synthesis gas comprises an H2 to CO ratio that is less than 2 to 1.

[0071] In another example, a process is provided in which the synthesis gas comprises a stoichiometric ratio of (H2- CO2) / (CO + CO2) that is less than 2 to 1.

[0072] In another example, a process is provided in which the synthesis gas comprises a Ribblet ratio of (H2) / (2CO + 3CO2), which is less than 1 to 1.

[0073] In another example, a process is provided wherein converting synthesis gas into a mixture comprising liquid hydrocarbons comprises: carrying out a Fischer-Tropsch synthesis to convert synthesis gas into a mixture comprising liquid hydrocarbons.

[0074] In another example, a process is provided in which the Fischer-Tropsch synthesis is carried out with an iron-based catalyst.

[0075] In another example, a process is provided wherein when the Fischer-Tropsch synthesis is carried out to convert synthesis gas into a mixture comprising liquid hydrocarbons, the process further comprises: a water-gas exchange reaction to increase the concentration of H2.

[0076] In another example, a process is provided wherein the Fischer-Tropsch synthesis is carried out at a pressure of approximately 2 MPa; or at a pressure greater than 2 MPa; or approximately 2.5 MPa; or ) ci «nn / 1 ζηζ / E / γίΛΐ approximately 2.8 MPa.

[0077] In another example, a process is provided wherein the Fischer-Tropsch synthesis is carried out at a pressure in a range of approximately 1.5 MPa to 5 MPa; or in a range of approximately 2 MPa to approximately 4 MPa; or in a range of approximately 2 MPa to approximately 3 MPa; or in a range of approximately 1.5 to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0078] In another example, a process is provided in which the Fischer-Tropsch synthesis is carried out at a pressure greater than 2 MPa.

[0079] In another example, a process is provided wherein the mixture comprising liquid hydrocarbons comprises an alkene to alkane ratio greater than 1 to 1.

[0080] In another example, a process is provided wherein refining the mixture comprising liquid hydrocarbons to isolate a kerosene product comprises: carrying out a vapor-liquid equilibrium separation in the mixture comprising liquid hydrocarbons; and separating the mixture into the kerosene product and at least one of an aqueous product, a naphtha and gas product, or a gas oil and a heavier product.

[0081] In another example, a process is provided in which the vapor-liquid equilibrium separation is carried out as a single-stage separation and / or a multi-stage separation.

[0082] In another example, a process is provided in which an aqueous product is separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: adding the separated aqueous product to the mixture comprising biocrude before gasifying the mixture comprising biocrude when converting the feedstock to synthesis gas.

[0083] In another example, a process is provided wherein, when a naphtha and gas product is separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: oligomerizing the naphtha and gas product to form a mixture comprising a first additional kerosene product.

[0084] In another example, a process is provided in which oligomerizing the naphtha and gas product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

[0085] In another example, a process is provided wherein oligomerizing the naphtha and gas product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0086] In another example, a process is provided in which oligomerization of the naphtha and gas product is carried out with a non-sulfured catalyst.

[0087] In another example, a process is provided in which oligomerization of the naphtha and gas product is carried out with an acidic ZSM-5 zeolite catalyst.

[0088] In another example, a process is provided wherein the first additional kerosene product comprises alkene and aromatic compounds. tci «nn / 1 ζηζ / E / γίΛΐ

[0089] In another example, a process is provided wherein the first additional kerosene product comprises approximately 0% to approximately 60% aromatic compounds; approximately 1% to approximately 60% aromatic compounds; or approximately 1% to approximately 50% aromatic compounds; or approximately 1% to approximately 40% aromatic compounds; or approximately 1% to approximately 30% aromatic compounds; or approximately 0% to approximately 1% aromatic compounds; or approximately 1% to approximately 7% aromatic compounds; or approximately 8% to approximately 25% aromatic compounds; or approximately 8% aromatic compounds.

[0090] In another example, a process is provided in which, when a gas oil and a heavier product are separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: hydrocracking the gas oil and the heavier product to form a mixture comprising an additional second kerosene product.

[0091] In another example, a process is provided in which hydrocracking of the gas oil and the heavier product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

[0092] In another example, a process is provided wherein hydrocracking of gas oil and heavier product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

[0093] In another example, a process is provided in which hydrocracking of gas oil and the heavier product is carried out with a non-sulfured catalyst.

[0094] In another example, a process is provided in which hydrocracking is carried out with a noble metal catalyst supported on an amorphous silica-alumina. In another example, the catalyst is Pt / SiC₅-AhOs.

[0095] In another example, a process is provided in which hydrotreating the kerosene product to form synthetic jet fuel comprises: hydrotreating the kerosene product, and when a naphtha and gas product is separated, hydrotreating the first additional kerosene product to form a mixture comprising paraffinic hydrocarbons; and fractionating the mixture comprising paraffinic hydrocarbons, and when a gas oil and a heavier product are separated, fractionating the mixture comprising the second additional kerosene product to isolate the synthetic jet fuel.

[0096] In another example, a process is provided in which, when fractionating the mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising the second additional kerosene product, the process further comprises: adding the mixture comprising the second additional kerosene product to the mixture comprising paraffinic hydrocarbons before fractionation.

[0097] In another example, a process is provided wherein each of the kerosene product, the first additional kerosene product, and the second additional kerosene product have a normal boiling point temperature range of approximately 140°C to approximately 300°C.

[0098] In another example, a process is provided in which hydrotreating is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa. tci Rnn / 1 ζηζ / E / γίΛΐ

[0099] In another example, a process is provided wherein hydrotreating is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa. [OO1OO] In another example, a process is provided in which hydrotreatment is carried out with a non-sulfur catalyst.

[00101] In another example, a process is provided in which hydrotreatment is carried out with a reduced base metal catalyst supported on alumina or silica. In another example, the catalyst is reduced Ni / AhOs.

[00102] In another example, a process is provided wherein the synthetic jet fuel is a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination thereof.

[00103] Before explaining the present invention in detail, it is understood that the invention is not limited to the exemplary embodiments contained in this application. This invention is capable of other embodiments and can be practiced or carried out in a variety of ways. The phraseology and terminology employed herein are understood to be for the purpose of description and not for limitation.

[00104] For the sake of simplicity and clarity, reference numbers may be repeated between figures where appropriate to indicate corresponding or analogous elements or steps. Furthermore, numerous specific details are provided to ensure a complete understanding of the exemplary methods described herein. However, those skilled in the art will understand that the methods described herein can be implemented without these specific details. In other cases, well-known methods, procedures, and components have not been described in detail so as not to obscure the methods described herein. Moreover, this description should not be considered a limitation on the scope of the methods described herein in any way, but rather a mere description of one exemplary implementation of the various methods described herein.

[00105] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by a person skilled in the art to which this invention pertains.

[00106] As used in the descriptive memory and claims, the singular forms “a”, “an” and “the” include plural references unless the context clearly indicates otherwise.

[00107] The term “comprising” as used herein shall be understood to mean that the following list is not exhaustive and may or may not include any other suitable additional items, e.g. one or more additional features, components and / or ingredients as appropriate.

[00108] As used herein, the terms “around” and “approximately” are used in conjunction with ranges of dimensions, concentrations, temperatures, or other physical or chemical properties and characteristics. The use of these terms is intended to cover slight variations that may exist in the upper and lower limits of the values ​​or ranges of properties and characteristics, for example, by ±10% or ±5%.

[00109] As used herein, “aviation turbine fuel” or “jet fuel” refers to kerosene tci Rnn / 1 ζηζ / E / γίΛΐ prior to the addition of fuel additives required to meet the specification requirements for synthetic aviation turbine fuel, either as a component of a jet fuel blend with petroleum-derived kerosene (i.e., semi-synthetic jet fuels), or as a jet fuel without any petroleum-derived kerosene (i.e., fully synthetic jet fuel). For example, these specification requirements are described in the appropriate standards documents, such as the United Kingdom Ministry of Defence. Defence Standard 91-91, Issue 7. Turbine Fuel, Kerosene Type, Jet A-1, NATO Code: F-35, Joint Service Designation: AVTUR; Ministry of Defense: London, 18 February 2011, and ASTM D 7566—15b updated to ASTM D 7566-19 (for example, see Annex A1, synthesized paraffinic kerosene (SPK) with aromatics).Standard specification for aviation turbine fuel containing synthesized hydrocarbons] American Society for Testing and Materials: West Conshohocken, PA, 2015. As a person skilled in the art would recognize, only a few of the specification requirements will be met by adding additives; many of these specification requirements can be met through the refining process (for example, see Example 4 below, where it was possible to meet the requirements after adding only a static heat sink). [OO11O] As used herein, “feedstock” means biomass, organic materials, waste streams, or combinations thereof. Examples of feedstock include, but are not limited to, a waste stream from a grain ethanol plant (bagasse, vinasse, wastewater, and glycerin), cellulosic biomass (wood, energy crops, pastures), organic waste (residual products from green bin collection; drainage sludge), agricultural waste (farm waste or residues, manure), waste streams from pulp and paper mills (wood waste, pre-hydrolysate), municipal organic waste gassed, biodiesel (glycerin), and any combination thereof. Examples of biomass include, but are not limited to, materials that are byproducts of activities such as forestry, product manufacturing, construction, and the collection or handling of demolition debris;and lignocellulosic biomass, for example, wood waste, which is classified into three categories: forestry waste, urban waste, and mill waste. Examples of organic materials include, but are not limited to, any one of the cellulosic materials, lignocellulosic materials, waste such as wood processing waste, agricultural waste, municipal green bin collections, manure, an effluent from a cellulosic material processing plant, an effluent from a paper mill, an effluent from a biomass ethanol process, thin or whole vinasse, dry distillers grains, and biodegradable wastewater; materials with carbon and hydrogen in their molecular structure, for example, alcohols, ketones, aldehydes, fatty acids, esters, carboxylic acids, ethers, carbohydrates, proteins, lipids, polysaccharides, monosaccharides, cellulose, nucleic acids, etc.;and may be present, for example, in waste (e.g., agricultural or industrial waste streams; drainage sludge), organic fluid streams, fresh biomass, pre-treated biomass, partially digested biomass, etc. In some examples, “raw material” as defined herein includes raw materials with a high water content and / or raw materials with a low energy density. In some examples, “raw material” as defined herein includes raw materials with a low water content.

[00111] In some examples, a high water content refers to a material that has water present as a separate phase under ambient conditions. In one example, a high water content refers to a material with a water content that exceeds the organic matter content. In other examples, a high water content refers to a water content of, for example, >40% by weight, or between approximately 50% by weight and approximately 95% by weight; or between approximately 60% by weight and approximately 90% by weight; or between approximately 70% by weight and approximately 90% by weight; or between approximately 80% by weight and approximately 90% by weight; or any value between approximately 50% by weight and approximately 70% by weight and any value between approximately 75% by weight and approximately 95% by weight. In some examples, a low water content refers to a material with no water present in a separate phase under ambient conditions.In other examples, a low water content refers to a water content of, for example, <40% by weight, or between approximately 5% by weight and approximately 40% by weight; or between approximately 10% by weight and approximately 40% by weight; or between approximately 20% by weight and approximately 40% by weight; or between approximately 30% by weight and approximately 40% by weight; or any value between approximately 5% by weight and approximately 20% by weight and any value between approximately 25% by weight and approximately 40% by weight.

[00112] As used herein, “oil raw material” refers to vegetable oils or animal fat oils. In some examples, “oil raw material” refers to residual vegetable oils or animal fat oils. “Sugar raw material” refers to sugar solutions. In some examples, the sugar may be residual sugar. “Alcohol raw material” refers to liquid alcohols such as glycerol. In some examples, the liquid alcohol may be residual alcohol.

[00113] As used herein, “pyrolyzing the raw material under aqueous conditions” means pyrolysis or heat treatment of the raw material in the presence of water as a separate phase under ambient conditions; such as, but not limited to, hydrothermal liquefaction. As used herein, “pyrolyzing the raw material” means pyrolysis or heat treatment of the raw material where water is not present as a separate phase under ambient conditions. As would be recognized by a person skilled in the art, “aqueous conditions” means water present in a sufficient quantity to act as, for example, a reagent, catalyst, solvent, or combination thereof.As an expert person would also recognize, “pyrolysis conditions” refers to the absence of water; or to water that is present in an amount that would not be sufficient to act as, for example, a reagent, catalyst, solvent, or combination thereof.

[00114] As used herein, “liquid hydrocarbons” refers to linear, branched and / or cyclic (olefin) alkanes and alkenes, or aromatic compounds that may be unsubstituted or substituted with oxygen-containing functional groups, such as but not limited to alcohols, aldehydes, carboxylic acids, ketones, ethers, etc.

[00115] As used herein, “biocrude” is a mixture that includes but is not limited to aromatic compounds, polyaromatic compounds, fatty acids, alkanes, alkenes, and / or oxygen-containing compounds.

[00116] As used herein, “paraffinic hydrocarbons” refers to linear or branched alkanes, and may include cycloalkanes. )CI «nn / 1 7Π7 / Β / YΙΛΙ

[00117] Described herein is a process that converts raw materials such as biomass, waste raw materials, oil raw materials, sugar raw materials, and / or alcohol raw materials into a synthetic jet fuel that is suitable for blending, or for direct use as a semi-synthetic or fully synthetic jet fuel. [OO11Θ] With reference to Figure 1, an example of the process is described in five steps, as indicated by the blocks with dashed lines. The five steps include (1) pyrolysis of the feedstock, or pyrolysis of the feedstock under aqueous conditions (e.g., hydrothermal liquefaction) to produce a mixture comprising biocrude, (2) gasification of the mixture comprising biocrude to form synthesis gas, and optionally adding an oil feedstock, a sugar feedstock, and / or an alcohol feedstock to the mixture comprising biocrude prior to gasification, (3) carrying out a Fischer-Tropsch synthesis to convert the synthesis gas into a mixture comprising liquid hydrocarbons, (4) refining the mixture comprising liquid hydrocarbons to isolate a kerosene product, and at least three other fractions, and (5) hydrotreating the kerosene product to produce jet fuel as a main product.In some examples, step 1 in Figure 1 is carried out in distributed locations and steps 2 to 5 in Figure 1 are carried out in a central location.

[00119] Step 1 in Figure 1 is aimed at converting raw materials, such as bulky, low-energy-density feedstocks, into a denser liquid that can be easily handled and transported. In an example of Step 1, pyrolysis under aqueous conditions involves hydrothermal liquefaction, as represented by block 1 in Figure 1. As depicted, hydrothermal liquefaction units are small-scale, distributed units that can be deployed near a feedstock source, such as a biomass source or waste materials. Hydrothermal liquefaction units are represented by blocks 1.1 to 1,n in Figure 1, where n is a positive integer.By deploying the direct liquefaction units in a distributed manner, the distance from the raw materials to a central plant is reduced. Since the product produced in step 1 (i.e., a mixture comprising biocrude) has a lower water content and a higher physical and energy density than the raw material, this conversion can make transport to a large, centralized finished product plant feasible. Producing a mixture comprising biocrude, which is a liquid product, is relatively easier than producing densified solid products. Optionally, one of the hydrothermal liquefaction units can be located at the central processing facility. In another example of step 1, not shown, other liquefaction technologies can be selected, as appropriate, for each of the distributed raw materials, such as pyrolysis to produce oil from dry / solid raw materials.In the example, blocks 1,n in step 1 are pyrolysis units. When only one individual localized power source is available, then n = 1 in Figure 1 and only one individual hydrothermal liquefaction unit is used.

[00120] Hydrothermal liquefaction is a process in which a feedstock is heated under aqueous conditions for a period of time sufficient to substantially hydrolyze the feedstock and produce a liquefied product with a lower average molecular weight than the feedstock. Hydrothermal liquefaction is an example of a direct liquefaction process. The hydrothermal liquefaction process can be implemented as a batch, semi-batch, or continuous process under subcritical or supercritical water conditions. The supercritical or subcritical operating conditions also minimize carbon formation and oxygen content in the liquefied product. Some non-condensable gases produced during this process can be used as fuel gases to provide the required energy. Hydrothermal liquefaction does not require the feedstock to be dried.Depending on the temperature to which the raw material is heated, pressure will develop autogenously to limit water vaporization. Following hydrothermal liquefaction, liquid-liquid phase separation can be employed to separate the water and the liquefied product. The hydrothermal liquefaction process can be implemented on a small scale, even in a mobile unit.

[00121] In an example of the process as described herein, hydrothermal liquefaction (HTL) is conducted at a temperature of approximately 350°C for 40 minutes. Alternatively, it is conducted in supercritical water at approximately 410°C for only a few minutes (e.g., approximately 5 minutes or less). A person skilled in the field would recognize that different hydrothermal liquefaction conditions can create different light biocrudes, a key difference being the amount of oxygen in the biocrudes: supercritical water HTL can produce biocrudes containing approximately 8% to approximately 10% oxygen, whereas HTL pyrolysis can produce biocrudes containing oxygen in the low range of 40%. The process as described herein can accept all different types of biocrudes / biooils.

[00122] In one example, trailers with mobile liquefaction units (e.g., hydrothermal liquefaction units, or pyrolysis units, etc.) can be parked on farms to process farm waste and biomass into a liquefaction product (e.g., a mixture comprising biocrude) that is collected in a mobile tank for intermittent collection. These mobile units would typically be designed for simple, unattended operation. In another example, larger stationary liquefaction units can be parked at facilities, such as municipal waste management facilities and sawmills or paper mills, where a collection network for biomass and waste raw materials is already in place. These stationary liquefaction units would typically be designed with more complex heat integration for greater operational efficiency due to their large scale.The rest of the process is conducted at a central facility, where the liquefaction product (e.g., a mixture comprising biocrude) is collected from the distributed liquefaction units and processed.

[00123] Step 2 in Figure 1 is directed toward combining and homogenizing the liquefaction product (i.e., the mixture comprising the biocrude) (see unit 2.1 in Figure 1) from step 1 (see 2a in Figure 1), and potentially an oil feedstock, a sugar feedstock, and / or an alcohol feedstock from sources other than step 1, such as residual vegetable or animal fat oils (see 2b in Figure 1), and then gasifying these feedstocks to crude syngas (see unit 2.2 in Figure 1). As shown in Figure 1, the feedstocks for crude syngas production (in unit 2.2) may additionally include an aqueous Fischer-Tropsch product (stream 4a) and raffinate material (stream 5b). The crude syngas is then cleaned (see unit 2.3 in Figure 1) to produce clean syngas. tci Rnn / 1 ζηζ / κ / γίΛΐ

[00124] The term crude synthesis gas refers to a gas that includes a mixture of hydrogen (H2) and carbon monoxide (CO), along with other compounds. These other compounds typically include, but are not limited to, carbon dioxide (CO2), water vapor (H2O), and methane (CH4). The term clean synthesis gas refers to crude synthesis gas after the removal of potentially harmful compounds that were present in the raw synthesis gas. The most common class of contaminants that must be removed are sulfur-containing compounds such as hydrogen sulfide (H2S) and carbonyl sulfide (COS). Additionally, other compounds may also be removed during cleaning to improve the efficiency of downstream processes.

[00125] Using a mixture comprising biocrude as a feedstock for crude synthesis gas production, along with other liquid feedstocks such as oil feedstocks, sugar feedstocks, and / or alcohol feedstocks, can reduce the impact of feed heterogeneity by blending it in a feed tank (see section 2.1 in Figure 1) prior to gasification. Since the feedstock is largely liquid, it is easier to homogenize feedstocks from different sources.Furthermore, a liquid feed can make crude syngas production relatively simpler and more efficient because it eliminates the need to handle solids; liquid feeds can be pumped for pressurization; liquid feeds can have superior heat transfer properties for gasification; and when washed, they are free of minerals that could potentially contaminate the syngas. The operating pressure of the crude syngas generation step affects downstream operations. It is advantageous to perform crude syngas generation at a higher pressure. For example, crude syngas is generated at a pressure of approximately 2 MPa or higher; or in the range of approximately 2 MPa to 5 MPa; or in the range of approximately 2 MPa to approximately 4 MPa; or in the range of approximately 2 MPa to approximately 3 MPa.

[00126] In an example of the process as described herein, crude synthesis gas is produced by supercritical water gasification (SCWG). With SCWG and the appropriate amount of water with respect to carbon / hydrogen / oxygen content, the heat required for gasification is generated within a reactor by the exothermic SCWG reactions once gasification has been initiated by an external heat source, such as a starter furnace. As such, SCWG does not require a constant external heat source, whereas excess water requires some external heat. Furthermore, the SCWG reactor operates at a low temperature and without the need for an externally supplied oxidant.The water in the SCWG reactor contributes some of its hydrogen, usually through the water-gas exchange reaction, to increase the hydrogen-to-carbon ratio in the raw syngas above that generally expected from gasifying the liquid feeds alone. All feed materials are introduced into the SCWG process in the liquid phase at high pressure, generally above the pressure requirements of a syngas feed for Fischer-Tropsch synthesis. This is both energy-efficient and less complex than compressing the raw syngas after it is produced. The hot gas leaving the SCWG reactor exchanges heat with the incoming feedstock, and the water vapors in the gas are cooled / condensed along with other water-soluble organic compounds and separated in pressurized liquid / gas separators. Some of the separated water-rich product is recycled back to the SCWG process.At this point, the crude syngas may still contain compounds other than hydrogen monoxide and carbon monoxide. Some of these compounds can be removed by condensation, but some gas cleaning (see section 2.3 in Figure 1) may be required to remove gaseous contaminants that could affect downstream processes. Clean syngas may still contain compounds other than hydrogen monoxide and carbon monoxide, such as water vapor and carbon dioxide, but it would be substantially free of sulfur-containing compounds. Methods for cleaning crude syngas to obtain clean syngas are known to those skilled in the art.

[00127] In one example of the process as described herein, supercritical water gasification (SCWG) is conducted at a temperature in the range of 570°C to 590°C, with a water content of approximately 30% to approximately 60%, and at a pressure in the range of approximately 20 MPa to approximately 30 MPa, or approximately 22.5 MPa to approximately 25 MPa. In another example, supercritical water gasification (SCWG) is conducted at a temperature of approximately >550°C, with the pressure being dependent on the reactor design and means for pressure control.

[00128] In some examples of step 2, reforming is used in conjunction with the production of clean syngas to convert the hydrocarbons present in the clean syngas to hydrogen monoxide and carbon. The presence of sufficient methane in the crude syngas, along with carbon dioxide, allows for the reforming of these gases using steam reforming and dry reforming. This enables the recycling of additional CO2 from the crude syngas to maximize the conversion of methane to carbon monoxide and hydrogen. Some carbon dioxide and water are also produced in the formation processes. The water can be removed by cooling the gases, and the carbon dioxide can be reduced in a syngas cleaning unit.

[00129] In their simplest form, the steam reforming and dry methane reforming reactions together with the water-gas swap and reverse water-gas swap reactions during step 2 are as follows: 1. CH4+ CO22CO+2 H2 2. CH4+2 H2O # CO+3H2 3. CO2 + H2CO + H2O 4. CO + H2O CO2 + H2

[00130] Optionally, the use of a water-to-gas converter can be considered to change the molar ratio of hydrogen monoxide to carbon in the clean syngas. At least some of the potential technologies that could be selected for step 3 may benefit from a molar ratio of hydrogen monoxide to carbon that is closer to 2:1. Optionally, the production of clean syngas is followed by the removal of some CO2 from the clean syngas. Some of the CO2 could be recycled.

[00131] Figure 9A-9C represents an example of a system for producing synthesis gas that can be used with the process as described herein, where A represents a hydrothermal liquefaction unit; B represents a superheated water gasification unit; and C represents a reforming unit.

[00132] More particularly, Figure 9A represents an example of a hydrothermal liquefaction (HTL) unit involving: • Raw materials of all types, such as all types of organic waste, manure, drainage sludge, agricultural and forestry waste, and all types of biomass; • Adjustment of the raw material ratio to adapt 20% dry matter, with possible adjustment of water; • Raw material (20% dry matter) pumped through a high-pressure feed pump to a heat recovery unit, and then pumped to a heating unit; • Feed, which may include an organic / aqueous phase from a Fischer-Tropsch unit, and is then pumped from the heating unit to an HTL reactor via an HP pump, and then back to the heating unit; • From the heating unit following the HTL reactor, the feed moves to a cooler and then to a product separator; • The product separator produces non-condensable gases and biocrude oil (which is then pumped to the supercritical water gasification unit of Figure 9B); and • The product separator also produces an HTL water collection which produces a salt purge, and recycled water after salt separation that goes to the high-pressure feed pump.

[00133] Figure 9B represents an example of a supercritical water (SCW) biocrude gasification unit involving: • Receive the biocrude oil from the HTL unit in Figure 9A, which moves to a heat recovery unit, and then to a heater; • From the heater, the feed moves to an SCWG reactor (which has an outlet to the energy sink Έ”); • The reactor feed outlet moves back to the heat recovery unit, and then to a pressure-reducing turbine (which also goes to the energy sink Έ”); • From the turbine, the feed moves to another heat recovery unit, then to a cooler; • From the cooler, the feed moves to a high-pressure gas / liquid separator (an HP flash evaporator) which produces an aqueous phase and a biogas (which then moves to the reforming unit in Figure 9C); and • The aqueous phase becomes part of a water recycle, which accepts makeup water and is then fed back to the second heat recovery unit (which feeds heat to the heater).

[00134] Figure 9C shows an example of a reformation unit involving: • Receive biogas from the SCWG unit in Figure 9B, which moves to a heat recovery unit, and then to an HRSG; The inputs to a heat recovery steam generator (HRSG) also include makeup water ! CI Rnn / 1 7P7 / B / YILI (pumped to the HRSG via an HRSG feedwater pump); o An HRSG output includes an excess current to the energy sink Έ”; The heat recovery unit and HRSG also feed a steam methane / dry methane reforming (SMR / DMR) unit, an output of which is fed back to the heat recovery unit; • From HRSG, the feed moves to a cooler, and then to an HP flash evaporator; • Another HP flash evaporator input includes recycled makeup water; and • From the HP flash evaporator, the feed is moved to a CO2 scrubbing unit which produces synthesis gas which can be directed to a Fischer-Tropsch unit and CO2 (including recycled CO2 which is fed back to the heat recovery unit, and excess CO2).

[00135] Step 3 in Figure 1 is directed toward the conversion of synthesis gas to a mixture comprising liquid hydrocarbons via a Fischer-Tropsch synthesis (see unit 3.1 in Figure 1). Methanol synthesis is an alternative process that can be employed for this step, but the conversion of methanol to hydrocarbons is known to produce 1,2,4,5-tetramethylbenzene, a kerosene-range product that is highly undesirable when producing jet fuel.

[00136] In its simplest form, the main reactions during step 3 for the Fischer-Tropsch synthesis can be represented by the following Equations 1-6, where Equation 6 is relevant only in the iron-catalyzed Fischer-Tropsch synthesis: Alkenes: n CO + 2n H2 —► (CH2)n+ η H2O(1) Alkanes: n CO + (2n+1) H2H(CH2)nH + n H2O(2) Alcohols: nCO + 2n H2H(CH2)nOH + (n-1) H2O(3) Carbonyls: n CO + (2n-1) H2(CH2)nO + (n-1) H2O(4) Carboxylic acids: n CO + (2n-2) H2—»(OH2)nO2+ (n-2) H2O (5) Water-gas change: CO + H2O CO2 + H2(6)

[00137] The value of n in Equations 1 to 6 depends on the probability of chain growth. The probability of chain growth, or the alpha value, depends on the nature and operation of the Fischer-Tropsch catalyst. The product distribution is reasonably well represented by an Anderson-Schulz-Flory distribution. With the Fischer-Tropsch synthesis of the process described herein, the products will usually have carbon numbers in the range of n = 1 to 100, although some products can be formed with n > 100.

[00138] In an example from step 3, iron-catalyzed Fischer-Tropsch synthesis is employed for the conversion of synthesis gas into a product mixture comprising liquid hydrocarbons. Iron-catalyzed Fischer-Tropsch syntheses do not require the synthesis gas composition to be adjusted to meet the hydrogen-to-carbon monoxide usage ratio of approximately 2:1, because iron-based Fischer-Tropsch catalysts are capable of carrying out the water-to-gas exchange reaction. In one example, the iron-catalyzed Fischer-Tropsch synthesis is carried out at a temperature of 240°C and higher, or at a temperature in the range of 240 to 280°C. Operating the Fischer-Tropsch synthesis at a higher temperature allows the exothermic heat of reaction to be removed by the production of high-pressure steam, typically to generate steam at a pressure of 4 MPa or higher.

[00139] In another example from step 3, the iron-based Fischer-Tropsch synthesis is carried out with a synthesis gas having a hydrogen-to-carbon monoxide ratio of less than 2:1. In another example, the iron-based Fischer-Tropsch synthesis is carried out with a synthesis gas having a stoichiometric ratio, (H2 CO2) / (CO + CO2), of less than 2:1. In another example, the iron-based Fischer-Tropsch synthesis is carried out with a synthesis gas having a Ribblet ratio, (H2) / (2 CO + 3 CO2), of less than 1:1. In another example, the Fischer-Tropsch synthesis is designed such that the mixture comprising liquid hydrocarbons from the Fischer-Tropsch synthesis has an alkene-to-alkane ratio greater than 1:1.An alkene-to-alkane ratio greater than 1 to 1 is generally desired for the process as described herein because, as the alkene-to-alkane ratio decreases, oligomerization may be affected (e.g., the oligomerization yield may decrease), which may reduce the ability to produce fully synthetic jet fuel.

[00140] In another example, the Fischer-Tropsch synthesis is designed such that the one-step carbon monoxide conversion of the synthesis gas during the Fischer-Tropsch synthesis is high, typically greater than 80% and more preferably greater than 90%. In another example, the Fischer-Tropsch synthesis is designed such that steam is fed to the Fischer-Tropsch synthesis as required for the reaction to proceed without excessive carbon formation.

[00141] The following is a more detailed description of an example of step 3 in Figure 1 (see Figure 2). In step 3, the synthesis gas, represented by stream 299 in Figure 2, is converted by the Fischer-Tropsch synthesis, represented by block 300, into a mixture comprising liquid hydrocarbons, represented by streams 301 and 302. Step 3 is conducted under temperature and pressure conditions where the Fischer-Tropsch reactor is likely to have both a gas phase and a liquid phase, with the catalyst in the solid phase. The reaction products of the Fischer-Tropsch synthesis (i.e., a mixture comprising liquid hydrocarbons) could exit the reactor as two separate phases, with the reactor itself serving as both a reactor and a phase separator. In Figure 2, stream 301 is the gas-phase product and stream 302 is the liquid-phase product leaving the Fischer-Tropsch reactor, block 300.The exact nature and position of the gas-phase and liquid-phase products leaving the reactor depend on the specific reactor technology selected, such as a multi-tubular fixed-bed reactor or a slurry-phase bubble column reactor. Any device required to retain the catalyst in block 300 is considered part of the technology in that block. Depending on the operation of the Fischer-Tropsch synthesis, the relative amounts of products in streams 301 and 302 may vary. In one example, no material leaves block 300 as stream 302. Due to the exothermic nature of the reaction in block 300 (Rnn / 1 znz / R / YiAi) in Figure 2, water is supplied as stream 303 and is vaporized to produce steam as stream 304.The water supplied in stream 303 does not mix with the process and both streams 303 and 304 can be considered separate utility streams from the process, but are integral to the heat removal from block 300.

[00142] Step 4 in Figure 1 is directed to separating the product of the Fischer-Tropsch synthesis (i.e., the mixture comprising liquid hydrocarbons) by separating the mixture into at least four product fractions (see unit 4.1 in Figure 1): (4a) aqueous product, (4b) a naphtha and gas product, (4c) a kerosene product, and (4d) a gas oil and a heavier product. The aqueous product comprises water and water-soluble molecules that condense during product separation. The naphtha and gas product comprises all material not present in the aqueous product that has a normal boiling point temperature lower than that of kerosene. The kerosene product comprises hydrocarbons with a boiling range compatible with the distillation requirements for jet fuel. Generally speaking, kerosene products have a normal boiling point temperature range of 140 to 300°C.The gas oil and the heavier product comprise material with a normal boiling point higher than that of kerosene. In some instances, the four products are not isolated as precise cuts. In some instances, vapor-liquid equilibria would naturally result in some separation in the reactor for the Fischer-Tropsch synthesis. Some or all of the gas oil and the heavier product (see stream 4d in Figure 1) could be available as a separate liquid product from the Fischer-Tropsch synthesis (see section 3.1 in Figure 1) and do not require separation in the fourth step. To separate the heavier and lighter products of the Fischer-Tropsch synthesis to conveniently upgrade jet fuel, a combination of vapor-liquid equilibrium separation techniques at different pressures and temperatures is used, and this can be combined with distillation of the selected separated fractions.This avoids the need for an atmospheric distillation unit in this part of the process, which can make step 4 relatively more energy-efficient and less capital-intensive.

[00143] The following is a more detailed description of an example of step 4 in Figure 1 (see Figure 2). The temperature of the gas-phase product in stream 301 of Figure 2 is reduced in block 400. This temperature change can be effected by devices known in the art. In one example, the temperature of stream 301 is reduced by heat exchange with stream 299 in a feed product heat exchanger represented by block 400. The temperature change in block 400 can also be effected in other ways, such as with a utility stream, or by air cooling.In another example, the temperature of stream 401 is such that the water present in stream 301 condenses, and the water in stream 401 is at or below its bubble point. The relationship between the bubble point temperature of the water in stream 401 and the pressure is determined by vapor-liquid equilibrium. In yet another example, the temperature of 401 °C is controlled and maintained constant by process control. Furthermore, this temperature is selected to optimize the product going to step 5, rather than being used to condense more material, as is generally the industrial practice. Therefore, this temperature is controlled to be at or near the bubble point of water in stream 401. The tci «nn / 1 ζηζ / κ / γίΛΐ stream 401 enters a phase separator, represented by block 410 in Figure 2. In this example, the phase separator is a three-phase phase separator.The purpose of the phase separator is to allow the separation of the phases present in stream 401 to produce a gaseous phase stream 411, an organic liquid phase stream 412, and an aqueous liquid phase stream 413. For example, blocks 400 and 410 are combined in a device that allows both temperature change and phase separation in the same unit. In another example, blocks 400 and 410 are combined such that the device has more than one equilibrium stage to effect the separation in streams 411, 412, and 413.

[00144] The relationship between the streams shown in Figures 1 and 2 is indicated in Figure 2. The gas-phase stream 411 comprises mainly gas fractionation products and naphtha, stream (4b). The organic liquid-phase stream 412 comprises mainly the kerosene product, stream (4c). The aqueous product stream 413 comprises mainly water with dissolved organic compounds, which are compounds containing mainly oxygen, stream (4a). The liquid product from the Fischer-Tropsch reactor is stream 302 and comprises mainly gas oil and heavier organic compounds, stream (4d). The design and control of the separation described herein allows the product to be routed in such a way that a separate atmospheric distillation unit is not required upstream of any of the units in step 5.This exploits the energy already available in the hot products of unit 300, without undetermined refinery operation.

[00145] Step 5 in Figure 1 is directed toward refining the four product portions separated from the Fischer-Tropsch liquefaction product (i.e., the mixture comprising liquid hydrocarbons). Refining employs three processes, specifically oligomerization (see unit 5.1 in Figure 1), hydrocracking (see unit 5.2 in Figure 1), and hydrotreating (see unit 5.3 in Figure 1). The aqueous product (see 4a in Figure 1) is recycled as a feedstock in the production of synthesis gas (see unit 2.2 in Figure 1). The aqueous product, similar to the hydrothermal liquefaction product, is acidic in nature. The combination of the hydrothermal liquefaction product and the aqueous Fischer-Tropsch product exploits the common need for acid-resistant construction material.Co-feeding the aqueous product with the hydrothermal liquefaction product (i.e., the mixture comprising biocrude) allows for the substantial conversion of acids to synthesis gas, instead of relying on chemical dosing. It eliminates the need to treat the aqueous product separately as an acidic wastewater with high chemical oxygen demand, a costly requirement frequently encountered in Fischer-Tropsch-based coal-to-liquid and gas-to-liquid plants.

[00146] The direct run gas and naphtha product (4b in Figure 1) is not further separated, as is common practice in post-Fischer-Tropsch synthesis. The gas and naphtha product, which also contains unreacted synthesis gas, is used directly as a feed material for an oligomerization process. Oligomerization refers to a conversion process involving the addition reaction of two or more unsaturated molecules. This procedure facilitates the conversion of lighter olefinic (i.e., alkenyl) products to heavier olefinic products, which are easier to recover by condensation. Furthermore, the more dilute nature of the feed aids in heat management during the exothermic oligomerization process, and the presence of hydrogen in the gas can suppress coking reactions.Furthermore, oxygen-containing organic molecules (oxygenated compounds) are converted to hydrocarbons, although this conversion may not be complete. For example, the oligomerization process employs a non-sulfur catalyst, such as an acidic ZSM-5 zeolite (MFI-type structure).

[00147] In its simplest form, the main reactions during the operation of the oligomerization process can be represented by the following Equations 7-9: Oligomerization / cracking: CxH2x + CyH2y# C(X+yjH(2X+2y)(7) Aromatization: alkenes —> aromatics + alkanes(8) Aromatic alkylation / dealkylation: (C6Hs)CxH(2X+i) + CyH2y (C6H5)C(X+y)H(2X+2yH-i)(9)

[00148] In addition to the reactions in Equations 7-9, several reactions involving oxygen-containing compounds, such as dehydration and ketonization, can be carried out. The reactions described are not intended to be exhaustive but are provided for illustrative purposes. The relative prevalence of these reactions depends on the temperature and pressure conditions of the oligomerization process. By manipulating the operating conditions in the oligomerization process, it is possible to produce a kerosene material that allows for the blending of fully synthetic jet fuel from the process described herein.By operating at least part of the oligomerization catalyst at a temperature and pressure that favors aromatization (Equation 8), the total amount of aromatic products can be manipulated to increase or decrease the amount of fully synthetic jet fuel relative to the semi-synthetic jet fuel produced by the process described herein. In one example, a non-sulfur catalyst, such as a non-promoted ZSM-5 catalyst, is used.

[00149] In an example of the oligomerization process as described herein, operating temperatures in the range of approximately 200°C to approximately 320°C would generally produce a product useful as a blending material for the production of semi-synthetic jet fuel, since it would be an isoparaffinic kerosene after hydrotreatment (e.g., see Examples 1 and 4). Operating temperatures of approximately >320°C (nominally from approximately 320°C to approximately 400°C) would typically be used to produce a product with more aromatic compounds, which would be suitable for blending fully synthetic jet fuel after hydrotreatment to saturate the olefins (e.g., see Examples 2 and 5). In some examples, in both cases, the pressure can be varied over a wide range, e.g., from approximately 0.1 MPa to approximately 20 MPa.

[00150] In general, the process as described herein can be operated at a pressure consistent with, or slightly lower than, the Fischer-Tropsch synthesis as described herein, for example, approximately 2 MPa, although operation at higher pressures is generally easier due to the higher partial pressure of olefins. Operation at a pressure consistent with, or lower than, the Fischer-Tropsch synthesis as described herein, without requiring prior separation to remove unconverted synthesis gas, avoids the separation and recompression required in the process as described herein.

[00151] In another example, the oligomerization process utilizes the gaseous product stream 411 (Figure 2), which includes the unconverted synthesis gas from the Fischer-Tropsch process. The unconverted synthesis gas includes, but is not limited to, H2, CO, CO2, and H2O. It is common practice to separate the light olefins from the unconverted synthesis gas, which comprises H2, CO, and CO2, eliminating a separation step that is usually present. Also, by employing oligomerization, alkenes, including ethylene, are converted to heavier products that are more readily recovered after oligomerization than before.

[00152] The product of the oligomerization process (for example, a mixture comprising a first additional kerosene product) comprises unconverted material and new products. The unconverted material comprises hydrogen, carbon monoxide, and paraffinic hydrocarbons. The new products have a boiling range distribution encompassing gas, naphtha, and distillates, ranging from normally gaseous compounds to compounds with a normal boiling point up to 360°C. The new products include a first additional kerosene product. The first additional kerosene product comprises olefinic and aromatic compounds. The ratio of olefinic to aromatic compounds depends on the operating conditions of the oligomerization process. This flexibility in adjusting the ratio of olefinic to aromatic compounds facilitates the production of semi-synthetic jet fuel and the production of fully synthetic jet fuel.The additional kerosene product (see 5a in Figure 1) is sent to the hydrotreator (unit 5.3 in Figure 1). The liquid product outside the kerosene range (see 5b in Figure 1) can be handled in one or more combinations of the following: (i) recovered as end products (as shown in Figure 1), (ii) sent to the hydrotreator (not shown in Figure 1), (iii) recycled to the oligomerization process (not shown in Figure 1), and / or recycled to synthesis gas production (see unit 2.2 in Figure 1).

[00153] In one example, olefinic and aromatic compounds outside the kerosene boiling range are converted as products. In another example, some or all of the olefinic and aromatic compounds outside the kerosene boiling range are recycled to the oligomerization process. In another example, some or all of the olefinic and aromatic products outside the kerosene boiling range are sent to the hydrotreator.

[00154] The unconverted material from the oligomerization process can be used at least as a source of hydrogen for the hydrocracker and hydrotreator. The nature of the gas treatment downstream of the oligomerization involves processes familiar to those skilled in gas treatment techniques, such as hot carbonate absorption to remove carbon dioxide, and pressure swing adsorption to recover hydrogen.

[00155] The kerosene product (see 4c in Figure 1) is sent to the hydrotreator. Optionally, some or all of this product may also be sent to a hydrocracking unit (routing not shown in Figure 1). The determining factor for whether any of this product is sent to the hydrocracker is the freezing point specification of the target jet fuel. For example, straight-run Fischer-Tropsch kerosene typically has a high linear hydrocarbon content. If there is too high a concentration of linear hydrocarbons in the kerosene, however, the freezing point will be too high to meet the aviation turbine fuel specifications.

[00156] The following is a more detailed description of an example of the oligomerization unit in step 5 of Figure 1. The oligomerization unit in step 5 is depicted in more detail in Figure 3. The conversion of stream 411 (i.e., the naphtha and gas product), comprising hydrocarbons, oxygen-containing organic compounds, and unconverted synthesis gas, is carried out in oligomerization unit 510. The product of 510 is stream 511 (i.e., the mixture comprising a first additional kerosene product), comprising a mixture of hydrocarbons that are on average heavier than those in stream 411, substantially less oxygen-containing organic compounds, and unconverted synthesis gas. The hydrocarbon composition in 511 depends on the operating conditions in 510, as described above.

[00157] Stream 511 is separated into 520. In one example, stream 511 is separated to produce a gaseous product 521, an organic liquid product 522, and a water-rich liquid product 523. This type of separation can be achieved by lowering the temperature to condense the portion of 511, which can then be separated in a three-phase vapor-liquid-liquid separator. Another way to achieve this type of separation is to use a device with more than one equilibrium stage. Another way to achieve this type of separation is to use a device that employs liquid absorption. Stream 521 can be applied in several ways. One potential use of stream 521 is as a fuel gas. Another potential use of stream 521 is to recycle some or all of 521 for either Fischer-Tropsch synthesis or synthesis gas production. In one example, stream 521 is treated as shown in Figure 4.Stream 521 is treated in unit 610 to remove some or almost all of the carbon dioxide, producing a CO2-rich stream 611 and a CO2-depleted stream 612. This type of separation can be carried out using process technology known in the art, such as hot carbonate absorption or amine absorption. The CO2-rich stream 611 is an effluent, but due to its high CO2 concentration, stream 611 may be suitable as feed for CO2 sequestration or for direct discharge. The CO2-depleted stream 612 may be split, with some or all of stream 612 going to stream 613. The remainder of stream 612 that does not go to stream 613 may go to stream 614. Due to the reduced CO2 content in stream 613, it can be used for the same purposes as stream 521, but with improved efficiency compared to using stream 521 directly.

[00158] Stream 614 is further separated from unit 620. Unit 620 is used to recover some of the hydrogen present in 614 as stream 621, the remainder of the material being in stream 622. One of the technologies commonly used for separation in 620 is pressure swing adsorption, which would produce H2 in stream 621 as a high-purity hydrogen stream. The hydrogen in stream 621 would be used in units 5.2 and 5.3 shown in Figure 1. Stream 522 is sent to the hydrotreator, unit 5.3 in Figure 1.

[00159] Optionally, the organic liquid product 522 can be further separated. This option is depicted in Figure 5, which shows the separation of 522 in unit 530 into a lighter fraction represented by stream 531, and a heavier fraction represented by stream 532. The lighter fraction in 531 is typically material with a normal boiling point below 140°C, and the heavier fraction in 532 is typically material with a normal boiling point of 140°C and above. Stream 532 is sent to the hydrotreater, unit 5.3 in Figure 1. The lighter fraction, stream 531, can be split with some or all of stream 531 going to stream 533. The remainder of stream 531 that does not go to stream 533 can go to stream 534.Stream 534 is recycled to the oligomerization unit 510 to convert part of the lighter fraction into products that, after conversion, would form part of the heavier fraction, represented by 532. In this way, recycling stream 534 allows the conversion of part of the lighter fraction into a heavier fraction, thereby increasing the ratio of 532 to 531, which increases the amount of material available for jet fuel production. Stream 533 is typically naphtha with properties suitable for blending into motor gasoline and can be sold as such. Stream 523 is combined with stream 413 and used as stream 4a in Figure 1. Optionally, stream 523 is considered a wastewater stream and treated as such.

[00160] The diesel fuel and the heavier product (see 4d in Figure 1) are sent to the hydrocracker, which converts the diesel fuel and the heavier product into lighter boiling products (i.e., a mixture comprising a second, additional kerosene product). The molecules in the product are also more branched than the molecules in the diesel fuel and the heavier product. The second, additional kerosene product from the hydrocracker can be used directly for blending with aviation turbine fuel. The remaining product can also be used as end products. Optionally, the lighter products can be used as a co-feed to the oligomerization unit. In one example, some or all of the material in the product with a higher boiling point than kerosene is recycled.In another example, a non-sulfur catalyst, such as a reduced noble metal supported on an amorphous silica-alumina catalyst, is used to carry out hydrocracking in a fixed-bed reactor. An example of a reduced noble metal supported on an amorphous silica-alumina catalyst is Pt / SiO₂-Al₂O₃. These catalysts would have a high metal-to-acid activity ratio to promote hydroisomerization.

[00161] In another example of the process as described herein, the hydrocracker is operated at a lower pressure than the Fischer-Tropsch synthesis to allow the direct use of hydrogen recovered from the unconverted product after the oligomerization process (e.g., see Example 3). In general, hydrocracking is carried out at approximately 350°C to approximately 400°C, and at pressures >3 MPa (e.g., typical mild hydrocracking at pressures of approximately 5–8 MPa and typical heavy hydrocracking at pressures of approximately 1020 MPa). However, as shown in Example 3 (see below), the hydrocracking as described herein was carried out using a pressure of <3 MPa (e.g., approximately 2 MPa), at a temperature of approximately 320°C.In some examples, hydrocracking as described herein can be carried out at a temperature of approximately 320°C to approximately 400°C, or approximately 320°C to approximately 380°C, or approximately 320°C to approximately 350°C. In other examples, hydrocracking as described herein can be carried out at a pressure of approximately 1 MPa to approximately 20 MPa, or approximately 1 MPa to approximately 15 MPa, or approximately 1 MPa to approximately 10 MPa, approximately 1 MPa to approximately 5 MPa, or approximately 1 MPa to approximately 3 MPa, or approximately 1 MPa to approximately 2 MPa.

[00162] The following is a more detailed description of an example of the hydrocracking unit in step 5 of Figure 1. The hydrocracking unit in step 5 is depicted in more detail in Figure 6. The primary feed (e.g., gas oil and the heavier product) to the hydrocracker unit 540 is stream 302. Optionally, the organic liquid stream 412 can be split, with some or all of stream 412 going to stream 414. The remainder of stream 412 not going to stream 414 can go to stream 415. Stream 415 is also a feed to the hydrocracker unit 540. Feed stream 415 to the hydrocracker is usually required only if the freezing point onset of the synthetic jet fuel is higher than the specification limit of -47°C. In the 540 hydrocracking unit, the feed materials are hydrocracked and hydroisomerized.In one example, stream 415 is not exposed to the entire catalyst in the hydrocracker, but rather partially introduced as an interbed feed. By doing so, stream 415, which is a lighter-boiling feed than stream 302, is less likely to hydrocrack and more likely to isomerize. This method improves the yield of synthetic jet fuel over conventional operation with a single liquid feed point to the hydrocracker. The product of hydrocracking and hydroisomerization 540 is stream 541.

[00163] The hydrogen feed and hydrogen recycling system of the hydrocracker unit 540 are not explicitly shown. The hydrogen loop of the hydrocracking technology is known in the art (e.g., Scherzer, J.; Gruía, A.J. Hydrocracking Science and Technology, CRC Press: Boca Raton, FL, 1996). The hydrogen feed for the hydrocracker can be obtained from the stream 621 in Figure 4, or in other ways described in the art, such as by separating the synthesis gas produced in step 2 of this invention.

[00164] Product stream 541 is separated into different fractions in separator unit 550. Optionally, the product from the hydrotreator, unit 5.3 in Figure 1, could be separated into stream 541 to reduce the number of separation steps. In separator unit 550, which is typically formed by distillation, the material is separated into a liberated hydrocarbon stream 551, a kerosene-range hydrocarbon stream 552 suitable for synthetic jet fuel blending, a gas oil stream 553, and an atmospheric residue stream 554. It is possible to select the separation such that stream 553 is zero. The separation in unit 550 is primarily carried out to ensure that stream 552 is suitable for synthetic jet fuel. Optionally, the heavier product, current 554, can be split with some or all of the current 554 going to current 555.The remainder of stream 554 that does not go to stream 555 can go to stream 556. Stream 556 is recycled to the hydrocracker unit 540. In one example, stream 556 is not exposed to all of the catalyst in the hydrocracker, but is partially introduced as an inter-bed feed.

[00165] Stream 551 may be further separated into product fractions and sold as propane, butane, and naphtha. This material may also be used for underground bitumen recovery from oil sands deposits. The naphtha may be used as a blending material for motor gasoline, or as refinery or petrochemical feedstock. The naphtha may be employed as a diluent for bitumen-derived oil sands, or in processes such as paraffin foam treatment for bitumen recovery. Stream 552 is used for semi-synthetic jet fuel. Stream 553 may be sold as a diesel fuel blending component and will typically have a cetane number of 51 or better, be sulfur-free, and have acceptable cold flow properties. The 554 stream can be sold as a component of lubricating base oil blend, zero sulfur fuel oil, or synthetic oil.

[00166] The feed materials (e.g., kerosene products) sent to the hydrotreator are hydrogenated to convert the oxygen-containing olefinic molecules to paraffinic molecules. The product after hydrotreatment is fractionated to obtain final products. The kerosene fraction is fractionated to be suitable as an aviation turbine fuel. In one example, a reduced, non-sulfured base metal supported on alumina or silica catalyst is used to carry out the hydrotreatment in a stationary milk reactor. An example of a reduced base metal supported on an alumina catalyst is a reduced Ni / Al₂O₃ catalyst.Using a reduced metal catalyst (e.g., hydrotreating) instead of a sulfur-based metal catalyst (e.g., hydrotreating) allows for the elimination of sulfur addition to the feed and enables reactions such as hydrotreating to be carried out under milder conditions than with a sulfur-based metal catalyst (e.g., hydrotreating). In some examples, the hydrotreator is operated at a temperature of approximately 80°C to approximately 200°C, or approximately 80°C to approximately 180°C, or approximately 80°C to approximately 150°C. In other examples, the hydrotreator operates at a temperature of approximately 180°C to approximately 420°C, or approximately 180°C to approximately 380°C, or approximately 260°C to approximately 380°C.In one example, the hydrotreater is operated at a lower pressure than the Fischer-Tropsch synthesis to allow the direct use of hydrogen recovered from the unconverted product after the oligomerization process. In other examples, the hydrotreater is operated at pressures of approximately 0.5 MPa to approximately 20 MPa, or approximately 1 MPa to approximately 15 MPa, or approximately 1 MPa to approximately 10 MPa, approximately 1 MPa to approximately 5 MPa, or approximately 1 MPa to approximately 3 MPa, or approximately 1 MPa to approximately 2 MPa. In another example of the hydrotreating process as described herein, it was found that, using a model feed (10% 1-hexene, 5% toluene, 85% n-octane), almost complete conversion of the definites was possible at approximately 80°C and approximately 1 MPa with a reduced Ni / AUCG ratio.

[00167] A principal product of the process described herein is a kerosene-range material that meets the specification requirements for synthetic aviation turbine fuel, either as a blending component of semi-synthetic jet fuel or a fully synthetic jet fuel.

[00168] The following is a more detailed description of an example of the hydrotreating unit in step 5. ) ci «nn / 1 ζηζ / Ε / γίΛΐ The hydrotreating unit in step 5 is shown in more detail in Figure 7. The hydrotreator receives two organic feed materials: one from the oligomerization unit (i.e., the first additional kerosene product) and one from the separation after the Fischer-Tropsch synthesis (i.e., the kerosene product). The material from the oligomerization unit is either stream 522 or stream 532, depending on whether stream 522 was further separated. The material from the separation after the Fischer-Tropsch synthesis is either stream 412 or stream 414, depending on whether any or all of this material was sent to the hydrocracking unit in stream 415. Therefore, it is possible for the hydrotreator to receive only the feed from the oligomerization unit. The hydrogen feed and the hydrogen recycling system of the hydrotreating unit 560 are not explicitly shown.The hydrogen feed for the hydrotreator can be obtained from stream 621 in Figure 4, or by other methods known in the art, such as by separating the synthesis gas produced in step 2 of this invention.

[00169] The hydrotreating product is stream 561. The product in stream 561 is substantially free of alkenes and oxygen-containing organic compounds. The product in stream 561 consists mainly of alkanes, cycloalkanes, and aromatic compounds; the relative abundance of each class of compound depends on both the operation of the hydrotreator unit 560 and the composition of the feed materials to the hydrotreator. When the feed material to the hydrotreator unit 560 comprises only stream 532, the entire stream 561 is likely to be suitable for use as either fully synthetic jet fuel or semi-synthetic jet fuel.Stream 561 is suitable as fully synthetic jet fuel when its aromatic content is between 8 and 25% by volume, and the distillation range of stream 532 is appropriately selected according to the jet fuel specifications. The process described herein comprises a refining process for producing fully synthetic jet fuel from a Fischer-Tropsch product (i.e., the mixture comprising liquid hydrocarbon) employing only two conversion steps: the oligomerization unit 510 and the hydrotreating unit 560.

[00170] Stream 561 is suitable as a semi-synthetic jet fuel when the aromatic content is lower, and the distillation range of stream 532 is appropriately selected according to the jet fuel specifications. The process described herein provides a refining process for producing a semi-synthetic jet fuel from a Fischer-Tropsch product (i.e., the mixture comprising liquid hydrocarbons) employing only the conversion steps, the oligomerization unit 510, and the hydrotreating unit 560.

[00171] Optionally, and independent of the composition of the feed materials going to hydrotreating unit 560, stream 561 can be separated in unit 550 as shown in Figure 6. Optionally, and independent of the composition of the feed materials going to hydrotreating unit 560, stream 561 can be further separated in unit 570 as shown in Figure 8. Separating stream 561 in unit 570 is convenient for producing products based on their distillation range that are useful for different applications. Separating stream 561 in unit 570 produces a naphtha stream 571, a kerosene stream 572, and a gas oil stream 573. Stream 571 is a naphtha range product. The naphtha can be... CI Rnn / 1 7P7 / B / YILI can be used as a blending material for motor gasoline, or as refinery feed or petrochemical feed.Naphtha can be used as a diluent for bitumen-derived oil sands, or in processes such as paraffin foam treatment for bitumen recovery. Stream 572 is used for semi-synthetic jet fuel or fully synthetic jet fuel. Stream 573 can be sold as a diesel fuel blending component and will typically have a cetane number of 51 or better, contain no sulfur, and have acceptable cold flow properties.

[00172] In some examples, it is possible to operate the oligomerization process in such a way that little or no aromatic products are produced. This type of operation is useful for increasing the production of semi-synthetic jet fuel (and extending the catalyst cycle time). In one specific example, if the aromatic content is 8% or more, for example, up to approximately 60%, the stream can be useful for the production of fully synthetic jet fuel, either alone or in a blend with one of the kerosene streams that do not contain aromatic products. Preferably, the fully synthetic jet fuel will have between 8% and 25% aromatic products. In some examples, the aromatic content is less than 8%. In other examples, the aromatic content is approximately 0 to 1%.In this example, the stream may be useful as a blending component for semi-synthetic jet fuel, with some of the pre-approved synthetic jet fuel classes (isoparaffinic kerosene) having < 1% aromatic products.

[00173] In examples of the process as described herein, the complete process generates a sufficient quantity of H2 to drive each process step that requires H2 as a reactant / input (e.g., as depicted in any of Figures 1 to 8) without having to use H2 from sources external to the process (e.g., a methane reformer / methane reformer, etc.). In the examples, the process as described herein does not require an H2 input from external sources.

[00174] In other examples of the process as described herein, the final output of the process—jet fuel having a high boiling point (e.g., between 140° and 260°C) and a low freezing point (e.g., < -60°C)—is produced in high yield. In some examples, the process as described herein produces more jet fuel having a high boiling point (e.g., between 140° and 260°C) and a low freezing point (e.g., < 60°C) than other current or standard technologies.

[00175] In other examples of the process as described herein, the use of one or more gas compressors between the Fischer-Tropsch unit (e.g., unit 3.1 in Figure 1) and the refining units (oligomerization (e.g., unit 5.1 in Figure 1), hydrocracking (e.g., unit 5.2 in Figure 1), and hydrotreating (e.g., unit 5.3 in Figure 1)) does not require an increase in the pressure at which the refining units operate. In some examples, the process as described herein uses the pressure from the Fischer-Tropsch unit (e.g., unit 3.1 in Figure 1) to drive the processes of the refining units (oligomerization (e.g., unit 5.1 in Figure 1), hydrocracking (e.g., unit 5.2 in Figure 1), and hydrotreating (e.g., unit 5.3 in Figure 1)).In some examples, the final refining steps as described herein (oligomerization c 1 Rnn / 1 ζηζ / E / γίΛΐ (e.g., unit 5.1 in Figure 1), hydrocracking (e.g., unit 5.2 in Figure 1), and hydrotreating (e.g., unit 5.3 in Figure 1)) are conducted at a pressure consistent with that of the Fischer-Tropsch synthesis as described herein: e.g., at a pressure of approximately 2 MPa; or approximately 2.5 MPa; or in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa. This is in contrast to, e.g., standard hydrotreating conditions, which require minimum pressures of approximately 8 to 10 MPa.

[00176] The following is a more detailed description of other examples of the final refining steps of the process as described herein; particularly oligomerization (e.g., unit 5.1 in Figure 1), hydrocracking (e.g., unit 5.2 in Figure 1), and hydrotreating (e.g., unit 5.3 in Figure 1).

[00177] Example 1 - Semi-synthetic Jet Fuel, 50% Mixture. A fixed-bed continuous flow reactor was used to produce an olefinic kerosene range product according to, for example, oligomerization unit 5.1 in Figure 1. Using a commercially available, non-sulfured H-ZSM-5 catalyst, a mixture of light paraffins, olefins, and oxygenates in the carbon number range Ci-C8 was converted over the catalyst at 240-280°C and 2 MPa to produce a product that included kerosene range material. The carbon number range of the feed was wider than that described in the prior art. The pressure was lower than that usually used for oligomerization and was typical of the outlet pressure after Fischer-Tropsch synthesis (for example, steps 3 and 4 in Figure 1). The feed material represents, for example, current 4b in Figure 1 and current 411 going to unit 510 in Figure 3.The concentration of olefin in the feed was 24% by weight.

[00178] In this example, the reactor was operated on a one-time basis. The conversion of the light olefins, using propylene as an example, was >95%. The mass selectivity to the >140°C material, which could potentially be suitable for inclusion in a jet fuel blend, was 29%. As previously described (Garwood, WE ACS Symp. Ser. 1983, 218, 383-396), the carbon number distribution on H-ZSM-5 is determined by the combination of temperature and pressure. An engineering procedure that can be employed to increase the overall yield of the >140°C fraction is to have an internal recycle of naphtha (Cs-140°C) to an oligomerization reactor. This was not done in the present example, as it was already known.

[00179] The olefinic product of the oligomerization was hydrotreated over a non-sulfured Ni / Al₂O₃ catalyst, reduced to an olefin content of <1%. For example, the hydrotreater is unit 5.3 in Figure 1. The hydrotreated product was distilled into different boiling fractions, and each boiling fraction was characterized in terms of density and freezing point onset (see Table 1). The number of fractions prepared is intended to illustrate the suitability of different cuts for potential inclusion in a jet fuel blend and is not proposed to represent a suggested separation strategy.

[00180] Table 1. Characterization of the different distillation cuts of the hydrotreated product from the oligomerization conversion carried out at 240-280°C and 2 MPa. jc 1 Rnn / 1 znz / R / YiAi Boiling range (°C) Density at 15.6°C (kg / m3) Freezing start (°C) 140-150 730 <-60 150-160 740 <-60 160-170 747 <-60 170-180 753 <-60 180-240 770 <-60 240-250 786 <-60 250-260 791 <-60 >260 812 not determined

[00181] It is noteworthy that all distillation cuts in the boiling range of 140-260°C met the maximum starting freezing point specification for Jet A-1, which is -47°C. It is usually difficult to obtain (e.g., using traditional or standard technologies) a product that has a high boiling point (e.g., between 140° and 260°C) and a low freezing point (e.g., < -60°C). This supports the fact that the process as described herein is capable of maximizing jet fuel yield.

[00182] Example 2 - Fully Synthetic Jet Fuel, 100% Blend. The process has the potential to produce material that will enable the formulation of fully synthetic jet fuel, without any petroleum-derived material. One of the requirements for fully synthetic jet fuel is that it must contain 8–25% by volume of aromatic products. In this example, a fixed-bed continuous flow reactor was employed to produce an olefinic and aromatic kerosene-range product according to, for example, the oligomerization unit 5.1 in Figure 1. The reactor, catalyst, and feed material were similar to those in Example 1. The feed was a mixture of light paraffins, olefins, and oxygenates in the carbon number range CrC8 and contained 25% by weight of olefins. The feed was converted over the catalyst at 350–380°C and 2 MPa to produce a product that included the kerosene-range material.

[00183] The olefinic and aromatic product from the oligomerization reactor was hydrotreated over a non-sulfured Ni / AhOs catalyst, reduced to an olefin content of <1%, but under conditions that would not substantially hydrogenate the aromatic products to cycloparaffins. For example, the hydrotreater is unit 5.3 in Figure 1. For the same reasons explained in Example 1, the hydrotreated product was distilled in different boiling fractions, and each boiling fraction was characterized in terms of density and freezing point onset (Table 2). [00184 ] Table 2. Characterization of the different distillation cuts of the hydrotreated product from the oligomerization conversion carried out at 350-380°C and 2 MPa. Boiling range (°C)____________Density at 15.6°C (kg / m3)_______Freezing start (°C) 140-150 772 <-60 150-160 791 <-60 160-170 801 <-60 170-180 809 <-60 180-240 834 <-60 240-250 863 <-60 250-260 871 <-60 >260 881 not determined

[00185] All distillation cuts in the boiling range of 140–260°C met the maximum starting freezing point specification for Jet A-1, which is -47°C. The higher density of the distillation cuts in Table 2 (compared to Table 1) was indicative of aromatic products and cycloparaffins in the treated product. Typically, the aromatic content of synthetic jet fuel is derived from a fossil fuel source. In contrast, in operation, for example, of unit 5.1 in Figure 1 at higher temperatures, the process allows the generation of compound classes (i.e., aromatic products) frequently absent from kerosene-based blending materials used for synthetic jet fuel blending. It also illustrates the flexibility of, for example, unit 5.1 in Figure 1, which can be used in different operating modes.

[00186] Example 3. This example illustrates the performance of the hydrocracking unit, for example, unit 5.2 in Figure 1, when operated at a pressure similar to that of Fischer-Tropsch synthesis, i.e., 2 MPa. A fixed-bed continuous flow reactor was operated with a Pt / SiO2-Al2O3 hydrocracking catalyst at 320°C, 2 MPa, an H2-to-feed ratio of 600 m3 / m3, and a liquid space velocity of 2 h1. These conditions were selected to show operation under milder conditions than those conventionally encountered for hydrocracking and to illustrate the benefit of its application in the process as described herein.

[00187] The feed material to the hydrocracker was wax, representative of, for example, stream 4d in Figure 1. When described in terms of boiling point, the wax was an atmospheric residue with an initial boiling point temperature of approximately 360°C and contained n-alkanes (paraffins) with carbon numbers C24 and higher. The reactor was operated on a one-time basis. For example, the engineering design for fully converting the wax by recycling the heavier product fraction to the hydrocracker is shown in Figure 6. Of interest for the manufacture of synthetic jet fuel is the kerosene-naphtha selectivity ratio. Under the operating conditions employed herein, the mass ratio of hydrocarbons in the boiling range of 140–260°C to hydrocarbons boiling below 140°C was 1:1.

[00188] The separation of the hydrocracked product did not reflect any separation strategy for the process, and the reduced cuts were prepared for the same reason as described in Example 1. The density and freezing point onset were determined for each of the reduced boiling fractions in the hydrocracked product (Table 3).

[00189] Table 3. Characterization of the different distillation costs of the hydrocracked product produced at 320°C and 2 MPa. ! CI Rnn / 1 7Π7 / Β / YILI Boiling range (°C) Density at 15.6°C (kg / m3) Freezing point (°C) 140-150 734 <-60 150-160 740 <-60 160-170 744 <-60 170-180 750 <-60 180-240 766 <-60 240-250 778 -49 250-260 780 -45

[00190] The reduced distillation cuts in the boiling range of 140-250°C had a freezing start that met the maximum A-1 freezing point specification start of -47°C.

[00191] Example 4. A semi-synthetic jet fuel was blended using the products described in Examples 1 and 3, together with a kerosene range product from a petroleum refinery. The kerosene range product from the petroleum refinery was redistilled to remove material boiling lighter than 150°C. The remaining petroleum-derived kerosene was characterized and had a density of 817.5 kg / m3, with a freezing start of -51°C.

[00192] A semi-synthetic jet fuel was prepared. The mixture consisted of 25% by volume of the 160–260°C fraction of the hydrotreated oligomerization product shown in Table 1, 25% by volume of the 160–240°C fraction of the hydrocracked product shown in Table 3, and 50% by volume of petroleum-derived kerosene. Considering the properties listed above, a wider boiling range could have been used, but the purpose was to show that a viable semi-synthetic jet fuel could be produced by the process as described herein. The mixture was not optimized to maximize jet fuel yield.

[00193] The semi-synthetic jet fuel prepared in this manner was characterized and compared to the Jet A-1 specification requirements (Table 4). A fuel laboratory performed the characterization, adding 1 mg / L of Stadis 450 to the semi-synthetic jet fuel prior to characterization. This was the only commonly used additive, as prescribed for jet fuel use, that was added. The standard test methods and specifications listed in Table 4 were the prescribed methods and specifications for the evaluation of Jet A-1 aviation turbine fuel.

[00194] In addition to the specifications listed in Table 4, the cold flow density and viscosity of the semi-synthetic jet fuel were measured. At -20°C, the density was 816 kg / m³, the viscosity was 3.75 mPa·s (cP), and the dynamic viscosity was 4.58 mm² / s (cSt). The maximum allowable dynamic viscosity at -20°C is 8 mm² / s (cSt). All tested parameters met the detailed requirements for a semi-synthetic Jet A-1 as described by ASTM D7566-18a for aviation turbine fuels containing synthesized hydrocarbons.

[00195] The flash boiling point temperature of 50.0°C (38°C minimum required) and density of 790.7 kg / m3 (775 kg / m3 minimum required) indicated that additional lower boiling material could be incorporated into the semi-synthetic jet fuel mixture. The freezing point onset of -56.3°C (-47°C maximum required), density of 790.7 kg / m3 (840 kg / m3 maximum required), smoke point of 23.0 mm (18 mm minimum required), and final boiling point temperature of 261.0°C (300°C maximum required) indicated that additional higher boiling material could be incorporated into the semi-synthetic jet fuel mixture.

[00196] Table 4. Characterization of semi-synthetic jet fuel and comparison with Jet A-1 specifications. Property evaluated Method of Units Semi-synthetic Jet Fuel Specification Pass / Fail Test A-1 yciRnn / ι ζηζ / E / γ minimum maximum Copper corrosion, ASTMD130 classification no. 1a - no.1 passes Aromatics ASTM % by volume 10.2 8 25 passes D1319 Smoke point ASTM D1322 mm 23.0 18 - passes 5 Naphthalene content ASTM % by volume 0.21 - 3.0 passes D1840 Electrical conductivity ASTM D2624 pS / m2 460 50 600 passes Sulfur mercaptan ASTM D3227 % by mass < 0.0003 - 0.003 passes Thermal oxidation stability, pressure drop ASTM mm Hg 0.1 - 25 passes 10 D3241 Thermal oxidation stability, visual classification of deposits ASTM < 1 - 3 passes D3241 Tube deposit (ETR), upper average ASTM nm 10 - 85 passes to 2.5 mm2 D3241 Acid number ASTM D3242 mg KOH / g 0.004 - 0.10 passes Net heat of combustion (corrected for ASTM MJ / kg 43.525 42.8 - passes 15 sulfur) D3338 Water separation characteristics, ASTM 72 70 passes MSEP-A D3948 Density @ 15°C ASTM D4052 kg / m3 790.7 775 840 passes Wear scar diameter ASTM D5001 mm 0.65 - 0.85 passes 20 Total sulfur ASTM D5453 mg / kg 3.6 - 3000 pass Flash Boiling Point ASTM D56 °C 50 38 - pass corrected Freezing Point ASTM D5972 °C -56.3 - -47 pass 10% of distillation recovered (corr) ASTM D86 °C 180.9 - 205 pass 50% of distillation recovered (corr) ASTM D86 °C 202.4 report pass 25 90% of distillation recovered (corr) ASTM D86 °C 238.4 report pass Final Boiling Point of Distillation ASTM D86 °C 261.0 - 300 pass Distillation Residue ASTM D86 % 1.2 - 1.5 pass Distillation Loss ASTM D86 % 0.2 - 1.5 pass Existing Gum Content IP540 mg / 100mL < 1 - 7 pass. , / ri Αηη / ι ζπζ / β / υ

[00197] Example 5. The process as described herein is also capable of producing a fully semi-synthetic jet fuel blend. Unlike a semi-synthetic jet fuel, the fully semi-synthetic jet fuel does not have a petroleum-derived blending component in the jet fuel blend.

[00198] A fully semi-synthetic jet fuel was blended using the products described in Examples 2 and 3. The blend consisted of 40 wt% of the 160–260°C fraction of the hydrotreated oligomerization product shown in Table 2, and 60 wt% of the 160–240°C fraction of the hydrocracked product shown in Table 3. This fully semi-synthetic jet fuel was characterized and compared to the requirements of the Jet A-1 specification (Table 5). A fuel laboratory performed the characterization, adding 1 mg / L of Stadis 450 to the fully semi-synthetic jet fuel prior to characterization.

[00199] In addition to the specifications listed in Table 5, the cold flow density and viscosity of the fully semi-synthetic jet fuel were measured. At -20°C, the density was 812 kg / m³, the viscosity was 3.27 mPa·s (cP), and the dynamic viscosity was 4.02 mm² / s (cSt). The maximum allowable dynamic viscosity at -20°C is 8 mm² / s (cSt). Based on these analyses, the fully semi-synthetic jet fuel met the requirements for synthetic Jet A-1 as described by ASTM D7566-18a for aviation turbine fuel containing synthesized hydrocarbons.

[00200] The T50-T10 = (197.8-181.7) = 16.1, which is greater than the minimum difference of 15°C required for a fully semi-synthetic jet fuel. The T90-T10 = 41, which is greater than the minimum difference of 40°C required for a fully semi-synthetic jet fuel. The flash boiling point temperature of 47.0°C (38°C minimum required) and density of 786.1 kg / m³ (775 kg / m³ minimum required) indicated that additional lower boiling material could be incorporated into the fully semi-synthetic jet fuel blend. The freezing point start of -72.2°C (-47°C maximum required), density of 786.1 kg / m3 (840 kg / m3 maximum required), smoke point of 24.0 mm (18 mm minimum required), and final boiling point temperature of 242.9°C (300°C maximum required), indicated that additional higher boiling material could be fitted into the fully semi-synthetic jet fuel mixture.

[00201] Table 5. Characterization of the fully semi-synthetic jet fuel and comparison with Jet A-1 specifications. ) c 1 «nn / 1 znz / R / YiAi Property Evaluated Test Method Units Semi-synthetic Jet Fuel Specification Jet A-1 Pass / Fail Minimum Maximum Copper Corrosion, Classification ASTM D130 No. 1b - No. 1 Pass Aromatics ASTM D1319 % by Volume 10.4 8 25 Pass Smoke Point ASTM D1322 mm 24.0 18 - Pass Naphthalene Content ASTM D1840 % by Volume 0.04 - 3.0 Pass Electrical Conductivity ASTM D2624 pS / m2 543 50 600 Pass Sulfur Mercaptan ASTM D3227 % by Mass < 0.0003 - 0.003 Pass Acid Number ASTM D3242 mg KOH / g 0.005 - 0.10 Pass Net Heat of Combustion (corrected for sulfur ASTM D3338 MJ / kg 43.547 42.8 - Pass) Separation Characteristics ASTM D3948 97 70 passes water, MSEP-A Density @ 15°C ASTM D4052 kg / m3 786.1 775 840 passes Wear scar diameter ASTM D5001 mm 0.62 - 0.85 passes Total Sulfur ASTM D5453 mg / kg 1.0 - 3000 pass Flash Boiling Point ASTM D56 °C 47.0 - 38 pass corrected Freezing Point ASTM D5972 °C -72.2 - -47 pass 10% Distillation Recovered (corr) ASTM D86 °C 181.7 - 205 pass 50% Distillation Recovered (corr) ASTM D86 °C 197.8 pass 90% Distillation Recovered (corr) ASTM D86 °C 222.8 pass Final Distillation Boiling Point ASTM D86 °C 242.9 - 300 pass Distillation Residue ASTM D86 % 1.2 - 1.5 pass Distillation Loss ASTM D86 % 0.4 - 1.5 pass Existing Gum Content IP540 mg / 100 mL < 1 - 7 passes

[00202] The embodiments described herein are intended to be examples only. Persons skilled in the art tci «nn / 1 znz / R / YiAi» may make alterations, modifications, and variations to the particular embodiments. The scope of the claims should not be limited by the particular embodiments set forth herein, but should be interpreted in a manner consistent with the specification as a whole.

[00203] All publications, patents, and patent applications mentioned in this Specification are indicative of the skill level of the practitioners in the art to which this invention belongs and are incorporated herein by reference to the same extent as if each individual publication, patent, or patent application were specifically and individually indicated to be incorporated by reference.

[00204] Having thus described the invention, it will be obvious that it can be varied in many ways. These variations should not be considered as a departure from the spirit and scope of the invention, and all modifications that are obvious to a person skilled in the art are intended to be included within the scope of the following claims.

Claims

1. A process for producing synthetic jet fuel, comprising converting feedstock to synthesis gas; converting the synthesis gas into a mixture comprising liquid hydrocarbons; refining the mixture comprising liquid hydrocarbons to isolate a kerosene product; and hydrotreating the kerosene product to form synthetic jet fuel.

2. The process of claim 1, wherein the conversion of raw material to synthesis gas comprises: pyrolyzing the raw material under aqueous conditions to form a mixture comprising biocrude.

3. The process of claim 2, wherein the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a high water content.

4. The process of claim 1, wherein the conversion of raw material to synthesis gas comprises: pyrolyzing the raw material to form a mixture comprising biocrude.

5. The process of claim 4, wherein the raw material comprises biomass, organic materials, waste streams, or a combination thereof with a low water content.

6. The process of any of claims 1 to 5, wherein converting raw material to synthesis gas further comprises: gasifying the mixture comprising biocrude to form the synthesis gas.

7. The process of claim 6, wherein gasifying the mixture comprising biocrude comprises: supercritical water gasification of the mixture comprising biocrude to form a mixture comprising CH4, CO, CO2, and H2; and reforming the mixture comprising CH4, CO, CO2, and H2 to form synthesis gas.

8. The process of claim 7, wherein the reforming comprises dry reforming and steam reforming.

9. The process of any of claims 6 to 8, wherein when the feedstock is converted to synthesis gas, the process further comprises: adding an oil feedstock, a sugar feedstock, and / or an alcohol feedstock to the mixture comprising biocrude prior to gasification.

10. The process of any of claims 1 to 9, wherein the synthesis gas comprises an H2 to CO ratio that is less than 2 to 1.

11. The process of any of claims 1 to 10, wherein the synthesis gas comprises a stoichiometric ratio of (H2 - CO2) / (CO + CO2) that is less than 2 to 1.

12. The process of any of claims 1 to 11, wherein the synthesis gas comprises a Ribblet ratio of (H2) / (2CO + 3CO2) that is less than 1 to 1.

13. The process of any of claims 1 to 12, wherein converting the synthesis gas into a mixture 1 c 1 Rnn / 1 znz / E / YiAi comprising liquid hydrocarbons comprises: carrying out a Fischer-Tropsch synthesis to convert the synthesis gas into a mixture comprising liquid hydrocarbons.

14. The process of claim 13, wherein the Fischer-Tropsch synthesis is carried out with an iron-based catalyst.

15. The process of claim 14, wherein the Fischer-Tropsch synthesis is carried out to convert the synthesis gas into a mixture comprising liquid hydrocarbons, the process further comprising: a water-gas exchange reaction to increase the concentration of H2.

16. The process of any of claims 13 to 15, wherein the Fischer-Tropsch synthesis is carried out at a pressure of approximately 2 MPa; or approximately 2.5 MPa; or approximately 2.8 MPa.

17. The process of any of claims 13 to 15, wherein the Fischer-Tropsch synthesis is carried out at a pressure in the range of approximately 1.5 MPa to 5 MPa; or in the range of approximately 2 MPa to approximately 4 MPa; or in the range of approximately 2 MPa to approximately 3 MPa; or in the range of approximately 1.5 to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

18. The process of any of claims 13 to 15, wherein the Fischer-Tropsch synthesis is carried out at a pressure greater than 2 MPa.

19. The process of any of claims 13 to 18, wherein the mixture comprising liquid hydrocarbons comprises an alkene to alkane ratio greater than 1 to 1.

20. The process of any of claims 1 to 19, wherein refining the mixture comprising liquid hydrocarbons to isolate a kerosene product comprises: carrying out a vapor-liquid equilibrium separation in the mixture comprising liquid hydrocarbons; and separating the mixture into the kerosene product and at least one of an aqueous product, a naphtha and gas product, or a gas oil and a heavier product.

21. The process of claim 20, wherein the vapor-liquid equilibrium separation is carried out as a single-stage separation and / or a multi-stage separation.

22. The process of claim 20 or 21, wherein, when an aqueous product is separated, the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: adding the separated aqueous product to the mixture comprising biocrude before gasifying the mixture comprising biocrude when converting the feedstock to synthesis gas.

23. The process of any of claims 20 to 22, wherein, when a naphtha and gas product is separated, refining the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: oligomerizing the naphtha and gas product to form a mixture comprising a first additional kerosene product.

24. The process of claim 23, wherein the oligomerization of the naphtha and gas product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

25. The process of claim 23, wherein the oligomerization of naphtha and gas product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

26. The process of any of claims 23 to 25, wherein the oligomerization of naphtha and gas product is carried out with a non-sulfured catalyst.

27. The process of claim 26, wherein the oligomerization of naphtha and gas product is carried out with an acidic ZSM-5 zeolite catalyst.

28. The process of any of claims 23 to 27, wherein the first additional kerosene product comprises alkene and aromatic compounds.

29. The process of claim 28, wherein the first additional kerosene product comprises approximately 0% to approximately 60% aromatic compounds; approximately 1% to approximately 60% aromatic compounds; or approximately 1% to approximately 50% aromatic compounds; or approximately 1% to approximately 40% aromatic compounds; or approximately 1% to approximately 30% aromatic compounds; or approximately 0% to approximately 1% aromatic compounds; or approximately 1% to approximately 7% aromatic compounds; or approximately 8% to approximately 25% aromatic compounds; or approximately 8% aromatic compounds.

30. The process of any of claims 20 to 29, wherein, when a gas oil and heavier product are separated, the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: hydrocracking the gas oil and the heavier product to form a mixture comprising an additional second kerosene product.

31. The process of claim 30, wherein the hydrocracking of the gas oil and the heavier product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

32. The process of claim 30, wherein the hydrocracking of the gas oil and the heavier product is carried out at a pressure in a range of approximately 1.5 MPa to 3 MPa; or in a range of approximately 1.5 MPa to approximately 2.5 MPa; or in a range of approximately 2 MPa to approximately 2.5 MPa.

33. The process of any of claims 30 to 32, wherein the hydrocracking of the gas oil and the heavier product is carried out with a non-sulfur catalyst 34. The process of any of claims 30 to 33, wherein the hydrocracking is carried out with a noble metal catalyst supported on amorphous silica-alumina.

35. The process of claim 34, wherein the catalyst is Pt / SiO2-Al2O3.

36. The process of any of claims 1 to 35, wherein the hydrotreating of the kerosene product tci Rnn / 1 ζηζ / E / γίΛΐ to form synthetic jet fuel comprises: hydrotreating the kerosene product, and when a naphtha and gas product is separated, hydrotreating the first additional kerosene product to form a mixture comprising paraffinic hydrocarbons; and fractionating the mixture comprising paraffinic hydrocarbons, and when a gas oil and the heavier product are separated, fractionating the mixture comprising the second additional kerosene product to isolate the synthetic jet fuel.

37. The process of claim 36, wherein, when fractionating the mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising the second additional kerosene product, the process further comprises: adding the mixture comprising the second additional kerosene product to the mixture comprising paraffinic hydrocarbons prior to fractionation.

38. The process of claim 36 or 37, wherein each of the kerosene product, the first additional kerosene product, and the second additional kerosene product have a normal boiling point temperature range of approximately 140°C to approximately 300°C.

39. The process of any of claims 36 to 38, wherein the hydrotreating is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

40. The process of any of claims 36 to 38, wherein the hydrotreating is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

41. The process of any of claims 36 to 40, wherein the hydrotreatment is carried out with a non-sulfur catalyst 42. The process of any of claims 36 to 41, wherein the hydrotreatment is carried out with a reduced base metal catalyst supported on alumina or silica.

43. The process of claim 42, wherein the catalyst is reduced NI / Al2O3.

44. The process of any of claims 1 to 43, wherein the synthetic jet fuel is a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination thereof.

45. The process of claim 44, wherein the synthetic jet fuel has a boiling point between approximately 140°C and approximately 260°C and a freezing point < -60°C.

46. ​​A process for producing synthetic jet fuel, comprising converting feedstock to synthesis gas, comprising pyrolyzing the feedstock to form a mixture comprising biocrude and gasifying the mixture comprising biocrude to form synthesis gas, the feedstock comprising biomass, organic materials, waste streams or a combination thereof; converting the synthesis gas into a mixture comprising liquid hydrocarbons; refining the mixture comprising liquid hydrocarbons to isolate a kerosene product; and hydrotreating the kerosene product to form synthetic jet fuel.

47. The process of claim 46, wherein the conversion of the raw material to synthesis gas comprises: pyrolyzing the raw material under aqueous conditions, wherein the raw material comprises a high water content.

48. The process of claim 46, wherein the conversion of the raw material to synthesis gas comprises: pyrolyzing the raw material, wherein the raw material comprises a low water content.

49. The process of claim 46, wherein the gasification of the mixture comprising biocrude comprises: supercritical water gasification of the mixture comprising biocrude to form a mixture comprising CH4, CO, CO2, and H2; and reforming the mixture comprising CH4, CO, CO2, and H2 to form synthesis gas.

50. The process of claim 49, wherein the reforming comprises dry reforming and steam reforming.

51. The process of any of claims 46 to 50, wherein, when converting the feedstock to synthesis gas, the process further comprises: adding an oil feedstock, a sugar feedstock, and / or an alcohol feedstock to the mixture comprising biocrude prior to gasification.

52. The process of any of claims 46 to 51, wherein the synthesis gas comprises an H2 to CO ratio that is less than 2 to 1.

53. The process of any of claims 46 to 52, wherein the synthesis gas comprises a stoichiometric ratio of (H2 - CO2) / (CO + CO2) that is less than 2 to 1.

54. The process of any of claims 46 to 53, wherein the synthesis gas comprises a Ribblet ratio of (H2) / (2CO + 3CO2) that is less than 1 to 1.

55. The process of any of claims 46 to 54, wherein converting the synthesis gas into a mixture comprising liquid hydrocarbons comprises: carrying out a Fischer-Tropsch synthesis to convert the synthesis gas into a mixture comprising liquid hydrocarbons.

56. The process of claim 55, wherein the Fischer-Tropsch synthesis is carried out with an iron-based catalyst.

57. The process of claim 56, wherein, when the Fischer-Tropsch synthesis is carried out to convert the synthesis gas into a mixture comprising liquid hydrocarbons, the process further comprises: a water-gas swap reaction to increase the concentration of H2.

58. The process of any of claims 55 to 57, wherein the Fischer-Tropsch synthesis is carried out at a pressure of approximately 2 MPa; or approximately 2.5 MPa; or approximately 2.8 MPa.

59. The process of any of claims 55 to 57, wherein the Fischer-Tropsch synthesis is carried out at a pressure in the range of approximately 1.5 MPa to 5 MPa; or in the range of approximately 2 MPa to approximately 4 MPa; or in the range of approximately 2 MPa to approximately 3 MPa; or in the range of approximately 1.5 to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

60. The process of any of claims 55 to 57, wherein the Fischer-Tropsch synthesis is carried out at a pressure greater than 2 MPa.

61. The process of any of claims 55 to 60, wherein the mixture comprising liquid hydrocarbons comprises an alkene to alkane ratio greater than 1:

1.

62. The process of any of claims 46 to 61, wherein the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product comprises: carrying out a vapor-liquid equilibrium separation in the mixture comprising liquid hydrocarbons; and separating the mixtures into the kerosene product and at least one of an aqueous product, a naphtha and gas product, or a gas oil and a heavy product.

63. The process of claim 62, wherein the vapor-liquid equilibrium separation is carried out as a single-stage separation and / or a multi-stage separation.

64. The process of claim 62 or 63, wherein, when an aqueous product is separated, the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: adding the separated aqueous product to the mixture comprising biocrude before gasifying the mixture comprising biocrude when converting the feedstock to synthesis gas.

65. The process of any of claims 62 to 64, wherein, when a naphtha and gas product is separated, the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: oligomerizing the naphtha and gas product to form a mixture comprising a first additional kerosene product.

66. The process of claim 65, wherein oligomerizing the naphtha and gas product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

67. The process of claim 65, wherein oligomerizing the naphtha and gas product is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

68. The process of any of claims 65 to 67, wherein oligomerizing the naphtha and gas product is carried out with a non-sulfured catalyst.

69. The process of claim 68, wherein oligomerizing the naphtha and gas product is carried out with an acidic zeolite catalyst ZSM-5.

70. The process of any of claims 65 to 69, wherein the first additional kerosene product comprises alkene and aromatic compounds.

71. The process of claim 70, wherein the first additional kerosene product comprises approximately 0% to approximately 60% aromatic compounds; approximately 1% to approximately 60% aromatic compounds; or approximately 1% to approximately 50% aromatic compounds; or approximately 1% to approximately 40% aromatic compounds; or approximately 1% to approximately 30% aromatic compounds; or approximately 0% to approximately 1% aromatic compounds; or approximately 1% to approximately 7% aromatic compounds; or approximately 8% to approximately 25% aromatic compounds; or approximately 8% aromatic compounds.

72. The process of any of claims 62 to 71, wherein, when a gas oil and heavier product are separated, the refining of the mixture comprising liquid hydrocarbons to isolate a kerosene product further comprises: hydrocracking the gas oil from the heavier product to form a mixture comprising an additional second kerosene product.

73. The process of claim 72, wherein hydrocracking of the heavier product gas oil is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

74. The process of claim 72, wherein hydrocracking of the heavier product gas oil is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

75. The process of any of claims 72 to 74, wherein the hydrocracking of the heavier product gas oil is carried out with a non-sulfured catalyst.

76. The process of any of claims 72 to 75, wherein the hydrocracking is carried out with a noble catalyst supported on amorphous silica-alumina.

77. The process of claim 76, wherein the catalyst is Pt / SIO2-Al2O3.

78. The process of any of claims 46 to 77, wherein hydrotreating the kerosene product to form synthetic jet fuel comprises: hydrotreating the kerosene product, and when a naphtha and gas product is separated, hydrotreating the first additional kerosene product to form a mixture comprising paraffinic hydrocarbons; and fractionating the mixture comprising paraffinic hydrocarbons, and when a gas oil and heavier product is separated, fractionating the mixture comprising the second additional kerosene product to isolate the synthetic jet fuel. ! CI Rnn / 1 7P7 / B / YILI 79. The process of claim 78, wherein, when fractionating the mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising the second additional kerosene product, the process further comprises: adding the mixture comprising the second additional kerosene product to the mixture comprising paraffinic hydrocarbons prior to fractionation.

80. The process of claim 78 or 79, wherein each of the kerosene product, the first additional kerosene product, and the second additional kerosene product have a normal boiling point temperature range of approximately 140°C to approximately 300°C.

81. The process of any of claims 78 to 80, wherein the hydrotreating is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

82. The process of any of claims 78 to 80, wherein the hydrotreating is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

83. The process of any of claims 78 to 82, wherein the hydrotreatment is carried out with a non-sulfur catalyst.

84. The process of any of claims 78 to 83, wherein the hydrotreatment is carried out with a catalyst based on or reduced to alumina or silica.

85. The process of claim 84, wherein the catalyst is reduced NI / Al2O3.

86. The process of any of claims 46 to 85, wherein the synthetic jet fuel is a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination thereof.

87. The process of claim 86, wherein the synthetic jet fuel has a boiling point between approximately 140°C and approximately 260°C and a freezing point < -60°C.

88. A process for producing synthetic jet fuel, comprising pyrolyzing the feedstock to form a mixture comprising biocrude, the feedstock comprising biomass, organic materials, waste streams, or a combination thereof; gasifying the mixture comprising biocrude, the gasification comprising supercritical water gasification of the mixture comprising biocrude to form a mixture comprising CH4, CO, CO2, and H2; and reforming the mixture comprising CH4, CO, CO2, and H2 to form synthesis gas; converting the synthesis gas into a mixture comprising liquid hydrocarbons, comprising carrying out a Fischer-Tropsch synthesis to convert the synthesis gas into a mixture comprising liquid hydrocarbons; refining the mixture comprising liquid hydrocarbons to isolate a kerosene product,The refining comprises carrying out a vapor-liquid equilibrium separation of the mixture comprising liquid hydrocarbons and separating the mixtures into a kerosene product and at least one aqueous product, a naphtha and gas product, or a gas oil and a heavy product, wherein when an aqueous product is separated, the refining further comprises adding the separated aqueous product to the mixture comprising biocrude before gasification of the mixture comprising biocrude, when a naphtha and gas product is separated, the refining further comprises oligomerizing the naphtha and gas product to form a mixture comprising a first additional kerosene product, and when a gas oil and heavier product is separated,The refining further comprises hydrocracking the gas oil from the heavier product to form a mixture comprising a second additional kerosene product; and hydrotreating the kerosene product to form synthetic jet fuel having a boiling point between approximately 140°C and approximately 260°C and a freezing point < -60°C, and when a naphtha and gas product is separated, the hydrotreating further comprises hydrotreating the first additional kerosene product to form a mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising paraffinic hydrocarbons, and when a gas oil and heavier product is separated, the hydrotreating further comprises fractionating the mixture comprising the second additional kerosene product, to isolate the synthetic jet fuel.

89. The process of claim 88, wherein the pyrolysis of the raw material comprises: pyrolyzing the raw material under aqueous conditions, wherein the raw material comprises a high water content.

90. The process of claim 88, wherein the pyrolysis of the raw material comprises: pyrolyzing the raw material, wherein the raw material comprises a low water content.

91. The process of claim 88, wherein the reforming comprises dry reforming and steam reforming.

92. The process of any of claims 88 to 91, wherein, when the raw material is pyrolyzed, the process further comprises: adding an oil raw material, a sugar raw material, and / or an alcohol raw material to the mixture comprising biocrude prior to gasification.

93. The process of any of claims 88 to 92, wherein the synthesis gas comprises an H2 to CO ratio that is less than 2 to 1.

94. The process of any of claims 88 to 93, wherein the synthesis gas comprises a stoichiometric ratio of (H2 - CO2) / (CO + CO2) that is less than 2 to 1.

95. The process of any of claims 88 to 94, wherein the synthesis gas comprises a Ribblet ratio of (H2) / (2CO + 3CO2) that is less than 1 to 1.

96. The process of any of claims 88 to 95, wherein the Fischer-Tropsch synthesis is carried out with an iron-based catalyst.

97. The process of claim 96, wherein when the Fischer-Tropsch synthesis is carried out to convert the synthesis gas into a mixture comprising liquid hydrocarbons, the process further comprises: a water-gas swap reaction to increase the concentration of H2.

98. The process of any of claims 88 to 97, wherein the Fischer-Tropsch synthesis is carried out at a pressure of approximately 2 MPa; or approximately 2.5 MPa; or approximately 2.8 MPa.

99. The process of any of claims 88 to 97, wherein the Fischer-Tropsch synthesis is carried out at a pressure in the range of approximately 1.5 MPa to 5 MPa; or in the range of approximately 2 MPa to approximately 4 MPa; or in the range of approximately 2 MPa to approximately 3 MPa; or in the range of approximately 1.5 to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

100. The process of any of claims 88 to 97, wherein the Fischer-Tropsch synthesis is carried out at a pressure greater than 2 MPa.

101. The process of any of claims 88 to 100, wherein the mixture comprising liquid hydrocarbons comprises an alkene to alkane ratio greater than 1 to 1.

102. The process of any of claims 88 to 101, wherein the vapor-liquid equilibrium separation is carried out as a single-stage separation and / or a multi-stage separation.

103. The process of any of claims 88 to 102, wherein oligomerizing the naphtha and gas product is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

104. The process of any of claims 88 to 102, wherein oligomerizing the naphtha and gas product is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

105. The process of any of claims 88 to 104, wherein oligomerizing the naphtha and gas product is carried out with a non-sulfured catalyst.

106. The process of claim 105, wherein oligomerizing the naphtha and gas product is carried out with an acidic ZSM-5 zeolite catalyst.

107. The process of any of claims 88 to 106, wherein the first additional kerosene product comprises alkene and aromatic compounds.

108. The process of claim 107, wherein the first additional kerosene product comprises approximately 0% to approximately 60% aromatic compounds; approximately 1% to approximately 60% aromatic compounds; or approximately 1% to approximately 50% aromatic compounds; or approximately 1% to approximately 40% aromatic compounds; or approximately 1% to approximately 30% aromatic compounds; or approximately 0% to approximately 1% aromatic compounds; or approximately 1% to approximately 7% aromatic compounds; or approximately 8% to approximately 25% aromatic compounds; or approximately 8% aromatic compounds.

109. The process of any of claims 88 to 109, wherein the hydrocracking of the heavier product gas oil is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

110. The process of any of claims 88 to 109, wherein the hydrocracking of the heavier product gas oil is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

111. The process of any of claims 88 to 111, wherein the hydrocracking of the heavier product gas oil is carried out with a non-sulfured catalyst.

112. The process of any of claims 88 to 112, wherein the hydrocracking is carried out with a noble metal catalyst supported on amorphous silica-alumina.

113. The process of claim 113, wherein the catalysts are Pt / SiO2-Al2O3.

114. The process of any of claims 88 to 114, wherein, when fractionating the mixture comprising paraffinic hydrocarbons and fractionating the mixture comprising the second additional kerosene product, the process further comprises: adding the mixture comprising the second additional kerosene product to the mixture comprising paraffinic hydrocarbons prior to fractionation.

115. The process of any of claims 88 to 115, wherein each of the kerosene product, the first additional kerosene product, and the second additional kerosene product have a normal boiling point temperature range of approximately 140°C to approximately 300°C.

116. The process of any of claims 88 to 116, wherein the hydrotreating is carried out at a pressure of approximately 2.5 MPa; or approximately 2 MPa.

117. The process of any of claims 88 to 116, wherein the hydrotreating is carried out at a pressure in the range of approximately 1.5 MPa to 3 MPa; or in the range of approximately 1.5 MPa to approximately 2.5 MPa; or in the range of approximately 2 MPa to approximately 2.5 MPa.

118. The process of any of claims 88 to 118, wherein the hydrotreatment is carried out with a non-sulfur catalyst.

119. The process of any of claims 88 to 119, wherein the hydrotreatment is carried out with a catalyst based on or reduced on alumina or silica.

120. The process of claim 120, wherein the catalyst is reduced NI / Al2O3.

121. The process of any of claims 88 to 121, wherein the synthetic jet fuel is a semi-synthetic jet fuel, a fully synthetic jet fuel, or a combination thereof.