Method for producing jet fuel with heat integration

Abstract

A process separates a liquid hydrocracking stream from a liquid hydroisomerization stream, thus heat in the hydrocracking stream can be preserved. Preserving heat in the hydrocracking stream avoids having to reheat the hydrocracking stream prior to product fractionation. In particular, kerosene in the hydrocracking stream is not cooled with the hydroisomerization stream and then reheated in fractionation to distill kerosene range hydrocarbons from the diesel range hydrocarbons.

Description

[0001] Priority Claim

[0002] This application claims priority to U.S. Provisional Application No. 63 / 418,020, filed Oct. 20, 2022, the entire disclosure of which is incorporated herein by reference. Technical Field

[0003] This field is the production of hydrocarbons from hydrocarbon feedstocks that can be used as aviation fuels. In particular, this field can relate to the production of aviation fuels from renewable feedstocks such as triglycerides and free fatty acids found in materials such as plant and animal fats and oils. Background Art

[0004] As the demand for fuel increases worldwide, there is increasing interest in producing fuels from sources other than crude oil and blending components from sources other than crude oil. These sources are commonly referred to as biogenic renewable sources and include, but are not limited to, vegetable oils such as corn oil, rapeseed oil, canola oil, soybean oil; microbial oils such as algal oil; animal fats such as inedible tallow; fish oil; and various waste streams such as yellow and brown grease and sewage sludge. A common characteristic of these sources is that they are composed of glycerides and free fatty acids (FFAs). Both triglycerides and FFAs contain aliphatic carbon chains having 8 to 24 carbon atoms. The aliphatic carbon chains in triglycerides or FFAs can be fully saturated or mono-unsaturated, di-unsaturated, or poly-unsaturated.

[0005] Hydroprocessing can include methods of converting hydrocarbons to more valuable products in the presence of a hydroprocessing catalyst and hydrogen. Hydrotreating or hydrogenation is a method of contacting hydrogen with hydrocarbons in the presence of a hydrotreating catalyst, which is mainly actively used to remove heteroatoms such as sulfur, nitrogen, oxygen, and metals from hydrocarbon feedstocks. In hydrotreating, hydrocarbons having double and triple bonds such as olefins can be saturated.

[0006] The production of hydrocarbon products in the diesel boiling range can be achieved by hydroprocessing biogenic renewable feedstocks. The biogenic renewable feedstocks can be hydroprocessed to deoxygenate, decarboxylate, and / or decarbonylate oxygenated hydrocarbons. Decarboxylation and decarbonylation remove carbon from alkane molecules; while deoxygenation does not. Hydroisomerization can be carried out after hydroprocessing to improve the cold flow properties of the product diesel and jet fuels. Hydroisomerization or hydrodewaxing is a hydroprocessing method of increasing the alkyl branching on the hydrocarbon backbone in the presence of hydrogen and a hydroisomerization catalyst to improve the cold flow characteristics of hydrocarbons. Hydroisomerization includes hydrodewaxing herein.

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

[0008] When preparing jet fuel using triglycerides (also known as "fats"), a certain degree of hydrocracking and isomerization is required to meet the jet fuel specifications outlined in ASTM D7566 Annex 2 and ASTM D1655. The key specifications for jet fuel in D7566 are: a freezing point not higher than -40 °C (ASTM D5972, D7153 or D7154), a density not higher than 772 kg / m 3 (ASTM D1298 or D4052), a T10 less than 205 °C (ASTM D86) and a final boiling point (FBP) less than 300 °C (ASTM D86). Larger molecules that do not meet these jet fuel specifications are mainly made to meet these specifications through hydrocracking, which will necessarily result in low yields and low fuel energy density in the preparation process, which is undesirable. Aviation fuel is valued for its high energy per unit volume.

[0009] Carbon intensity is a term that refers to the number of moles of carbon dioxide produced per mole of fuel manufactured. The combustion of hydrocarbons (such as heating a hydrocarbon feed stream in a hydrotreating unit) increases the carbon intensity. It is desirable to provide renewable fuels from methods that reduce the carbon concentration by reducing the heating requirements. Summary of the Invention

[0010] We have found that preheating all reactor feed streams can be achieved by heat exchange with the hydrotreated effluent stream from the hydrotreating reactor. Therefore, since there is no hydrocarbon combustion providing enthalpy, the flame feed heater can be omitted, resulting in reduced capital and operating expenses and a reduction in carbon intensity. Brief Description of the Drawings

[0011] Figure 1 is a schematic process flow diagram of the present disclosure.

[0012] Definition

[0013] The term "communicates" means that material flow is operably permitted between the enumerated components.

[0014] The term "downstream communicates" means that at least a portion of the material flowing towards the main body in the downstream communication can flow operably from the object with which it communicates.

[0015] The term "upstream communicates" means that at least a portion of the material flowing out of the main body in the upstream communication can flow operably towards the object with which it communicates.

[0016] The term "directly communicates" means that the flow from the upstream component enters the downstream component without passing through a fractionation or conversion unit and does not undergo a compositional change due to physical fractionation or chemical conversion.

[0017] The term "indirect connection" means that the flow from an upstream component passes through a fractionation or conversion unit and then enters a downstream component, with a compositional change occurring due to physical fractionation or chemical conversion.

[0018] The term "bypass" means that the object loses downstream connection with the bypass subject at least within the bypass range.

[0019] The term "column" means one or more distillation columns used to separate one or more components with different volatilities. Unless otherwise specified, each column includes a condenser at the top of the column for condensing a portion of the overhead stream and returning it to the top of the column, and a reboiler at the bottom of the column for vaporizing a portion of the bottoms stream and returning it to the bottom of the column. The feed to the column can 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 bottoms outlet temperature. The overhead line and the bottoms line refer to the net lines from downstream of the column to any reflux or reboiling to the column. A stripping column can omit the reboiler at the bottom of the column and instead provide the heating requirement and separation driving force for a liquefied inert medium (such as steam). A stripping column typically feeds from the top tray and withdraws the main product from the bottom.

[0020] As used herein, the term "rich component stream" means a rich stream exiting a vessel having a greater component concentration than the feed to the vessel.

[0021] As used herein, the term "lean component stream" means a lean stream exiting a vessel having a smaller component concentration than the feed to the vessel.

[0022] As used herein, the term "boiling point temperature" means the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling temperature and the distillation pressure, as calculated using the formulas provided in ASTM D86 or ASTM D2887.

[0023] As used herein, the term "true boiling point" (TBP) means the test method for determining the boiling point of a substance in accordance with ASTM D-2892, which is used to produce liquefied gases, distillate fractions, and residues of standardized quality for which analytical data can be obtained, and to determine the yields of the above fractions by both mass and volume, from which the relationship between distillation temperature and mass % is obtained in a column with fifteen theoretical trays at a reflux ratio of 5:1 based on the mass and volume.

[0024] As used herein, the terms "T5" or "T95" mean the temperature at which 5 mass percent or 95 mass percent of a sample boils, as determined using ASTM D-86 or TBP, as appropriate.

[0025] 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 appropriate.

[0026] As used herein, the term "final boiling point" (FBP) means the temperature at which a sample has completely boiled using ASTM D2887, ASTM D-86, or TBP, as appropriate.

[0027] As used herein, the term "diesel boiling range" means that, using the TBP distillation method, hydrocarbons boil in the range of the IBP or T5 to the "diesel cut point": the IBP is between 125 °C (257 °F) and 175 °C (347 °F), the T5 is between 150 °C (302 °F) and 200 °C (392 °F), and the "diesel cut point" includes the T95 between 343 °C (650 °F) and 399 °C (750 °F).

[0028] As used herein, the term "diesel conversion" means the conversion of feed boiling above the diesel cut point to material boiling at or below the diesel cut point in the diesel boiling range.

[0029] As used herein, the term "separator" means a vessel having an inlet and at least one overhead vapor outlet and one bottoms liquid outlet, and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator that can be in downstream communication with a separator that can operate at a higher pressure.

[0030] As used herein, the term "major" or "substantially" means greater than 50%, suitably greater than 75%, and preferably greater than 90%.

[0031] As used herein, the term "C x " is to be understood to refer to a molecule having the number of carbon atoms indicated by the subscript "x". Similarly, the term "C x -" refers to molecules containing less than or equal to x, and preferably x and fewer carbon atoms. The term "C x +" refers to molecules having greater than or equal to x, and preferably x and more carbon atoms.

[0032] As used herein, the term "carbon number" refers to the number of carbon atoms per hydrocarbon molecule and typically per alkane molecule. Detailed Description

[0033] We have found that all feed heating requirements in diesel and jet fuel production processes can be provided by the hydrotreated effluent stream. In particular, the hydrodeoxygenation of oxygenated hydrocarbons from glyceride molecules obtained from renewable biogenic feeds provides sufficient heating requirements for the feed streams to the hydrotreating reactor, the hydroisomerization reactor, and even the hydrocracking reactor (if used).

[0034] In Figure 1 , according to an exemplary embodiment, a method 10 for treating a hydrocarbon feedstock is shown. Preferably, the hydrocarbon feedstock is a biogenic hydrocarbon feedstock. A feed line 12 transports a hydrocarbon stream of fresh, preferably biogenic feedstock, into a feed buffer tank 14. The biogenic feedstock can be mixed with a mineral feed stream, but preferably the biogenic feedstock comprises mainly or all of the biogenic feedstock. The mineral feedstock is a conventional feed derived from crude oil extracted from the ground. The biogenic feedstock can have a nitrogen concentration of 1 wppm to 2000 wppm. The biogenic feedstock can have a high oxygen content of up to 10 wt% or higher. The biogenic feedstock can also contain 1 wppm to 500 wppm sulfur, typically not exceeding 200 wppm sulfur.

[0035] A variety of different bio-renewable feedstocks can be applicable to Method 10. The term "bio-renewable feedstock" is intended to include feedstocks other than those obtained from crude oil. Bio-renewable feedstocks can include any of those feedstocks that contain at least one of glycerides and free fatty acids. Most glycerides are triglycerides, but monoglycerides and diglycerides can also be present and processed. Free fatty acids can be obtained from phospholipids, which can provide phosphorus in the feedstock. Examples of these bio-renewable feedstocks include, but are not limited to, linseed oil, canola oil, corn oil, soybean 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, fat in milk, fish oil, algal oil, sewage sludge, etc. Additional examples of bio-renewable feedstocks include non-edible vegetable oils from the group including: Jatropha curcas (Ratanjot, Wild Castor, Jangli Erandi), Madhuca indica (Mohuwa), Pongamia pinnata (Karanji, Honge), Calophyllum inophyllum, Moringa oleifera, and Azadirachta indica (Neem). The triglycerides and FFA of typical plant or animal fats contain aliphatic hydrocarbon chains having 8 to 30 carbon atoms in their structure. Bio-renewable feedstocks can also include pyrolysis oil of biomass and Fischer-Tropsch wax. As will be understood, bio-renewable feedstocks can include mixtures of one or more of the foregoing examples. The bio-renewable feedstock can be pretreated to remove contaminants and filtered to remove solids.

[0036] The hydrocarbon stream in the feed line 12 may flow out of the feed buffer tank 14 via a feed pump after injecting a sulfiding agent in line 15, and be mixed with the recycle hydrotreating hydrogen stream in the hydrotreating hydrogen line 20 to provide a combined hydrocarbon stream in line 24. The combined hydrocarbon stream in line 24 is mixed with the hydrotreating recycle stream in the recycle line 16 to provide a hydrotreating feed hydrocarbon stream in the hydrotreating feed line 26. The recycle-to-feed ratio may be from 1:1 to 5:1. The hydrotreating feed stream in line 26 may be preheated in the hydrotreating feed exchanger 22 by heat exchange with the twice-cooled hydrotreating stream in the twice-cooled hydrotreating line 32b. Then the heated hydrotreating feed hydrocarbon stream in the hydrotreating feed line 26 may be fed to the hydrotreating reactor 25. The heat exchange with the twice-cooled hydrotreating stream in the hydrotreating feed exchanger 22 provides all the preheating requirements needed for the hydrotreating reactor 25. The heat exchange with the hydrotreating stream is sufficient; no fired heater is required to bring the hydrotreating feed stream in line 26 to the hydrotreating reaction temperature. The hydrotreating feed stream is heated only by indirect heat exchange with other unburned streams.

[0037] The hydrotreating reactor 25 may include a guard bed reactor 27. The guard bed reaction temperature may range between 246 °C (475 °F) and 343 °C (650 °F), and suitably between 288 °C (550 °F) and 304 °C (580 °F). The guard bed reactor 27 is low enough to prevent polymerization of olefins in the FFA, but high enough to promote the occurrence of olefin saturation, hydrodemetallization, hydrodeoxygenation, hydrodesulfurization, and hydrodenitrogenation reactions. The hydrodeoxygenation reaction preferably minimizes the hydrodecarbonylation and hydrodecarboxylation reactions to retain the carbon atoms on the paraffin chain.

[0038] The guard bed reactor 27 may include 1 to 5 guard catalyst beds. In Figure 1Among them, the guard bed reactor 27 includes three guard catalyst beds. The guard bed catalyst may comprise a base metal catalyst on a support. The base metals that can be used in this process include non-noble metals, nickel, chromium, molybdenum, and tungsten. Other base metals that can be used include tin, indium, germanium, lead, cobalt, gallium, and zinc. Metal sulfides can also be used in this process, where the metal in the metal sulfide is selected from one or more of the listed base metals. The hydrotreating feed stream can be charged through the base metal catalyst at a pressure of 1379 kPa (abs) (200 psia) to 13790 kPa (abs) (2000 psia). In an additional embodiment, the guard bed catalyst may comprise 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. A nickel molybdenum catalyst on alumina can be a suitable catalyst in the guard bed reactor 27. Suitable guard catalysts include BGB 300 purchased from UOP LLC, Des Plaines, Illinois, USA. Although the guard bed reactor 27 is shown in Figure 1 Among them, one or more guard beds, such as two, three, or more, can be included in a single hydrotreating reactor. Hydrogen quench from the hydrogen manifold 18 taken from the recycle hydrogen stream in line 19 can be injected at the inter-bed location to control the exothermic temperature.

[0039] The contacted hydrocarbon stream will be discharged from the guard bed reactor 27 in line 28. In the guard bed reactor 27, most of the hydrodemetallation and hydrodeoxygenation reactions will occur along with some hydrodenitrogenation and hydrodesulfurization. The metals removed from the bio-renewable feedstock will include alkali metals, alkaline earth metals, and phosphorus. The contacted hydrocarbon stream will be discharged from the guard bed reactor 27 in line 28, receive hydrogen quench from the hydrogen manifold 18, and enter the hydrogenation reactor 29.

[0040] The hydrotreating reactor 25 also includes a hydrogenation reactor 29. In the hydrogenation reactor 29, under hydrotreating conditions and in the presence of hydrogen, the contacted hydrocarbon stream is contacted with a hydrotreating catalyst to saturate the olefinic or unsaturated portions of the normal paraffin chains in the feedstock. The hydrotreating catalyst also catalyzes hydrodeoxygenation reactions, including hydrodecarboxylation and hydrodecarbonylation reactions, to remove oxygen-containing functional groups from the hydrocarbon molecules in the bio-renewable feedstock, which are converted into water and carbon oxides. The hydrotreating catalyst also catalyzes hydrodesulfurization of organic sulfur and hydrodenitrogenation of organic nitrogen in the bio-renewable feedstock. Basically, the hydrotreating reaction removes heteroatoms from the hydrocarbon and saturates the olefins in the feed stream.

[0041] The hydrotreating catalyst can be provided in one, two, or more beds in a single or multiple vessels, and an inter-bed hydrogen quench stream from a hydrogen quench stream is employed. The recycled hydrogen quench stream taken from the recycle hydrogen pipeline 19 in the hydrogen manifold pipeline 18 can be provided to the processing reactor 29 for inter-bed quenching. Figure 1 Two hydrotreating catalyst beds 29 are shown, but one or more are contemplated.

[0042] The hydrotreating catalyst can include nickel, nickel / molybdenum, or cobalt / molybdenum dispersed on a high-surface area support such as alumina. Other catalysts include one or more noble metals dispersed on a high-surface area support. Non-limiting examples of noble metals include platinum and / or palladium dispersed on an alumina support such as gamma-alumina. Suitable hydrotreating catalysts include BDO 200, BDO 300, or BDO 400 available from UOP LLC, Des Plaines, Illinois, USA. The hydrotreating reaction temperature can range between 271 °C (520 °F) and 427 °C (800 °F), and preferably between 304 °C (580 °F) and 400 °C (752 °F). Generally, the hydrotreating conditions include a pressure of 700 kPa (100 psig) to 21 MPa (3000 psig).

[0043] A hydrotreating stream containing a hydrocarbon fraction having a significant concentration of normal paraffins is produced in the hydrotreating pipeline 32 from the hydrogenation reactor 29 in the hydrotreating reactor 25. The oxygenate concentration in the hydrocarbon fraction is substantially zero, while the olefin concentration is significantly reduced relative to the contacting stream. The organic sulfur concentration in the hydrocarbon fraction can be no more than 500 wppm, and the organic nitrogen concentration in the hydrocarbon fraction can be less than 10 wppm.

[0044] The reaction occurring in the hydrotreating reactor 25 is highly exothermic, so the enthalpy in the hydrotreating stream 32 leaving the hydrotreating reactor 25 is very large, providing an opportunity for heat transfer, especially to the reactor feed stream.

[0045] The hydrotreating stream in the hydrotreating line 32 can first flow to the combined isomerization feed exchanger 34 to heat the hydroisomerization feed stream in the hydroisomerization feed line 44, thereby providing a heated hydroisomerization feed stream in the heated hydroisomerization feed line 46 and cooling the hydrotreating stream through indirect heat exchange, thereby providing a once-cooled hydrotreating stream in line 32a. The once-cooled hydrotreating stream in the hydrotreating line 32a can then exchange heat with the combined hydrocracking feed stream in the combined hydrocracking feed line 154 in the hydrocracking effluent feed heat exchanger 155 to heat the combined hydrocracking feed stream in the combined hydrocracking feed line 154, thereby providing a heated hydrocracking feed stream in the heated hydrocracking feed line 156 and further cooling the once-cooled hydrotreating stream in the hydrotreating line 32a, thereby providing a twice-cooled hydrotreating stream in line 32b. The twice-cooled hydrotreating stream in the hydrotreating line 32b can then exchange heat with the combined hydrocarbon stream in line 26 as previously described in the combined feed heat exchanger 22 to further cool the twice-cooled hydrotreating stream in the hydrotreating line 32b, thereby providing a three-times-cooled hydrotreating stream in the hydrotreating line 32c and heating the hydrotreating feed stream, thereby providing a heated hydrotreating feed stream in the hydrotreating line 31. The three-times-cooled hydrotreating stream in the hydrotreating line 32 can then be further cooled before separation, possibly for steam generation. There is sufficient heat in the hydrotreating stream in line 32 to heat all the reactor feed streams 44, 154, and 26. The reactor feed streams in lines 44, 154, and 26 can be further heated through heat exchange to increase their temperature or help raise their temperature to the reaction temperature, but intense heating such as in a flame heater burning hydrocarbons is not necessary to reach the reaction temperature. The feed streams are heated only through indirect heat exchange with other unburned streams.

[0046] Before the hydrocracking feed stream in line 154 is heated by exchanging heat with the hydrotreating stream in line 32a, the hydroisomerization feed stream in line 44 is heated by exchanging heat with the hydrotreating stream in line 32 with respect to the flow direction of the hydrotreating stream 32. In addition, before the hydrotreating feed stream is heated by exchanging heat with the hydrotreating stream in line 32b, the hydrocracking feed stream in line 154 is heated by exchanging heat with the hydrotreating stream in line 32a with respect to the flow direction of the hydrotreating stream.

[0047] The cooled hydrocarbon feed stream can be separated in a hydrotreating separator 36, which can include an enhanced heat separator (EHS), by means of a stripping gas fed from a stripping line 39 of the isomerization overhead line 58. The hydrotreating feed stream is separated to provide a hydrotreated vapor feed stream in the hydrotreating overhead line 38 and a hydrotreated liquid feed stream in the hydrotreating bottoms line 40, the hydrotreated liquid feed stream having a lower oxygen concentration than the hydrotreating feed stream in line 26. The hydrotreating separator 36 can be a high-pressure stripper. In the hydrotreating separator 36, the hydrotreating feed stream from the hydrotreating line 32 flows downward through the column, where the hydrotreating feed stream is partially stripped of hydrogen, carbon dioxide, carbon monoxide, water vapor, propane, hydrogen sulfide, and phosphine, which are potential hydroisomerization catalyst poisons, by contact with the stripping gas from the stripping line 39. The stripping gas can include make-up hydrogen that has passed through the isomerization reactor 48 and the hydrocracking reactor 150 and the hydrotreating separator 56, as described below.

[0048] The stripping gas in the stripping line 39 enters the hydrotreating separator 36 below the inlet of the hydrotreating feed stream in the hydrotreating line 32. The hydrotreating separator 36 can include internal components such as trays or packing located between the inlet of the hydrotreating feed stream in line 32 and the inlet of the stripping gas in the stripping line 39 to facilitate the stripping of the hydrotreating feed stream. The stripping gas, including the stripped gas, exits as a hydrotreated vapor feed stream in the hydrotreating overhead line 38 extending from the top of the hydrotreating separator 36, which is mixed with a hydroisomerization liquid feed stream in the hydroisomerization bottoms line 60 and cooled in a cooler 64 after being mixed with a cold water-containing feed stream in a cold water-containing line 63 from a reservoir of the cold separator 62 and then enters the cold separator 62.

[0049] The hydrotreating separator 36 operates at a temperature of from 177 °C (350 °F) to 371 °C (700 °F), and preferably at a temperature of from 204 °C (400 °F) to 260 °C (500 °F). Taking into account the pressure drop through the intervening equipment, the hydrotreating separator 36 can operate at a pressure slightly lower than that of the hydrotreating reactor 25. The hydrotreating separator 36 can operate at a pressure between 3.4 MPa (gage) (493 psig) and 20.4 MPa (gage) (2959 psig). The temperature of the hydrotreated vapor feed stream in the hydrotreating overhead line 38 can be the operating temperature of the hydrotreating separator 36.

[0050] The hydrotreated liquid stream that may have been stripped is collected at the bottom of the hydrotreating separator 36 and flows in the hydrotreating bottoms line 40. The liquid hydrotreating stream contains diesel-range material and has a high paraffin concentration if the hydrocarbon feed contains a bioregenerable feedstock. The liquid hydrotreating stream in the hydrotreating separator bottoms line 40 can be split into two streams: a hydroisomerization feed stream taken in the hydroisomerization feed line 42 and a recycle hydrotreating stream taken in the recycle line 16, both taken from the liquid hydrotreating stream in the hydrotreating bottoms line 40. The recycle hydrotreating stream in the recycle line 16 can be pumped and combined with the combined hydrocarbon stream in line 24 as previously described to provide a hydrotreating feed stream in the hydrotreating feed line 26.

[0051] Although the desired products (such as transportation fuels) can be provided in the hydrotreating bottoms line 40 due to the liquid hydrotreating stream containing a higher concentration of normal paraffins, it will have poor cold flow properties and a high FBP, making it not meet the jet fuel specifications. Therefore, to improve the cold flow properties and reduce the FBP, the hydrotreating liquid stream can be hydroisomerized.

[0052] The make-up hydrogen in the make-up line 41 can be compressed in the make-up gas compressor 45 to provide compressed make-up gas in the compressed make-up gas header 47. A hydroisomerization make-up gas stream is taken from the compressed 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 the combined hydroisomerization feed line 44. The combined hydroisomerization feed stream in the combined hydroisomerization feed line 44 can be heated in the hydroisomerization feed exchanger 34 by heat exchange with the hydrotreating stream in the hydrotreating line 32 as previously described to bring the combined hydroisomerization feed stream to the hydroisomerization temperature before feeding the combined hydroisomerization feed stream to the hydroisomerization reactor 48. The heat exchange with the hydrotreating stream is sufficient; no fired heater is required to bring the hydroisomerization feed stream in line 44 to the hydroisomerization reaction temperature. However, heat exchange can be used to bring the combined hydroisomerization feed stream in the combined hydroisomerization feed line 44 to the reaction temperature upstream of the heat exchange that takes place in the combined hydroisomerization feed exchanger 34 with the hydrotreating stream in line 32. For example, the combined hydroisomerization feed stream in the combined hydroisomerization feed line 44 can be heat exchanged with the hydroisomerization stream in the hydroisomerization line 50 to preheat the combined hydroisomerization feed stream in the combined hydroisomerization feed line 44 upstream of the combined isomerization feed exchanger 34. The hydroisomerization feed stream is heated only by indirect heat exchange with other unburned streams.

[0053] The hydroisomerization (including hydrodewaxing) of the n-paraffins in the hydroisomerization reactor 48 can be accomplished by one or more hydroisomerization catalyst beds, and the hydroisomerization can be operated in a co-current operation mode. Fixed bed, trickle bed downflow, or fixed bed liquid immersion upflow mode are all suitable.

[0054] The hydroisomerization catalyst includes a dehydrogenation metal, a molecular sieve, and a metal oxide binder. The hydroisomerization catalyst can include a dehydrogenation metal containing a Group VIII metal. The dehydrogenation metal can 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 can be 0.05 wt% to 5 wt% based on the transition metal composition.

[0055] The dehydrogenation metal distributed between the molecular sieve and the binder is 40 wt% to 65 wt% (preferably 45 wt% to 60 wt%) of the metal distributed on the molecular sieve and 40 wt% to 65 wt% (preferably 45 wt% to 60 wt%) of the metal distributed on the binder. The relevant beneficial effect of the hydroisomerization catalyst is the high activity and selectivity of hydroisomerization. In an additional embodiment, the hydroisomerization catalyst further contains less than 0.5 wt% of carbon and has the relevant beneficial effect of high activity and selectivity in hydroisomerization.

[0056] In one embodiment, the hydroisomerization catalyst includes 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, such as 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 β. The relevant beneficial effect of the molecular sieve is being active in the hydroisomerization of linear hydrocarbons.

[0057] The metal oxide binder can be selected from alumina, silica, silica-alumina, and titanium dioxide or a mixture thereof. Preferably, the metal oxide binder is alumina, and preferably it is γ-alumina.

[0058] Hydroisomerization catalysts typically comprise fine particles having a diameter of from 1 mm to 5 mm. The preparation of the catalyst generally involves forming a stable porous support, followed by impregnation with an active metal. The stable porous support generally comprises a metal oxide and a molecular sieve, which can be a zeolite. A stable support with high porosity is prepared to ensure the maximum surface area, and it is generally desirable to disperse the active metal over the entire internal and external surface area of the support. DI-200, available from UOP LLC, Des Plaines, Illinois, can be a suitable hydroisomerization catalyst.

[0059] Hydroisomerization conditions generally include a temperature of from 150 °C (302 °F) to 450 °C (842 °F) and a pressure of from 1724 kPa (absolute) (250 psia) to 13.8 MPa (absolute) (2000 psia). In another embodiment, the hydroisomerization conditions include a temperature of from 300 °C (572 °F) to 388 °C (730 °F), a pressure of from 3102 kPa (abs) (450 psia) to 13790 kPa (abs) (2000 psia), a LHSV of -1 from 0.5 h -1 to 3 h 3 / m 3 (2,000 scf / bbl) to 2,527 Nm 3 / m 3 oil (15,000 scf / bbl) hydrogen rate. The hydroisomerization quench gas can be withdrawn from the quench gas manifold 57 and provided to the hydroisomerization reactor 48 at an interbed location.

[0060] The hydroisomerization stream from the hydroisomerization reactor 48 in the hydroisomerization line 50 is a stream rich in branched alkanes. Preferably, the hydroisomerization stream is predominantly a branched alkane stream. It is contemplated that the hydroisomerization effluent can contain 80 wt%, 90 wt% or 95 wt% branched alkanes of the total alkane content. The hydroisomerization conditions in the hydroisomerization reactor 48 are selected to avoid undesired cracking, so the major product in the hydroisomerization stream in the hydroisomerization line 50 is branched alkanes. By avoiding undesired cracking, the hydroisomerization stream in the hydroisomerization line 50 has a composition that is close and only slightly less in carbon number than the hydroisomerization feed stream in the hydroisomerization feed line 42. The optimum amount of remaining normal alkanes in line 50 depends on the selectivity of the hydroisomerization catalyst, but can generally be between 1 wt% - 7 wt%.

[0061] The hydroisomerization stream in hydroisomerization line 50 from hydroisomerization reactor 48 can be mixed with the hydrocracking stream in line 152 to provide a combined hydrotreating stream in line 54. The combined hydrotreating stream in line 54 can be further cooled in cold liquid exchanger 55 by heat exchange with the cold separator bottoms stream in line 70 and fed to hydrotreating separator 56 to be separated into a liquid hydrotreating stream and a vapor hydrotreating stream. Internal packing can be located at the top of hydrotreating separator 56 to ensure prevention of liquid components from leaving the hydrotreating overhead line 58. The vapor hydrotreating stream in hydrotreating overhead line 58 extending from the top of hydrotreating separator 56 can be cooled, fed to a drum to separate out condensate and compressed in compressor 59 to provide stripping gas for stripping line 39 in hydrotreating separator 36 and quench gas in quench gas manifold 57.

[0062] In an embodiment, the liquid hydrotreating stream in hydrotreating bottom line 60 extending from the bottom of hydrotreating separator 56 can be pumped to cold separator 62 for further separation together with the vapor hydrotreating stream in line 38 and the cold aqueous stream pumped around the sump of cold separator 62 in cold aqueous line 63. The cold aqueous stream in line 63 can be combined with the vapor hydrotreating stream in line 38 and the liquid hydrotreating stream in line 60 to provide a cooler hydrotreating stream in line 61. The cooler hydrotreating stream in line 61 can be cooled in cooler 64 and fed to cold separator 62. The cold aqueous stream in cold aqueous line 63 is added to the liquid hydrotreating stream and the vapor hydrotreating stream to dissolve salts that may be present in the liquid hydrocarbons in cold separator 62.

[0063] In cold separator 62, the vapor components in the hydrotreating liquid stream and the vapor hydrotreating stream will separate and rise to provide a cold vapor hydrotreating stream in cold overhead line 68, a liquid hydrotreating stream in cold bottom line 70, and a cold aqueous stream taken from the sump in cold aqueous line 63. Some of the cold aqueous stream taken from the sump can be subjected to water treatment. The cold vapor hydrotreating stream in cold overhead line 68 can be washed in scrubber 74 to remove acid gas, thereby providing a washed hydrogen stream in line 72. The washed hydrogen stream in line 72 can be split between the recycle hydrogen stream in line 19 and the purge gas stream. The recycle hydrogen stream in line 19 is compressed in a recycle gas compressor and recycled in manifold line 18 to hydrotreating reactor 25 for interbed quenching and recycled to hydrotreating hydrogen line 20 for combination with the hydrocarbon stream in feed line 12.

[0064] The liquid fuel components in the liquid hydrotreated stream and the vapor hydrotreated stream will leave the cold separator in the cold hydroisomerization bottom line 70. The stripper liquid hydroisomerization stream in the cold hydrotreated bottom line 70 contains diesel and jet boiling range fuels as well as other hydrocarbons such as propane and naphtha.

[0065] In an embodiment, the cold liquid hydrotreated stream in the cold bottom line 70 can be stripped in the stripper tower 86 to remove hydrogen sulfide and other gases. The stripper liquid hydroisomerization stream in the cold bottom line 70 can be heated by heat exchange with the hydrotreated stream in the hydrotreated line 54 in the cold liquid exchanger 55 to cool the hydrotreated stream and heat the cold liquid hydrotreated stream and feed it to the stripper tower 86.

[0066] A stripping medium such as steam, which is an inert gas from the stripping medium line 89, can be used to strip light gases from the stripper liquid hydroisomerization stream in the line 70. The stripper tower 86 provides an overhead stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam and other gases in the stripper overhead line 87, and a fractionator hydroisomerization stream in the stripper bottom line 90. The overhead stripping stream in the overhead line 87 can be cooled, condensed and separated in the stripping receiver 95. The net stripper overhead line 88 from the receiver 95 can convey the net stripper overhead stream to the sponge absorber 140. The unstabilized liquid naphtha from the bottom of the receiver 95 can be conveyed in the stripper receiver bottom line 96 to the debutanizer 170 for naphtha and LPG recovery. The acidic water stream can be collected from the sump of the overhead receiver 95.

[0067] The stripper tower 86 can be operated at an overhead pressure of 0.35 MPa (gage) (50 psig), preferably not less than 0.70 MPa (gage) (100 psig) to not more than 2.0 MPa (gage) (290 psig). The temperature in the overhead receiver 95 is in the range of 38 °C (100 °F) to 66 °C (150 °F), and the pressure is substantially the same as the overhead pressure of the stripper tower 86.

[0068] The stripped hydroprocessing stream in the stripper bottom line 90 can be heated and fed to the product fractionator 120 to provide a fractionated product. The diesel stream in the bottom line 124 is taken out from the bottom of the product fractionator 120. The hydrocracking feed stream in the pipeline 126 can be taken out from the diesel stream in the bottom line 124 from the product fractionator 120. The product fractionator 120 can be reboiled to provide the heat required for distillation by heat exchange with a suitable hot stream or in a fired heater 121. Alternatively, a stripping medium such as steam as an inert gas from the stripping medium pipeline can be used to heat the tower. The reboiled stream is taken to the fired heater 121 and boiled back to the product fractionator 120. The diesel product stream can be taken to the diesel pool in the diesel product line 125 and can be green diesel. The diesel stream in the 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).

[0069] The product fractionator 120 provides an overhead gaseous stream of naphtha in an overhead line 122. The fractionator overhead stream may be fully condensed and separated from water in a fractionation receiver 130. Unstabilized liquid naphtha from the bottom of receiver 130 in a fractionator overhead liquid line 132 may be combined with the naphtha stream in line 176. A sour water stream may be collected from a storage tank of the distillation receiver 130.

[0070] A kerosene stream may be withdrawn from the side of the product fractionation column 120 in a side line 134. The kerosene stream withdrawn in the side line 134 may be stripped in a kerosene stripper 136 to drive off lower boiling point materials, which are returned to the product fractionation column 120 at a higher elevation in an overhead kerosene line 135. A stripped bottoms kerosene stream is produced in a bottoms kerosene line 137 to provide a jet fuel product stream. The jet fuel product stream in line 137 meets the jet fuel specifications according to ASTM D86 and may be a green jet fuel stream withdrawn from the bottom of the kerosene stripper 136. The jet fuel product stream in line 137 may be cooled and sent to a jet fuel pool.

[0071] Optionally, a light diesel stream can be withdrawn in a second side line and stripped in a side diesel stripper not shown.

[0072] The product fractionator 120 can operate at a bottom temperature between 149 °C (300 °F) and 288 °C (550 °F), preferably not exceeding 260 °C (500 °F), and a top pressure of 0.35 MPa (gauge) (50 psig), preferably not less than 0.70 MPa (gauge) (100 psig) to not greater than 2.0 MPa (gauge) (290 psig). The temperature in the top receiver 130 is in the range of 38 °C (100 °F) to 66 °C (150 °F), and the pressure is substantially the same as the top pressure of the product fractionator 120. It is also contemplated that the product fractionator 120 can provide a net top stream containing jet fuel only in the fractionator top liquid line 132, where naphtha and lighter streams are withdrawn in the fractionator receiver net top line (not shown).

[0073] The top stripping stream of naphtha, LPG, hydrogen, hydrogen sulfide, steam, and other gases in the stripper net top line 88 can optionally be washed to remove acid gases and be transferred to the sponge absorber column 140 for hydrocarbon recovery.

[0074] The sponge absorber column 140 can receive the hydrocarbon-rich stream in the stripper net top line 88. The lean absorbent stream in the lean absorbent line 142 can be fed into the sponge absorber column 140 through the absorbent inlet. The lean absorbent can include a naphtha stream in the lean absorbent line 142, possibly from the debutanizer bottoms stream in line 176. In the sponge absorber column 140, the lean absorbent stream and the washed hydrocarbon-rich stream contact countercurrently. The sponge absorbent absorbs LPG hydrocarbons from the net stripper gaseous stream into the stream of rich absorbent.

[0075] The hydrocarbons absorbed by the sponge absorbent include some methane and ethane, as well as most of the LPG, C 3 and C 4 hydrocarbons, and any C 5 and C 6+ light naphtha hydrocarbons in the net stripper gaseous stream. The sponge absorber column 140 operates at a temperature between 34 °C (93 °F) and 60 °C (140 °F) and a pressure substantially the same as or lower than that of the waste gas scrubber 140 to reduce frictional losses. The sponge absorbent exhaust stream depleted of LPG hydrocarbons is discharged from the top of the sponge absorber column 140 through the sponge absorber top line 144 at the top outlet. The sponge absorbent exhaust stream in the sponge absorber top line 144 can be conveyed to a fuel gas header (not shown) for providing fuel gas demand. The rich absorbent stream rich in LPG hydrocarbons is discharged from the bottom of the sponge absorber column 140 at the bottom outlet in the rich absorber bottom line 146, which can be fed to the debutanizer 170 via the stripper top liquid stream in the stripper receiver bottom line 96.

[0076] In an embodiment, the debutanizer 170 can fractionate the stripper liquid overhead stream in line 96 and the rich absorbent stream in the rich absorber bottoms line 146 into a debutanizer bottoms stream mainly containing C 5+ hydrocarbons and a debutanizer overhead stream containing LPG hydrocarbons. The debutanizer overhead stream in the debutanizer overhead line 172 can provide for the recovery of LPG in the debutanizer overhead liquid stream. The debutanizer bottoms stream can be discharged from the bottom of the debutanizer 170 in the debutanizer bottoms line 176. The debutanizer bottoms stream containing naphtha in line 176 can be supplemented with liquid naphtha from the bottom of the receiver 130 in the fractionator overhead liquid line 132 and split between the lean absorbent stream in the lean absorbent line 142 and the product naphtha stream, which is cooled and sent to the gasoline pool in line 178.

[0077] The fractionator bottoms stream in the fractionator bottoms line 124 can contain diesel boiling range hydrocarbons. In an embodiment, the jet fuel stream in line 137 and the diesel stream in line 125 can be withdrawn once without recycle. The fractionation point in the product fractionator 120 between the diesel stream in the bottoms line 124 and the jet fuel stream in the side line 134 can be adjusted to ensure that the jet fuel stream has an appropriate composition to meet the jet fuel specifications, at least after mixing, and in particular to meet the jet fuel density specification. However, since the larger paraffins are concentrated in the fractionator bottoms stream, it is well-suited for hydrocracking into kerosene range hydrocarbons.

[0078] In an optional embodiment, the hydrocracking feed stream in the hydrocracking feed line 126 can be fed into the hydrocracking reactor 150. The hydrocracking reactor 150 is downstream of the hydroisomerization reactor 48 and the hydrotreating reactor 25. The hydrocracking feed stream can be mixed with the hydrocracking hydrogen feed stream taken from the compressed make-up gas header 47 in the line 52 to provide a combined hydrocracking feed stream in the combined hydrocracking feed line 154. The combined hydrocracking feed stream can be heated by heat exchange with the once-cooled hydrotreating feed stream in the line 32a in the hydrocracking effluent feed exchanger 155 to provide the twice-cooled hydrotreating feed stream in the line 32b and the heated hydrocracking feed stream in the heated hydrocracking feed line 156, and the heated hydrocracking feed stream is fed into the hydrocracking reactor 150. The heat exchange in the hydrocracking effluent feed exchanger 155 as described above is sufficient to bring the combined hydrocracking feed stream to the hydrocracking reaction temperature before feeding the combined hydrocracking feed stream into the hydrocracking reactor 150. The heat exchange with the hydrotreating feed stream is sufficient; there is no need for a fired heater to bring the hydrocracking feed stream in the line 154 to the hydrocracking reaction temperature. However, heat exchange can be used to bring the combined hydrocracking feed stream in the combined hydrocracking feed line 154 in the hydrocracking effluent feed exchanger 155 to the reaction temperature upstream of the heat exchange with the once-cooled hydrotreating feed stream in the line 32a. For example, the combined hydrocracking feed stream in the combined hydrocracking feed line 44 can be heat-exchanged with the hydrocracking feed stream in the hydrocracking line 152 to preheat the combined hydrocracking feed stream in the hydrocracking feed line 154 upstream of the hydrocracking effluent feed exchanger 155. The hydrocracking feed stream is heated only by indirect heat exchange with other unburned feed streams.

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

[0080] In the presence of the hydrocracking hydrogen feed stream from the hydrocracking hydrogen line 52, the combined hydrocracking feed stream is hydrocracked in the hydrocracking reactor 150 by a hydrocracking catalyst to provide a hydrocracked feed stream. The quench gas taken from the quench gas manifold 57 can be provided to the hydrocracking reactor 150 at the inter-bed position.

[0081] The hydrocracking reactor can provide a heated hydrocracking feed stream in the hydrocracking feed line 156 to a product in the heavy diesel range with a boiling point lower than 293 °C (560 °F) to 310 °C (590 °F) with a total conversion of at least 20 volume % and typically greater than 60 volume %. The hydrocracking reactor 150 can operate based on the total conversion with a partial conversion of more than 30 volume % or a complete conversion of at least 90 volume % of the feed. The hydrocracking reactor 150 can operate under mild hydrocracking conditions, which will provide a total conversion of the hydrocracking feed stream to a product with a boiling point lower than the heavy diesel boiling range of 20 volume % to 60 volume %, preferably 20 volume % to 50 volume %.

[0082] The hydrocracking catalyst can use an amorphous silica - alumina base or a zeolite base in combination with one or more Group VIII or Group VIB metal hydrogenation components to selectively produce a balance of light diesel and jet fuel distillates. In another aspect, a catalyst typically comprising any crystalline zeolite cracking base with a Group VIII metal hydrogenation component deposited thereon can be suitable. Additional hydrogenation components can be selected from Group VIB to combine with the zeolite base. In addition, the hydroisomerization catalyst of the hydroisomerization reactor 48 can be used as a hydrocracking catalyst in the hydrocracking reactor 150 but operating at the high end of the hydroisomerization temperature range.

[0083] Zeolite cracking bases are sometimes referred to as molecular sieves in the art and typically consist of silica, alumina, and one or more exchangeable cations (such as sodium, magnesium, calcium, rare earth metals). They are also characterized by having crystal pores with a relatively uniform diameter between 4 Å and 14 Å. Zeolites with a relatively high silica / alumina molar ratio (between 3 and 12) are preferably employed. Suitable zeolites found in nature include, for example, mordenite, stilbite, heulandite, ferrierite, gmelinite, 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 with a crystal pore diameter between 8 Å and 12 Å, where the silica / alumina molar ratio is 4 to 6. An example of a zeolite falling into the preferred group is synthetic Y molecular sieve.

[0084] Naturally occurring zeolites usually exist in the sodium form, alkaline earth metal form, or a mixed form. Synthetic zeolites are almost always prepared in the sodium form. In any case, for use as a cracking base, it is preferred that most or all of the original zeolite monovalent metals are ion - exchanged with polyvalent metals and / or with ammonium salts, and then heated to decompose the ammonium ions associated with the zeolite, leaving in their place hydrogen ions and / or exchange sites that are effectively cation - free by further removal of water. Hydrogen or "cation - free" Y zeolites of this nature are more specifically described in US 3,100,006.

[0085] Mixed multivalent metal - hydrogen zeolites can be prepared by ion - exchange with an ammonium salt, followed by partial back - exchange with a multivalent metal salt, and then calcination. In some cases, such as in the case of synthesizing mordenite, the hydrogen form can be prepared by direct acid treatment of an alkali metal zeolite. In one aspect, preferred cracking substrates are those that lack at least 10 wt% and preferably at least 20 wt% of metal cations based on the initial ion - exchange capacity. In another aspect, a desirable and stable class of zeolites is one in which hydrogen ions satisfy at least 20 wt% of the ion - exchange capacity.

[0086] The active metals used as hydrogenation components in the preferred hydrocracking catalysts of the present disclosure are the active metals of Group VIII, namely iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium, iridium, and platinum. In addition to these metals, other promoters can also be used in combination, including Group VIB metals such as molybdenum and tungsten. The amount of hydrogenation metal in the catalyst can vary over a wide range. Generally, any amount between 0.05 wt% and 30 wt% can be used. For noble metals, it is usually preferred to use 0.05 wt% to 2 wt% of noble metals. Noble metals can preferably be used as hydrogenation metals on the hydrocracking catalyst to provide selectivity to jet fuel, since hydrogen sulfide and ammonia, which can deactivate noble metal catalysts, have been removed upstream in the process.

[0087] The method of incorporating the hydrogenation metal is to contact the substrate material with an aqueous solution of a suitable compound of the desired metal, where the metal is present in cationic form. After adding one or more selected hydrogenation metals, the resulting catalyst powder is then filtered, dried, pelletized as needed with added lubricants, binders, etc., and calcined in air at a temperature, for example, between 371 °C (700 °F) and 648 °C (1200 °F), in order to activate the catalyst and decompose ammonium ions. Alternatively, the substrate component can be pelletized, then the hydrogenation component is added and activated by calcination.

[0088] The above - mentioned catalysts can be used in undiluted form, or the powdered catalyst can be mixed with other catalysts of relatively lower activity, diluents, or binders such as alumina, silica gel, silica - alumina co - gel, activated clay, etc. in a proportion within the range of 5 wt% and 90 wt% and co - pelletized. These diluents can be used as they are, or they can contain a smaller proportion of added hydrogenation metals, such as Group VIB and / or Group VIII metals. Additional metal - promoted hydrocracking catalysts can also be used in the method of the present disclosure, which include, for example, aluminophosphate molecular sieves, crystalline chromosilicates, and other crystalline silicates. Crystalline chromosilicates are more fully described in US 4,363,178.

[0089] By a method, the hydrocracking conditions can 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), 0.4 hr -1 to less than 2.5 hr -1 of liquid hourly space velocity (LHSV), and a hydrogen rate of 337 Nm 3 / m 3 (2,000 scf / bbl) to 2,527 Nm 3 / m 3 oil (15,000 scf / bbl).

[0090] The hydrocracked stream can leave the hydrocracking reactor 150 in the hydrocracking line 152. The hydrocracked stream in the line 152 is combined with the hydroisomerization stream in the line 50 to provide a hydrotreated stream in the line 54 and is processed as described above.

[0091] In the foregoing method, all reactor feed streams are heated to the reaction temperature by heat exchange with the hydrotreated stream in the line 32. Therefore, no fired heater is required to heat the pressurized reactor feed streams.

[0092] Embodiment

[0093] We simulated the disclosed method which does not use a fired heater to preheat the feed to any of the reactors. The duty of each heater or exchanger is provided in the table below. In the table, for each heater or exchanger in the drawings, the reference numeral of the element in the drawings is provided in parentheses.

[0094] Table

[0095]

[0096] It is apparent from the simulation that all of the tasks for preheating the feed to the isomerization reactor 48, the hydrotreating reactor 25, and the hydrocracking reactor 150 are provided by heat exchange with the hydrotreated stream in the line 32. By the disclosed method, the feed heaters for the hydrotreating combination and the isomerization feed heater (which are fired heaters typically required in conventional methods) and their utilities are eliminated.

[0097] Specific implementation

[0098] Although the following is described in connection with specific embodiments, it should be understood that the description is intended to illustrate and not limit the scope of the foregoing description and the appended claims.

[0099] A first embodiment of the present invention is a method for hydrotreating a hydrocarbon feed stream, the method comprising heating a hydrotreating feed stream by heat exchange with a hydrotreated stream to provide a heated hydrotreating feed stream; hydrotreating the heated hydrotreating feed stream in the presence of hydrogen by a hydrotreating catalyst to provide the hydrotreated stream; heating a hydroisomerization feed stream by heat exchange with the hydrotreated stream to provide a heated hydroisomerization feed stream; and hydroisomerizing the heated hydroisomerization feed stream in the presence of hydrogen by a hydroisomerization catalyst to provide a hydroisomerized stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating a hydrocracking feed stream by heat exchange with the hydrotreated stream to provide a heated hydrocracking feed stream; and hydrocracking the heated hydrocracking feed stream in the presence of hydrogen to provide a hydrocracked stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydrotreating feed stream without heating the hydrotreating feed stream in a fired heater. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydrotreating feed stream only by heat exchange with the hydrotreated stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydroisomerization feed stream without heating the hydroisomerization feed stream in a fired heater. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydroisomerization feed stream only by heat exchange with an additional stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydrocracking feed stream without heating the hydrocracking feed stream in a fired heater. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, and further comprises heating the hydrocracking feed stream only by heat exchange with an additional stream.One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein with respect to the hydrotreating stream, before the hydrotreating feed stream is heated by heat exchange with the hydrotreating stream, the hydroisomerization feed stream is heated by heat exchange with the hydrotreating stream. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein with respect to the hydrotreating stream, before the hydrocracking feed stream is heated by heat exchange with the hydrotreating stream, the hydroisomerization feed stream is heated by heat exchange with the hydrotreating stream. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein with respect to the hydrotreating stream, before the hydrotreating feed stream is heated by heat exchange with the hydrotreating stream, the hydrocracking feed stream is heated by heat exchange with the hydrotreating stream. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein hydrotreating the heated hydrotreating feed stream includes hydrotreating the hydrotreating feed stream in a guard reactor and in a hydrotreating reactor. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein the hydrotreating feed stream is a fresh hydrocarbon stream. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein the hydroisomerization feed stream is taken from the hydrotreating stream. One embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph to the first embodiment in this paragraph, wherein the hydrocracking feed stream is taken from the hydroisomerization stream.

[0100] A second embodiment of the present invention is a method for hydrotreating a hydrocarbon feed stream, the method comprising heating a hydrotreating feed stream by heat exchange with a hydrotreated stream to provide a heated hydrotreating feed stream; hydrotreating the heated hydrotreating feed stream in the presence of hydrogen by a hydrotreating catalyst to provide the hydrotreated stream; heating a hydroisomerization feed stream by heat exchange with the hydrotreated stream to provide a heated hydroisomerization feed stream; hydroisomerizing the heated hydroisomerization feed stream in the presence of hydrogen by a hydroisomerization catalyst to provide a hydroisomerized stream; heating a hydrocracking feed stream by heat exchange with the hydrotreated stream to provide a heated hydrocracking feed stream; and hydrocracking the heated hydrocracking feed stream in the presence of hydrogen to provide a hydrocracked stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the second embodiment in this paragraph, and further comprises heating the hydrotreating feed stream, the hydroisomerization feed stream and the hydrocracking feed stream only by heat exchange with the hydrotreated stream.

[0101] A third embodiment of the present invention is a method for hydrotreating a hydrocarbon feed stream, the method comprising heating a hydrotreating feed stream by heat exchange with a hydrotreating effluent stream to provide a heated hydrotreating feed stream; hydrotreating the heated hydrotreating feed stream in the presence of hydrogen by a hydrotreating catalyst to provide the hydrotreating effluent stream; withdrawing a hydroisomerization feed stream from the hydrotreating effluent stream; heating the hydroisomerization feed stream by heat exchange with the hydrotreating effluent stream to provide a heated hydroisomerization feed stream; and hydroisomerizing the heated hydroisomerization feed stream in the presence of hydrogen by a hydroisomerization catalyst to provide a hydroisomerization effluent stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the third embodiment in this paragraph, and further comprises withdrawing a hydrocracking feed stream from the hydroisomerization effluent stream; heating the hydrocracking feed stream by heat exchange with the hydrotreating effluent stream to provide a heated hydrocracking feed stream, and hydrocracking the heated hydrocracking feed stream in the presence of hydrogen to provide a hydrocracking effluent stream. One embodiment of the present invention is one, any or all of the previous embodiments in this paragraph to the third embodiment in this paragraph, wherein with respect to the hydrotreating effluent stream, the hydroisomerization feed stream is heated by heat exchange with the hydrotreating effluent stream before the hydrocracking feed stream is heated by heat exchange with the hydrotreating effluent stream, and the hydrocracking feed stream is heated by heat exchange with the hydrotreating effluent stream before the hydrotreating feed stream is heated by heat exchange with the hydrotreating effluent stream.

[0102] Although no further detailed description is provided, it is believed that those skilled in the art can make the most of the present disclosure by using the foregoing description and can easily determine the basic features of the present disclosure without departing from the spirit and scope of the present invention, and various changes and modifications can be made to the present disclosure and adapted to various uses and conditions. Therefore, the foregoing preferred specific embodiments should be understood as being illustrative only and not in any way limiting the remainder of the present disclosure, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0103] In the foregoing, all temperatures are shown in degrees Celsius and all parts and percentages are by weight unless otherwise indicated.

Claims

1. A method for hydrotreating a hydrocarbon feed stream, the method comprises: heating a hydrotreating feed stream by heat exchange with a hydrotreated stream to provide a heated hydrotreating feed stream; hydrotreating the heated hydrotreating feed stream in the presence of hydrogen by a hydrotreating catalyst to provide the hydrotreated stream; heating a hydroisomerization feed stream by heat exchange with the hydrotreated stream to provide a heated hydroisomerization feed stream; and hydroisomerizing the heated hydroisomerization feed stream in the presence of hydrogen by a hydroisomerization catalyst to provide a hydroisomerized stream.

2. The method according to claim 1, the method further comprises heating a hydrocracking feed stream by heat exchange with the hydrotreated stream to provide a heated hydrocracking feed stream, and hydrocracking the heated hydrocracking feed stream in the presence of hydrogen to provide a hydrocracked stream.

3. The method according to claim 1, the method further comprises heating the hydrotreating feed stream without heating the hydrotreating feed stream in a fired heater.

4. The method according to claim 1, the method further comprises heating the hydrotreating feed stream only by heat exchange with the hydrotreated stream.

5. The method according to claim 1, the method further comprises heating the hydroisomerization feed stream without heating the hydroisomerization feed stream in a fired heater.

6. The method according to claim 1, the method further comprises heating the hydroisomerization feed stream only by heat exchange with another stream.

7. The method according to claim 1, the method further comprises heating the hydrocracking feed stream without heating the hydrocracking feed stream in a fired heater.

8. The method according to claim 1, the method further comprises heating the hydrocracking feed stream only by heat exchange with another stream.

9. The method according to claim 1, wherein with respect to the hydrotreated stream, the hydroisomerization feed stream is heated by heat exchange with the hydrotreated stream before the hydrotreating feed stream is heated by heat exchange with the hydrotreated stream.

10. The method according to claim 2, wherein with respect to the hydrotreated stream, the hydroisomerization feed stream is heated by heat exchange with the hydrotreated stream before the hydrocracking feed stream is heated by heat exchange with the hydrotreated stream.

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