Process for producing jet fuel from bio-renewable feedstock

Abstract

To provide a process for producing hydrocarbons useful as aviation fuel from bio-renewable feedstock such as triglycerides and free fatty acids.SOLUTION: The process produces a diesel stream from the bio-renewable feedstock through hydrotreating to remove five heteroatoms and hydroisomerization to improve low-temperature fluidity. The heavy diesel can be hydrocracked into jet fuel-range materials or further hydroisomerized to enhance its value (the freezing point can be lowered), while the light diesel can be used as motor fuel.SELECTED DRAWING: Figure 1

Description

[Technical field]

[0001] (Statement of priority) This application claims the benefit of Indian Provisional Patent Application No. 2020 / 11046430, filed on October 24, 2020, which is incorporated herein by reference in its entirety.

[0002] The following specification particularly describes the invention and the manner in which it may be practiced.

[0003] FIELD OF THEINVENTION This field produces hydrocarbons useful as aviation fuels from bio-renewable feedstocks such as triglycerides and free fatty acids found in materials such as plant and animal fats and oils. [Background technology]

[0004] As the demand for fuel increases worldwide, there is growing interest in producing fuels from sources other than crude oil and blending components. These sources, often referred to as bio-renewable sources, include, but are not limited to, vegetable oils such as corn, rapeseed, canola, soybean, microbial oils such as algae oil, animal fats such as non-edible tallow, fish oil, yellow and brown grease, and sewage sludge. The common feature of these sources is that they are composed of glycerides and free fatty acids (FFA). Both triglycerides and FFAs contain aliphatic carbon chains having from 8 to 24 carbon atoms. The aliphatic carbon chains in triglycerides or FFAs can be fully saturated or mono-, di-, or polyunsaturated.

[0005] Hydroprocessing may include processes that convert hydrocarbons into more valuable products in the presence of a hydroprocessing catalyst and hydrogen. Hydroprocessing is the process of contacting hydrogen with hydrocarbons in the presence of a hydroprocessing catalyst that is active for removing heteroatoms such as sulfur, nitrogen, oxygen, and metals from the hydrocarbon feedstock. In hydroprocessing, hydrocarbons with double and triple bonds, such as olefins, may be saturated.

[0006] The production of diesel boiling range hydrocarbon products can be achieved by hydrotreating the biorenewable feedstock. The biorenewable feedstock can be hydroprocessed by hydrotreating to deoxygenate the oxygenated hydrocarbons, including decarbonation and decarbonylation. Hydrotreating can be followed by hydroisomerization to improve the low temperature fluidity of the product diesel and jet fuel. Hydroisomerization or hydrodewaxing is a hydroprocessing process that, in the presence of hydrogen and a hydroisomerization catalyst, increases the alkyl branching on the hydrocarbon backbone to improve the low temperature fluidity of the hydrocarbon. Hydroisomerization as used herein includes hydrodewaxing.

[0007] Hydrocracking is a hydroprocessing process in which hydrocarbons are cracked into lower molecular weight hydrocarbons in the presence of hydrogen and a hydrocracking catalyst. Depending on the desired production output, a hydrocracking unit may contain one or more beds of the same or different catalysts.

[0008] As refiners seek to add capacity to process bio-renewable feedstocks, processes are needed to produce greater quantities of jet fuel due to its high value and demand. What is desired is a process that allows this. Summary of the Invention

[0009] The process produces a diesel stream from a bio-renewable feedstock by hydrotreating the feedstock to remove heteroatoms and hydroisomerizing to improve low temperature fluidity. Heavy diesel can be hydrocracked into jet fuel range materials to enhance its value, while light diesel can be used as a motor fuel. [Brief description of the drawings]

[0010] [Figure 1] FIG. 1 is a simplified process flow diagram of the present disclosure. [Diagram 2] FIG. 2 is a simplified process flow diagram of an alternative embodiment of FIG. 1. [Diagram 3] FIG. 3 is a simplified process flow diagram of a further alternative embodiment of FIG. 1 or FIG. 2. [Figure 4] FIG. 3 is a simplified process flow diagram of a further alternative embodiment of FIG. 2. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0011] definition The term "communication" means operatively permitting the flow of material between the recited components.

[0012] The term "downstream communication" means that at least a portion of the material flowing to the object in the downstream communication can operatively flow from the object with which it is in communication.

[0013] The term "upstream communication" means that at least a portion of the material flowing from the object in the upstream communication can operatively flow to the communicating object.

[0014] The term "direct communication" means that a stream from an upstream component enters a downstream component without passing through a fractionation or conversion unit and undergoing a change in composition by physical fractionation or chemical conversion.

[0015] The term "indirect communication" means that a stream from an upstream component passes through a fractionation or conversion unit and undergoes a change in composition by physical fractionation or chemical conversion before entering the downstream component.

[0016] The term "bypass" means that an object is out of downstream communication with a bypass subject, at least to the extent that it bypasses.

[0017] The term "column" refers to one or more distillation columns for separating one or more components of different volatility. Unless otherwise stated, each column includes a condenser at the overhead of the column to condense and reflux a portion of the overhead stream returning to the top of the column, and a reboiler at the bottom of the column to vaporize and return a portion of the bottom stream to the bottom of the column. The feed to the column may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. The overhead and bottom lines refer to the net lines from column to column downstream of any reflux or reboil. A stripper column may omit a reboiler at the bottom of the column and instead provide the heating requirements and the driving force for the separation from a fluidized inert medium such as steam. A stripping column typically feeds the feed to a top tray and removes the main product from the bottom.

[0018] As used herein, the term "component rich stream" means that the rich stream exiting a vessel has a higher concentration of a component than the feed to the vessel.

[0019] As used herein, the term "component lean stream" means that the lean stream exiting a vessel has a lower concentration of the component than the feed to the vessel.

[0020] As used herein, the term "boiling point temperature" means the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling point and the distillation pressure calculated using the formula provided in ASTM D86 or ASTM D2887.

[0021] As used herein, the term "True Boiling Point" (TBP) refers to a test method for determining the boiling point of a substance which corresponds to ASTM D-2892 for producing liquefied gases, distillate fractions, and bottoms of standardized quality for which analytical data can be obtained, and for determining the yields of said fractions by both mass and volume, where a graph of temperature vs. mass % distilled is produced using 15 theoretical plates in a column having a reflux ratio of 5:1.

[0022] As used herein, the terms "T5" or "T95" mean the temperature at which 5 percent or 95 percent, by weight, respectively, of a sample boils using ASTM D-86 or TBP, as the case may be.

[0023] As used herein, the term "initial boiling point" (IBP) The term refers to the temperature at which a sample begins to boil, using ASTM D2887, ASTM D-86, or TBP, as the case may be.

[0024] As used herein, the term "end point" (EP) refers to This refers to the temperature at which the sample has completely evaporated, using ASTM D2887, ASTM D-86, or TBP, as appropriate.

[0025] As used herein, the term "diesel boiling range" means that the hydrocarbons boil within a range of "diesel cut points" including an IBP of 125°C (257°F) to 175°C (347°F) or a T5 of 150°C (302°F) to 200°C (392°F), and a T95 of 343°C (650°F) to 399°C (750°F) using the TBP distillation method.

[0026] As used herein, the term "diesel conversion" means the conversion of a feed boiling above the diesel cut point to a material boiling below the diesel cut point within the diesel boiling range.

[0027] As used herein, the term "separator" means a vessel having an inlet and at least an overhead vapor outlet and a bottom liquid outlet, and may also have an aqueous outlet from a boot. A flash drum is a type of separator that may be in downstream communication with a separator that may be operated at a higher pressure.

[0028] As used herein, the term "predominant" or "predominantly" means greater than 50%, suitably greater than 75%, and preferably greater than 90%.

[0029] As used herein, "C x " should be understood to refer to a molecule having the number of carbon atoms represented by the subscript "x." Similarly, "C x The term "-" refers to less than or equal to x, preferably x and less. Refers to molecules that contain carbon atoms. x The term "+" means "more than or equal to x" al to x, preferably x and more carbon atoms.

[0030] As used herein, the term "carbon number" refers to the number of carbon atoms per hydrocarbon molecule, typically a paraffin molecule.

[0031] (Detailed Description) As the environment and sustainable economy become more important, refiners are increasingly looking to add renewable identification numbers (RIs) to their fuels under the Renewable Fuel Standard program. In order to maximize the profitability of the company from the RIN (Revenue Input Number), It is becoming increasingly attractive to use RINs to produce green fuels. RINs are credits used for compliance that can be traded within the program to increase profitability. The present disclosure allows refiners to maximize jet fuel yields produced from bio-renewable sources and provides flexibility to optimize the yield of jet fuel product relative to diesel fuel product depending on market demand.

[0032] In FIG. 1, a process 10 for processing biorenewable feedstock is shown according to an exemplary embodiment. A feed line 12 transports a feed stream of fresh biorenewable feedstock to a feed surge drum 14. The biorenewable feedstock may be blended with a mineral feed stream, but preferably the biorenewable feedstock predominates. The mineral feedstock is a conventional feed derived from crude oil extracted from the earth. The biorenewable feedstock may contain nitrogen concentrations of 50 wppm to 800 wppm. The biorenewable feedstock may contain high oxygen content, which may be up to 10 wppm or more. The biorenewable feedstock may also contain 1 to 500 wppm sulfur, typically 200 wppm or less.

[0033] A variety of different bio-renewable feedstocks may be suitable for process 10. The term "bio-renewable feedstock" is meant to include feedstocks other than those derived from crude oil. Bio-renewable feedstocks may include any of these feedstocks that contain at least one of glycerides and free fatty acids. Most of the glycerides will be triglycerides, but mono- and diglycerides may be present and processed as well. Free fatty acids may be derived from phospholipids, which may provide the phosphorus in the feedstock. Examples of these biorenewable feedstocks include, but are not limited to, camelina oil, canola oil, corn oil, soy oil, rapeseed oil, soybean oil, rapeseed oil, tall oil, sunflower oil, hempseed oil, olive oil, linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard oil, tallow, used cooking oils and oil-contaminated waste, lard, whale oil, dairy fat, fish oil, algae oil, sewage sludge, etc. Further examples of biorenewable feedstocks include Jatropha curcas (ratanjo, wild castor, jangulierandi), Madhuca indica (mowa), Pongamia Examples of non-edible vegetable oils include those from the group including: Azadirachta (Kalange, Hongji), Calophyllum inophyllum, Moringa oleifera, and Azadirachta indica (Neem). Typical vegetable or animal fat triglycerides and FFAs contain aliphatic hydrocarbon chains with 8 to 30 carbon atoms in their structure. As will be appreciated, the bio-renewable feedstock may include one or more of the aforementioned examples or a mixture of two. The bio-renewable feedstock may be pre-treated to remove contaminants or filtered to remove solids.

[0034] The bio-renewable feed stream in feed line 12 flows from a feed surge drum 14 via a charge pump and mixes with a hot recycle stream in recycle line 16 and a recycled hydroprocessed hydrogen stream in hydroprocessed hydrogen line 20 to provide a combined bio-renewable feed stream. The recycle to feed ratio can be from 2:1 to 5:1. The combined bio-renewable feed stream 12 is heated by heat exchange with a hydroprocessed stream in hydroprocessing line 42 to provide a combined bio-renewable feed stream. The combined feed exchanger 22 can then be heated. The heated and combined bio-renewable feed stream in combined feed line 24 may be charged to hydroprocessing reactor section 25 .

[0035] The hydrotreating reactor section 25 may include a guard bed reactor 26. The guard bed temperature may range from 246° C. (475° F.) to 343° C. (650° F.), preferably from 288° C. (550° F.) to 304° C. (580° F.). The reaction temperature is operated low enough to prevent the olefins in the FFA from polymerizing, but high enough to promote olefin saturation, hydrodemetallation, hydrodeoxygenation (including hydrodecarbonylation and hydrodecarboxylation), hydrodesulfurization, and hydrodenitrification reactions to occur.

[0036] The guard bed may include a base metal on a support. Base metals that can be used in the process include non-precious metals, nickel, chromium, molybdenum, and tungsten. Other base metals that may be used include tin, indium, germanium, lead, cobalt, gallium, and zinc. The method may also use metal sulfides, where the metal in the metal sulfide is selected from one or more of the listed base metals. The biorenewable feedstock may be charged through the base metal catalyst at a pressure of 1379 kPa(abs) (200 psia) to 6895 kPa(abs) (1000 psia). In further embodiments, the guard bed catalyst may include a second metal, where 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 preferred catalyst in guard bed reactor 26. Multiple guard beds, such as two, three or more, may be contained in guard bed reactor 26, and hydrogen quench from hydrogen quench line 18 may be injected at interbed locations to control temperature exotherm.

[0037] The contacted biorenewable feed stream exits guard bed reactor 26 into contact feed line 32. Within guard bed reactor 26, the majority of hydrodeoxygenation reactions, including hydrodemetallation, and hydrodecarbonylation and hydrodecarboxylation, will occur, with some hydrodenitrification and hydrodesulfurization occurring. Metals removed will include alkali and alkaline earth metals and phosphorus.

[0038] The contacted biorenewable feed stream may be heated in guard bed discharge heat exchanger 34 by heat exchange with the hydrotreating stream in hydrotreating line 42 to increase the temperature of the contacted biorenewable feed stream. Additionally, the contacted biorenewable feed stream may be further heated in charge heater 36, which may be a fired heater, to increase the temperature of the contacted biorenewable feed stream. Hydrotreating reactor section 25 may also include a hydrotreating reactor 44. The heated, contacted biorenewable feed stream is charged to hydrotreating reactor 44 of hydrotreating reactor section 25.

[0039] In the hydrotreating reactor 44, the heated and contacted biorenewable feed stream is contacted with a hydrotreating catalyst in the presence of hydrogen at hydrotreating conditions to saturate the olefinic or unsaturated portions of the n-paraffinic chains in the biorenewable feedstock. The hydrotreating catalyst also catalyzes hydrodeoxygenation reactions, including hydrodecarbonylation and hydrodecarbonylation reactions, to remove oxygenated functional groups from the hydrocarbon molecules in the biorenewable feedstock, and the biorenewable feedstock is converted to water and carbon oxides. The hydrotreating catalyst also catalyzes hydrodesulfurization of organic sulfur and hydrodenitrogenation of organic nitrogen in the biorenewable feedstock. In essence, the hydrotreating reactions remove heteroatoms from the hydrocarbons and saturate the olefins in the feed stream.

[0040] The hydrotreating catalyst can be provided in one, two, or more beds to use an interbed hydrogen quench stream from the hydrogen quench stream from hydrogen quench line 18. Two hydrotreating catalyst beds are shown in Figure 1, although one or more are contemplated.

[0041] The hydrotreating catalyst may include nickel, nickel / molybdenum, or cobalt / molybdenum dispersed on a high surface area support such as alumina. Other catalysts include one or more precious metals dispersed on a high surface area support. Non-limiting examples of precious metals include platinum and / or palladium dispersed on an alumina support such as gamma-alumina. Suitable hydrotreating catalysts include BDO 200 or BDO 300 available from UOP LLC, Des Plaines, Ill. Hydrotreating reaction temperatures may range from 343° C. (650° F.) to 427° C. (800° F.), preferably 349° C. (690° F.) to 400° C. (752° F.). Generally, hydrotreating conditions include pressures of 700 kPa (100 psig) to 21 MPa (3000 psig).

[0042] The hydrotreated stream is produced in hydrotreating line 42 from hydrotreating reactor 44 of hydrotreating reactor section 25 and includes a hydrocarbon fraction having a significant n-paraffin concentration. The oxygenate concentration in the hydrocarbon fraction is essentially zero while the olefin concentration is significantly reduced relative to the contacted bio-renewable feed stream. The organic sulfur concentration in the hydrocarbon fraction is less than or equal to 500 wppm and the organic nitrogen concentration in the hydrocarbon fraction is less than 10 wppm.

[0043] The hydrotreat stream in hydrotreat line 42 first flows to a combined isomerization feed exchanger 46, which supplies the hydroisomerization feed stream to the hydroisomerization feed line 42. 90 to heat the hydroisomerization feed stream and cool the hydrotreated stream. As previously described, the cooled hydrotreated stream in hydrotreatment line 42 may then be heat exchanged with the contacted biorenewable feed stream in guard bed discharge heat exchanger 34 to cool the hydrotreated stream in hydrotreatment line 42 and heat the contacted biorenewable feed stream in contacting line 32. The twice-cooled hydrotreated steam in hydrotreatment line 42 may then be further cooled in combined feed exchanger 22 by heat exchange with the combined biorenewable feed stream in combined feed line 24 to heat the combined biorenewable feed stream and cool the hydrotreated stream in hydrotreatment line 42. The thrice-cooled hydrotreated stream may be still further cooled, possibly after creating steam, and separated to provide a hydrotreated vapor stream and a hydrotreated liquid stream having a lower oxygen concentration than the biorenewable feed stream.

[0044] The hydrotreating stream may be separated in a high temperature separator 48 to provide a high temperature hydrocarbonaceous vapor stream in a high temperature separator overhead line 50 and a high temperature hydrocarbonaceous liquid stream in a high temperature separator bottoms line 52. The separator 48 may be in downstream communication with the hydrotreating reactor 44. The high temperature separator 48 operates at between 177°C (350°F) and 371°C (700°F), and preferably between 232°C (450°F) and 315°C (600°F). The high temperature separator 34 may be operated at a slightly lower pressure than the hydrotreating reactor 44, taking into account pressure drops through intervening equipment. The high temperature separator 48 may be operated at a pressure between 3.4 MPa (gauge) (493 psig) and 20.4 MPa (gauge) (2959 psig). The high temperature vapor stream in the high temperature separator overhead line 50 may have a temperature of the operating temperature of the high temperature separator 48.

[0045] The hot liquid stream in hot separator bottoms line 52 may be separated into two streams: a hot process liquid stream in process line 54, which is taken from the hot liquid stream in hot separator bottoms line 52, and a hot recycle liquid stream in recycle line 16, which is also taken from the hot liquid stream in hot separator bottoms line 52. The hot recycle liquid stream in recycle line 16 may be combined with the bio-renewable feed stream in line 12, as previously described.

[0046] A hot process liquid stream removed from the hot liquid stream in process line 54 may be further separated in hydrotreating separator 56, which may include an enhanced hot separator (EHS), with the aid of stripping gas provided from isomerization overhead line 58. The hot process liquid stream is separated to provide a hydrotreated vapor stream and a hydrotreated liquid stream. Hydrotreating separator 56 may be a high pressure stripping column. In hydrotreating separator 56, the hot process liquid stream from process line 54 flows down through a column where it is partially stripped of potential isomerization catalyst poisons such as hydrogen, carbon dioxide, carbon monoxide, water vapor, propane, hydrogen sulfide, and phosphine by contact with stripping gas from isomerization overhead line 58. The stripping gas may include make-up hydrogen gas passed through isomerization reactor 74 and isomerization separator 80, as described below.

[0047] The stripping gas in isomerization overhead line 58 enters hydrotreater separator 56 below the inlet for the hot process liquid stream in process liquid line 54. Hydrotreater separator 56 may include internals, such as trays or packing, located between the inlet for the hot process liquid stream in process liquid line 54 and the inlet for the stripping gas in isomerization overhead line 58 to facilitate stripping of the hot process liquid stream in process line 54. The stripping gas, including the stripped gas, exits in a hydrotreater vapor stream in hydrotreater overhead line 60 extending from the top of hydrotreater separator 56 and mixes with the hot vapor stream in hot overhead line 50, and the isomerized liquid stream in isomerization bottoms line 82, and optionally a cold aqueous stream in cold aqueous line 87 from the cold separator boot, and a hydrocracked liquid stream in line 186 to provide a cold separator feed stream in cold feed line 84.

[0048] The hydrotreated liquid stream, which may have been stripped, collects at the bottom of hydrotreating separator 56 and flows in hydrotreating bottoms line 62 to the suction side of the bottoms pump. The hydrotreated liquid stream contains diesel range material with high paraffin concentrations due to the composition of the biorenewable feedstock.

[0049] The high temperature liquid stream contains a higher concentration of normal paraffins, so while a desired product, such as transportation fuels, may be fed to hydroprocessing bottoms line 62, the product has poor low temperature fluidity. Therefore, to improve the low temperature fluidity, the hydroprocessed liquid stream may be contacted with a hydroisomerization catalyst under hydroisomerization conditions in hydroisomerization reactor 74 to hydroisomerize the normal paraffins to branched paraffins.

[0050] The hydrotreated liquid stream may be hydroisomerized over a hydroisomerization catalyst in the presence of a hydroisomerization hydrogen stream. Make-up hydrogen gas in make-up line 86 may be compressed in make-up gas compressor 88 and mixed with the hydrotreated liquid stream pumped from hydrotreating bottoms line 62 to provide a hydroisomerization feed stream in hydroisomerization feed line 90. The hydroisomerization feed stream in hydroisomerization feed line 90 may be heated in isomerization feed exchanger 46 by heat exchange with the hydrotreated stream in hydrotreating line 42. The heated hydroisomerization feed stream may optionally be mixed with the total hydrocracked stream or the liquid hydrocracked stream in recycle line 98 to provide a combined hydroisomerization feed stream in combined hydroisomerization feed line 100. Prior to charging the combined hydroisomerization feed stream to the hydroisomerization reactor 74, the combined hydroisomerization feed stream may be heated in a hydroisomerization charge heater 72 to bring the combined hydroisomerization feed stream to a hydroisomerization temperature.

[0051] Hydroisomerization (including hydrodewaxing) of linear hydrocarbons in hydroisomerization reactor 74 may be accomplished over one or more beds of hydroisomerization catalyst, and hydroisomerization may be operated in a co-current mode of operation, a fixed bed trickle bed downflow mode, or a fixed bed liquid loaded upflow mode. is preferred. A make-up hydrogen quench stream removed from make-up line 86 may be fed to hydroisomerization reactor 74 for interbed quenching.

[0052] Suitable hydroisomerization catalysts may include metals and support materials in Group VIII (IUPAC 8-10) of the periodic table. 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 hydrotreating reactor as in FIG. 3, non-precious metals that are not susceptible to sulfur deactivation in sour environments should be used. Examples of suitable non-precious metals include Ni, Mo, Co, W, Mn, Cu, Zn, or Ru. Mixtures of hydrogenation metals such as Co / Mo, Ni / Mo, and Ni / W may also be used. The amount of hydrogenation metal may range from 0.1 to 5 wt.% based on the catalyst weight. Methods for supporting the metals on the support material include, for example, impregnation and heating of the support material with a metal salt of the hydrogenation component. The catalyst support material containing the hydrogenation metals may also be sulfided prior to use.

[0053] The support material may be amorphous or crystalline. Suitable support materials include amorphous alumina, amorphous silica-alumina, ferrierite, 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, ELAPSO-11, ELAPSO-31, ELAPSO-41, laumontite, cancrinite, offretite, hydrogen form of stilbite, magnesium or calcium form of mordenite, and magnesium or calcium form of persite, each of which may be used alone or in combination. ALPO-31 is described in U.S. Patent No. 4,310,440. SAPO-11, SAPO-31, SAPO-37, and SAPO-41 are described in U.S. Patent No. 4,440,871. SM-3 is described in U.S. Patent No. 4,943,424, U.S. Patent No. 5,087,347, U.S. Patent No. 5,158,665, and U.S. Patent No. 5,208,005. MgAPSO is MeAPSO, which is an acronym for metal aluminumsilicophosphate molecular sieve, where the metal Me is magnesium (Mg). Suitable MgAPSO-31 catalysts include MgAPSO-31. MeAPSO is described in U.S. Pat. No. 4,793,984 and MgAPSO is described in U.S. Pat. No. 4,758,419. MgAPSO-31 is the preferred MgAPSO, with 31 meaning MgAPSO having structure type 31. As taught in U.S. Pat. Nos. 4,795,623 and 4,924,027, many naturally occurring zeolites such as ferrierite, which have initially reduced pore size, can be converted to a form suitable for olefin skeletal isomerization by ammonium ion exchange and calcination to remove associated alkali metal or alkaline earth metal to produce substantially hydrogen form. Additional catalysts and conditions for skeletal isomerization are disclosed in U.S. Pat. Nos. 5,510,306, 5,082,956, and 5,741,759. The hydroisomerization catalyst may also include a modifier selected from the group consisting of lanthanum, cerium, praseodymium, neodymium, samarium, gadolinium, terbium, and mixtures thereof, as described in U.S. Pat. Nos. 5,716,897 and 5,851,949. Other suitable support materials include ZSM-22, ZSM-23, and ZSM-35, which are described for use in dewaxing in U.S. Pat. No. 5,246,566 and in an article by S. J. Miller entitled "New Molecular Sieve Process for Lube Dewaxing by Wax Isomerization," 2 Microporous Materials 439-449 (1994). U.S. Pat. Nos. 5,444,032 and 5,444,032 are also suitable. No. 608,968 teaches a suitable bifunctional catalyst composed of amorphous silica-alumina gel and one or more metals belonging to group VIIIA, which is effective in the hydroisomerization of long chain normal paraffins containing more than 15 carbon atoms. Nos. 5,981,419 and 5,908,134 teach a suitable bifunctional catalyst comprising (a) a porous crystalline material isostructurally similar to beta zeolite selected from borosilicates (BOR-B) and boroaluminosilicates (Al-BOR-B) with a SiO2:Al2O3 ratio higher than 300:1, and (b) one or more metals belonging to group VIIIA selected from platinum and palladium in an amount comprised within the range of 0.05-5 wt.%. V. Calemma et al., App. Catal. A: Gen., 190 (2000), 207 teaches yet another suitable catalyst. Alumina or silica may be added to the support material.

[0054] DI-100, available from UOP LLC (Des Plaines, Ill.), may be a suitable hydroisomerization catalyst.

[0055] Hydroisomerization conditions typically include temperatures from 150° C. (302° F.) to 450° C. (842° F.) and pressures from 1724 kPa (abs) (250 psia) to 13.8 MPa (abs) (2000 psia). In another embodiment, hydroisomerization conditions include temperatures from 300° C. (572° F.) to 360° C. (680° F.) and pressures from 3102 kPa (abs) (450 psia) to 6895 kPa (abs) (1000 psia).

[0056] The hydroisomerized stream in hydroisomerization line 76 from isomerization reactor 74 is a branched paraffin rich stream. The term "rich" means that the effluent stream has a higher concentration of branched paraffins than the stream entering isomerization reactor 74, and preferably contains branched paraffins greater than 50 wt.% of the total paraffin content. It is contemplated that the hydroisomerized effluent may contain 80, 90, or 95 wt.% of the total paraffin content branched paraffins. The hydroisomerization conditions in hydroisomerization reactor 74 are selected to avoid undesired cracking, and thus the primary products in the hydroisomerized stream in hydroisomerization line 76 are branched paraffins. By avoiding undesired cracking, the hydroisomerized stream in hydroisomerization line 76 will have a higher yield to C9+ hydrocarbons for producing jet or diesel fuel. The optimal amount of residual normal paraffins in line 76 depends on the selectivity of the hydroisomerization catalyst, but may typically be 1-7 wt.%.

[0057] The hydroisomerized stream in hydroisomerization line 76 from isomerization reactor 74 flows to isomerate exchanger 77 where it is cooled by heat exchange with a cold liquid stream in cold bottoms line 92 before entering hydroisomerization separator 80 where it is separated into a liquid hydroisomerized stream and a steam hydroisomerized stream. The steam hydroisomerized stream in hydroisomerization overhead line 58 extending from the top of hydroisomerization separator 80 flows to hydrotreater separator 56 where it may function as a stripping gas. A portion of the steam hydroisomerized stream may optionally bypass hydrotreater separator 56 and enter cold feed line 84 through a control valve.

[0058] The liquid hydroisomerized stream in hydroisomerization bottoms line 82 extending from the bottom of hydroisomerization separator 80 may be sent directly to distillation column 140 to produce a product stream without condensation and cooling. However, the liquid hydroisomerized stream from hydroisomerization separator 80 in hydroisomerization bottoms line 82 may be further separated in cold separator 94 along with a hot vapor stream in hot overhead line 50, a hydrotreating vapor stream in hydrotreating overhead line 60, a cold aqueous stream in cold aqueous line 87 from the boot of cold separator 94, and a liquid hydrocracked stream in hydrocracker separator bottoms line 186, all combined in the cold separator stream in cold separator feed line 84. A cold aqueous stream in cold aqueous line 87 supplemented with water from line 85 is added to cold separator feed line 84 to dissolve salts that may be present in the hydrocarbon phase. can be.

[0059] The cold separator stream in cold separator feed line 84 is cooled and fed to cold separator 94 .

[0060] In cold separator 94, the vapor components in the hydroisomerized liquid stream will separate and rise with the hydrotreated vapor stream from hydrotreating overhead line 60 and the hot vapor stream in hot overhead line 50 to provide a cold vapor stream in cold overhead line 96. The cold vapor stream in cold overhead line 96 may be passed to a tray or pack type recirculating scrubbing column 104 where it is scrubbed with a scrubbing liquid, such as an aqueous solution provided by scrubbing liquid line 102, to remove acid gases, including hydrogen sulfide and carbon dioxide, by extraction into the aqueous solution. Preferred scrubbing liquids include Selexol™ available from UOP LLC, Des Plaines, Ill., as well as diethanol amine (DEA), monoethanolamine (NO), and ethanolamine (EO). Examples of suitable scrubbing liquids include amines such as alkanolamines, including monoethanol amine (MEA), methyl diethanol amine (MDEA), diisopropanol amine (DIPA), and diglycol amine (DGA). Other scrubbing liquids can be used in place of or in addition to the preferred amines. The lean scrubbing liquid contacts the low temperature vapor stream to absorb acid gas contaminants such as hydrogen sulfide and carbon dioxide. The resulting "sweetened" low temperature vapor stream is removed from the top outlet of the recycle scrubber column 104 in a recycle scrubber overhead line 106, and rich scrubbing liquid is removed from the bottom at the bottom outlet of the recycle scrubber column 104 in a recycle scrubber bottom line 108. Spent scrubbing liquid from the bottom can be regenerated and recycled back to the recycle scrubbing column 104 in the scrubbing liquid line 102.

[0061] The scrubbed hydrogen-rich stream exits the scrubber via recycle scrubber overhead line 106 and may be compressed in recycle compressor 110. The compressed hydrogen stream in scrubber overhead line 106 supplies hydrogen to the hydrotreating hydrogen stream in hydrotreating hydrogen line 20, the interbed quench stream through quench line 18 for guard bed reactor 26 and hydrotreating reactor 44, and the hydrocracked hydrogen stream in line 152 for the hydrocracking reactor.

[0062] The recycle scrubbing column 104 may be operated at a gas inlet temperature between 38° C. (100° F.) and 66° C. (150° F.), and an overhead pressure between 3 MPa (gauge) (435 psig) and 20 MPa (gauge) (2900 psig). Suitably, the recycle scrubbing column 104 may be operated at a temperature between 40° C. (104° F.) and 125° C. (257° F.), and a pressure between 1200 and 1600 kPa. The temperature of the hot vapor stream to the recycle scrubbing column 104 may be between 20° C. (68° F.) and 80° C. (176° F.), and the temperature of the scrubbing liquid stream in the scrubbing liquid line 102 may be between 20° C. (68° F.) and 70° C. (158° F.).

[0063] Liquid components from the liquid hydrocracked stream in line 186 sink into the cold liquid stream in cold bottoms line 92. The cold liquid stream in cold bottoms line 92 contains hydrocarbons useful as fuels in the diesel boiling range, as well as other hydrocarbons such as propane, naphtha, and jet fuel. Thus, they may be fractionated in distillation column 140. A cold aqueous stream may be collected in cold aqueous line 87 from the boot of the cold separator.

[0064] In one embodiment, the cold liquid stream may first be stripped in stripping column 120 to remove hydrogen sulfide and other gases. The cold liquid stream in cold bottoms line 92 is converted to hydrogen sulfide in isomerize exchanger 77 by heat exchange with the hydroisomerization stream in hydroisomerization line 76. 1 to heat a cold liquid stream which may be fed to stripping column 120 at an inlet which may be in the lower half of the column. A stripping medium which is an inert gas such as steam from stripping medium line 122 may be used to strip the light gases from cold bottoms line 92. Stripping column 120 supplies an overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases to stripper overhead line 126 and a stripped liquid isomerization stream to stripped bottoms line 128. The overhead stripping stream may be condensed and separated in stripping receiver 130. A net stripper overhead line 132 from receiver 130 may carry the net stripper gas stream to sponge absorber 160 for LPG recovery. Unstabilized liquid naphtha from the bottom of receiver 130 in a liquid overhead stream may be transported in stripper receiver bottoms line 134 to debutanizer column 170 for naphtha and LPG recovery. A sour water stream may be collected from the boot of overhead receiver 130.

[0065] Stripping column 120 may be operated at a bottom temperature between 149° C. (300° F.) and 288° C. (550° F.), preferably at or below 260° C. (500° F.), and an overhead pressure between 0.35 MPa (gauge) (50 psig), preferably at or above 0.70 MPa (gauge) (100 psig) and 2.0 MPa (gauge) (290 psig). The temperature in overhead receiver 130 ranges from 38° C. (100° F.) to 66° C. (150° F.), and the pressure is essentially the same as in the top of stripping column 120.

[0066] The stripped liquid hydroisomerization stream in stripper bottoms line 128 may be fed to distillation column 140. Distillation column 140 may be reboiled by heat exchange with a suitable hot stream or in a fired heater to provide the heat required for the distillation. Alternatively, a stripping medium that is an inert gas such as steam from stripping medium line 142 may be used to heat the column. Distillation column 140 provides an overhead gas stream of naphtha and steam in overhead line 146 and a distillation bottoms liquid stream in distillation bottoms line 148. The distillation overhead stream may be completely condensed and separated from water in distillation receiver 178. Unstabilized liquid naphtha from the bottom of receiver 178 in distillation overhead liquid line 154 may be combined with the naphtha stream in line 176. A sour water stream may be collected from the boot of distillation receiver 178.

[0067] Two product streams may be removed from the side of the distillation column 140. The first side stream, removed above the first side stream, is removed in a first side line 144 and may comprise a jet fuel stream having a T5 of 115° C. (239° F.) to 130° C. (266° F.) and a T90 of 240° C. (464° F.) to 270° C. (518° F.). The jet fuel may meet ASTM D7566 jet fuel specifications. The second side stream in a second side line 152 may comprise a light diesel stream having a T5 of 230° C. (446° F.) to 250° C. (482° F.) and a T90 of 279° C. (560° F.) to 296° C. (590° F.). The distillation bottoms liquid stream in distillation bottoms line 148 may be a heavy diesel stream having a T5 of 279° C. (560° F.) to 296° C. (590° F.) and a T90 of 343° C. (650° F.) to 399° C. (750° F.). Both side streams may be stripped in a side stripper, not shown.

[0068] The normal paraffins will be concentrated in the heavier hydrocarbon stream. Distilling the jet fuel in the first side stream, and also the light diesel in the second side stream, will significantly enrich the concentration of normal paraffins in the heavy diesel stream in stripper bottoms line 148, leaving a jet fuel stream and a light diesel stream with acceptable normal paraffin concentrations that allow the jet fuel stream to meet jet fuel specifications. The heavy diesel stream in distillation bottoms line 148, with its increased concentration of normal paraffins, can then be subjected to additional hydroisomerization or hydrotreating with recycle to further manage the normal paraffin concentration. The normal paraffins may be subjected to hydrocracking in a hydrocracking reactor. Enrichment of normal paraffins concentration in hydrocracking reactor 150 increases conversion by increasing reaction rate. Higher normal paraffins concentration also promotes more production of isoparaffins by starting the reaction further from equilibrium in hydroisomerization reactor 74. In one embodiment, the normal paraffins concentration of the jet fuel stream in first side line 144 may be 1% or less, suitably less than 0.6% and preferably 0.5% or less by weight of the total paraffin content of the jet fuel stream in line 144. A preferred paraffin concentration may meet a freezing point of -40°C.

[0069] In one embodiment, the concentration of normal paraffins of a given carbon number in the distillate bottoms line 148 should be at least two times, and more preferably at least three times, the concentration in the hydroisomerized stream in the hydroisomerization line 76. This enrichment is needed to promote more selective hydrocracking of normal paraffins to jet and diesel range products in the hydrocracking reactor 150 and / or selective hydroisomerization of normal paraffins in the hydroisomerization reactor 74, thereby increasing jet fuel yields.

[0070] Distillation column 140 may be operated at a bottom temperature of from 149° C. (300° F.) to 288° C. (550° F.), preferably not more than 260° C. (500° F.), and an overhead pressure of 0.35 MPa (gauge) (50 psig), preferably from at least 0.70 MPa (gauge) (100 psig) to not more than 2.0 MPa (gauge) (290 psig). The temperature in overhead receiver 178 ranges from 38° C. (100° F.) to 66° C. (150° F.), and the pressure is essentially the same as in the overhead of stripping column 140.

[0071] The sponge absorber column 160 may receive the net stripper gas stream in net stripper overhead line 132. A lean absorbent stream in lean absorbent line 162 may be fed to the sponge absorber column 160 through an absorbent inlet. The lean absorbent may include a naphtha stream in lean absorbent line 162 from a debutanizer bottoms stream, possibly in line 176. In the sponge absorber column 160, the lean absorbent stream and the net stripper gas stream are contacted in a countercurrent manner. The sponge absorbent absorbs LPG hydrocarbons from the net stripper gas stream into an absorbent rich stream.

[0072] The hydrocarbons absorbed by the sponge absorbent consist of some of the methane and ethane in the net stripper gas stream, as well as most of the LPG, C3 and C4 hydrocarbons, and any C5 and C6 hydrocarbons. 6+and light naphtha hydrocarbons. The sponge absorber column 160 may be operated at a temperature of 34° C. (93° F.) to 60° C. (140° F.)° C. and at a pressure essentially the same as or lower than the stripping receiver 130 with little friction loss. A sponge absorbed off-gas stream depleted in LPG hydrocarbons is withdrawn from the top of the sponge absorber column 160 at an overhead outlet through sponge absorber overhead line 164. The sponge absorbed off-gas stream in sponge absorber overhead line 164 may be transported to a hydrogen recovery unit, not shown, for hydrogen recovery. A rich absorbent stream rich in LPG hydrocarbons is withdrawn from the bottom of the sponge absorber column 160 at a bottom outlet into rich absorber bottom line 166 and may be fed to the debutanizer column 170 via the stripper liquid overhead stream in stripper receiver bottom line 134.

[0073] In one embodiment, the debutanizer column 170 converts the stripper liquid overhead stream and the rich absorbent stream in the stripper receiver bottoms stream 134 into a primarily C 5+ The debutanizer column 170 may be fractionated into a debutanizer bottoms stream containing hydrocarbons and a debutanizer overhead stream containing LPG hydrocarbons. The debutanizer overhead stream in debutanizer overhead line 172 may be completely condensed into a debutanizer overhead liquid stream in net receiver bottoms line 174 with reflux to the debutanizer column 170 and recovery of LPG. The debutanizer bottoms stream may be withdrawn from the bottom of the debutanizer column 170 into debutanizer bottoms line 176. A reboil stream removed from the debutanizer bottoms stream of may be boiled in a reboil line and sent back to the debutanizer column 170 to provide heat to the column. Alternatively, a hot inert medium stream, such as steam, may be fed to column 170 to provide heat.

[0074] The distillation bottoms stream in distillation bottoms line 148 may contain heavy diesel boiling range hydrocarbons. Normal paraffins are concentrated in the bottoms stream and are therefore well suited for hydrocracking or further hydroisomerization. Refiners may wish to convert the heavy diesel to jet fuel to improve the composition of their product list. Thus, the heavy diesel stream in distillation bottoms line 148 may be mixed with a hydrocracked hydrogen stream in line 152, taken from the compressed make-up hydrogen stream in line 86, heated in heater 154, and fed in line 156 to hydrocracking reactor 150.

[0075] Utilizing hydroisomerization, distillation, and hydrocracking together provides unique advantages. For example, the hydroisomerized stream may require a specification of 0.8% or less 16 carbon atom normal paraffins relative to all 16 carbon atom paraffins to meet the jet freezing point specification. However, to achieve this specification in the hydroisomerization reactor 74 alone, the hydroisomerized stream may produce only 85% jet fuel range hydrocarbons due to parallel undesirable hydrocracking reactions in the hydroisomerization reactor resulting from operating the hydroisomerization reactor 74 at the increased temperature and residence time required to achieve sufficient conversion of 16 carbon atom normal paraffins to such low concentrations. In accordance with the present disclosure, by relaxing the specification of 16 carbon atom normal paraffins in the hydroisomerized stream by increasing it from 0.8% to 3% normal paraffins, the yield of jet fuel range material could be increased to 93%. These normal paraffins could then be enriched in distillation column 140 to at least 6% of the 16 carbon paraffins in the distillate bottoms stream 148 and sent to hydrocracking reactor 150 where they could be more selectively hydrocracked and hydroisomerized, possibly with recycle to hydroisomerization reactor 74, to produce an overall jet range yield of greater than 85%. Similarly, the same principles can be applied to other paraffins of different carbon numbers, such as 18 carbon atom paraffins, with a normal paraffin limit in the final fuel product.

[0076] Hydrocracking reactor 150 may be a fixed bed reactor containing one or more vessels, single or multiple catalyst beds in each vessel, and various combinations of hydrocracking catalysts in one or more vessels. Hydrocracking reactor 150 may be operated in a conventional continuous gas phase, moving bed, or fluidized bed hydroprocessing reactor. A portion of the heavy diesel stream in line 160

[0077] The heavy diesel stream is hydroprocessed over a hydrocracking catalyst in a hydrocracking reactor in the presence of a hydrocracked hydrogen stream from hydrocracking hydrogen line 152 to provide a hydrocracked stream. A portion of the diesel stream in line 168 may be used as an interbed quench to cool the hydrocracked effluent between the catalyst beds. In another embodiment, additional hydrogen may be added between the catalyst beds.

[0078] The hydrocracking reactor may provide an overall conversion of at least 20% by volume, typically greater than 60% by volume, of the heavy diesel stream in the distillation bottoms line 148 to products boiling below the heavy diesel range of 293° C. (560° F.) to 310° C. (590° F.). The hydrocracking reactor 150 may be operated at a partial conversion of greater than 30% by volume of the feed, or at least a full conversion of 90% by volume, based on the overall conversion. The hydrocracking reactor 40 may be operated at mild hydrocracking conditions that provide an overall conversion of 20-60% by volume, preferably 20-50% by volume, of the hydrocarbon feed stream to products boiling below the heavy diesel boiling range.

[0079] The hydrocracking catalyst comprises one or more Group VIII or Group VIB metal hydrogenation components. An amorphous silica-alumina base or a zeolite base in combination with may be utilized to selectively produce a balance of light diesel and jet fuel distillates. In another embodiment, catalysts comprising generally any crystalline zeolite cracking base upon which a Group VIII metal hydrogenation component is deposited may be suitable. An additional hydrogenation component may be selected from Group VIB for incorporation into the zeolite base.

[0080] Zeolite cracking bases, sometimes referred to in the art as molecular sieves, are usually composed of silica, alumina, and one or more exchangeable cations, such as sodium, magnesium, calcium, and rare earth metals. They are further characterized by relatively uniform diameter crystal pores of 4-14 angstroms. It is preferred to use zeolites having a relatively high silica / alumina molar ratio of 3-12. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, dachyardite, chabazite, erionite, and faujasite. Suitable synthetic zeolites include, for example, B, X, Y, and L crystal types, such as synthetic faujasite and mordenite. Preferred zeolites are those having crystal pore diameters of 8-12 angstroms and a silica / alumina molar ratio of 4-6. One example of a zeolite in the preferred group is the synthetic Y molecular sieve.

[0081] Naturally occurring zeolites are usually found in sodium, alkaline earth metal, or mixed forms. Synthetic zeolites are almost always prepared in the sodium form. In any case, for use as a cracking base, it is desirable to ion-exchange most or all of the original zeolite monovalent metal with a polyvalent metal and / or with an ammonium salt, followed by heating to decompose the ammonium ions associated with the zeolite, leaving behind hydrogen ions and / or exchange sites at those sites which are in effect decationized by further removal of water. This type of hydrogen or "decationized" Y zeolite is described in more detail in U.S. Pat. No. 3,100,006.

[0082] Mixed polyvalent metal-hydrogen zeolites can be prepared by ion-exchanging with ammonium salts, followed by partial back-exchanging with polyvalent metal salts, and then calcining. In some cases, as in the case of synthetic mordenite, the hydrogen form can be prepared by direct acid treatment of the alkali metal zeolite. In one aspect, the preferred cracking bases are those that are at least 10% by weight, and preferably at least 20% by weight, deficient in metal cations, based on the initial ion-exchange capacity. In another aspect, a desirable stable class of zeolites is one in which at least 20% by weight of the ion-exchange capacity is filled by hydrogen ions.

[0083] The active metals used as hydrogenation components in the preferred hydrocracking catalysts of the present invention are those of Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. In addition to these metals, other promoters may also be used therewith, including metals of Group VIB, such as molybdenum and tungsten. The amount of hydrogenation metal in the catalyst may vary within a wide range. In general, any amount between 0.05% and 30% by weight may be used. In the case of precious metals, it is usually preferred to use 0.05 to 2% by weight of precious metal. Although precious metals may deactivate precious metal catalysts, they may be preferred as hydrogenation metals on hydrocracking catalysts to provide selectivity to jet fuel, due to the absence of hydrogen sulfide and ammonia being removed upstream in the process.

[0084] The method for incorporating the hydrogenation metals is to contact the base material with an aqueous solution of a suitable compound of the desired metal, where the metal is present in cationic form. After addition of the selected hydrogenation metal or metals, the resulting catalyst powder is filtered, dried, and optionally diluted with a lubricant. The base component is pelletized with the addition of a binder, etc., and calcined in air at a temperature of, for example, 371° C. (700° F.) to 648° C. (200° F.) to activate the catalyst and decompose the ammonium ions. Alternatively, the base component may be pelletized, followed by the addition of the hydrogenation component and activation by calcination.

[0085] The aforementioned catalysts may be used in undiluted form, or the powder catalyst may be mixed and co-pelletized with other relatively less active catalysts, diluents, or binders, such as alumina, silica gel, silica-alumina cogels, activated clays, etc., in proportions ranging from 5 to 90% by weight. These diluents may be used neat or may contain small amounts of added hydrogenation metals, such as Group VIB and / or Group VIII metals. Additional metal-promoted hydrocracking catalysts may also be utilized in the process of the present invention, including, for example, aluminophosphate molecular sieves, crystalline chromosilicates, and other crystalline silicates. Crystalline chromosilicates are more fully described in U.S. Pat. No. 4,363,178.

[0086] According to one approach, hydrocracking conditions 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) (400 psig) to 20.7 MPa (gauge) (3000 psig), and a reaction time of 0.4 to 2.5 hours. -1 and a liquid hourly space velocity (LHSV) of less than 421 Nm 3 / m 3 Oil (2,500scf / bbl)~2,527Nm 3 / m 3 The hydrogen rate of the oil (15,000 scf / bbl) may be included.

[0087] The hydrocracked stream may exit hydrocracking reactor 150 in hydrocracking line 158. In one embodiment, the hydrocracked stream may be fed directly to hydroisomerization reactor 74. In this embodiment, the hydrocracked stream in hydrocracking line 158 is recycled directly through line 159 and through a control valve thereon to recycle line 98. From recycle line 98, the hydrocracked stream is mixed with the hydroisomerization feed stream in 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.

[0088] In an alternative embodiment, the hydrocracked stream in hydrocracker line 158 may be transported in hydrocracker separator line 181 through a control valve thereon to hydrocracker separator 180. The hydrocracked stream may then be separated in hydrocracker separator 180. The hydrocracked stream may be separated in hydrocracker separator 180 to provide a hydrocarbonaceous steam hydrocracked stream in hydrocracker separator overhead line 182 and a hydrocarbonaceous hydrocracked liquid stream in hydrocracker separator bottoms line 184. The hydrocracker separator 180 may be in downstream communication with the hydrocracker reactor 150. The hydrocracker separator 180 operates at between 177° C. (350° F.) and 371° C. (700° F.), preferably between 232° C. (450° F.) and 315° C. (600° F.). Hydrocracker separator 180 may be operated at a slightly lower pressure than hydrocracking reactor 150 to account for pressure drops through intervening equipment. Hydrocracker separator 180 may be operated at a pressure between 3.4 MPa (gauge) (493 psig) and 20.4 MPa (gauge) (2959 psig). The steam hydrocracked stream in hydrocracker separator overhead line 182 may have a temperature of the operating temperature of hydrocracker separator 180. The steam hydrocracked stream in hydrocracker separator overhead line 182 may be combined with stripping gas in isomerization overhead line 58 removed from the hot separator bottoms stream to strip the process stream in line 54.

[0089] The hydrocracked liquid stream in hydrocracker separator bottoms line 184 can be treated in at least two ways. In a first embodiment, a control valve on line 186 is opened to allow at least a portion of the hydrocracked liquid stream from line 184 in combination with the cold separator feed stream in line 84 to be treated with a liquid hydroisomerization stream in hydroisomerization bottoms line 82, a hot separator feed stream in line 50, and a hot separator feed stream in line 52. , along with a hydrotreated vapor stream in hydrotreating overhead line 60, and a cold aqueous stream in cold aqueous line 87, may be cooled and separated in cold separator 94. The jet fuel and light diesel components in the hydrocracked liquid stream are then optionally stripped in stripping column 120 and distilled in distillation column 140 to produce a jet fuel stream in line 144, a light diesel stream in line 152, and a heavy diesel stream in line 148.

[0090] In a second embodiment, a control valve on the hydroisomerization tie line 188 is opened to permit flow of at least a portion of the hydrocracker separator bottoms line 184 in the form of a hydrocracked liquid stream to the hydroisomerization reactor 74 to improve the low temperature fluidity of the jet fuel range hydrocarbons produced in the hydrocracking reactor 150. The liquid hydrocracked stream in the hydroisomerization tie line 188 is transported to the recycle 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 charge heater 72 and hydroisomerized in the hydroisomerization reactor 74 as previously described. The hydroisomerized and hydrocracked liquid is then processed with the remainder of the hydroisomerization stream in line 76.

[0091] Figure 2 shows an alternative embodiment in which a bed of hydrocracking catalyst 150' and a bed of hydroisomerization catalyst 74' are located within a single reactor vessel 190, which may be more ideal in the event of a repair than the embodiment of Figure 1. In Figure 2, elements having the same configuration as Figure 1 have the same reference numbers as Figure 1. Elements in Figure 2 having a different configuration than the corresponding elements in Figure 1 have the same reference numbers but are designated with a prime symbol ('). The configuration and operation of the embodiment of Figure 2 is essentially the same as Figure 1, with the following exceptions.

[0092] The heavy diesel stream in distillation bottoms line 148' is mixed with the hydrocracked hydrogen stream in line 152', heated in heater 154', and fed to hydrocracking / hydroisomerization reactor vessel 190. The heated heavy diesel stream is fed through a first reactor inlet to hydrocracking catalyst bed 150'. As in FIG. 1, the hydrocracking catalyst can be a precious metal catalyst because hydrogen sulfide and ammonia, which deactivate the hydrocracking catalyst, are removed upstream of hydrocracking catalyst bed 150'. All of the hydrocracking stream leaving hydrocracking catalyst bed 150' mixes with the isomerization feed stream in isomerization feed line 90 in the interbed space 75 between hydrocracking catalyst bed 150' and hydroisomerization catalyst bed 74'. The mixture of hydrocracked and isomerization feed streams enters hydroisomerization catalyst bed 74', located below hydrocracking catalyst bed 150', from interbed space 75. The hydrocracked stream and the isomerization feed stream are hydroisomerized together in the presence of hydrogen over a hydroisomerization catalyst. The hydroisomerization stream exits hydroisomerization bed 74' in hydroisomerization line 76 and is treated as described for FIG.

[0093] The conditions in the hydrocracking / hydroisomerization reactor 190 are 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) (400 psig) to 20.7 MPa (gauge) (3000 psig), and a reaction time of 0.4 to 2.5 hours. -1 Liquid hourly space velocity (LHSV) of less than 421 Nm 3 / m 3 Oil (2,500scf / bbl)~2,527Nm 3 / m 3 The hydrogen rate of the oil (15,000 scf / bbl) may be included.

[0094] FIG. 3 shows a further alternative embodiment in which a bed of hydrotreating catalyst 44'' and a bed of hydroisomerization catalyst 74'' are located within a single reactor vessel 40. Hydroisomerization is carried out in a sour environment, in the presence of hydrogen sulfide, water, and ammonia. A hydrocracking reactor 150'' converts heavy diesel to jet fuel components. In FIG. 3, elements having the same configuration as in FIG. 1 or FIG. 2, respectively, have the same reference numbers as in FIG. 1 or FIG. 2. Elements in FIG. 3 having a different configuration than the corresponding elements in FIG. 1 or FIG. 2, respectively, have the same reference numbers, but are arranged in a dual-phase reactor. 3 is indicated by an imaginary symbol (''). The construction and operation of the embodiment of FIG. 3 is essentially the same as that of FIG. 1 or FIG. 2, with the following exceptions.

[0095] The contact feed stream from the guard bed reactor 26 in the contact feed line 32 is heated in the guard bed discharge heat exchanger 34 and heater 36 and fed into the hydrotreating / hydroisomerization reactor vessel 40, which may contain at least two catalyst beds. The heated contact feed stream is fed through a first reactor inlet to a hydrotreating catalyst bed 44''. More than one catalyst bed 44'' may be utilized. All of the hydrotreating stream exiting the hydrotreating catalyst bed 44'' (or the last hydrotreating catalyst bed 44'' if multiple hydrotreating beds are utilized) mixes with the quench hydrogen stream in the interbed space 45 between the hydrotreating catalyst bed 44' and the hydroisomerization catalyst bed 74''. The hydrotreating stream, replenished with quench hydrogen and cooled, passes from the interbed space 45 into the hydroisomerization catalyst bed 74'' located below the hydrotreating catalyst bed 44''. The hydrotreating stream is hydroisomerized in the presence of hydrogen over the hydroisomerization catalyst in the hydroisomerization catalyst bed 74''. More than one hydroisomerization catalyst bed 74'' may be utilized.

[0096] Hydrotreating / hydroisomerization reaction temperatures may range from 343° C. (650° F.) to 427° C. (800° F.), preferably from 349° C. (690° F.) to 400° C. (752° F.). Generally, hydrotreating / hydroisomerization conditions include pressures from 700 kPa (100 psig) to 21 MPa (3000 psig).

[0097] A hydroisomerized stream is produced in hydroisomerization line 42'' from hydroisomerization catalyst bed 74''. The hydroisomerized stream in hydroisomerization line 42'' may first flow to combined hydrocracking feed exchanger 46'' to heat the hydrocracking feed stream in hydrocracking feed line 90'' and to cool the hydroisomerized stream. As previously described, the cooled hydroisomerized stream in hydroisomerization line 42'' may then exchange heat with the contacted biorenewable feed stream in guard bed discharge heat exchanger 34 to cool the hydroisomerized stream in hydroisomerization line 42'' and to heat the contacted biorenewable feed stream. The twice-cooled hydroisomerized steam in hydroisomerization line 42" may then be further cooled in combined feed exchanger 22 by heat exchange with the combined bio-renewable feed stream in combined feed line 24 to heat the combined bio-renewable feed stream and cool the hydroisomerized stream in hydroisomerization line 42". The thrice-cooled hydroisomerized stream may be further cooled, possibly after creating steam, and separated to provide a hydroisomerized vapor stream and a hydrotreated liquid stream.

[0098] The hydroisomerization stream may be separated in high temperature separator 48 to provide a hot hydrocarbonaceous vapor stream in high temperature separator overhead line 50 and a hot hydrocarbonaceous liquid stream in high temperature separator bottoms line 52. The hot vapor stream in high temperature separator overhead line 50 may have a temperature of the operating temperature of high temperature separator 48.

[0099] The hot liquid stream in hot separator bottoms line 52 may be separated into two streams: a hot process liquid stream in process line 54, which is taken from the hot liquid stream in hot separator bottoms line 52, and a hot recycle liquid stream in recycle line 16, which is also taken from the hot liquid stream in hot separator bottoms line 52. The hot recycle liquid stream in recycle line 16 may be combined with the bio-renewable feed stream in line 12, as previously described.

[0100] A hot process liquid stream removed from the hot liquid stream in process line 54 may be further separated in hydroisomerization separator 56'', which may contain EHS, with the aid of stripping gas provided from hydrocracking vapor line 58''. The hot process liquid stream is separated to provide a hydroisomerized vapor stream and a hydroisomerized liquid stream. Hydroisomerization separator 56'' may be a high pressure stripping column. In hydroisomerization separator 56'', the process The hot process liquid stream from line 54 flows down through the column where it is partially stripped of potential isomerization catalyst poisons such as hydrogen, carbon dioxide, carbon monoxide, water vapor, propane, hydrogen sulfide, and phosphine by contacting it with stripping gas from hydrocracking vapor line 58''. The stripping gas may include make-up hydrogen gas that has been passed through hydrocracking reactor 150'' and hydrocracking separator 80'', as described below.

[0101] The stripping gas in hydrocracked vapor line 58'' enters hydroisomerization separator 56'' below the inlet for the hot process liquid stream in process liquid line 54. Hydroisomerization separator 56'' may include internals, such as trays or packing, located between the inlet for the hot process liquid stream in process liquid line 54 and the inlet for the stripping gas in hydrocracked vapor line 58'' to facilitate stripping of the hot process liquid stream in process line 54. The stripped gas and stripping gas exit into a hydroisomerization vapor stream in hydroisomerization overhead line 60'' extending from the top of hydroisomerization separator 56'' and mix with the hot vapor stream in hot overhead line 50, and the hydrocracked liquid stream in hydrocracked bottoms line 82'', and optionally a cold aqueous stream in cold aqueous line 87 from the cold separator boot to provide a cold separator feed stream in cold feed line 84''.

[0102] The hydroisomerized liquid stream, which may have been stripped, collects at the bottom of hydroisomerization separator 56'' and flows in hydroisomerization bottoms line 62'' to the suction side of the bottoms pump. The hydroisomerized liquid stream contains primarily diesel range material.

[0103] The hydroisomerized liquid stream may be hydrocracked over a hydrocracking catalyst in the presence of a hydrocracked hydrogen stream. Make-up hydrogen gas in make-up line 86 may be compressed in make-up gas compressor 88 and mixed with the hydroisomerized liquid stream pumped from hydroisomerization bottoms line 62'' and the distillation bottoms stream in distillation bottoms line 148'' to provide a combined hydrocracked feed stream in hydrocracking feed line 90''. The distillation bottoms stream contains heavy diesel that may be too heavy to make jet fuel specifications. Thus, by hydrocracking the heavy diesel in the distillation bottoms stream, greater yields of light diesel and jet fuel may be produced.

[0104] The combined hydrocracking feed stream in hydrocracking feed line 90'' may be heated in combined hydrocracking feed exchanger 46'' by heat exchange with the hydroisomerization stream in hydroisomerization line 42'' and heated in hydrocracking charge heater 72'' to bring the combined hydrocracking feed stream to hydrocracking temperatures prior to charging to hydrocracking reactor 150''. The hydrocracking in hydrocracking reactor 150'' is as described in FIG. 1.

[0105] The hydrocracked stream in hydrocracking line 76'' from hydrocracking reactor 150'' has a reduced boiling point compared to the hydrocracking feed steam. The hydrocracked stream in hydrocracking line 76'' from hydrocracking reactor 150'' flows to hydrocracking exchanger 77'' for heat exchange with a cold liquid stream in cold bottoms line 92 for cooling before entering hydrocracking separator 80'' for separation into a liquid hydrocracked stream and a steam hydrocracked stream. The steam hydrocracked stream in hydrocracking overhead line 58'' extending from the top of hydrocracking separator 80'' flows to hydroisomerization separator 56'' and may function as a stripping gas in hydroisomerization separator 56''. A portion of the steam hydrocracked stream may optionally bypass hydroisomerization separator 56'' and enter cold feed line 84 through a control valve.

[0106] The remainder of the construction and operation of the embodiment of FIG. 3 is as described in FIGS.

[0107] FIG. 4 illustrates a bed of hydrocracking catalyst 150' and a bed of hydroisomerization catalyst 74' located in a single reactor vessel 190, but in a deoctadecanizer column 200. 4 shows an alternative embodiment of FIG. 2 that performs a split between light and heavy diesel depending on the fuel. In FIG. 4, elements having the same configuration as FIG. 2 have the same reference numbers as FIG. 2. Elements in FIG. 4 that have a different configuration than the corresponding elements in FIG. 2 have the same reference numbers but are marked with an asterisk symbol ( * 4. The configuration and operation of the embodiment of FIG. 4 is essentially the same as that of FIG. 2, with the following exceptions.

[0108] Hydrotreating column bottoms line 62, which may be stripped * The hydrotreated liquid stream in collects at the bottom of hydrotreater separator 56 and flows to a deoctadecanizer column 200 which distills the hydrotreated bottoms stream to produce C in overhead line 202. 17 - an overhead stream containing light diesel and light gases of hydrocarbons, and C in bottoms line 204 18 + a bottoms stream comprising heavy diesel of hydrocarbons. The deoctadecanizer column 200 may be reboiled in a fired heater or by heat exchange with a suitable hot stream to provide the heat required for distillation. Alternatively, the column may be heated with a stripping medium that is an inert gas such as steam from stripping medium line 206. The deoctadecanizer column 200 produces in overhead line 202 naphtha and C 10 ~C 17 The overhead stream is condensed and separated from water in the deoctadecanizer receiver 210 to provide an overhead gas stream of linear hydrocarbons in the range of 0.1 to 1.5 carbon atoms, as well as water vapor. The overhead stream is condensed and separated from water in the deoctadecanizer receiver 210 to provide an overhead liquid stream in line 208. 10 ~C 17The unstabilized naphtha stream may be taken in the net steam stream in line 212 overhead of receiver 210. A sour water stream may be collected from the boot of deoctadecanizer receiver 210. The deoctadecanizer overhead liquid stream may be combined with the make-up hydrogen gas stream in line 86 to provide an isomerization feed stream in isomerization feed line 90* sent to hydroisomerization catalyst bed 74' in reaction vessel 190. 18 The deoctadecanizer bottoms stream, containing the heavy diesel + hydrocarbons, is transported in bottoms line 204 to hydrocracking catalyst bed 150 ′ within reactor vessel 190 .

[0109] Deoctadecanizer column 200 may be operated at a bottom temperature between 260° C. (500° F.) and 316° C. (600° F.), and an overhead pressure of 0.35 MPa (gauge) (50 psig), preferably between 0.70 MPa (gauge) (100 psig) and 2.0 MPa (gauge) (290 psig).

[0110] Line 92 * The cold separator bottoms in the jet stripper column 120 * to produce light gas in a net stripper overhead stream in line 132 and naphtha in an overhead liquid stream 134. * The stripped stream therein is a jet product that meets ASTM D7566 jet fuel specifications and may be sent to a jet fuel pool. In one embodiment, recycle line 129 may recycle a portion of the jet product stream via line 208 to hydroisomerization catalyst bed 74' for further hydroisomerization. The remainder of Figure 4 is constructed and operated as described for Figures 1 and 2.

[0111] Any of the above lines, conduits, units, devices, vessels, ambient environments, zones, or the like may be instrumented with one or more monitoring components, including sensors, measurement devices, data capture devices, or data transmission devices. Signals, process, or condition measurements, and data from the monitoring components may be used to monitor conditions in, around, and on the process equipment. Signals, measurements, and / or data generated or recorded by the monitoring components may be collected, processed, and / or transmitted over one or more networks or connections, which may be private or public, general or specific, direct or indirect, wired or wireless, encrypted or unencrypted, and / or a combination thereof. The specification is not intended to be limiting in this respect.

[0112] Signals, measurements, and / or data generated or recorded by the 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 process that may include one or more steps. For example, the one or more computing devices may be configured to receive data related to at least one piece of equipment associated with the process from the one or more monitoring components. The one or more computing devices or systems may be configured to analyze the data. Based on the analysis of the data, the 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 processes described herein. The one or more computing devices or systems may be configured to transmit encrypted or unencrypted data including one or more recommended adjustments to one or more parameters of one or more processes described herein.

[0113] Specific Embodiments While the following is described in conjunction with specific embodiments, it will be understood that this description is illustrative and not intended to limit the scope of the foregoing description and the appended claims.

[0114] A first embodiment of the present disclosure is a process for hydroprocessing a biorenewable feedstock, the process comprising: hydrotreating a biorenewable feed stream over a hydrotreating catalyst in the presence of hydrogen to hydrodeoxygenate the biorenewable feed stream to provide a hydrotreated stream; hydroisomerizing a hydroisomerized feed stream removed from the hydrotreated stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream; separating the hydrotreated stream and / or the hydroisomerized stream into a hydroprocessed vapor stream and a hydroprocessed liquid stream; distilling the hydroprocessed liquid stream or the hydroisomerized stream, optionally after stripping, to produce a jet fuel stream and a diesel stream; and hydrocrack the diesel stream to provide a hydrocracked stream comprising jet fuel. An embodiment of the present disclosure is one, some, or all of the preceding embodiment of this paragraph to the first embodiment of this paragraph, further comprising distilling the hydroisomerized stream and the hydrocracked stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising distilling the hydroisomerized stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising hydroisomerizing the hydrocracked stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising hydroisomerizing the hydrocracked stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising distilling the hydrocracked stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising hydroisomerizing the hydrotreated steam in the presence of hydrogen over a hydroisomerization catalyst to produce a hydroisomerized stream. An embodiment of the present disclosure is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, which further comprises separating the hydroisomerization stream in a separation step. An embodiment of the present disclosure is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, which further comprises distilling the hydrocracked stream with the hydroprocessed liquid stream.An embodiment of the present disclosure is one, some, or all of the preceding embodiment of this paragraph to the first embodiment of this paragraph, wherein the diesel stream is a heavy diesel stream, and further comprising producing a light diesel stream in a distillation process. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising: separating the hydrotreated stream in a separation step; distilling the hydroprocessed liquid stream; hydroisomerizing the jet fuel stream; and hydrocracking the diesel stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising: hydroisomerizing the hydrocracked stream with the jet fuel stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising: separating the hydroisomerized stream into a hydroisomerized liquid stream and a hydroisomerized vapor stream. An embodiment of the disclosure is one, some, or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising: stripping the hydroisomerized liquid stream into a naphtha stream and a jet fuel stream. An embodiment of the present disclosure is one, some, or all of the preceding embodiment of this paragraph through the first embodiment of this paragraph, further comprising enriching the concentration of normal paraffins of a given carbon number in the diesel stream by at least 2 relative to the hydroisomerized stream.

[0115] A second embodiment of the present disclosure is a process for hydroprocessing a biorenewable feedstock, the process comprising: hydrotreating a biorenewable feed stream over a hydrotreating catalyst in the presence of hydrogen to hydrodeoxygenate the biorenewable feed stream to provide a hydrotreated stream; hydroisomerizing a hydroisomerization feed stream removed from the hydrotreated stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream; enriching a concentration of normal paraffins of a given carbon number in a diesel stream removed from the hydroisomerized stream by at least 2 relative to the hydroisomerized stream; and hydrocrack or hydroisomerize the diesel stream to provide a hydrocracked stream comprising jet fuel. An embodiment of the present disclosure is one, some, or all of the preceding embodiments of this paragraph to the second embodiment of this paragraph, in which the enrichment step is achieved by distillation of the hydroisomerized liquid stream. An embodiment of the present disclosure is one, some, or all of the preceding embodiment of this paragraph through the second embodiment of this paragraph, further comprising hydrocracking the diesel stream and hydroisomerizing the hydrocracked stream.

[0116] A third embodiment of the present disclosure is a process for hydroprocessing a biorenewable feedstock, the process comprising: hydrotreating a biorenewable feed stream over a hydrotreating catalyst in the presence of hydrogen to hydrodeoxygenate the biorenewable feed stream to provide a hydrotreated stream; hydroisomerizing the hydrotreated stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream; separating the hydroisomerized stream into a hydroprocessed vapor stream and a hydroprocessed liquid stream; distilling the hydroprocessed liquid stream or the hydroisomerized stream, optionally after stripping, to produce a jet fuel stream and a diesel stream; and hydrocrack the diesel stream to provide a hydrocracked stream comprising jet fuel. An embodiment of the present disclosure is one, some, or all of the preceding embodiment of this paragraph through the third embodiment of this paragraph, further comprising hydroisomerizing the hydrocracked stream. Without further elaboration, it is believed that, using the preceding description, one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of the present invention without departing from the spirit and scope of the present invention, and can make various changes and modifications to the present invention to adapt it to various uses and conditions. The preceding preferred specific embodiments are therefore to be construed as merely illustrative, and are not limitative of the remainder of the disclosure in any way, but are intended to cover various modifications and equivalent arrangements falling within the scope of the appended claims.

[0117] Above, all temperatures are set forth in degrees Celsius and all parts and percentages are by weight unless otherwise stated.

Claims

1. 1. A process for hydroprocessing a biorenewable feedstock comprising: hydrotreating a biorenewable feed stream over a hydrotreating catalyst in the presence of hydrogen to hydrodeoxygenate the biorenewable feed stream to provide a hydrotreated stream; hydroisomerizing a hydroisomerization feed stream removed from the hydroprocessing stream in a hydroisomerization reactor in the presence of hydrogen over a hydroisomerization catalyst to provide a hydroisomerized stream; separating the hydrotreated stream and / or the hydroisomerized stream into a hydroprocessed vapor stream and a hydroprocessed liquid stream; distilling the hydroprocessed liquid stream or the hydroisomerized stream, optionally after stripping, to produce a jet fuel stream and a diesel stream; hydrocracking the diesel stream in a hydrocracking reactor to provide a hydrocracked stream comprising jet fuel; feeding the hydrocracked stream to the hydroisomerization reactor; The process includes:

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

3. 10. The process of claim 1 further comprising distilling the hydroisomerization stream.

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