Process for producing jet fuel from isomerization and hydrocracking

Abstract

The process may isolate the liquid hydrocracked stream from the liquid hydroisomerized stream, thus conserving heat in the hydrocracked stream. Conserving heat in the hydrocracked stream avoids the need to reheat the hydrocracked stream prior to product fractionation. In particular, the kerosene in the hydrocracked stream is not cooled with the hydroisomerized stream and then reheated in fractionation to distill kerosene range hydrocarbons from diesel range hydrocarbons.

Description

[Technical Field]

[0001] (Statement of priority) This application claims priority to U.S. Provisional Patent Application No. 63 / 404,525, filed September 7, 2022, the entire contents of which are incorporated herein by reference.

[0002] FIELD OF THE INVENTION The field is producing hydrocarbons useful as aviation fuels from hydrocarbon feedstocks. In particular, the field can relate to producing 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]

[0003] As global demand for fuel increases, there is growing interest in producing fuels and blending components from sources other than crude oil. These sources, often referred to as biorenewable sources, include, but are not limited to, vegetable oils such as corn, rapeseed, canola, and soybean; microbial oils such as algal oil; animal fats such as inedible tallow; fish oil; and various waste streams such as yellow and brown grease and sewage sludge. A common feature of these sources is that they are composed of glycerides 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.

[0004] Hydroprocessing can include processes that convert hydrocarbons into more valuable products in the presence of a hydroprocessing catalyst and hydrogen. Hydrotreating is a process in which hydrogen is contacted with hydrocarbons in the presence of a hydrotreating catalyst that is primarily active for removing heteroatoms, such as sulfur, nitrogen, oxygen, and metals, from the hydrocarbon feedstock. Hydrotreating can saturate hydrocarbons with double and triple bonds, such as olefins.

[0005] The production of hydrocarbon products in the diesel boiling range can be achieved by hydrotreating biorenewable feedstocks. Biorenewable feedstocks can be hydroprocessed by hydrotreating to deoxygenate, decarboxylate, and / or decarbonylate oxygenated hydrocarbons. Decarboxylation and decarbonylation remove carbon from paraffin molecules, while deoxygenation does not. Hydrotreating can be followed by hydroisomerization to improve the cold flow properties of the product diesel and jet fuels. Hydroisomerization, or hydrodewaxing, is a hydroprocessing process that increases alkyl branching on the hydrocarbon backbone in the presence of hydrogen and a hydroisomerization catalyst, improving the cold flow properties of the hydrocarbons. Hydroisomerization, as used herein, includes hydrodewaxing.

[0006] 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.

[0007] When producing jet fuel from triglycerides (also called "fats"), some degree of hydrocracking and isomerization is required to meet the jet fuel specifications outlined in ASTM D7566 Annex 2 and ASTM D1655. These key specifications required for jet fuel in D7566 are a freezing point of -40°C or less (ASTM D5972, D7153, or D7154), a freezing point of 772 kg / m³, and a saturation temperature of 100°C. 3The jet fuel specifications are: density below 100°C (ASTM D1298 or D4052), T10 below 205°C (ASTM D86), and final boiling point (FBP) below 300°C (ASTM D86). Larger molecules that do not meet these jet fuel specifications are primarily hydrocracking to meet these specifications, which inherently results in low yields in the production process and undesirably low energy density fuel. Aviation fuels are valued for their high energy per volume.

[0008] Carbon intensity is a term that refers to the number of moles of carbon dioxide produced to produce one mole of fuel. Combustion of hydrocarbons, such as heating a hydrocarbon stream in a hydroprocessing unit, increases carbon intensity. It is desirable to provide renewable fuels from processes that reduce carbon intensity by reducing heating requirements. Summary of the Invention

[0009] The present inventors have discovered that by isolating the liquid hydrocracked stream from the liquid hydroisomerization stream, heat in the hydrocracked stream can be conserved. By conserving heat in the hydrocracked stream, reheating the hydrocracked stream prior to product fractionation is avoided. In particular, the kerosene in the hydrocracked stream is not cooled with the hydroisomerization stream and then reheated in fractionation to distill kerosene range hydrocarbons from diesel range hydrocarbons. [Brief explanation of the drawings]

[0010] [Figure 1] FIG. 1 is a schematic process flow diagram of the present disclosure. [Figure 2] FIG. 2 is a schematic process flow diagram of an alternative embodiment of FIG. 1. [Figure 3] FIG. 2 is a schematic process flow diagram of another alternative embodiment of FIG. 1. [Figure 4] FIG. 2 is a schematic process flow diagram of a further embodiment of FIG. 1.

[0011] definition The term "communication" means operatively permitting the flow of materials between the listed 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 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 the stream from the upstream component enters the 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 enters a downstream component after passing through a fractionation or conversion unit and undergoing a change in composition by physical fractionation or chemical conversion.

[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 a distillation column or columns for separating one or more components of different volatility. Unless otherwise indicated, each column includes a condenser at the top of the column for condensing and refluxing a portion of the overhead stream that returns to the top of the column, and a reboiler at the bottom of the column for vaporizing a portion of the bottom stream and returning it 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 the reboiler at the bottom of the column and instead provide the required heat and driving force for separation from a fluidized inert medium such as steam. A stripping column typically feeds the feed to the 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 the vessel has a higher concentration of the component than the feed to the vessel.

[0019] As used herein, the term "component lean stream" means that the lean stream exiting the vessel has a lower concentration of the component than the feedstock 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 test method 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 yield of said fractions by both mass and volume, where a graph of temperature versus mass % distilled is produced using 15 theoretical plates in a column with 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, of a sample boils using ASTM D-86 or TBP, respectively, as the case may be.

[0023] As used herein, the term "initial boiling point" (IBP) means 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 "final boiling point" (FBP) means the temperature at which a sample has completely evaporated using ASTM D2887, ASTM D-86, or TBP, as the case may be.

[0025] As used herein, the term "diesel boiling range" means that 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 bottoms 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 more than 50%, suitably more than 75%, and preferably more 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 "x" subscript. x The term "-" refers to a molecule containing less than or equal to x, preferably x and less, carbon atoms. x The term "+" refers to a molecule having more than or equal 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. DETAILED DESCRIPTION OF THE INVENTION

[0031] FIG. 1 illustrates a process 10 for processing a hydrocarbon feedstock according to one exemplary embodiment. Preferably, the hydrocarbon feedstock is a biorenewable hydrocarbon feedstock. A feed line 12 transports a hydrocarbon stream of fresh biorenewable feedstock to a feed surge drum 14. The biorenewable feedstock can 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 can contain nitrogen concentrations of 50 wppm to 2000 wppm. The biorenewable feedstock can contain a high oxygen content, which can be up to 10% by weight or more. The biorenewable feedstock can also contain 1 to 500 wppm sulfur, typically 200 wppm or less.

[0032] A variety of different biorenewable feedstocks may be suitable for process 10. The term "biorenewable feedstock" is meant to include feedstocks other than those derived from crude oil. Biorenewable feedstocks may include any of those feedstocks that contain glycerides and / or free fatty acids. Most of the glycerides will be triglycerides, but monoglycerides and diglycerides exist and can be similarly processed. 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, babassu oil, castor oil, peanut oil, palm oil, mustard oil, tallow, yellow and brown grease, lard, whale oil, milk fat, fish oil, algae oil, sewage sludge, etc. Further examples of biorenewable feedstocks include non-edible vegetable oils from the group including Jatropha curcas (ratanjo, wildcaster, jangulierandi), Madhuca indica (mowa), Pongamia pinnata (karanji, 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. Biorenewable feedstocks may also include biomass pyrolysis oils and Fischer-Tropsch waxes. As will be appreciated, 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.

[0033] The hydrocarbon stream in feed line 12, possibly after injection with a sulfiding agent in line 15, flows from feed surge drum 14 via charge pump and combines with a recycled hydrotreated hydrogen stream in hydrotreated hydrogen line 20 to provide a mixed hydrocarbon stream in line 24. The mixed hydrocarbon stream in line 24 is combined with a hydrotreated recycle stream in recycle line 16 to provide a hydrotreated feed hydrocarbon stream in hydrotreated feed line 26. The recycle-to-feed ratio can be from 1:1 to 5:1. The hydrotreated feed hydrocarbon stream in line 26 can be reheated in combined feed exchanger 22 by heat exchange with the hydrotreated stream in hydrotreated line 32, and possibly in fired heater 23. The heated hydrotreated feed hydrocarbon stream in hydrotreated feed line 26 can then be fed to hydrotreating reactor 28.

[0034] The hydrotreating reactor 28 may include a guard bed reactor, or guard bed 27. In FIG. 1, the hydrotreating reactor 28 includes a guard bed 27. The guard bed reaction 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, hydrodesulfurization, and hydrodenitridation reactions to occur. The hydrodeoxygenation reaction preferably minimizes the hydrodecarbonylation and hydrodecarboxylation reactions to preserve the carbon atoms on the paraffin chains.

[0035] The guard bed 27 may comprise a base metal on a support. Base metals usable in this process include non-noble metals, nickel, chromium, molybdenum, and tungsten. Other base metals that may be used include tin, indium, germanium, lead, cobalt, gallium, and zinc. The process may also use metal sulfides, where the metal in the metal sulfide is selected from one or more of the listed base metals. The hydrotreating feed stream may be fed through the base metal catalyst at a pressure of 1379 kPa (abs) (200 psia) to 13790 kPa (abs) (2000 psia). In further embodiments, the guard bed catalyst may comprise a second metal, where the second metal comprises 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 guard bed 27. Although only one guard bed is shown in Figure 1, multiple guard beds, such as two, three or more, may be contained in hydroprocessing reactor 28, and hydrogen quench from hydrogen manifold 18 may be injected at interbed locations to control temperature exotherms.

[0036] The contacted hydrocarbon stream exits guard bed 27. In guard bed 27, the majority of the hydrodemetallization and hydrodeoxygenation reactions occur, with some hydrodenitrification and hydrodesulfurization occurring. Metals removed from the biorenewable feedstock include alkali and alkaline earth metals, as well as phosphorus. If the guard bed has its own dedicated reaction vessel, the contacted hydrocarbon stream exits the guard bed reactor. However, in FIG. 1, guard bed 27 is housed in hydrotreating reactor 28, so the contacted stream receives a hydrogen quench from hydrogen manifold 18 and enters hydrotreating catalyst bed 29.

[0037] In hydrotreating reactor 28, the contacted hydrocarbon stream contacts a hydrotreating catalyst in hydrotreating catalyst bed 29 in the presence of hydrogen under 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 hydrodecarboxylation and hydrodecarbonylation reactions, to remove oxygenated functional groups from the hydrocarbon molecules in the biorenewable feedstock, converting the biorenewable feedstock to water and carbon oxides. The hydrotreating catalyst also catalyzes the hydrodesulfurization of organic sulfur and hydrodenitrogenation of organic nitrogen in the biorenewable feedstock. Essentially, hydrotreating reactions remove heteroatoms from the hydrocarbons to saturate the olefins in the feedstream.

[0038] The hydrotreating catalyst may be provided in one, two or more beds to use an interbed hydrogen quench stream from the hydrogen quench stream. A recycle hydrogen quench stream taken from hydrogen recycle hydrogen line 19 in hydrogen manifold 18 may be fed to hydrotreating reactor 28 for interbed quenching. Three hydrotreating catalyst beds 29 are shown in Figure 1, although more than one is contemplated.

[0039] Hydrotreating catalysts can 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, BDO 300, or BDO 400, available from UOP LLC of Des Plaines, Illinois. Hydrotreating reaction temperatures can range from 271°C (520°F) to 427°C (800°F), preferably from 304°C (580°F) to 400°C (752°F). Typically, hydrotreating conditions include pressures of 700 kPa (100 psig) to 21 MPa (3000 psig).

[0040] The hydrotreated stream is produced in hydrotreating line 32 from hydrotreating reactor 28 and comprises a hydrocarbon fraction having a significant n-paraffin concentration. The oxygenate concentration in the hydrocarbon fraction is essentially zero, while the olefin concentration is substantially reduced relative to the contacted biorenewable feed stream. The organic sulfur concentration in the hydrocarbon fraction is 500 wppm or less, and the organic nitrogen concentration in the hydrocarbon fraction is less than 10 wppm.

[0041] The hydrotreat stream in hydrotreating line 32 may first flow to combined isomerization feed exchanger 34 to heat the hydroisomerization feed stream in hydroisomerization feed line 44 and cool the hydrotreat stream. As previously mentioned, the cooled hydrotreat stream in hydrotreating line 32 may then exchange heat with the combined hydrocarbon stream in line 24 in combined feed heat exchanger 22 to further cool the hydrotreat stream in hydrotreating line 32 and heat the hydrotreat feed hydrocarbon stream in hydrotreating line 32. The twice-cooled hydrotreat steam in hydrotreating line 32 may then be further cooled in combined feed exchanger 22 by heat exchange with the combined hydrocarbon stream in combined feed line 24 to heat the combined hydrocarbon stream and cool the hydrotreat stream in hydrotreating line 32. The twice-cooled hydrotreat stream may be further cooled, possibly to produce steam, before being separated.

[0042] The cooled hydrotreat stream may be separated in hydrotreater separator 36, which may include an enhanced hot separator (EHS), with the aid of stripping gas taken from isomerization overhead line 58 and fed to stripping line 39. The hydrotreater stream is separated to provide a hydrotreated vapor stream in hydrotreater overhead line 38 and a hydrotreated liquid stream in hydrotreater bottoms line 40, having a lower oxygen concentration than the hydrotreater feed hydrocarbon stream in line 26. Hydrotreater separator 36 may be a high-pressure stripping column. In hydrotreater separator 36, the hydrotreater stream from hydrotreater line 32 flows downward 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 stripping line 39. The stripping gas may include make-up hydrogen gas that has passed through isomerization reactor 48 and isomerization separator 56, as described below.

[0043] The stripping gas in stripping line 39 enters hydrotreater separator 36 below the inlet for the hydrotreater stream in hydrotreater line 32. Hydrotreater separator 36 may include internals, such as trays or packing, located between the inlet for the hydrotreater stream in line 32 and the inlet for the stripping gas in stripping line 39 to facilitate stripping of the hydrotreater stream. The stripping gas, including the stripping gas present in the hydrotreater vapor stream in hydrotreater overhead line 38 extending from the top of hydrotreater separator 36, is mixed with a cold aqueous stream in cold aqueous line 63 from the boot of cryogenic separator 62, cooled, mixed with the isomerized liquid stream in isomerization bottoms line 60, and enters cryogenic separator 62.

[0044] Hydrotreater separator 36 operates at 177°C (350°F) to 371°C (700°F), preferably 232°C (450°F) to 315°C (600°F). Hydrotreater separator 36 may be operated at a slightly lower pressure than hydrotreater reactor 28, taking into account pressure drops due to intervening equipment. Hydrotreater separator 36 may be operated at a pressure of 3.4 MPa (gauge) (493 psig) to 20.4 MPa (gauge) (2959 psig). The hydrotreater vapor stream in hydrotreater separator overhead line 38 may have a temperature at the operating temperature of hydrotreater separator 36.

[0045] The hydrotreated liquid stream, which may be stripped, collects at the bottom of hydrotreater separator 36 and flows in hydrotreater bottoms line 40. The liquid hydrotreater stream contains diesel-range materials, with a high paraffin concentration if the hydrocarbon feed contains a biorenewable feedstock. The liquid hydrotreater stream in hydrotreater separator bottoms line 40 may be split into two streams: a hydroisomerization feed stream taken in hydroisomerization feed line 42, and a recycled hydrotreater stream taken in recycle line 16, both taken from the liquid hydrotreater stream in hydrotreater bottoms line 40. The recycled hydrotreater stream in recycle line 16 may be pumped and combined with the combined hydrocarbon stream in line 24, as described above.

[0046] While a desired product, such as transportation fuel, may be provided to hydrotreater bottoms line 40 because the liquid hydrotreated stream contains a higher concentration of normal paraffins, this product has poor cold flow properties and a high FBP that precludes it from meeting jet fuel specifications. Therefore, to improve the cold flow properties and reduce the FBP, the hydrotreated liquid stream may be hydroisomerized.

[0047] Make-up hydrogen gas in make-up line 41 may be compressed in make-up gas compressor 45 to provide compressed make-up gas in compressed make-up gas header 47. A hydroisomerization make-up gas stream is taken from make-up gas header 47 in line 43 and mixed with the hydroisomerization feed stream in line 42 to provide a combined hydroisomerization feed stream in combined hydroisomerization feed line 44. The combined hydroisomerization feed stream in combined hydroisomerization feed line 44 may be heated in hydroisomerization feed exchanger 34 by heat exchange with a hydrotreat stream in hydrotreat line 32. Prior to feeding the combined hydroisomerization feed stream to hydroisomerization reactor 48, the combined hydroisomerization feed stream may be heated in hydroisomerization feed heater 46 to bring the combined hydroisomerization feed stream to a hydroisomerization temperature.

[0048] The hydroisomerization (including hydrodewaxing) of linear hydrocarbons in hydroisomerization reactor 48 may be accomplished over one or more beds of hydroisomerization catalyst, and the hydroisomerization may be operated in a co-current mode of operation. Both a fixed bed trickle bed downflow mode or a fixed bed liquid-loaded upflow mode are suitable.

[0049] The hydroisomerization catalyst comprises a dehydrogenation metal, a molecular sieve, and a metal oxide binder. The hydroisomerization catalyst may comprise a dehydrogenation metal comprising a Group VIII metal. The dehydrogenation metal may be selected from platinum, palladium, nickel, nickel molybdenum sulfide, or nickel tungsten sulfide. Preferably, the dehydrogenation metal is selected from platinum or nickel tungsten sulfide. The concentration of the dehydrogenation metal on the hydroisomerization catalyst may comprise 0.05 to 5 wt. % based on the transition metal.

[0050] The dehydrogenation metals are distributed between the molecular sieve and the binder, with 40 to 65 wt. %, preferably 45 to 60 wt. %, of the metals distributed on the molecular sieve and 40 to 65 wt. %, preferably 45 to 60 wt. %, of the metals distributed on the binder. An associated advantage of the hydroisomerization catalyst is high activity and selectivity for hydroisomerization. In a further embodiment, the hydroisomerization catalyst further comprises less than 0.5 wt. % carbon, with the associated benefits of high activity and selectivity for hydroisomerization.

[0051] In one embodiment, the hydroisomerization catalyst comprises one or more molecular sieves having a topology selected from AEI, AEL, AFO, AFX, ATO, BEA, CHA, FAU, FER, MEL, MFI, MOR, MRE, MTT, MWW, or TON, e.g., EU-2, ZSM-11, ZSM-22, ZSM-23, ZSM-48, SAPO-5, SAPO-11, SAPO-31, SAPO-34, SAPO-41, SSZ-13, SSZ-16, SSZ-39, MCM-22, zeolite Y, ferrierite, mordenite, ZSM-5, or zeolite beta, with the associated benefit that the molecular sieve is active in the hydroisomerization of linear hydrocarbons.

[0052] The metal oxide binder may be taken from the group comprising alumina, silica, silica-alumina, and titania, or mixtures thereof. Preferably, the metal oxide binder is alumina, preferably gamma alumina.

[0053] The hydroisomerization catalyst can include a molecular sieve having an AEL topology, and more specifically, can be SAPO-11. Most of the acid sites on the SAPO-11 are weak to medium acid sites. More specifically, at least 50% of the total acidity on the SAPO-11 is weakly acidic, and at least 60-80% of the external acidity on the SAPO-11 is weakly acidic.

[0054] Hydroisomerization catalysts typically comprise particles having diameters of 1 to 5 millimeters. Catalyst production typically involves the formation of a stable porous support followed by impregnation with the active metal. Stable porous supports typically include metal oxides and molecular sieves, which may be zeolites. Stable supports are produced with high porosity to ensure maximum surface area, and it is typically desirable to distribute the active metal over the entire internal and external surface area of ​​the support. DI-200, available from UOP LLC of Des Plaines, Illinois, may be a suitable hydroisomerization catalyst.

[0055] Hydroisomerization conditions generally include a temperature of 150°C (302°F) to 450°C (842°F) and a pressure of 1724 kPa (abs) (250 psia) to 13.8 MPa (abs) (2000 psia). In another embodiment, hydroisomerization conditions include a temperature of 300°C (572°F) to 388°C (730°F), a pressure of 3102 kPa (abs) (450 psia) to 13790 kPa (abs) (2000 psia), and a time of 0.5 to 3 hours. -1 LHSV of 337Nm 3 / m 3 (2,000 scf / bbl)~2527Nm 3 / m 3 Includes hydrogen rate of oil (15,000 scf / bbl).

[0056] The hydroisomerized stream in hydroisomerization line 50 from hydroisomerization reactor 48 is a branched paraffin-rich stream. Preferably, the hydroisomerized stream is a predominantly branched paraffin stream. It is contemplated that the hydroisomerized effluent may contain 80, 90, or 95 wt. % branched paraffins of the total paraffin content. The hydroisomerization conditions in hydroisomerization reactor 48 are selected to avoid undesired cracking, and thus the predominant product in the hydroisomerized stream in hydroisomerization line 50 is branched paraffins. By avoiding undesired cracking, the hydroisomerized stream in hydroisomerization line 50 has a composition that is close to the same, with only a slight decrease in carbon number, as the hydroisomerization feed stream in hydroisomerization feed line 42. The optimal amount of residual normal paraffins in line 50 depends on the selectivity of the hydroisomerization catalyst, but may typically be between 1 and 7 wt. %.

[0057] The hydroisomerized stream in hydroisomerization line 50 from hydroisomerization reactor 48 flows to hydroisomerization exchanger 52, where it is heat exchanged with a stripper liquid hydroisomerized stream in cold bottoms line 70, cooled, and combined with a vaporous hydrocracked stream in line 182 to provide a mixed hydroisomerized stream in line 54. The mixed hydroisomerized stream in line 54 is further cooled in hydroisomerization cooler 55 and fed to hydroisomerization separator 56 for separation into a liquid hydroisomerized stream and a vaporous hydroisomerized stream. Internal packing may be placed at the top of hydroisomerization separator 56 to ensure that liquid components are prevented from leaving hydroisomerization overhead line 58. The vaporous hydroisomerized stream in hydroisomerization overhead line 58 extending from the top of hydroisomerization separator 56 may be compressed in compressor 59 to provide stripping gas in stripping line 39 of hydrotreating separator 36.

[0058] A liquid hydroisomerized stream in hydroisomerization bottoms line 60 extending from the bottom of hydroisomerization separator 56 may be fed to stripping column 100 and to product fractionation column 120, described below, where it is isolated from the hydrocracking liquid stream. In one embodiment, the liquid hydroisomerized stream in hydroisomerization bottoms line 60 is pumped to cryogenic separator 62 and may be further separated, along with a cooled vaporous hydrotreated stream in line 38 and a cold aqueous stream in cold aqueous line 63 pumped from the boot of cryogenic separator 62. The cold aqueous stream in line 63 may be combined with the vaporous hydrotreated stream in line 38 to provide a colder hydrotreated stream in line 61. The colder hydrotreated stream in line 61 may be cooled in cooler 64 and combined with the liquid hydroisomerized stream in line 60 to provide a cold separator feed stream in line 66, which may be fed to cryogenic separator 62. The cold aqueous stream in cold aqueous line 63 is added to the cold separator feed line 66 via the liquid hydroisomerization stream in line 60 to dissolve salts that may be present in the liquid hydrocarbons in cold separator 62.

[0059] In cold separator 62, the hydroisomerized liquid stream and the vapor components in the hydrotreated vapor are separated and ascend to provide a cold vaporous hydroisomerized stream in cold overhead line 68, a stripper liquid hydroisomerized stream in cold bottoms line 70, and a cold aqueous stream taken from the boot in cold aqueous line 63. The cold vaporous hydroisomerized stream in cold overhead line 68 may be split into a recycle hydrogen stream in line 19 and a net cold vaporous hydroisomerized stream in net cold overhead line 72. The recycle hydrogen stream in line 19 is compressed in a recycle gas compressor and recycled to hydrotreating reactor 28 in manifold line 18 for interbed quenching and to the hydrocarbon stream in feed line 12 via hydrotreating hydrogen line 20.

[0060] The net cold vapor hydroisomerization stream in net cold overhead line 72 may be passed through a tray-type or pack-type purge scrubbing column 74 and scrubbed with a scrubbing liquid, such as an aqueous solution supplied by scrubbing liquid line 76, 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 of Des Plaines, Illinois, and amines, such as alkanolamines, including diethanolamine (DEA), monoethanolamine (MEA), methyl diethanolamine (MDEA), diisopropanolamine (DIPA), and diglycolamine (DGA). Other scrubbing liquids can be used in place of or in addition to the preferred amines. The lean scrubbing liquid contacts the cold vapor stream and absorbs acid gaseous pollutants. The resulting "sweetened" cold vapor stream is taken from the top outlet of purge scrubbing column 74 in purge scrubber overhead line 78, and acid gas-rich scrubbing liquid is taken from the bottom at the bottom outlet of purge scrubbing column 74 in purge scrubber bottoms line 80. Spent scrubbing liquid from the bottom can be regenerated and recycled back to purge scrubbing column 74 in scrubber liquid line 76. A scrubbed hydrogen-rich stream emerges from purge scrubbing column 74 in purge scrubber overhead line 78 and can be sent to a pressure swing adsorption unit 82 or other hydrogen recovery plant to produce high purity hydrogen in line 84.

[0061] Recycle scrubbing column 74 may be operated at a gas inlet temperature of 38°C (100°F) to 66°C (150°F) and an overhead pressure of 3 MPa (gauge) (435 psig) to 20 MPa (gauge) (2900 psig). Suitably, purge scrubbing column 74 may be operated at a temperature of 40°C (104°F) to 125°C (257°F) and a pressure of 1200 to 1600 kPa. The temperature of the net cold vaporous hydroisomerization stream 72 to purge scrubbing column 74 may be from 20°C (68°F) to 80°C (176°F), and the temperature of the scrubbing liquid stream in scrubbing liquid line 76 may be from 20°C (68°F) to 70°C (158°F).

[0062] The liquid hydroisomerized fuel components in the liquid hydroisomerization stream and the stripper liquid hydroisomerization stream from the vaporous hydrotreated stream exit the cryogenic separator in cold hydroisomerization bottoms line 70. The stripper liquid hydroisomerization stream in cold hydroisomerization bottoms line 70 contains diesel and jet boiling range fuels, as well as other hydrocarbons such as propane, naphtha, etc. A cold aqueous stream can be collected from the boot of the cryogenic separator in cold aqueous line 63.

[0063] In one embodiment, the stripper liquid hydroisomerized stream in cold column bottoms line 70 may be stripped to remove hydrogen sulfide and other gases in cold stripping column 86. The stripper liquid hydroisomerized stream in cold bottoms line 70 may be heated by heat exchange in hydroisomerization exchanger 52 with the hydroisomerized stream in hydroisomerization line 50 to heat the cold liquid hydroisomerized stream and provide it to cold stripping column 86.

[0064] In one embodiment, the cryogenic stripping column 86 may be part of a dual stripping vessel 100 including a cryogenic stripping column 86 and a hot stripping column 102, each separated by an intervening wall 103. A stripping medium, which is an inert gas, such as steam from a stripping medium line 89, may be used to strip light gases from the stripper liquid hydroisomerization stream in line 70. The cryogenic stripping column 86 supplies an overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases to a stripper overhead line 87 and a fractionator hydroisomerization stream to a cryogenic stripped bottoms line 90. The overhead stripping stream in overhead line 87 may be condensed and separated by cooling in a stripping receiver 95. A stripper overhead line 88 from receiver 95 may carry the stripper overhead stream to an off-gas scrubber 140. The unstabilized liquid naphtha from the bottom of receiver 95 may be split to provide a reflux stream to cryogenic stripping column 86 and a stripper liquid overhead stream that may be transported in stripper receiver bottoms line 96 to naphtha and debutanizer column 170 for LPG recovery. An acid water stream may be collected from the boot of overhead receiver 95.

[0065] Cryogenic stripping column 86 may be operated at an overhead pressure of 0.35 MPa (gauge) (50 psig), preferably greater than 0.70 MPa (gauge) (100 psig) to 2.0 MPa (gauge) (290 psig) or less. The temperature in overhead receiver 95 ranges from 38°C (100°F) to 66°C (150°F), and the pressure is essentially the same as in the overhead of cryogenic stripping column 86. It is envisioned that cryogenic stripping column 86 and hot stripping column 102 may be two completely separate vessels.

[0066] The fractionator liquid hydroisomerized stream in cold stripper bottoms line 90 can be heated and fed into product fractionation column 120. The fractionator liquid hydrocracked stream in hot stripper bottoms line 106 can also be heated and fed into product fractionation column 120. The fractionator liquid hydrocracked stream in hot stripper bottoms line 106 is a separate liquid stream from the fractionator liquid hydroisomerized stream in cold stripper bottoms line 90, which is also a liquid stream. The fractionator liquid hydrocracked stream in hot stripper bottoms line 106 can be fed to product fractionation column 120 separately from or together with the fractionator liquid hydroisomerized stream in cold stripper bottoms line 90. However, the fractionator liquid hydrocracked stream in hot stripper bottoms line 106 and the fractionator liquid hydroisomerized stream in cold stripper bottoms line 90 are produced separately. These streams are taken separately and held until stripping, or fractionation, serves to conserve heat in the fractionator liquid hydrocracked stream so that less heat is required to boil the kerosene range boiling point components and separate them from the diesel components in product fractionation column 120.

[0067] A diesel stream in bottoms line 124 is taken from the bottom of product fractionation column 120. A hydrocracking feed stream in line 126 is taken from the diesel stream in bottoms line 124 from product fractionation column 120. Product fractionation column 120 can be reboiled by heat exchange with a suitable hot stream or in a fired heater 121 to provide the heat necessary for distillation. Alternatively, an inert gas stripping medium, such as steam from the stripping medium, can be used to heat the column. The reboiled stream is sent to fired heater 121 and, while boiling, is returned to product fractionation column 120. A diesel product stream can be taken in diesel product line 125 to a diesel pool and can be green diesel. The diesel stream in distillation bottoms line 124 may be a diesel stream having a T5 of 230°C (446°F) to 296°C (590°F) and a T90 of 343°C (650°F) to 399°C (750°F).

[0068] Product fractionation column 120 provides a naphtha overhead gas stream in overhead line 122. The fractionation overhead stream may be completely condensed and separated from water in distillation receiver 130. Unstabilized liquid naphtha from the bottom of receiver 130 in fractionator overhead liquid line 132 may be combined with the naphtha stream in line 176, while the condensed reflux stream is refluxed to the column. An acid water stream may be collected from the boot of distillation receiver 130.

[0069] A kerosene stream may be taken from the side of product fractionation column 120 in side line 134. The kerosene stream taken in side line 134 may be stripped in kerosene stripper column 136 to remove low boiling materials, which are returned to product fractionation column 120 at a higher point in overhead kerosene line 135. A stripped bottoms kerosene stream is produced in bottoms kerosene line 137, from which a boil-up stream is reboiled and returned to kerosene stripper column 136, and a jet fuel product stream is taken in line 138. The jet fuel product stream in line 138 may be a green jet fuel stream that meets jet fuel specifications according to ASTM D86 and is taken from the bottom of kerosene stripper column 136. The jet fuel product stream in line 138 may be cooled and transported to a jet fuel pool.

[0070] Optionally, a light diesel stream may be taken in a second side line, not shown, and stripped in a side diesel stripper. Additionally, heat may be removed from the product fractionation column in a pump-around steam generator 139.

[0071] Product fractionation column 120 may be operated at a bottoms temperature between 149°C (300°F) and 288°C (550°F), preferably up to 260°C (500°F), and an overhead pressure of 0.35 MPa (gauge) (50 psig), preferably from 0.70 MPa (gauge) (100 psig) to 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 product fractionation column 120. It is also envisioned that product fractionation column 120 may provide a net overhead stream comprising jet fuel in fractionator overhead liquid line 132, with naphtha and lighter streams being taken in fractionator receiver overhead line 131. In such cases, compressor 133 is not required.

[0072] The overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases in stripper overhead line 88 may be passed to a tray-type or packed off-gas scrubbing column 140 and scrubbed with a scrubbing liquid, such as an aqueous solution supplied by scrubbing liquid line 142, 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 of Des Plaines, Illinois, and amines such as alkanolamines, including diethanolamine (DEA), monoethanolamine (MEA), methyl diethanolamine (MDEA), diisopropanolamine (DIPA), and diglycolamine (DGA). Other scrubbing liquids can be used in place of or in addition to the preferred amines. The lean scrubbing liquid contacts the overhead stripping stream to absorb acid gaseous pollutants, such as hydrogen sulfide and carbon dioxide. The resulting "sweetened" overhead stripping stream is taken from the top outlet of the off-gas scrubbing column 140 into a recycle scrubber overhead line 144, and acid gas-rich scrubbing liquid is taken from the bottom at the bottom outlet of the recycle scrubber column 140 into a recycle scrubber bottom line 146. Spent scrubbing liquid from the bottom can be regenerated and recycled back to the off-gas scrubbing column 140 in a scrubbing liquid line 142. A scrubbed hydrocarbon-rich stream exits the off-gas scrubbing column 140 via an off-gas scrubbing column overhead line 144 and can be sent to a sponge absorber column 160 for hydrocarbon recovery.

[0073] Off-gas scrubbing column 140 may be operated at a gas inlet temperature of 38°C (100°F) to 66°C (150°F) and an overhead pressure of 3 MPa (gauge) (435 psig) to 20 MPa (gauge) (2900 psig). Preferably, off-gas scrubbing column 140 may be operated at a temperature of 40°C (104°F) to 125°C (257°F) and a pressure of 1200 to 1600 kPa. The temperature of the overhead stripping stream 88 to off-gas scrubbing column 140 may be between 20°C (68°F) and 80°C (176°F), and the temperature of the scrubbing liquid stream in scrubbing liquid line 142 may be between 20°C (68°F) and 70°C (158°F).

[0074] Sponge absorber column 160 may receive the scrubbed hydrocarbon-rich stream in off-gas scrubber overhead line 144. A lean absorbent stream in lean absorbent line 162 may be fed to sponge absorber column 160 through an absorbent inlet. The lean absorbent may include a naphtha stream in lean absorbent line 162, possibly from the debutanizer bottoms stream in line 176. In sponge absorber column 160, the lean absorbent stream and the scrubbed hydrocarbon-rich stream contact in a countercurrent manner. The sponge absorbent absorbs LPG hydrocarbons from the net stripper gas stream into the absorbent-rich stream.

[0075] The hydrocarbons absorbed by the sponge absorbent comprise some 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+The sponge absorber column 160 contains light naphtha hydrocarbons. The sponge absorber column 160 can be operated at a temperature of 34°C (93°F) to 60°C (140°F) and at a pressure essentially the same as or lower than that of the off-gas scrubbing column 140, with minimal friction losses. 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 can be transported to a fuel gas header (not shown) to provide fuel gas demand. 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 bottoms line 166 and can be supplied to debutanizer column 170 via the stripper overhead liquid stream in stripper receiver bottoms line 96.

[0076] In one embodiment, debutanizer column 170 converts the stripper liquid overhead stream and the rich absorbent stream in stripper receiver bottoms line 134 into a stream of 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 liquid overhead stream in net receiver bottoms line 174, with reflux to the debutanizer column 170 and recovery of LPG. The debutanized overhead liquid stream in net receiver bottoms line 174 may be taken as an LPG product stream. A debutanizer bottoms stream may be withdrawn from the bottom of the debutanizer column 170 in debutanizer bottoms line 176. A reboil stream taken from the debutanizer bottoms stream in debutanizer bottoms line 175 from the bottom of the debutanizer column 170 may be boiled in the 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. The net debutanizer bottoms stream in line 176 containing naphtha may be split into a lean absorbent stream in lean absorbent line 162 and a product naphtha stream that is cooled and sent to the gasoline pool in line 178.

[0077] The fractionation bottoms stream in fractionation bottoms line 124 may contain diesel boiling range hydrocarbons. In the embodiment of Figure 1, the jet fuel stream in line 138 and the diesel stream in line 125 may be taken once through without recycle. The cut point in product fractionation column 120 between the diesel stream in bottoms line 124 and the jet fuel stream in side line 134 may be adjusted to ensure that the jet fuel stream, at least after blending, has the appropriate composition to meet jet fuel specifications, particularly jet fuel density specifications. However, larger paraffins are concentrated in the fractionation bottoms stream and are therefore well suited to hydrocracking into kerosene range hydrocarbons.

[0078] The hydrocracking feed stream in hydrocracking feed line 126 may be stored in hydrocracking feed surge drum 127 and pumped to hydrocracking reactor 150. Hydrocracking reactor 150 is downstream of hydroisomerization reactor 48. The hydrocracking feed stream may be mixed with a hydrocracked hydrogen stream in line 152, taken from the compressed make-up hydrogen stream in compressed make-up gas header 47, to provide a combined hydrocracking feed stream in combined hydrocracking feed line 154, which may be heated by heat exchange with the hydrocracked stream in line 158 in hydrocracking effluent feed heater 155 and fed in line 154 to hydrocracking reactor 150.

[0079] Hydrocracking reactor 150 can be a fixed bed reactor containing one or more vessels, single or multiple catalyst beds within each vessel, and various combinations of hydrocracking catalysts within one or more vessels. Hydrocracking reactor 150 can be operated in a conventional continuous gas phase, moving bed, or fluidized bed hydroprocessing reactor.

[0080] The combined hydrocracked stream is hydrocracked over a hydrocracking catalyst in hydrocracking reactor 150 in the presence of a hydrocracking hydrogen stream from hydrocracking hydrogen line 152 to provide a hydrocracked stream. A portion of the hydrocracking feed stream in line 126 can be used as an interbed quench to cool the hydrocracked effluent between catalyst beds. Alternatively, recycled hydrogen from recycle hydrogen line 19 can be added between hydrocracking catalyst beds.

[0081] The hydrocracking reactor may provide an overall conversion of at least 20% by volume, and typically greater than 60% by volume, of the hydrocracking feed stream in hydrocracking feed line 126 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 a full conversion of at least 90% by volume, based on overall conversion. The hydrocracking reactor 150 may be operated at mild hydrocracking conditions that provide an overall conversion of 20 to 60% by volume, and preferably 20 to 50% by volume, of the hydrocracking feed stream to products boiling below the heavy diesel boiling range.

[0082] The hydrocracking catalyst may utilize an amorphous silica-alumina base or a zeolite base combined 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, generally, catalysts comprising any crystalline zeolite cracking base upon which a Group VIII metal hydrogenation component is deposited may be suitable. Additional hydrogenation components may be selected from Group VIB for incorporation into the zeolite base. Additionally, the hydroisomerization catalyst from hydroisomerization reactor 48 may be used as a hydrocracking catalyst in hydrocracking reactor 150, but may be operated at the upper end of the hydroisomerization temperature range.

[0083] Zeolite cracking bases, 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, or rare earth metals. They are further characterized by crystal pores with relatively uniform diameters of 4 to 14 angstroms. Zeolites with a relatively high silica-to-alumina molar ratio of 3 to 12 are preferred. Suitable naturally occurring zeolites include, for example, mordenite, stilbite, heulandite, ferrierite, dacialdite, 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 have crystal pore diameters of 8 to 12 angstroms and silica-to-alumina molar ratios of 4 to 6. One example of a preferred group of zeolites is synthetic Y molecular sieve.

[0084] 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 preferred to ion-exchange most or all of the original zeolite's monovalent metal with a polyvalent metal and / or ammonium salt, followed by heating to decompose the ammonium ions associated with the zeolite, leaving hydrogen ions and / or exchange sites at those sites that are effectively 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.

[0085] Mixed polyvalent metal-hydrogen zeolites can be prepared by ion-exchanging with an ammonium salt, followed by partial back-exchanging with a polyvalent metal salt, 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 base is one that is 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 and stable class of zeolites is one in which at least 20% by weight of the ion-exchange capacity is filled with hydrogen ions.

[0086] The active metals used as the hydrogenation component in the preferred hydrocracking catalysts of the present disclosure are those of Group VIII, 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 also be used therewith. The amount of hydrogenation metal in the catalyst may vary within a wide range. Generally, any amount between 0.05 wt. % and 30 wt. % may be used. In the case of noble metals, it is usually preferred to use 0.05 wt. % to 2 wt. % of the noble metal. Although noble metals can deactivate noble 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.

[0087] A 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 adding the selected hydrogenation metal(s), the resulting catalyst powder is filtered, dried, pelletized with the addition of lubricants, binders, etc., as needed, and calcined in air at temperatures ranging from 700°F (371°C) to 200°F (648°C) to activate the catalyst and decompose the ammonium ions. Alternatively, the base component can be pelletized, followed by the addition of the hydrogenation component and activation by calcination.

[0088] The aforementioned catalysts can be used in undiluted form, or the powder catalyst can be mixed and co-pelletized with other 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. These diluents can be used neat or can contain small amounts of added hydrogenation metals, such as Group VIB and / or Group VIII metals. Additional metal-promoted hydrocracking catalysts can also be utilized in the disclosed process, 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.

[0089] 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 time of 0.4 to 2.5 hours. -1 and a liquid hourly space velocity (LHSV) of less than 337 Nm 3 / m 3 Oil (2,000scf / bbl)~2,527Nm 3 / m 3 It may contain hydrogen rates of oil (15,000 scf / bbl).

[0090] The hydrocracked stream may exit hydrocracking reactor 150 in hydrocracking line 158. In one embodiment, the hydrocracked stream may be cooled by heat exchange with the combined hydrocracked feed stream in line 154 and transported to hydrocracking separator 180 for separation. The hydrocracked stream may be separated in hydrocracking separator 180 to provide a liquid hydrocracked stream comprising a vaporous hydrocracked stream in hydrocracking separator overhead line 182 and a stripper liquid hydrocracked stream in hydrocracking separator bottoms line 184. Hydrocracking separator 180 may be in downstream communication with hydrocracking reactor 150.

[0091] Hydrocracker separator 180 operates at 177°C (350°F) to 371°C (700°F), preferably 232°C (450°F) to 315°C (600°F). Hydrocracker separator 180 may be operated at a slightly lower pressure than hydrocracking reactor 150 to account for pressure drops due to intervening equipment. Hydrocracker separator 180 may be operated at a pressure of 3.4 MPa (gauge) (493 psig) to 20.4 MPa (gauge) (2959 psig). The vaporous hydrocracked stream in hydrocracker separator overhead line 182 may have a temperature at the operating temperature of hydrocracker separator 180. The vaporous hydrocracked stream in hydrocracker separator overhead line 182 can be combined with the cooled hydroisomerized stream 52 in hydroisomerization line 50 to provide a mixed hydroisomerized stream in line 54, which can be separated together in hydroisomerization separator 56. Only the vapor component of the hydrocracked stream is mixed with the liquid component of the hydroisomerized stream to retain heat in the liquid hydrocracked stream in line 184. Thus, the liquid hydrocracked stream is not mixed with the liquid hydroisomerized stream, but is separated from the liquid hydrocracked stream until stripping or fractionation.

[0092] The stripper liquid hydrocracked stream in line 184 may be fed to hot stripping column 102 to strip light gases. In one embodiment, the stripper liquid hydrocracked stream in line 184 may be stripped in hot stripping column 102 to remove hydrogen sulfide, naphtha, and light gases. The stripper liquid hydrocracked stream in hydrocracker bottoms line 184 may be fed directly to hot stripping column 102 without being cooled. Hot stripping column 102 may be operated at a bottoms temperature of from 149°C (300°F) to 288°C (550°F), preferably below 260°C (500°F).

[0093] In one embodiment, hot stripping column 102 may be part of a dual stripping vessel 100 including cold stripping column 86 and hot stripping column 102, each separated by an intervening wall 103. A stripping medium, which is an inert gas such as steam from hot stripping medium line 104, may be used to strip light gases from a stripper liquid hydrocracked stream in line 184. Hot stripping column 86 supplies an overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases into hot stripper overhead line 105 and a separator liquid hydrocracked stream to hot stripped bottoms line 106. Hot stripper overhead line 105 preferably supplies cold stripping column 86 for further stripping of lighter boiling point components. The fractionator liquid hydrocracked stream in hot stripping line 106 is preferably heated without a fired heater and fed to product fractionation column 120 at a feed location above the feed location of the fractionator liquid hydroisomerized stream in cold stripping bottoms line 90. The fractionator liquid hydrocracked stream is fractionated in product fractionation column 120 along with the fractionator liquid hydroisomerized stream, as previously described.

[0094] It is important to separate the liquid fuel components, particularly the kerosene components, in the hydrocracked stream 158 from the liquid fuel components in the hydroisomerized stream in line 50 to conserve heat in the hydrocracked stream and avoid having to heat the fuel components in the hydrocracked stream to the kerosene boiling point to separate the kerosene components from the diesel components. In one embodiment, the hydroisomerized stream in line 50 and the hydrocracked stream in line 158 are completely isolated from each other before being separated in respective separators 56 and 180. The liquid hydrocracked stream from hydrocracker separator 180 in line 184 is isolated from the liquid hydroisomerized stream in line 60 from hydroisomerization separator 56 and the stripper liquid hydroisomerized stream in line 70 from cryogenic separator 62. Additionally, a fractionator liquid hydroisomerized stream in line 90 is isolated from the fractionator liquid hydrocracked stream in line 106.

[0095] Figure 2 is a further alternative embodiment to Figure 1 of a process 10' in which a liquid hydrocracked stream taken from the hydrocracked stream is flashed to provide a fractionator liquid hydrocracked stream separate from stripping a stripper hydroisomerized stream. Elements in Figure 2 having the same configuration as Figure 1 will have the same reference numbers as Figure 1. Elements in Figure 2 having a different configuration from the corresponding elements in Figure 1 will have the same reference numbers but are indicated with a prime ('). The configuration and operation of the embodiment of Figure 2 is essentially the same as Figure 1, with the following exceptions.

[0096] Stripping vessel 100' of Figure 2 is a single stripping column 86' that receives and strips light gases from the stripper liquid hydroisomerization stream in cold bottoms line 70 using an inert gas, such as steam, from stripping medium line 89'. Product fractionation column 120' provides a naphtha overhead gas stream in overhead line 122. The fractionation overhead stream may be completely condensed and separated from water in fractionation receiver 130. Unstabilized liquid naphtha from the bottom of receiver 130' in fractionator overhead liquid line 132' may be fed to debutanizer column 170, possibly along with a stripper liquid overhead stream in stripper receiver bottoms line 96 and a rich absorbent stream in rich absorber bottoms line 166, with the condensed reflux stream being refluxed to the column. The fractionator off-gas stream in line 131 is compressed in off-gas compressor 133 to provide a compressed off-gas stream in line 92 and may be combined with a cold stripper overhead stream in cold stripper overhead line 87' to provide a condenser stream in line 94. The overhead stripping stream in overhead line 87' may be mixed with the off-gas compressed stream in line 92 to create a condenser stream in line 94. The condenser stream in line 94 is condensed by cooling and separated in stripping receiver 95. The stripped fractionator liquid hydroisomerization stream in line 90' ​​is fed to product fractionation column 120' for fractionation.

[0097] The liquid hydrocracked stream in hydrocracker bottoms line 184' is fed to hydrocracker flash drum 102' to provide a flashed vaporous hydrocracked stream in flash overhead line 105' and a fractionator liquid hydrocracked stream in flash bottoms line 106'. The vaporous flash hydrocracked stream in flash overhead line 105' may be fed to stripping column 86' to strip volatiles along with a stripped liquid hydroisomerized stream from cold bottoms line 70. The fractionator liquid hydrocracked stream in flash bottoms line 106' may be fed to product fractionation column 120 at a location above the feed for the fractionator liquid hydroisomerized stream in line 90'.

[0098] 3 is a further alternative embodiment to FIG. 1 of process 10" in which a cold stripper liquid hydroisomerization stream in line 70 and a stripper liquid hydrocracked stream in line 184 are stripped in the same stripping column 102" in a single stripping vessel 100'. Elements in FIG. 3 having the same configuration as FIG. 1 will have the same reference numerals as FIG. 1. Elements in FIG. 3 having a different configuration from the corresponding elements in FIG. 1 will have the same reference numerals but are designated with a double prime (''). The configuration and operation of the embodiment of FIG. 3 is essentially the same as FIG. 1 with the following exceptions: A single stripped fractionator liquid stream comprising a stripped liquid hydroisomerization stream in stripped line 106" and a stripped liquid hydrocracked stream is fed to product fractionation column 120. Fractionator overhead gas stream 122 is completely condensed, so that fractionator receiver 130 produces only a liquid bottoms stream, a portion of which is refluxed, and the remaining liquid naphtha in overhead liquid line 132 is fed to be combined with the naphtha stream in the debutanized naphtha stream in line 176 to produce a product naphtha stream in line 178.

[0099] Figure 4 is a further alternative embodiment to Figure 1 of process 10+ in which the cold liquid hydroisomerization stream in line 70+ and the liquid hydrocracked stream in line 184+ are not stripped but are fed directly to product fractionation column 120. Elements in Figure 4 that have the same configuration as Figure 1 will have the same reference numbers as Figure 1. Elements in Figure 4 that have a different configuration from the corresponding elements in Figure 1 will have the same reference numbers but are indicated with a cross symbol (+). The configuration and operation of the embodiment of Figure 4 is essentially the same as Figure 1, with the following exceptions.

[0100] Stripping column 100 of Figure 1, and all accessories thereto, are not present in Figure 4. The fractionator off-gas stream in fractionator column receiver overheads line 131+ is compressed in off-gas compressor 133+ to provide a compressed off-gas stream in line 92+ and is supplied to off-gas scrubbing column 140+. Additionally, a rich absorbent bottoms stream in rich absorber bottoms line 166+ from the bottom of sponge absorber column 160 can be supplied to debutanizer column 170. Unstabilized liquid naphtha from the bottom of receiver 130+ in fractionator overhead liquid line 132+ can be supplied to debutanizer column 170, possibly as a rich absorbent stream in rich absorber bottoms line 166+, while a condensed reflux stream is refluxed to the column.

[0101] All of the liquid hydrocracked stream in lines 184 or 106 may be separated from any of the liquid hydroisomerized streams in lines 60, 70, and 90 in Figure 1 before entering stripping column 100 or product fractionation column 120. This arrangement prevents kerosene in the liquid hydrocracked stream from being cooled and reboiling in product fractionation column 120, which would waste heat. It is contemplated that the liquid hydrocracked stream and the liquid hydroisomerized stream may enter the product fractionation column together. [Example]

[0102] The inventors have simulated the disclosed process using dedicated separators for the hydroisomerization effluent and the hydrocracking effluent. The duty of each heater or exchanger is provided in the table below. In the table, the reference number of the element in the figure is provided for each heater or exchanger, except where not shown in the figure.

[0103] [Table 1]

[0104] It is clear that the disclosed process substantially reduces the load on the fractionator reboiler 121 and the hydroisomerize exchanger 52.

[0105] Specific Embodiments While the following will be described in conjunction with specific embodiments, it will be understood that this description is illustrative, but not intended to limit the scope of the preceding description and appended claims.

[0106] A first embodiment of a process for hydroprocessing a hydrocarbon stream includes hydroisomerizing a hydroisomerization feed stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream, hydrocracking a hydrocracked feed stream in the presence of hydrogen to provide a hydrocracked stream, separating the liquid hydroisomerized stream from the hydroisomerized stream, separating the liquid hydrocracked stream from the hydrocracked stream separated from the liquid hydroisomerized stream, feeding the liquid hydrocracked stream to a product fractionation column, and feeding the liquid hydrocracked stream to the product fractionation column. One embodiment of the present disclosure is one, any, or all of the previous embodiments in this paragraph, including through the first embodiment of this paragraph, further including separating the hydrocracked stream in a hydrocracking separator to provide a vaporous hydrocracked stream and a liquid hydrocracked stream, and feeding the liquid hydrocracked stream to a fractionation column. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising separating the hydroisomerization stream in a hydroisomerization separator to provide a vaporous hydroisomerization stream and a liquid hydroisomerization stream, and feeding the liquid stream to a fractionation column. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein the hydroisomerization feed stream is a biorenewable stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein the hydrocracking feed stream is taken from the product fractionation column. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising cooling the liquid hydroisomerization stream, separating the cooled liquid hydroisomerization stream into a cold vaporous hydroisomerization stream and a cold liquid hydroisomerization stream, and feeding the cold liquid hydroisomerization stream to a fractionation column.An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising combining the vaporous hydrocracked stream with the liquid hydroisomerization stream.An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising stripping the hydroisomerization stream to provide a liquid hydroisomerized stream, and stripping the hydrocracked stream separately from stripping the hydroisomerized stream to provide a liquid hydrocracked stream.An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising stripping the hydroisomerization stream and flashing the hydrocracked stream separately from stripping the hydroisomerization stream to provide a liquid hydrocracked stream. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising hydrotreating the hydrocarbon stream to provide a hydrotreated stream; separating the hydrotreated stream to provide a vaporous hydrotreated stream and a liquid hydrotreated stream; and removing a hydroisomerization feed stream from the liquid hydrotreated stream.

[0107] A second embodiment is a process for hydroprocessing a hydrocarbon stream, the process comprising: hydroisomerizing a hydroisomerization feed stream in the presence of hydrogen over a hydroisomerization catalyst to provide a hydroisomerized stream; separating the hydroisomerized stream in a hydroisomerization separator to provide a vaporous hydroisomerized stream and a liquid hydroisomerized stream; taking a fractionator hydroisomerized stream from the liquid hydroisomerized stream; hydrocracking a hydrocracked feed stream in the presence of hydrogen to provide a hydrocracked stream; separating the hydrocracked stream in the hydrocracking separator to provide a vaporous hydrocracked stream and a liquid hydrocracked stream; taking a fractionator hydrocracked stream from the liquid hydrocracked stream; feeding the fractionator hydroisomerized stream to a product fractionation column; and feeding the fractionator hydrocracked stream to the product fractionation column. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, wherein the hydroisomerization feed stream is a biorenewable stream. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, further comprising cooling the liquid hydroisomerization stream to provide a cooled liquid hydroisomerization stream, separating the cooled liquid hydroisomerization stream into a cold vaporous hydroisomerization stream and a cold liquid hydroisomerization stream, and recovering a fractionator hydroisomerization stream from the cold liquid hydroisomerization stream. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, further comprising combining a vaporous hydrocracked stream with the liquid hydroisomerization stream. One embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, further comprising stripping a stripper hydroisomerization stream taken from the cold liquid hydroisomerization stream to provide a fractionator hydroisomerization stream, and stripping a stripper hydrocracked stream taken from the liquid hydrocracked stream to provide a fractionator hydrocracked stream.An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, further comprising stripping a stripper hydroisomerization stream taken from the cold liquid hydroisomerization stream to provide a fractionator hydroisomerization stream, and flashing the liquid hydrocracked stream to provide a fractionator hydrocracked stream. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the second embodiment of this paragraph, further comprising hydrotreating the hydrocarbon stream to provide a hydrotreated stream, separating the hydrotreated stream to provide a vaporous hydrotreated stream and a liquid hydrotreated stream, and taking a hydroisomerization feed stream from the liquid hydrotreated stream.

[0108] A third embodiment of a process for hydroprocessing a biorenewable feed stream includes hydroisomerizing a hydroisomerization feed stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream; hydrocracking a hydrocracked feed stream in the presence of hydrogen to provide a hydrocracked stream; separating the liquid hydroisomerized stream from the hydroisomerized stream; separating the liquid hydrocracked stream from the hydrocracked stream separated from the liquid hydroisomerized stream; feeding the liquid hydroisomerized stream to a product fractionator; and feeding the liquid hydrocracked stream to a product fractionation column. An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the third embodiment of this paragraph, further comprising stripping a stripper hydroisomerized stream taken from the hydroisomerization stream to provide a liquid hydroisomerized stream, and stripping a stripper hydrocracked stream taken from the hydrocracked stream separately from stripping the stripper hydroisomerized stream to provide a liquid hydrocracked stream.An embodiment of the present disclosure is one, any, or all of the previous embodiments of this paragraph, including through the third embodiment of this paragraph, further comprising stripping a stripper hydroisomerized stream taken from the hydroisomerization stream to provide a liquid hydroisomerized stream, and flashing a flash liquid stream taken from the hydrocracked stream separately from stripping the stripper hydroisomerized stream to provide a liquid hydrocracked stream.

[0109] Without further elaboration, it is believed that, using the preceding description, one skilled in the art can utilize the present disclosure to its fullest extent and easily ascertain the essential characteristics of the present disclosure, and can make various changes and modifications to the present disclosure to adapt it to various uses and conditions, without departing from the spirit and scope of the present disclosure. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0110] Above, all temperatures are set forth in degrees Celsius and all parts and percentages are by weight unless otherwise indicated.

Claims

1. 1. A process for hydroprocessing a hydrocarbon stream, comprising: hydroisomerizing the hydroisomerization feed stream over a hydroisomerization catalyst in the presence of hydrogen to provide a hydroisomerized stream; hydrocracking a hydrocracking feed stream in the presence of hydrogen to provide a hydrocracked stream; separating a liquid hydroisomerization stream from the hydroisomerization stream; separating a liquid hydrocracked stream from the hydrocracked stream separated from the liquid hydroisomerized stream; feeding said liquid hydroisomerized stream to a product fractionation column; and feeding said liquid hydrocracked stream to said product fractionation column.

2. 10. The process of claim 1, further comprising separating the hydrocracked stream in a hydrocracking separator to provide a vaporous hydrocracked stream and a liquid hydrocracked stream, and feeding the liquid hydrocracked stream to the fractionation column.

3. 3. The process of claim 2, further comprising separating the hydroisomerized stream in a hydroisomerization separator to provide a vaporous hydroisomerized stream and the liquid hydroisomerized stream, and feeding the liquid stream to the fractionation column.

4. 10. The process of claim 1, wherein the hydroisomerization feed stream is a biorenewable stream.

5. 10. The process of claim 1, wherein the hydrocracking feed stream is taken from the product fractionation column.

6. 4. The process of claim 3, further comprising cooling the liquid hydroisomerization stream; separating the cooled liquid hydroisomerization stream into a cold vapor hydroisomerization stream and a cold liquid hydroisomerization stream; and feeding the cold liquid hydroisomerization stream to the fractionation column.

7. 7. The process of claim 6, further comprising mixing the vaporous hydrocracked stream with the liquid hydroisomerized stream.

8. 10. The process of claim 1, further comprising stripping a hydroisomerized stream to provide said liquid hydroisomerized stream; and stripping a hydrocracked stream separately from stripping said hydroisomerized stream to provide said liquid hydrocracked stream.

9. 10. The process of claim 1, further comprising stripping a hydroisomerized stream and flashing a hydrocracked stream to provide said liquid hydrocracked stream separately from stripping said hydroisomerized stream.

10. 10. The process of claim 1, further comprising hydrotreating a hydrocarbon stream to provide a hydrotreated stream; separating the hydrotreated stream to provide a vaporous hydrotreated stream and a liquid hydrotreated stream; and recovering the hydroisomerization feed stream from the liquid hydrotreated stream.

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