Process for producing jet fuel from biorenewable feedstocks

Abstract

This invention provides a method for producing diesel streams from biorenewable feedstocks by removing five heteroatoms through hydrotreating and improving cold flow properties through hydroisomerization. Heavy diesel can be hydrogenated and cracked into jet fuel-range materials or further hydroisomerized to increase its value and lower its pour point, while light diesel can be used as engine fuel.

Description

[0001] Priority Statement

[0002] This application claims priority to Indian Provisional Patent Application Serial No. 202011046430, filed on October 24, 2020, the entire contents of which are incorporated herein by reference.

[0003] The following description details the present invention and its embodiments. Technical Field

[0004] In this field, hydrocarbons used as aviation fuels are being produced from biorenewable feedstocks such as triglycerides and free fatty acids found in materials such as plant and animal fats and oils. Background Technology

[0005] With increasing global demand for fuels, the production of fuels from sources other than crude oil and the blending of components from sources other than crude oil are gaining increasing attention. These sources are often referred to as biorenewable sources and include, but are not limited to, vegetable oils such as corn oil, rapeseed oil, low-erucic acid rapeseed oil, and soybean oil; microbial oils such as algal oil; animal fats such as inedible tallow; fish oil; and various waste streams such as yellow and brown greases and sewage sludge. A common characteristic of these sources is that they consist of triglycerides and free fatty acids (FFAs). Both triglycerides and FFAs contain aliphatic carbon chains with 8 to 24 carbon atoms. The aliphatic carbon chains in triglycerides or FFAs can be fully saturated or mono, di, or polyunsaturated.

[0006] Hydrogenation can include methods of converting hydrocarbons into more valuable products in the presence of a hydrogenation catalyst and hydrogen. Hydrotreating is a method of contacting hydrocarbons with hydrogen in the presence of a hydrogenation catalyst, which is primarily used to remove heteroatoms such as sulfur, nitrogen, oxygen, and metals from hydrocarbon feedstocks. In hydrogenation, hydrocarbons with double and triple bonds, such as alkenes, can be saturated.

[0007] The production of hydrocarbon products within the boiling range of diesel can be achieved through hydrotreating biorenewable feedstocks. Hydrotreating can deoxygenate oxygenated hydrocarbons, including decarboxylation and decarbonylation. Following hydrotreating, hydroisomerization can be performed to improve the cold-flow properties of the resulting diesel and jet fuel. Hydroisomerization, or hydrodewaxing, is a hydrogenation process that increases alkyl branching on the hydrocarbon backbone in the presence of hydrogen and a hydroisomerization catalyst to improve the cold-flow properties of the hydrocarbon. Hydroisomerization includes the hydrodewaxing discussed herein.

[0008] Hydrocracking is a hydrogenation process in which hydrocarbons are broken down into lower molecular weight hydrocarbons in the presence of hydrogen and a hydrogenation catalyst. Depending on the desired output, a hydrogenation cracking unit may contain one or more identical or different catalyst beds.

[0009] As refineries seek to increase their capacity to process biorenewable feedstocks, they are looking for methods to produce larger volumes of jet fuel due to their high value and demand. Methods are needed for producing diesel fuel from biorenewable feedstocks and for increasing jet fuel production. Summary of the Invention

[0010] This method produces diesel streams from biorenewable feedstocks by removing heteroatoms through hydrotreating and improving cold stream properties through hydroisomerization. Heavy diesel can be hydrogenated and cracked into jet fuel range materials to increase its value, while light diesel can be used as engine fuel. Attached Figure Description

[0011] Figure 1 This is a simplified process flow diagram disclosed herein.

[0012] Figure 2 yes Figure 1 A simplified process flow diagram of the alternative implementation scheme.

[0013] Figure 3 yes Figure 1 or Figure 2 A simplified process flow diagram of another alternative implementation scheme.

[0014] Figure 4 yes Figure 2 A simplified process flow diagram of another alternative implementation scheme.

[0015] definition

[0016] The term "connectivity" means that material flow is operatively permitted between enumerated components.

[0017] The term "downstream connectivity" means that in downstream connectivity at least a portion of the material flowing toward the main body can be operatively flowed from the object with which it is connected.

[0018] The term "upstream connectivity" means that at least a portion of the material flowing out of the main body in an upstream connectivity can be operatively flowed to the object connected to it.

[0019] The term "direct connection" means that the flow from the upstream component enters the downstream component without passing through fractionation or conversion units, and the composition does not change due to physical fractionation or chemical conversion.

[0020] The term "indirect connection" means that the flow from the upstream component enters the downstream component after passing through the fractionation or conversion unit, and the composition changes due to physical fractionation or chemical conversion.

[0021] The term "bypass" means that an object loses downstream connectivity with the bypassed entity, at least within the scope of the bypass.

[0022] The term "tower" refers to one or more distillation columns used to separate one or more components with different volatility. Unless otherwise specified, each column includes a condenser at the top of the column for condensing a portion of the overhead feed and refluxing it back to the top of the column, and a reboiler at the bottom of the column for vaporizing a portion of the bottom feed and returning it to the bottom of the column. The feed to the column may be preheated. Top pressure is the pressure of the vapor at the top of the column at the vapor outlet. Bottom temperature is the liquid temperature at the bottom outlet of the column. Top and bottom lines refer to the net lines from any downstream reflux or reboiler to the column. Stripping columns may omit the reboiler at the bottom of the column and instead provide the heating requirements and separation power for liquefied inert media such as steam. Stripping columns typically feed from the top tray and remove the main product from the bottom.

[0023] As used herein, the term "rich component stream" refers to a rich stream exiting a container with a higher component concentration than the feed into the container.

[0024] As used herein, the term "lean stream" refers to a lean stream exiting a container with a lower component concentration than the feed into the container.

[0025] As used herein, the term “boiling point temperature” refers to the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling temperature and distillation pressure, as provided in ASTM D86 or ASTM D2887.

[0026] As used herein, the term “true boiling point” (TBP) refers to a test method conforming to ASTM D-2892 for determining the boiling point of a substance. ASTM D-2892 is used to produce standardized masses of liquefied gases, distillate fractions, and residues for which analytical data are available, and to determine the yield of the aforementioned fractions by both mass and volume, based on which a graph of distillation temperature versus mass% is obtained using fifteen theoretical plates in a column with a reflux ratio of 5:1.

[0027] As used herein, the terms “T5” or “T95” refer to the boiling temperature of a 5% or 95% mass percentage sample obtained using ASTM D-86 or TBP (as applicable).

[0028] As used herein, the term “initial boiling point” (IBP) refers to the temperature at which a sample begins to boil, as determined using ASTM D2887, ASTM D-86, or TBP (as applicable).

[0029] As used herein, the term “endpoint” (EP) refers to the temperature at which a sample, obtained using ASTM D2887, ASTM D-86, or TBP (as applicable), reaches complete boiling.

[0030] As used herein, the term “diesel boiling range” means, using the TBP distillation method, that the hydrocarbon boils in the range of IBP between 125°C (257°F) and 175°C (347°F), or between 150°C (302°F) and 200°C (392°F), and “diesel fractionation point” includes T95 between 343°C (650°F) and 399°C (750°F).

[0031] As used herein, the term "diesel conversion rate" refers to the rate of conversion of feedstock above the diesel fractionation point boiling point into a material with a diesel fractionation point boiling point equal to or below the diesel boiling point range.

[0032] As used herein, the term "separator" refers to a vessel having an inlet and at least one overhead vapor outlet and a bottom liquid outlet, and may also have an outlet for a water-containing feed stream from a boot. A flash tank is a type of separator that can be connected downstream to a separator that can operate at higher pressures.

[0033] As used herein, the terms “major” or “most” mean greater than 50%, suitably greater than 75%, and preferably greater than 90%.

[0034] As used in this article, the term "C" x "This should be understood as referring to a molecule having the number of carbon atoms indicated by the subscript "x". Similarly, the term "C" x "-" refers to a molecule containing x carbon atoms or less, and preferably x and fewer. The term "C" x "+" refers to a molecule that has x or more carbon atoms, and preferably x and more.

[0035] As used in this article, the term "carbon number" refers to the number of carbon atoms in each hydrocarbon molecule, and typically in alkane molecules. Detailed Implementation

[0036] With increasing emphasis on the environment and a sustainable economy, it is becoming increasingly attractive for refineries to produce green fuels from Renewable Identifiers (RINs) accounted for according to the Renewable Fuels Standard Procedure as part of their portfolios to maximize profitability. RINs are credits used for compliance and can be traded within the procedure to enhance profitability. This disclosure enables refineries to maximize jet fuel yields from biorenewable sources and provides the flexibility to optimize jet fuel production relative to diesel fuel production in response to market demand.

[0037] exist Figure 1 In this example embodiment, a process 10 for processing biorenewable feedstock is shown. A feed line 12 delivers a feed stream of fresh biorenewable feedstock to a feed buffer tank 14. The biorenewable feedstock may be mixed with a mineral feed stream, but preferably comprises the primary biorenewable feedstock. The mineral feedstock is a conventional feedstock derived from crude oil extracted from underground. The biorenewable feedstock may contain a nitrogen concentration of 50 wppm to 800 wppm. The biorenewable feedstock may contain a high oxygen content of up to 10% by weight or higher. The biorenewable feedstock may also contain sulfur of 1 wppm to 500 wppm, typically not exceeding 200 wppm.

[0038] Various biorenewable feedstocks are applicable to Method 10. The term "biorenewable feedstock" is intended to include feedstocks other than those derived from crude oil. Biorenewable feedstocks may include any of those feedstocks containing at least one of glycerides and free fatty acids. Most glycerides are triglycerides, but monoglycerides and diglycerides may also be present and processed. Free fatty acids may be obtained from phospholipids, which can provide phosphorus in the feedstock. Examples of such biorenewable feedstocks include, but are not limited to, linseed oil, low-erucic acid rapeseed oil, corn oil, soybean oil, rapeseed oil, soybean oil, rapeseed oil, tallow, sunflower oil, hemp seed oil, olive oil, linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard oil, tallow, yellow and brown fats, lard, whale oil, fats in milk, fish oil, algal oil, sewage sludge, etc. Additional examples of biorenewable feedstocks include non-edible vegetable oils from the group comprising: Jatropha curcas (Ratanjot, Wild Castor, Jangli Erandi), Madhuca indica (Mohuwa), Pongamia pinnata (Karanji, Honge), Calophyllum inophyllum, Moringa oleifera, and Azadirachta indica (Neem). Typical plant or animal fats, including triglycerides and FFAs, contain aliphatic hydrocarbon chains with 8 to 30 carbon atoms in their structures. As will be understood, biorenewable feedstocks may include mixtures of one or more of the foregoing examples. Biorenewable feedstocks may be pretreated to remove contaminants and filtered to remove solids.

[0039] The biorenewable feed stream in feed line 12 flows from feed buffer tank 14 via a feed pump and is mixed with the hot recirculated stream in recirculation line 16 and the recirculated hydrotreated hydrogen stream in hydrotreated hydrogen line 20 to provide a combined biorenewable feed stream. The recirculation feed ratio can be from 2:1 to 5:1. The combined biorenewable feed stream 12 can be heated in combined feed exchanger 22 by heat exchange with the hydrotreated feed stream in hydrotreated line 42. The heated combined biorenewable feed stream in combined feed line 24 can then be fed into hydrotreated reactor section 25.

[0040] The hydrotreating reactor section 25 may include a guard bed reactor 26. The guard bed temperature may range between 246°C (475°F) and 343°C (650°F), and suitably between 288°C (550°F) and 304°C (580°F). The reaction temperature is low enough to prevent olefin polymerization in the FFA, but high enough to promote olefin saturation, hydrodemetallization, hydrodeoxygenation (including hydrodecarbonylation and hydrodecarboxylation), hydrodesulfurization, and hydrodenitrogenation reactions.

[0041] The guard bed may contain a base metal on a support. Base metals that can be used in this process include non-precious metals, nickel, chromium, molybdenum, and tungsten. Other base metals that can be used include tin, indium, germanium, lead, cobalt, gallium, and zinc. The process may also use metal sulfides, wherein the metal in the metal sulfide is selected from one or more of the listed base metals. Biorenewable feedstock may be loaded through a base metal catalyst at a pressure of 1379 kPa (abs) (200 psia) to 6895 kPa (abs) (1000 psia). In another embodiment, the guard bed catalyst may contain a second metal, wherein the second metal includes one or more of the following metals: tin, indium, ruthenium, rhodium, rhenium, osmium, iridium, germanium, lead, cobalt, gallium, zinc, and thallium. An alumina-supported nickel-molybdenum catalyst may be a suitable catalyst in the guard bed reactor 26. Multiple guard beds may be included in the guard bed reactor 26, such as two, three, or more, and hydrogen quenching from hydrogen quenching line 18 may be injected at an interbed location to control the exothermic temperature.

[0042] The biorenewable feed stream from the contact feed line 32 exits from the guard bed reactor 26. In the guard bed reactor 26, most of the hydrodemetallization and hydrodeoxygenation (including hydrodecarbonylation and hydrodecarboxylation) reactions occur along with some hydrodenitrogenation and hydrodesulfurization. The removed metals include alkali metals, alkaline earth metals, and phosphorus.

[0043] The contact biorenewable feed stream can be heated in the protective bed exhaust heat exchanger 34 by heat exchange with the hydrotreatment feed stream in the hydrotreatment line 42 to increase the temperature of the contact biorenewable feed stream. Furthermore, the contact biorenewable feed stream can be further heated in the feed heater 36, which can be a flame heater, to increase the temperature of the contact biorenewable feed stream. The hydrotreatment reactor section 25 may also include a hydrotreatment reactor 44. The heated, contact biorenewable feed stream is fed into the hydrotreatment reactor 44 of the hydrotreatment reactor section 25.

[0044] In hydrotreating reactor 44, under hydrotreating conditions, a heated, contacting biorenewable feed stream is brought into contact with a hydrotreating catalyst in the presence of hydrogen to saturate the olefins or unsaturated portions of the positive-chain alkane chains in the biorenewable feedstock. The hydrotreating catalyst also catalyzes hydrodeoxygenation reactions, including hydrodecarboxylation and hydrodecarbonylation, to remove oxygen-containing functional groups from hydrocarbon molecules in the biorenewable feedstock, which are then converted into water and carbon oxides. The hydrotreating catalyst also catalyzes the hydrodesulfurization of organic sulfur and the hydrodenitrification of organic nitrogen in the biorenewable feedstock. Essentially, the hydrotreating reaction removes heteroatoms from hydrocarbons and saturates the olefins in the feed stream.

[0045] The hydrotreating catalyst can be provided in one, two or more beds, and an interbed hydrogen quenching flow is used from the hydrogen quenching flow from hydrogen quenching line 18. Figure 1 Two hydrotreating catalyst beds are shown, but one or more are considered.

[0046] Hydrotreating catalysts may include nickel, nickel / molybdenum, or cobalt / molybdenum dispersed on a high surface area support, such as alumina. Other catalysts include one or more noble metals dispersed on a high surface area support. Non-limiting examples of noble metals include platinum and / or palladium dispersed on an alumina support such as γ-alumina. Suitable hydrotreating catalysts include BDO 200 or BDO 300, available from UOP LLC of Des Plaines, Illinois. The hydrotreating reaction temperature may range between 343°C (650°F) and 427°C (800°F), and preferably between 349°C (690°F) and 400°C (752°F). Typically, hydrotreating conditions include pressures from 700 kPa (100 psig) to 21 MPa (3000 psig).

[0047] A hydrotreated feed stream comprising a hydrocarbon fraction with a significant concentration of n-alkane is produced in the hydrotreated line 42 of the hydrotreated reactor 44 in hydrotreated reactor section 25. The concentration of oxygenated compounds in the hydrocarbon fraction is essentially zero, while the olefin concentration is significantly reduced relative to the contacting biorenewable feed stream. The concentration of organic sulfur in the hydrocarbon fraction does not exceed 500 W ppm, and the concentration of organic nitrogen in the hydrocarbon fraction is less than 10 W ppm.

[0048] The hydrotreating feed stream in hydrotreating line 42 may first flow to combined isomerization feed exchanger 46 to heat and cool the hydrotreating feed stream in hydroisomerization feed line 90. As previously described, the cooled hydrotreating feed stream in hydrotreating line 42 may then exchange heat with the contacting bioregenerative feed stream in guard bed exhaust heat exchanger 34 to cool the hydrotreating feed stream in hydrotreating line 42 and heat the contacting bioregenerative feed stream in contact line 32. The hydrotreating vapor, which has been cooled twice in hydrotreating line 42, may then be further cooled in combined feed exchanger 22 by heat exchange with the combined bioregenerative feed stream in combined feed line 24 to heat the combined bioregenerative feed stream and cool the hydrotreating feed stream in hydrotreating line 42. The tertiary-cooled hydrotreating stream can even be further cooled, perhaps to produce steam, before separating it into a vapor stream for hydrotreating and a liquid stream for hydrotreating with a lower oxygen concentration than the bioregenerable feed stream.

[0049] The hydrotreating feed stream can be separated in a thermal separator 48 to provide a hydrocarbon-containing hot vapor stream in the thermal separator top line 50 and a hydrocarbon-containing hot liquid stream in the thermal separator bottom line 52. The thermal separator 48 can be connected downstream of the hydrotreating reactor 44. The thermal separator 48 operates at 177°C (350°F) to 371°C (700°F), and preferably at 232°C (450°F) to 315°C (600°F). The thermal separator 34 can operate at a pressure slightly lower than that of the hydrotreating reactor 44, which causes a pressure drop through the intervention equipment. The thermal separator 48 can operate at a pressure between 3.4 MPa (gauge pressure) (493 psig) and 20.4 MPa (gauge pressure) (2959 psig). The temperature of the hot vapor stream in the thermal separator top line 50 can be the operating temperature of the thermal separator 48.

[0050] The hot liquid flow in the bottom line 52 of the thermal separator can be divided into two flows: a hot process liquid flow in the process line 54, which is drawn from the hot liquid flow in the bottom line 52, and a hot recirculation liquid flow in the recirculation line 16, which is also drawn from the hot liquid flow in the bottom line 52. The hot recirculation liquid flow in the recirculation line 16 can be combined with the biorecyclable feed flow in line 12, as previously described.

[0051] The hot process liquid stream drawn from process line 54 can be further separated in a hydrotreatment separator 56, which may include an enhanced thermal separator (EHS) using stripping gas fed from isomerization tower overhead line 58. The hot process liquid stream is separated to provide a vapor stream and a liquid stream for hydrotreatment. Hydrotreatment separator 56 may be a high-pressure stripping tower. In hydrotreatment separator 56, the hot process liquid stream from process line 54 flows downward through the tower, where it is partially stripped of hydrogen, carbon dioxide, carbon monoxide, water vapor, propane, hydrogen sulfide, and phosphine—potential isomerization catalyst poisons—through contact with stripping gas from isomerization tower overhead line 58. The stripping gas may contain supplemental hydrogen already passed through isomerization reactor 74 and isomerization separator 80, as described below.

[0052] The stripping gas in isomerization tower top line 58 enters hydrotreating separator 56 below the inlet of the hot process liquid stream in process liquid line 54. Hydrotreating separator 56 may include internal components such as trays or packing located between the inlet of the hot process liquid stream in process liquid line 54 and the inlet of the stripping gas in isomerization tower top line 58 to facilitate stripping of the hot process liquid stream in process line 54. The stripping gas, including the stripped gas, exits as a hydrotreated vapor stream in hydrotreating tower top line 60 extending from the top of hydrotreating separator 56 and mixes with the hot vapor stream in hot tower top line 50, the isomerized liquid stream in isomerization tower bottom line 82, and optionally, the cold water stream in cold water line 87 from the cold separator reservoir and the hydrocracking liquid stream in line 186 to provide a cold separator feed stream in cold feed line 84.

[0053] The hydrotreated liquid stream, which may have been stripped, is collected at the bottom of the hydrotreatment separator 56 and flows in the hydrotreatment bottom line 62 to the suction side of the bottom pump. The hydrotreated liquid stream contains diesel-based materials and has a high alkanes concentration due to the composition of the biorenewable feedstock.

[0054] Although the hot liquid stream, containing a high concentration of n-alkanes, can provide the desired products (such as transport fuels) in the bottom line 62 of the hydrotreating tower, it will have poor cold flow properties. Therefore, to improve the cold flow properties, the hydrotreating liquid stream can be contacted with a hydroisomerization catalyst in a hydroisomerization reactor 74 under hydroisomerization conditions to hydroisomerize n-alkanes into branched alkanes.

[0055] The hydrotreated liquid stream can be hydroisomerized via a hydroisomerization catalyst in the presence of a hydroisomerization hydrogen stream. Supplemental hydrogen in supplemental line 86 can be compressed in supplemental gas compressor 88 and mixed with the hydrotreated liquid stream pumped from hydrotreated bottom line 62 to provide a hydroisomerization feed stream in hydroisomerization feed line 90. The hydroisomerization feed stream in hydroisomerization feed line 90 can be heated in isomerization feed exchanger 46 by heat exchange with the hydrotreated feed stream in hydrotreated line 42. The heated hydroisomerization feed stream can optionally be mixed with either the total hydrocracking feed stream or the liquid hydrocracking feed stream in recirculation line 98 to provide a combined hydroisomerization feed stream in combined hydroisomerization feed line 100. The combined hydroisomerization feed stream can be heated in the hydroisomerization feed heater 72 to bring it to the hydroisomerization temperature, and then the combined hydroisomerization feed stream is fed into the hydroisomerization reactor 74.

[0056] Hydroisomerization (including hydrodewaxing) of n-hydrocarbons in hydroisomerization reactor 74 can be accomplished via one or more hydroisomerization catalyst beds, and hydroisomerization can be operated in a co-current mode. Fixed bed, trickle-down, or fixed bed liquid-immersion upflow modes are all suitable. A supplementary hydrogen quenching stream from supplementary line 86 can be provided to hydroisomerization reactor 74 for inter-bed quenching.

[0057] Suitable hydroisomerization catalysts may include metals from Group VIII of the periodic table (IUPAC 8-10) and support materials. Suitable Group VIII metals include platinum and palladium, each of which may be used alone or in combination. If the hydroisomerization catalyst is located in a hydrotreatment reactor, such as Figure 3 As shown, non-noble metals that are not prone to sulfur deactivation in acidic environments should be used. Examples of suitable non-noble metals include Ni, Mo, Co, W, Mn, Cu, Zn, or Ru. Mixtures of metal hydrides, such as Co / Mo, Ni / Mo, and Ni / W, can also be used. The amount of one or more metal hydrides can range from 0.1% to 5% by weight based on the catalyst weight. Methods for loading the metal onto the support material include, for example, impregnating the support material with a metal salt of the hydride component and heating. Catalyst support materials containing metal hydrides can also be sulfided before use.

[0058] The support material can be amorphous or crystalline. Suitable support materials include amorphous alumina, amorphous silica-alumina, magnesium alkali zeolite, ALPO-31, SAPO-11, SAPO-31, SAPO-37, SAPO-41, SM-3, MgAPSO-31, FU-9, NU-10, NU-23, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, ZSM-50, ZSM-57, MeAPO-11, MeAPO- 31. MeAPO-41, MgAPSO-11, MgAPSO-31, MgAPSO-41, MgAPSO-46, ELAPO-11, ELAPO-31, ELAPO-41, ELAPO-11, ELAPO-31, ELAPO-11, ELAPO-31, ELAPO-41, zeolite, nepheline, pyroxene, zeolite in hydrogen form, mordenite in magnesium or calcium form, and calcite in magnesium or calcium form, each of which may be used alone or in combination. ALPO-31 is described in US4,310,440. SAPO-11, SAPO-31, SAPO-37, and SAPO-41 are described in US4,440,871. SM-3 is described in US4,943,424, US5,087,347, US5,158,665, and US5,208,005. MgAPSO is MeAPSO, an acronym for metallic aluminum phosphosilicate molecular sieves, where the metallic Me is magnesium (Mg). Suitable MgAPSO-31 catalysts include MgAPSO-31. MeAPSO is described in US 4,793,984, while MgAPSO is described in US 4,758,419. MgAPSO-31 is the preferred MgAPSO, where 31 refers to MgAPSO having a structural type of 31. Many natural zeolites initially having reduced pore size (such as magnesium alkali zeolite) can be converted to forms suitable for olefin skeletal isomerization to produce essentially hydrogen forms by ammonium ion exchange and calcination to remove the associated alkali or alkaline earth metals, as taught in US 4,795,623 and US 4,924,027. Other catalysts and conditions for skeletal isomerization are disclosed in US 5,510,306, US 5,082,956 and US 5,741,759. The hydroisomerization catalyst may also include a modifier selected from lanthanum, cerium, praseodymium, neodymium, samarium, gadolinium, terbium, and mixtures thereof, as described in US5,716,897 and US5,851,949.Other suitable support materials include ZSM-22, ZSM-23, and ZSM-35, which are described for dewaxing in US 5,246,566 and in the article “New Molecular Sieve Process for Lube Dewaxing by Wax Isomerization,” 2 Microporous Materials, pp. 439-449 (1994) by SJ Miller. US 5,444,032 and US 5,608,968 teach suitable bifunctional catalysts composed of amorphous silica-alumina gel and one or more metals belonging to Group VIIIA, and are effective for the hydroisomerization of long-chain n-alkanes containing more than 15 carbon atoms. US5,981,419 and US5,908,134 teach a suitable bifunctional catalyst comprising: (a) a porous crystalline material isomorphous to a β-zeolite selected from borosilicates (BOR-B) and borosilicates (Al-BOR-B), wherein the molar ratio of SiO2:Al2O3 is greater than 300:1; and (b) one or more metals belonging to Group VIIIA, selected from platinum and palladium, in an amount ranging from 0.05 wt% to 5 wt%. V. Calemma et al., Applied Catalysis A: Overview (App. Catal. A: Gen.), 190 (2000), 207, teach another suitable catalyst. Alumina or silica can be added to the support material.

[0059] DI-100, available from UOP LLC in Des Plaines, Illinois, is a suitable hydroisomerization catalyst.

[0060] Hydroisomerization conditions typically include temperatures ranging from 150°C (302°F) to 450°C (842°F) and pressures ranging from 1724 kPa (abs) (250 psia) to 13.8 MPa (abs) (2000 psia). In another embodiment, hydroisomerization conditions include temperatures ranging from 300°C (572°F) to 360°C (680°F) and pressures ranging from 3102 kPa (abs) (450 psia) to 6895 kPa (abs) (1000 psia).

[0061] The hydroisomerization stream in the hydroisomerization line 76 from the isomerization reactor 74 is a branched-chain alkanes-rich stream. The term "rich" means that the effluent has a higher concentration of branched-chain alkanes than the stream entering the isomerization reactor 74, and preferably contains more than 50% by mass of branched-chain alkanes in total alkane content. It is envisioned that the hydroisomerization effluent may contain 80%, 90%, or 95% by mass of branched-chain alkanes in total alkane content. The hydroisomerization conditions in the hydroisomerization reactor 74 are selected to avoid undesirable cracking, so that the major product in the hydroisomerization stream in the hydroisomerization line 76 is branched-chain alkanes. By avoiding undesirable cracking, the hydroisomerization stream in the hydroisomerization line 76 will have a higher C9+ hydrocarbon yield for the production of jet fuel or diesel fuel. The optimal amount of residual n-chain alkanes in line 76 depends on the selectivity of the hydroisomerization catalyst, but is typically between 1% and 7% by mass.

[0062] The hydroisomerized feed stream from the hydroisomerization line 76 of the isomerization reactor 74 flows to the isomer exchanger 77 to exchange heat with the cold liquid stream in the cold bottom line 92, cooling it before it enters the hydroisomerization separator 80 to be separated into a liquid hydroisomerized feed stream and a vapor hydroisomerized feed stream. The vapor hydroisomerized feed stream from the hydroisomerization top line 58 extending from the top of the hydroisomerization separator 80 flows to the hydrotreatment separator 56 and can be used as stripping gas in the hydrotreatment separator 56. A portion of the vapor hydroisomerized feed stream may optionally bypass the hydrotreatment separator 56 and enter the cold feed line 84 via a control valve.

[0063] The liquid hydroisomerization feed stream from the bottom of the hydroisomerization separator 80, extending into the bottom line 82, can be directly fed into the distillation column 140 for the production product stream without condensation and cooling. However, the liquid hydroisomerization feed stream from the hydroisomerization separator 80 in the bottom line 82 can be further separated in the cold separator 94 along with the hot vapor stream from the hot column top line 50, the hydrotreatment vapor stream from the hydrotreatment column top line 60, the cold water stream from the cold water line 87 of the cold separator 94's storage tank, and the liquid hydrocracking feed stream from the bottom line 186 of the hydrocracking separator. All of these are combined into a cold separator feed stream in the cold separator feed line 84. The cold water stream from the cold water line 87, supplemented with water from line 85, is added to the cold separator feed line 84 to dissolve any salts that may be present in the hydrocarbon phase.

[0064] The cold separator feed stream in the cold separator feed line 84 is cooled and fed into the cold separator 94.

[0065] In the cold separator 94, the vapor component in the hydroisomerization liquid stream is separated from and rises from the hydrotreatment vapor stream from the hydrotreatment tower overhead line 60 and the hot vapor stream from the hot tower overhead line 50 to provide a cold vapor stream in the cold tower overhead line 96. The cold vapor stream in the cold tower overhead line 96 can be passed through a tray or packed recirculation scrubber 104, where the cold vapor stream is scrubbed with a scrubbing liquid (such as an aqueous solution) fed through the scrubbing liquid line 102 to remove the acidic gases by extracting the acidic gases containing hydrogen sulfide and carbon dioxide into the aqueous solution. Preferred scrubbing liquids include Selexol. TM The scrubbing liquid is purchased from UOP LLC in Des Plaines, Illinois, and contains amines such as alkanolamines, including diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), diisopropanolamine (DIPA), and diethylene glycolamine (DGA). Other scrubbing liquids may be used instead of the preferred amines. The lean scrubbing liquid is contacted with a cold vapor stream and absorbs acidic gaseous contaminants such as hydrogen sulfide and carbon dioxide. The resulting “warmed” cold vapor stream is withdrawn from the top outlet of the recirculating scrubber tower 104 in recirculating scrubber tower top line 106, and the rich scrubbing liquid is withdrawn from the bottom outlet of the recirculating scrubber tower 104 in recirculating scrubber tower bottom line 108. The used scrubbing liquid from the bottom of the tower can be regenerated in scrubbing liquid line 102 and recycled back to the recirculating scrubber tower 104.

[0066] The washed hydrogen-rich stream is discharged from the scrubber via recirculation scrubber top line 106 and can be compressed in recirculation compressor 110. The compressed hydrogen stream in scrubber top line 106 supplies hydrogen to the hydrotreatment hydrogen stream in hydrotreatment hydrogen line 20, the interbed quenching stream through quenching line 18 for protecting bed reactor 26 and hydrotreatment reactor 44, and the hydrocracking hydrogen stream in line 152 for the hydrocracking reactor.

[0067] The recirculating scrubbing tower 104 can operate at a gas inlet temperature between 38°C (100℉) and 66°C (150℉) and a tower top pressure between 3 MPa (gauge pressure) (435 psig) and 20 MPa (gauge pressure) (2900 psig). Suitably, the recirculating scrubbing tower 104 can operate at a temperature between 40°C (104℉) and 125°C (257℉) and a pressure between 1200 kPa and 1600 kPa. The temperature of the hot vapor stream entering the recirculating scrubbing tower 104 can be between 20°C (68℉) and 80°C (176℉), and the temperature of the scrubbing liquid stream in the scrubbing liquid line 102 can be between 20°C (68℉) and 70°C (158℉).

[0068] The liquid components from the liquid hydrocracking feed stream in line 186 enter the cold liquid stream in the cold tower bottom line 92 under gravity. The cold liquid stream in the cold tower bottom line 92 contains hydrocarbons that can be used as fuels in the diesel boiling range, as well as other hydrocarbons such as propane, naphtha, and jet fuel. Therefore, they can be fractionated in distillation column 140. The cold water stream can be collected from the storage tank of the cold separator in the cold water line 87.

[0069] In one embodiment, the cold liquid stream may first be stripped in stripping tower 120 to remove hydrogen sulfide and other gases. The cold liquid stream in the cold tower bottom line 92 may be heated by heat exchange with the hydroisomerization stream in the hydroisomerization line 76 in the isomer exchanger 77, thereby heating the cold liquid stream and feeding it into stripping tower 120 through an inlet that can be located at the bottom half of the tower. An inert stripping medium, such as steam, from the stripping medium line 122 may be used to strip light gases from the cold tower bottom line 92. Stripping tower 120 provides an overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases in stripping tower top line 126 and a stripping liquid isomerization stream in stripping tower bottom line 128. The overhead stripping stream may be condensed and separated in stripping receiver 130. The top line 132 of the clean stripper from receiver 130 can deliver the clean stripper gas stream to sponge absorber 160 for LPG recovery. Unstabilized liquid naphtha from the bottom of receiver 130 in the liquid overhead stream can be delivered to butanizer 170 in stripper receiver bottom line 134 for naphtha and LPG recovery. Acidic water stream can be collected from the storage tank of top receiver 130.

[0070] The stripping column 120 can operate at a bottom temperature between 149°C (300℉) and 288°C (550℉), preferably not exceeding 260°C (500℉), and a top pressure of 0.35 MPa (gauge pressure) (50 psig), preferably not less than 0.70 MPa (gauge pressure) (100 psig) and not more than 2.0 MPa (gauge pressure) (290 psig). The temperature in the top receiver 130 is in the range of 38°C (100℉) to 66°C (150℉), and the pressure is substantially the same as the top pressure of the stripping column 120.

[0071] The liquid hydroisomerized feed stripped from the bottom line 128 of the stripping column can be fed into the distillation column 140. The distillation column 140 can be reboiled to provide the heat required for distillation by heat exchange with a suitable heat flow or in a flame heater. Alternatively, the column can be heated using a stripping medium, such as steam, as an inert gas from the stripping medium line 142. The distillation column 140 provides a top gaseous stream of naphtha and steam in the top line 146 and a bottom liquid stream in the bottom line 148. The top stream can be completely condensed and separated from water in the distillation receiver 178. The unstabilized liquid naphtha from the bottom of receiver 178 in the top liquid line 154 can be combined with the naphtha stream in line 176. Acidic water can be collected from the storage tank of the distillation receiver 178.

[0072] Two product streams can be drawn from the side of distillation column 140. The first side stream, obtained above the first side stream, can be obtained in the first side line 144, which contains a jet fuel stream of T5 with a temperature of 115°C (239℉) to 130°C (266℉) and T90 with a temperature of 240°C (464℉) to 270°C (518℉). The jet fuel will conform to ASTM D7566 jet fuel specifications. The second side stream in the second side line 152 can contain a light diesel oil stream of T5 with a temperature of 230°C (446℉) to 250°C (482℉) and T90 with a temperature of 279°C (560℉) to 296°C (590℉). The distillation column bottom liquid flow in distillation column bottom line 148 can be a heavy diesel oil flow of T5 with a temperature of 279°C (560°F) to 296°C (590°F) and T90 with a temperature of 343°C (650°F) to 399°C (750°F). Both side flows can be stripped in a side stripping column (not shown).

[0073] N-alkanes will be concentrated in the heavier hydrocarbon stream. Distilling the jet fuel in the first side stream and even the light diesel in the second side stream will highly enrich the N-alkanes in the heavy diesel stream in stripping tower bottom line 148, thus giving both the jet fuel stream and the light diesel stream acceptable N-alkanes concentrations, allowing the jet fuel stream to meet jet fuel specifications. The heavy diesel stream in distillation tower bottom line 148 with increased N-alkanes concentration can then undergo further hydroisomerization via recirculation or hydrocracking in a hydrocracking reactor to further control the N-alkanes concentration. Enriching the N-alkanes concentration in hydrocracking reactor 150 increases conversion by increasing the reaction rate. Higher N-alkanes concentrations also cause the reaction in hydroisomerization reactor 74 to deviate further from equilibrium, promoting the production of more isoalkanes. In one aspect, the concentration of n-alkane in the jet fuel stream in the first side line 144 may not exceed 1% by mass of the total alkane content of the jet fuel stream in line 144, suitably less than 0.6% by mass and preferably not more than 0.5% by mass. A preferred paraffin concentration satisfies a freezing point of -40°C.

[0074] In one respect, the concentration of n-alkanes with a given number of carbon atoms in the distillate bottoms line 148 should be at least twice, but more preferably at least three times, the concentration in the hydroisomerization feed in the hydroisomerization line 76. This enrichment is needed to promote more selective hydrocracking of n-alkanes in the hydrocracking reactor 150 into jet fuel and diesel range products and / or to promote selective hydroisomerization of n-alkanes in the hydroisomerization reactor 74, thereby increasing jet fuel yield.

[0075] Distillation column 140 can operate at a bottom temperature between 149°C (300℉) and 288°C (550℉), preferably not exceeding 260°C (500℉), and a top pressure of 0.35 MPa (gauge pressure) (50 psig), preferably not less than 0.70 MPa (gauge pressure) (100 psig) and not more than 2.0 MPa (gauge pressure) (290 psig). The temperature in the top receiver 178 is in the range of 38°C (100℉) to 66°C (150℉), and the pressure is substantially the same as the top pressure of stripping column 140.

[0076] The sponge absorber 160 can receive the gaseous feed stream from the clean stripper top line 132. The lean absorbent stream from the lean absorbent line 162 can be fed into the sponge absorber 160 through the absorption inlet. The lean absorbent may include the naphtha stream from the lean absorbent line 162, possibly originating from the butanizer bottom stream in line 176. In the sponge absorber 160, the lean absorbent stream comes into countercurrent contact with the clean stripper gaseous feed stream. The sponge absorbent draws LPG hydrocarbons from the clean stripper gaseous feed stream into the absorbent-rich stream.

[0077] The hydrocarbons absorbed by the sponge absorbent include some methane and ethane, as well as most LPG, C3 and C4 hydrocarbons, and any C5 and C4 hydrocarbons in the gaseous stream of the clean stripping tower. 6+ Light naphtha hydrocarbons. The sponge absorber 160 operates at a temperature of 34°C (93℉) to 60°C (140℉) and at a pressure substantially the same as or lower than that of the stripper receiver 130, thereby reducing frictional losses. The sponge absorber waste gas stream, depleted of LPG hydrocarbons, is discharged from the top of the sponge absorber 160 at the top outlet via the sponge absorber top line 164. The sponge absorber waste gas stream in the sponge absorber top line 164 can be fed to a hydrogen recovery unit (not shown) for hydrogen recovery. The LPG-rich absorbent stream is discharged from the bottom of the sponge absorber 160 at the bottom outlet via the rich absorber bottom line 166, and can be fed to the stripper liquid overhead stream in the stripper receiver bottom line 134 to the butane remover 170.

[0078] In one embodiment, the butanizer 170 can fractionate the liquid overhead stream from the stripper and the absorbent-rich stream in the bottom line 134 of the stripper receiver into a product mainly containing C. 5+ The debutanizer includes a bottom stream of hydrocarbons and an overhead stream containing LPG hydrocarbons. The overhead stream in debutanizer overhead line 172 can be completely condensed by reflux to debutanizer 170 and recovery of LPG in the overhead liquid stream in the net receiver bottom line 174. The bottom stream can be discharged from the bottom of debutanizer 170 in debutanizer bottom line 176. The reboiler stream taken from the bottom of debutanizer 170 or the bottom stream in debutanizer bottom line 176 can be boiled in a reboiler line and returned to debutanizer 170 to provide heat to the column. Alternatively, a thermally inert medium stream, such as steam, can be fed to column 170 to provide heat.

[0079] The distillation column bottom feed in distillation column bottom line 148 may contain hydrocarbons within the boiling range of heavy diesel. Because n-alkanes are concentrated in the bottom feed, it is well-suited for hydrocracking or further hydroisomerization. Refineries may wish to convert heavy diesel into jet fuel to improve product composition. Therefore, the heavy diesel stream in distillation column bottom line 148 can be mixed with a hydrocracking hydrogen stream taken from the compressed makeup hydrogen stream in line 86 in line 152, heated in heater 154, and fed into hydrocracking reactor 150 in line 156.

[0080] Using hydroisomerization, distillation, and hydrocracking together offers unique advantages. For example, a hydroisomerization feed stream may require a specification of no more than 0.8% n-alkanes of sixteen carbon atoms relative to all sixteen-carbon alkanes to meet jet freezing point specifications. However, to achieve this specification solely in the hydroisomerization reactor 74, the hydroisomerization feed stream may only produce 85% of the hydrocarbons in the jet fuel range due to parallel, undesirable hydrocracking reactions in the hydroisomerization reactor caused by operating the hydroisomerization reactor 74 at elevated temperatures and residence times necessary to achieve adequate conversion of n-alkanes of sixteen carbon atoms to such low concentrations. According to this disclosure, by relaxing its specifications by increasing the n-alkanes of sixteen carbon atoms in the hydroisomerization feed stream from 0.8% to 3%, the yield of the jet fuel range material can be increased to 93%. These n-alkanes will then be enriched in distillation column 140 to at least 6% of the sixteen-carbon alkanes in the distillate column bottom stream 148 and fed to hydrocracking reactor 150, where they can be more selectively hydrocrashed and possibly hydroisomerized by recycling to hydroisomerization reactor 74 to produce a total jet-range yield greater than 85%. Similarly, the same principle can be applied to other alkanes with different carbon numbers that have n-alkane limits in the final fuel product, such as alkanes with eighteen carbon atoms.

[0081] The hydrocracking reactor 150 can be a fixed-bed reactor, comprising one or more vessels, single or multiple catalyst beds in each vessel, and various combinations of hydrocracking catalysts in the one or more vessels. The hydrocracking reactor 150 can operate in conventional continuous gas-phase, moving-bed, or fluidized-bed hydrotreatment reactors. A portion of the heavy diesel oil stream in pipeline 160...

[0082] In the presence of a hydrocracking hydrogen stream from hydrocracking hydrogen line 152, a heavy diesel feed stream is hydrogenated by a hydrocracking catalyst in a hydrocracking reactor to provide a hydrocracking feed stream. A portion of the diesel stream in line 168 can be used as an interbed quenching agent to cool the hydrocracking effluent between the catalyst beds. Alternatively, supplemental hydrogen can be added between the catalyst beds.

[0083] The hydrocracking reactor can provide a total conversion of at least 20 vol% and typically greater than 60 vol% of the product from the heavy diesel feedstream 148 to the heavy diesel range with boiling points below 293°C (560°F) to 310°C (590°F). The hydrocracking reactor 150 can operate based on the total conversion at a partial conversion of more than 30 vol% of the feed or a complete conversion of at least 90 vol%. The hydrocracking reactor 40 can operate under mild hydrocracking conditions, which will provide a total conversion of 20 vol% to 60 vol%, preferably 20 vol% to 50 vol%, of the product from the hydrocarbon feedstream with boiling points below the heavy diesel boiling point range.

[0084] Hydrocracking catalysts can utilize amorphous silica-alumina or zeolite-based feedstocks in combination with one or more Group VIII or Group VIB metal hydrogenation components to selectively produce a balance of light diesel and jet fuel distillates. Alternatively, catalysts typically comprising any crystalline zeolite cracking feedstock with a Group VIII metal hydrogenation component deposited thereon can be suitable. Additional hydrogenation components may be selected from Group VIB to combine with the zeolite feedstock.

[0085] Zeolite pyrolysis substrates, sometimes referred to in the art as molecular sieves, are typically composed of silica, alumina, and one or more exchangeable cations such as sodium, magnesium, calcium, rare earth metals, etc. They are also characterized by relatively uniform pore sizes between 4 and 14 angstroms. Zeolites with a relatively high silica / alumina molar ratio (between 3 and 12) are preferred. Suitable zeolites found in nature include, for example, mordenite, zeolite, flaky zeolite, magnesia-alkali zeolite, cycloid zeolite, chalcogenide, bufosite, and octahedral zeolite. Suitable synthetic zeolites include, for example, B, X, Y, and L crystal types, such as synthetic octahedral zeolite and mordenite. Preferred zeolites are those with pore sizes between 8 and 12 angstroms, wherein the silica / alumina molar ratio is 4 to 6. An example of a zeolite falling into the preferred group is synthetic Y molecular sieve.

[0086] Naturally occurring zeolites are typically found in sodium, alkaline earth metal, or mixed forms. Synthetic zeolites are almost always prepared in sodium form. In any case, for use as a pyrolysis substrate, it is preferable that most or all of the original zeolite monovalent metals are ion-exchanged with polyvalent metals and / or with ammonium salts, followed by heating to decompose the ammonium ions associated with the zeolite, thereby leaving hydrogen ions and / or exchange sites at their locations that are effectively decation-free through further water removal. This property of hydrogen-free or "cation-free" Y zeolites is described more specifically in US 3,100,006.

[0087] Mixed multivalent metal-hydrogen zeolites can be prepared by exchanging ions with ammonium salts, followed by partial reverse exchange with multivalent metal salts, and then calcination. In some cases, such as in the synthesis of mordenite, the hydrogen form can be prepared by direct acid treatment of alkali metal zeolites. In one aspect, preferred pyrolysis substrates are those based on an initial ion exchange capacity lacking at least 10 wt% and preferably at least 20 wt% of metal cations. In another aspect, an ideal and stable class of zeolites is those in which hydrogen ions satisfy an ion exchange capacity of at least 20 wt%.

[0088] In the preferred hydrocracking catalyst of this invention, the active metal used as the hydrogenation component is a Group VIII active metal, namely iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. In addition to these metals, other promoters, including Group VIB metals such as molybdenum and tungsten, may be used in combination. The amount of hydride metal in the catalyst can vary over a wide range. Generally, any amount between 0.05 wt% and 30 wt% can be used. Regarding noble metals, it is generally preferred to use 0.05 wt% to 2 wt% of noble metals. Noble metals are preferably used as hydride metals on the hydrocracking catalyst to provide selectivity for jet fuels, because hydrogen sulfide and ammonia, which could deactivate the noble metal catalyst, have been removed upstream of the process.

[0089] The method of incorporating metal hydrides involves contacting the base material with an aqueous solution of a suitable compound of the desired metal, wherein the metal exists in cationic form. After adding one or more selected metal hydrides, the resulting catalyst powder is then filtered, dried, and pelletized as needed with added lubricants, binders, etc., and calcined in air at a temperature, for example, 371°C (700°F) to 648°C (200°F), to activate the catalyst and decompose ammonium ions. Alternatively, the base material component can be pelletized, and then the hydride component can be added and activated by calcination.

[0090] The catalysts described above can be used undiluted, or powdered catalysts can be mixed with other relatively less active catalysts, diluents, or binders such as alumina, silica gel, silica-alumina cogel, activated clay, etc., in proportions ranging from 5% to 90% by weight and co-prepared into pellets. These diluents can be used as is, or they may contain a small proportion of added hydride metals, such as Group VIB and / or Group VIII metals. Additional metal-promoted hydrogenation cracking catalysts can also be used in the methods of this invention, including, for example, aluminum phosphate molecular sieves, crystalline chromosilicates, and other crystalline silicates. Crystalline chromosilicates are described more fully in US 4,363,178.

[0091] A method may be used to perform hydrogenation cracking under conditions including a temperature of 290°C (550°F) to 468°C (875°F), preferably 300°C (572°F) to 445°C (833°F), a pressure of 2.7 MPa (gauge pressure) (400 psig) to 20.7 MPa (gauge pressure) (3000 psig), and a 0.4 hr... -1 to less than 2.5hr -1 The liquid hourly space velocity (LHSV) and 421 Nm 3 / m 3 (2,500 scf / bbl) to 2,527 Nm 3 / m 3 Hydrogen rate of oil (15,000 scf / bbl).

[0092] The hydrocracking feed stream can exit the hydrocracking reactor 150 in hydrocracking line 158. In one embodiment, the hydrocracking feed stream can be fed directly to the hydroisomerization reactor 74. In this embodiment, the hydrocracking feed stream in hydrocracking line 158 is recirculated to recirculation line 98 via direct line 159 through a control valve thereon. The hydrocracking feed stream from recirculation line 98 is mixed with the hydroisomerization feed stream from hydroisomerization feed line 90 to provide a combined hydroisomerization feed stream in combined hydroisomerization feed line 100, which is heated in heater 72 and fed to hydroisomerization reactor 74.

[0093] In an alternative embodiment, the hydrocracking feed stream in hydrocracking line 158 can be conveyed to hydrocracking separator 180 via a control valve in hydrocracking separator line 181. The hydrocracking feed stream can then be separated in hydrocracking separator 180. The hydrocracking feed stream can be separated in hydrocracking separator 180 to provide a hydrocarbon-containing vapor hydrocracking feed stream in hydrocracking separator top line 182 and a hydrocarbon-containing hydrocracking liquid stream in hydrocracking separator bottom line 184. Hydrocracking separator 180 can be in downstream communication with hydrocracking reactor 150. Hydrocracking separator 180 operates at 177°C (350°F) to 371°C (700°F), and preferably at 232°C (450°F) to 315°C (600°F). Hydrocracking separator 180 can operate at a pressure slightly lower than that of hydrocracking reactor 150, which causes a pressure drop through the intervention equipment. The hydrogenation cracking separator 180 can operate at pressures between 3.4 MPa (gauge pressure) (493 psig) and 20.4 MPa (gauge pressure) (2959 psig). The temperature of the vapor hydrogenation cracking feed stream in the hydrogenation cracking separator overhead line 182 can be the operating temperature of the hydrogenation cracking separator 180. The vapor hydrogenation cracking feed stream in the hydrogenation cracking separator overhead line 182 can be combined with the stripping gas in the isomerization tower overhead line 58 for use as the process feed stream taken from the bottom stream of the thermal separator in the stripping line 54.

[0094] The hydrocracking liquid stream in the bottom line 184 of the hydrocracking separator can be treated in at least two ways. In a first embodiment, a control valve on line 186 is opened to combine at least some of the hydrocracking liquid stream from line 184 with the cold separator feed stream in line 84, to cool in cold separator 94 and separate from the liquid hydroisomerization feed stream in the bottom line 82 of the hydroisomerization tower, the hot vapor stream in the hot tower top line 50, the hydrotreatment vapor stream in the hydrotreatment tower top line 60, and the cold water stream in the cold water line 87. The jet fuel and light diesel oil components in the hydrocracking liquid stream are then optionally stripped in stripping tower 120 and distilled in distillation tower 140 into the jet fuel stream in line 144, the light diesel oil stream in line 152, and the heavy diesel oil stream in line 148.

[0095] In the second embodiment, a control valve on the hydroisomerization connection line 188 is opened to allow at least some of the hydrocracking liquid stream from the bottom line 184 of the hydrocracking separator to flow to the hydroisomerization reactor 74, thereby improving the cold flow properties of the jet fuel-range hydrocarbons produced in the hydrocracking reactor 150. The liquid hydrocracking feed stream in the hydroisomerization connection line 188 is conveyed to the recirculation line 98 and mixed with the hydroisomerization feed stream in the hydroisomerization feed line 90 to produce a combined hydroisomerization feed stream in the combined hydroisomerization feed line 100, which is heated in the feed heater 72 and hydroisomerized in the hydroisomerization reactor 74 as previously described. The hydroisomerized, hydrocracking liquid is then processed together with the remaining hydroisomerization feed stream in line 76.

[0096] Figure 2 An alternative embodiment is shown, which places the hydrogenation cracking catalyst bed 150' and the hydroisomerization catalyst bed 74' in a single reactor vessel 190, which may be more suitable for modified scenarios than Figure 1 The implementation plan in [the document] is more ideal. It has [the following characteristics]: Figure 1 The same configuration Figure 2 The components in will have the same Figure 1 The same icon number as in the text. It has the same... Figure 1 Different configurations of corresponding elements Figure 2 The elements in the diagram have the same reference numerals, but are indicated by an apostrophe ('). Figure 2 The configuration and operation of the implementation scheme are basically the same as Figure 1 The same as in the above, but with the following exceptions.

[0097] The heavy diesel stream from the bottom pipeline 148' of the distillation column is mixed with the hydrogen stream from the hydrocracking pipeline 152', heated in heater 154', and fed into the hydrocracking / hydroisomerization reactor vessel 190. The heated heavy diesel stream is then fed through the inlet of the first reactor into the hydrocracking catalyst bed 150'. Figure 1 Similar to the previous method, the hydrocracking catalyst can be a noble metal catalyst because hydrogen sulfide and ammonia, which deactivate the hydrocracking catalyst, are removed upstream of the hydrocracking catalyst bed 150'. All the hydrocracking feed streams leaving the hydrocracking catalyst bed 150' are mixed with the isomerization feed stream in the isomerization feed line 90 in the interbed space 75 between the hydrocracking catalyst bed 150' and the hydroisomerization catalyst bed 74'. The mixture of the hydrocracking feed stream and the isomerization feed stream enters the hydroisomerization catalyst bed 74' located below the hydrocracking catalyst bed 150' from the interbed space 75. The hydrocracking feed stream and the isomerization feed stream are hydroisomerized together by the hydroisomerization catalyst in the presence of hydrogen. The hydroisomerization feed stream leaves the hydroisomerization bed 74' in the hydroisomerization line 76 and proceeds as follows: Figure 1The process is then carried out.

[0098] Conditions in the hydrogenation cracking / hydroisomerization reaction vessel 190 may include a temperature of 290°C (550°F) to 468°C (875°F), preferably 300°C (572°F) to 445°C (833°F), a pressure of 2.7 MPa (gauge pressure) (400 psig) to 20.7 MPa (gauge pressure) (3000 psig), and a 0.4 hr... -1 to less than 2.5hr -1 The liquid hourly space velocity (LHSV) and 421 Nm 3 / m 3 (2,500 scf / bbl) to 2,527 Nm 3 / m 3 Hydrogen rate of oil (15,000 scf / bbl).

[0099] Figure 3 Another alternative embodiment is shown, which places a hydrotreating catalyst bed 44” and a hydroisomerization catalyst bed 74” in a single reaction vessel 40. Hydroisomerization is carried out in an acidic environment in the presence of hydrogen sulfide, water, and ammonia. A hydrocracking reactor 150” converts heavy diesel fuel into jet fuel components. It has the same characteristics as... Figure 1 or Figure 2 The same configuration Figure 3 The components in the middle will each have the same as Figure 1 or Figure 2 The same icon number as in the text. They have the same... Figure 1 or Figure 2 Different configurations of corresponding elements Figure 3 The elements in the reference numerals will have the same reference numerals, but will be enclosed in double quotes (“). Figure 3 The configuration and operation of the implementation scheme are basically the same as Figure 1 or Figure 2 The same as in the above, but with the following exceptions.

[0100] The contact feed stream from the guard bed reactor 26 in the contact feed line 32 is heated in the guard bed exhaust heat exchanger 34 and heater 36 and fed into the hydrotreatment / hydroisomerization reaction vessel 40, which may contain at least two catalyst beds. The heated contact feed stream is fed into the hydrotreatment catalyst bed 44” through the first reactor inlet. More than one catalyst bed 44” may be used. All hydrotreatment feed streams leaving the hydrotreatment catalyst bed 44” (or the last hydrotreatment catalyst bed 44” if multiple hydrotreatment beds are used) are mixed with a quenched hydrogen stream in the interbed space 45 between the hydrotreatment catalyst bed 44” and the hydroisomerization catalyst bed 74”. The hydrotreatment feed stream, replenished and cooled with quenched hydrogen, enters the hydroisomerization catalyst bed 74” located below the hydrotreatment catalyst bed 44” from the interbed space 45. The hydrotreatment feed stream undergoes hydroisomerization in the hydroisomerization catalyst bed 74” in the presence of hydrogen via the hydroisomerization catalyst. More than one hydroisomerization catalyst bed 74 can be used.

[0101] The hydrotreating / hydroisomerization reaction temperature can range between 343°C (650°F) and 427°C (800°F), and is preferably between 349°C (690°F) and 400°C (752°F). Typically, the hydrotreating / hydroisomerization conditions include pressures from 700 kPa (100 psig) to 21 MPa (3000 psig).

[0102] The hydroisomerization feed stream is generated from the hydroisomerization catalyst bed 74” in the hydroisomerization line 42”. The hydroisomerization feed stream in the hydroisomerization line 42” may first flow to the combined hydrocracking feed exchanger 46” to heat the hydrocracking feed stream in the hydrocracking feed line 90” and cool the hydroisomerization feed stream. As previously described, the cooled hydroisomerization feed stream in the hydroisomerization line 42” can then exchange heat with the contacting biorenewable feed stream in the guard bed exhaust heat exchanger 34 to cool the hydroisomerization feed stream in the hydroisomerization line 42” and heat the contacting biorenewable feed stream. The hydroisomerization vapor, cooled twice in hydroisomerization line 42", can then be further cooled in combined feed exchanger 22 by heat exchange with the combined bioregenerative feed stream in combined feed line 24, to heat the combined bioregenerative feed stream and cool the hydroisomerization stream in hydroisomerization line 42". The tertiary-cooled hydroisomerization stream can even be further cooled, perhaps to produce steam, before separating the tertiary-cooled hydroisomerization stream to provide the hydroisomerization vapor stream and the hydrotreated liquid stream.

[0103] The hydroisomerization feed stream can be separated in thermal separator 48 to provide a hydrocarbon-containing hot vapor stream in thermal separator top line 50 and a hydrocarbon-containing hot liquid stream in thermal separator bottom line 52. The temperature of the hot vapor stream in thermal separator top line 50 can be the operating temperature of thermal separator 48.

[0104] The hot liquid flow in the bottom line 52 of the thermal separator can be divided into two flows: a hot process liquid flow in the process line 54, which is drawn from the hot liquid flow in the bottom line 52, and a hot recirculation liquid flow in the recirculation line 16, which is also drawn from the hot liquid flow in the bottom line 52. The hot recirculation liquid flow in the recirculation line 16 can be combined with the biorecyclable feed flow in line 12, as previously described.

[0105] The hot process liquid stream drawn from process line 54 can be further separated in a hydroisomerization separator 56”, which may include an EHS (Extractable Hybridizer and Separator) using stripping gas fed from hydrocracking vapor line 58”. The hot process liquid stream is separated to provide a hydroisomerization vapor stream and a hydroisomerization liquid stream. Hydroisomerization separator 56” may be a high-pressure stripping tower. In hydroisomerization separator 56”, the hot process liquid stream from process line 54 flows downward through the tower, where it is partially stripped of hydrogen, carbon dioxide, carbon monoxide, water vapor, propane, hydrogen sulfide, and phosphine, which are potential isomerization catalyst poisons, by contact with stripping gas from hydrocracking vapor line 58”. The stripping gas may contain supplemental hydrogen already passed through hydrocracking reactor 150” and hydrocracking separator 80”, as described below.

[0106] The stripping gas in the hydrocracking vapor line 58” enters the hydroisomerization separator 56” below the inlet of the hot process liquid stream in the process liquid line 54. The hydroisomerization separator 56” may include internal components such as trays or packing located between the inlet of the hot process liquid stream in the process liquid line 54 and the inlet of the stripping gas in the hydrocracking vapor line 58” to facilitate stripping of the hot process liquid stream in the process line 54. The stripped gas and stripping gas are discharged as a hydroisomerization vapor stream in the hydroisomerization tower top line 60” extending from the top of the hydroisomerization separator 56”, and are mixed with the hot vapor stream in the hot tower top line 50 and the hydrocracking liquid stream in the hydrocracking tower bottom line 82”, and optionally with the cold water stream from the cold water line 87 from the cold separator reservoir to provide a cold separator feed stream in the cold feed line 84”.

[0107] The hydroisomerized liquid stream, which may have been stripped, is collected at the bottom of the hydroisomerization separator 56” and flows to the suction side of the bottom pump in the hydroisomerization bottom line 62”. The hydroisomerized liquid stream mainly contains diesel-range materials.

[0108] The hydroisomerization liquid stream can be hydrocracking using a hydrocracking catalyst in the presence of a hydrocracking hydrogen stream. The supplemental hydrogen in supplemental line 86 can be compressed in supplemental gas compressor 88 and mixed with the hydroisomerization liquid stream pumped from hydroisomerization bottom line 62” and the distillation bottom stream from distillation bottom line 148” to provide a combined hydrocracking feed stream in hydrocracking feed line 90”. The distillation bottom stream contains heavy diesel oil, which may be too heavy to meet jet fuel specifications. Therefore, by hydrocracking the heavy diesel oil in the distillation bottom stream, higher yields of light diesel oil and jet fuel can be produced.

[0109] The combined hydrocracking feed stream in the hydrocracking feed line 90” is heated in the combined hydrocracking feed exchanger 46” by heat exchange with the hydroisomerization feed stream in the hydroisomerization line 42”, and further heated in the hydrocracking feed heater 72”, so that the combined hydrocracking feed stream reaches the hydrocracking temperature before being fed into the hydrocracking reactor 150”. The hydrocracking in the hydrocracking reactor 150” is as follows: Figure 1 As stated above.

[0110] The boiling point of the hydrogen pyrolysis feed stream from the hydrogen pyrolysis reactor 150” in the hydrogen pyrolysis line 76” is lower than that of the hydrogen pyrolysis feed vapor. The hydrogen pyrolysis feed stream from the hydrogen pyrolysis reactor 150” in the hydrogen pyrolysis line 76” flows to the hydrogen pyrolysis exchanger 77” to exchange heat with the cold liquid stream in the cold tower bottom line 92, cooling it before it enters the hydrogen pyrolysis separator 80” to be separated into liquid and vapor hydrogen pyrolysis feed streams. The vapor hydrogen pyrolysis feed stream from the hydrogen pyrolysis tower top line 58” extending from the top of the hydrogen pyrolysis separator 80” flows to the hydroisomerization separator 56” and can be used as stripping gas in the hydroisomerization separator 56”. Optionally, a portion of the vapor hydrogen pyrolysis feed stream can bypass the hydroisomerization separator 56” and enter the cold feed line 84 via a control valve.

[0111] Figure 3 The remaining arrangements and operations of the implementation plan are as follows: Figure 1 and Figure 2 As described in [the text].

[0112] Figure 4 It shows Figure 2 An alternative embodiment places the hydrogenation cracking catalyst bed 150' and the hydroisomerization catalyst bed 74' in a single reaction vessel 190, but relies on the deoctadecane tower 200 for separation between light and heavy diesel oil. Figure 2 The same configuration Figure 4 The components in will have the same Figure 2 The same icon number as in the text. It has the same... Figure 2Different configurations of corresponding elements Figure 4 The components in the diagram will have the same reference numerals, but will be indicated by an asterisk (*). Figure 4 The configuration and operation of the implementation scheme are basically the same as Figure 2 The same as in the above, but with the following exceptions.

[0113] The hydrotreated liquid stream, which may have been stripped, in the bottom line 62* of the hydrotreatment tower is collected at the bottom of the hydrotreatment separator 56 and flows to the deoctadecane tower 200, which distills the bottom feed stream to produce a C-containing product in the top line 202. 17 - The overhead feed stream of light diesel oil and light gases containing hydrocarbons and the bottom line 204 produces C. 18 The bottom feed stream of heavy diesel oil containing hydrocarbons. The deoctadecane tower 200 can be reboiled by heat exchange with a suitable heat stream or in a flame heater to provide the heat required for distillation. Alternatively, the tower can be heated using a stripping medium such as steam as an inert gas from the stripping medium line 206. The deoctadecane tower 200 provides naphtha and oil ranging from C10 to C20 in the top line 202. 10 To C 17 The overhead gaseous stream of n-carbon hydrocarbons and vapors. The overhead stream can be condensed and separated from water in the deoctadecane receiver 210 to provide n-carbon hydrocarbons in the overhead liquid stream in line 208. 10 To C 17 Hydrocarbons. Unstable fossil naphtha stream can be obtained from the net vapor stream in the overhead line 212 of receiver 210. Acidic water stream can be collected from the storage tank of deoctadecane receiver 210. The overhead liquid stream from deoctadecane receiver 210 can be combined with the makeup hydrogen stream in line 86 to provide an isomer feed stream in isomer feed line 90*, which is directed to the hydroisomerization catalytic bed 74' in reaction vessel 190. This will contain C 18 The bottom feed stream of heavy diesel oil containing hydrocarbons is transported in bottom line 204 and delivered to the hydrogenation cracking catalyst bed 150' in reaction vessel 190.

[0114] The deoctadecane tower 200 can be operated at a bottom temperature between 260°C (500℉) and 316°C (600℉) and a top pressure of 0.35 MPa (gauge pressure) (50 psig), preferably not less than 0.70 MPa (gauge pressure) (100 psig) and not more than 2.0 MPa (gauge pressure) (290 psig).

[0115] The cold separator bottom stream in line 92* can be fed to the jet stripper 120* to generate light gases in the clean stripper overhead stream in line 132 and naphtha in the overhead liquid stream 134. The stripping stream in line 128* is a jet product that meets ASTM D7566 jet fuel specifications and can be carried to the jet fuel pool. In one embodiment, recirculation line 129 can recycle some of the jet product stream to the hydroisomerization catalyst bed 74' for further hydroisomerization via line 208. Figure 4 The rest of the parts according to Figure 1 and Figure 2 The description is used for layout and operation.

[0116] Any of the aforementioned pipelines, conduits, units, equipment, containers, surrounding environment, areas, or the like may be equipped with one or more monitoring components, including sensors, measuring devices, data acquisition devices, or data transmission devices. Signal, method, or condition measurements, as well as data from the monitoring components, can be used to monitor conditions within, around, and in connection with the method or equipment. Signals, measurements, and / or data generated or recorded by the monitoring components may be collected, processed, and / or transmitted through one or more networks or connections, which may be private or public, general or dedicated, direct or indirect, wired or wireless, encrypted or unencrypted, and / or combinations thereof; this specification is not intended to be limiting in this respect.

[0117] Signals, measurements, and / or data generated or recorded by monitoring components may be transmitted to one or more computing devices or systems. The computing devices or systems may include at least one processor and a memory storing computer-readable instructions that, when executed by the at least one processor, cause the one or more computing devices to perform a method that may include one or more steps. For example, one or more computing devices may be configured to receive data from one or more monitoring components related to at least one device associated with the method. One or more computing devices or systems may be configured to analyze the data. Based on the data analysis, one or more computing devices or systems may be configured to determine one or more recommended adjustments to one or more parameters of one or more methods described herein. One or more computing devices or systems may be configured to transmit encrypted or unencrypted data comprising one or more recommended adjustments to one or more parameters of one or more methods described herein.

[0118] Specific implementation plan

[0119] While the following description is presented in conjunction with specific embodiments, it should be understood that the description is intended to illustrate, and not limit, the scope of the foregoing description and the appended claims.

[0120] A first embodiment of this disclosure is a method for hydrogenating a biorenewable feedstock, the method comprising: hydrogenating the biorenewable feedstock stream in the presence of hydrogen via a hydrotreatment catalyst to hydrodeoxygenate the biorenewable feedstock stream, thereby providing a hydrotreated feedstock stream; hydroisomerizing a hydroisomerized feedstock stream taken from the hydrotreated feedstock stream in the presence of hydrogen via a hydroisomerization catalyst to provide a hydroisomerized feedstock stream; separating the hydrotreated feedstock stream and / or the hydroisomerized feedstock stream into a hydrogenated vapor stream and a hydrogenated liquid stream; distilling the hydrogenated liquid stream or the hydroisomerized feedstock stream, optionally after stripping, to produce a jet fuel stream and a diesel stream; and hydrocracking the diesel stream to provide a hydrocracking feedstock stream containing jet fuel. An embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, and further includes distilling the hydroisomerized feedstock stream and the hydrocracking feedstock stream. One embodiment of this disclosure, which is one, any, or all of the embodiments described in this paragraph, from the previous embodiments to the first embodiment described in this paragraph, further includes distilling the hydroisomerization feed stream. One embodiment of this disclosure, which is one, any, or all of the embodiments described in this paragraph, from the previous embodiments to the first embodiment described in this paragraph, further includes hydroisomerizing the hydrogenocracking feed stream. One embodiment of this disclosure, which is one, any, or all of the embodiments described in this paragraph, from the previous embodiments to the first embodiment described in this paragraph, further includes hydroisomerizing the hydrotreatment vapor in the presence of hydrogen via the hydroisomerization catalyst to provide the hydroisomerization feed stream. One embodiment of this disclosure, which is one, any, or all of the embodiments described in this paragraph, from the previous embodiments to the first embodiment described in this paragraph, further includes separating the hydroisomerization feed stream in the separation step. One embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, further comprising distilling the hydrogenated pyrolysis feed stream with the liquid stream of the hydrogenation treatment. Another embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, wherein the diesel stream is a heavy diesel stream, and the embodiment further comprises generating a light diesel stream during the distillation step.One embodiment of this disclosure, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, further includes separating the hydrotreated feed stream in the separation step; distilling the hydrotreated liquid stream; hydroisomerizing the jet fuel stream; and hydrocracking the diesel stream. Another embodiment of this disclosure, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, further includes hydroisomerizing the hydrocracking feed stream with the jet fuel stream. Another embodiment of this disclosure, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, further includes separating the hydroisomerized feed stream into a hydroisomerized liquid stream and a hydroisomerized vapor stream. Finally, another embodiment of this disclosure, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, further includes stripping the hydroisomerized liquid stream into a naphtha stream and a jet fuel product stream. One embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment described in this paragraph, and further includes enriching the concentration of n-alkanes with a given number of carbons in the diesel stream to at least twice that of the hydroisomerized feed stream.

[0121] A second embodiment of this disclosure is a method for hydrogenating a biorenewable feedstock, the method comprising: hydrogenating the biorenewable feedstock stream in the presence of hydrogen via a hydrotreatment catalyst to hydrodeoxygenate the biorenewable feedstock stream, thereby providing a hydrotreated feedstock stream; hydroisomerizing a hydroisomerized feedstock stream taken from the hydrotreated feedstock stream in the presence of hydrogen via a hydroisomerization catalyst to provide a hydroisomerized feedstock stream; enriching the concentration of n-alkanes with a given number of carbons in a diesel stream taken from the hydroisomerized feedstock stream to at least twice the concentration of the hydroisomerized feedstock stream relative to the hydroisomerized feedstock stream; and hydrocracking or hydroisomerizing the diesel stream to provide a hydrocracking feedstock stream containing jet fuel. One embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the second embodiment described in this paragraph, wherein the enrichment step is achieved by distilling the hydroisomerized liquid stream. One embodiment of this disclosure is one, any, or all of the embodiments described in the preceding to the second embodiments of this paragraph, and further includes hydrocracking the diesel stream and hydroisomerizing the hydrocracking feed stream.

[0122] A third embodiment of this disclosure is a method for hydrogenating a biorenewable feedstock, the method comprising: hydrogenating the biorenewable feedstock stream in the presence of hydrogen via a hydrotreatment catalyst to hydrodeoxygenate the biorenewable feedstock stream, thereby providing a hydrotreated feedstock stream; hydroisomerizing the hydrotreated feedstock stream in the presence of hydrogen via a hydroisomerization catalyst to provide a hydroisomerized feedstock stream; separating the hydroisomerized feedstock stream into a hydrogenated vapor stream and a hydrogenated liquid stream; distilling the hydrogenated liquid stream or the hydroisomerized feedstock stream, optionally after stripping, to produce a jet fuel stream and a diesel stream; and hydrocracking the diesel stream to provide a hydrocracking feedstock stream containing jet fuel. One embodiment of this disclosure is one, any, or all of the embodiments described in the preceding embodiments to the third embodiment described in this paragraph, and further includes hydroisomerizing the hydrocracking feedstock stream. Although no further detailed description has been provided, it is believed that those skilled in the art will be able to make full use of the invention by employing the foregoing description and will be able to readily identify the essential features of the invention without departing from its spirit and scope, and to make various changes and modifications to adapt it to various uses and situations. Therefore, the foregoing preferred embodiments should be understood as illustrative only and not as limiting the remainder of this disclosure in any way, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0123] In the foregoing, all temperatures are expressed in degrees Celsius, and all portions and percentages are by weight unless otherwise specified.

Claims

1. A process for hydrotreating a biorenewable feedstock, the process comprising: hydrotreating the biorenewable feed stream over a hydrotreating catalyst in the presence of hydrogen to hydrodeoxygenate the biorenewable feed stream, thereby providing a hydrotreated stream; hydroisomerizing a hydroisomerization feed stream taken from the hydrotreated stream over a hydroisomerization catalyst in a hydroisomerization reactor in the presence of hydrogen to provide a hydroisomerized stream; separating the hydroisomerized stream into a hydrotreated vapor stream and a hydrotreated liquid stream; distilling the hydrotreated liquid stream in a distillation column to produce a jet fuel stream in a first side line, a light diesel stream in a second side line, and a heavy diesel stream in a distillation column bottom line; and hydrocracking the heavy diesel stream in a hydrocracking reactor to provide a hydrocracked stream comprising jet fuel; wherein the process comprises enriching the concentration of normal paraffins of a given carbon number in the heavy diesel stream relative to the hydroisomerized stream by a factor of at least two, wherein the enrichment is carried out in the distillation column; wherein the distillation column is operated at a column bottom temperature between 149°C and 260°C and a column top pressure of not less than 0.70 MPa gauge to not more than 2.0 MPa gauge; wherein the jet fuel stream in the first side line has a T5 of 115°C to 130°C and a T90 of 240°C to 270°C, the light diesel stream in the second side line has a T5 of 230°C to 250°C and a T90 of 279°C to 296°C, and wherein the heavy diesel stream in the distillation column bottom line has a T5 of 279°C to 296°C and a T90 of 343°C to 399°C.

2. The process of claim 1, further comprising distilling the hydroisomerized stream and the hydrocracked stream.

3. The process of claim 1, further comprising distilling the hydroisomerized stream.

4. The process of claim 3, further comprising hydroisomerizing the hydrocracked stream.

5. The process of claim 1, further comprising hydroisomerizing the hydrocracked stream.

6. The process of claim 1, further comprising distilling the hydrocracked stream.

7. The process of claim 5, further comprising hydroisomerizing a hydrotreated stream over the hydroisomerization catalyst in the presence of hydrogen to provide the hydroisomerized stream.

8. The process of claim 6, further comprising separating the hydroisomerized stream in a separation step.

9. The process of claim 5, further comprising distilling the hydrocracked stream with the hydrotreated liquid stream.

Images