New hydrocracking process for the production of high quality distillates from heavy gas oils

The present invention is a method of converting a material that boils in the boiling range of Vacuum Gas Oil into a high quality intermediate fraction and / or naphtha and a lighter product, more particularly a single hydrogen loop. Target the multi-stage method used.

In the refining of crude oil, a light oil hydrocracking apparatus is used to convert heavy gas oil into a lighter product by utilizing a single reaction stage or a multi-stage reaction stage. In most cases, different reaction stages are carried out at the same pressure level. If the pressure levels are different, a separate hydrogen loop is used. The multi-stage reaction stage is used to achieve the following: Overall, high conversion using minimum reactor volume and catalyst volume Better product quality Less hydrogen consumption

However, using a multi-reaction system requires more equipment, including a large number of costly high pressure pumps and compressors.

U.S. Pat. No. 5,980,729 discloses a configuration with multiple reaction regions in a single hydrogen loop. This method uses a hot stripper downstream of the denitrification / desulfurization area. The liquid from the hot stripper is pumped to the hydrocracking reactor upstream of the hydrorefining reactor. The recirculated oil from the sorting department is also pumped back to the hydrocracking reactor.

In a normal hydrocracking method, it is necessary to transfer hydrogen from the gas phase to the liquid phase where hydrogen can be used to react with petroleum molecules on the catalyst surface. This is achieved by circulating large volumes of hydrogen gas and oil through the catalyst layer. Oil and hydrogen pass through the layer and hydrogen is absorbed into the thin film of oil distributed on the catalyst. The amount of hydrogen required can be as high as 1000-5000 standard cubic feet / barrel of liquid (standard cubic feet / barrel of liquid), and the amount of catalyst required can also be large, so the reactor is very large. It can operate under harsh conditions of high pressures of several hundred psi to 5000 psi and temperatures of about 400 ° F to 900 ° F.

US Pat. No. 6,224,747 teaches that the flow of VGO is hydrocracked in the hydrocracking reaction zone within the integrated hydroconversion process. The effluent from the hydrocracking reaction zone is combined with a light, aromatic-containing feedstock stream and a mixed stream that is hydrorefined in the hydrorefining reaction zone. The hydrocracked effluent acts as a heat sink for the hydrorefining reaction zone. The integrated reaction system provides a single hydrogen supply and recirculation system for use in the two reaction systems. However, no temperature control is performed between the hydrocracking reaction region and the hydrorefining reaction region.

U.S. Pat. No. 3,592,757 (Baral) describes interregional temperature control by a heat exchanger, similar to the present invention. Baral does not use a single hydrogen loop as it does in the present invention. Baral discloses a hydrofiner (similar to a hydrotreater) that operates in series with a hydrocracker, at which time some of the product is hydrogenated. Supplied to the device. The gas oil supply raw material is supplied to the hydrofiner together with the replenishing hydrogen and the recirculated hydrogen. Recirculation flow and added recirculation hydrogen is added to the flow of hydrofiner products and the mixture is fed to the hydrocracking apparatus. The stream of hydrocracker products is cooled and separated into a stream of gas and a stream of liquid. The gas stream is sent to a circulating hydrogen compressor and recirculated to the hydrofiner. The liquid stream is fractionally distilled into top, middle and bottom streams. The bottom stream is recirculated to the hydrocracking device. The central stream is mixed with hydrogen from the replenishing hydrogen compressor and sent to the hydrogenator. The hydrogen recovered from the hydrogenator is compressed in the stage of the replenishment hydrogen compressor and sent to the hydrofiner.

U.S. Pat. No. 5,114,562 (Haun et al.) Teaches two-stage hydrodesulfurization (similar to hydrorefining) and hydrogenation methods for distillate hydrocarbons. There is heat exchange between the two stages, but no single hydrogen loop is used. Two separated reaction regions are used in succession, the first reaction region is for hydrodesulfurization and the second reaction region is for hydrogenation. The feedstock is mixed with the recirculated hydrogen and fed to the desulfurization reactor. Hydrogen sulfide is stripped from the desulfurization reactor product by countercurrent hydrogen. The flow of liquid products from this stripping operation is mixed with relatively clean recirculated hydrogen, the mixture being fed to the hydrogenation reaction zone. Hydrogen is recovered from the hydrogenation reactor and recirculated as a separated stream to the desulfurization reactor and the hydrogenation reactor. Hydrogen from the stripping operation passes through the separator, is mixed with some of the recirculated hydrogen that is sent to the hydrogenation reactor, is compressed, passes through processing steps, and is recirculated to the hydrogenation reaction. Thus, the hydrocarbon feed stream continuously passes through the desulfurization and hydrogenation reactors, while relatively low pressure hydrogen is supplied for the desulfurization step and relatively high pressure hydrogen is supplied for the hydrogenation step. To.

<p> The first embodiment of the present invention is disclosed in FIG. The process configuration of this first embodiment differs from US Pat. No. 5,980,729 in many respects. The first reactor is a hydropurification-hydrodecomposition combined reactor that does not use a recirculating liquid.</p><p> The liquid from the hot stripper downstream of the reactor is depressurized towards the next reaction stage where the hydrocracking reaction is complete. No pump is used to transport the liquid. In addition, the second hydrocracking stage operates at a lower pressure than the first reaction stage.</p><p> According to the present invention, medium to high conversion can be achieved using a single hydrogen loop. Product quality can be adjusted to meet specifications, elimination of product loss and hydrogen savings. The pressure in the reaction stage is maintained at a level suitable for the unique type of feedstock properties, i.e., only the first stage reactor, which processes the most difficult feedstock, must operate at the highest pressure level. This method does not require a high temperature, high pressure pump. The second hydrocracking reactor stage can operate in parallel or countercurrent mode with respect to the reaction gas, which is mainly replenishing hydrogen in the present invention. High-purity supplementary hydrogen is supplied to the second hydrogenation decomposition reaction stage in order to maximize the partial pressure of hydrogen. The second stage is filled with a very active catalyst that can be used for hydrocracking at relatively low pressures.</p><p> A second embodiment of the present invention is disclosed in FIGS. 2 and 3. The flow of reduced gas oil is first hydrocracked in the first stage hydrocracking reaction region of the integrated hydrogen conversion method. The integrated hydrogen conversion method has at least one hydrocracking stage and at least one hydrorefining stage. The effluent from the hydrodesulfurization reaction region of the first stage is combined with the flow of the light, aromatic-containing feedstock, and the mixed flow is hydrorefined in the second stage equipped with the hydrorefining reaction region. Will be done. Heat exchange takes place between the first-stage hydrocracking reaction region and the second-stage hydrorefining reaction region, enabling temperature control in the first-stage hydrorefining region. The temperature of the first-stage hydrogen purification apparatus is lower than the temperature of the first-stage hydrocracking apparatus. This improves the aromatic saturation of the converted hydrocarbons and also makes the catalyst in the first stage hydrorefining region different from the catalyst in the next hydrocracking region that may be present. can do. In one embodiment, the effluent from the first stage hydrorefining apparatus is heated by a heat exchanger and then sent to a high temperature and high pressure separator where the light overhead ends are removed and sent to the low temperature and high pressure separator. Sent. In the low temperature and high pressure separator, hydrogen and hydrogen sulfide gas are removed at the top, and the material that boils in the gasoline and diesel fuel range is sent to the rectification tower. Hydrogen sulfide is then removed in the absorber, the hydrogen is compressed, recirculated, used as an interbed quench, and mixed with the reduced gas oil feedstock.</p><p> The liquid effluent of the high temperature and high pressure separator, which may contain substances that boil in the diesel fuel range, is also sent to the rectification tower. The bottom of the rectification column is then hydrocracked and then the effluent is hydrorefined in a device not shown.</p><p> A second embodiment of the invention provides some notable advantages. The present invention provides a method of hydrogenating the flow of two essential oil devices using a single hydrogen supply and a single hydrogen recovery system. Furthermore, the present invention provides a method of hydrocracking one refinery stream and hydrorefining a second stream of refinery by supplying a common hydrogen source. The feedstock to the hydrocracking reaction zone is not contaminated by the contaminants present in the feedstock to the hydrorefining reaction zone. In addition, the present invention provides a good catalyst life and a high yield of refiner products in the desired product, especially in the distillate range, while maintaining a high flow of multiple different refinery devices in an integrated hydrogenation conversion method. Is targeted for hydrogenation. Such a different stream of refinery is derived from the effluent of a vacuum gas cracker refinery, with a significant amount of VGO, which is almost free of catalytic contaminants and / or aromatics compared to others. It may be derived from a different refining method such as FCC (Fluid Catalytic Cracking process) circulating oil or straight-run diesel fuel containing an aromatic compound.</p><p> The attached figure is a diagram illustrating a multi-stage reaction stage using a single hydrogenation treatment loop.</p>

Description of Figure 1 The preheated oil supplied in stream 1 is mixed with the hydrogen gas in stream 40, which is the preheated circulating and replenishing hydrogen gas (reactor supply gas). The feedstock is preheated in a process heat exchanger that has been pressurized to reactor pressure by a feed pump. A mixture of feedstock and reactor feed gas, here flow 2, is heat exchanged (in heat exchanger 41) and final reactor (42) before entering the first stage downflow fixed layer main reactor (3). ) Further preheats. The main reactor or first stage reactor contains a number of layers of hydrogenation catalyst, which can be catalyst layers for hydrogen purification or hydrogen decomposition. The chilled hydrogen from the circulating gas compressor is used as the interlayer coolant (4, 5, 6).

The effluent 7 of the first stage reactor is hydrorefined and partially hydrocracked, but contains hydrogen sulfide, ammonia, light gas, naphtha, intermediate fractions, and hydrorefined gas oil. .. The effluent enters the hot and high pressure separator (8) at a slightly lower pressure and a slightly lower temperature, where most of the diesel fuel and lighter materials are separated from the unconverted oil. The high temperature and high pressure separator has a disk and a donut-shaped tray. The hydrogen-rich gas heated by the heat exchanger 38 is introduced to the bottom for stripping through stream 9.

Flow 11 includes overhead from the hot and high pressure separator. At this point, intermediate fractions such as Light Cycle Oil (LCO), Light Coker Gas Oil (LCGO), Atmospheric Gas Oil (AGO), Light Visbreaker Gas Oil (LVBGO), etc. External raw materials that boil in the boiling range can be introduced (10). The stream 11 is cooled by process heat exchange or steam generation before entering the high pressure hydrogen stripper hydrorefining apparatus (14). The liquid in the stream 11 flows downward through a layer densely packed with the hydrorefining catalyst, during which it is brought into contact with hydrogen flowing in the opposite direction from the stream 25.

The upper stream 15 contains primarily hydrogen, ammonia and hydrogen sulfide, along with some light gas and naphtha. The flow is cooled by process heat exchange (44), contact with water (45), and further by air cooling (46) before being supplied to the low temperature and high pressure separator No. 1 (17). .. By injecting water, most of the ammonia can be removed from the hydrogen gas as an ammonium hydrosulfide solution. Hydrogen, hydrogen sulfide and light hydrocarbon gases are removed from the top as stream 18. Stream 20 is a stream of sour water containing ammonium hydrosulfide. Flow 19 is a flow of hydrocarbons containing effluent, kerosene and diesel fuel range effluents. The stream 18 is sent to the amine absorber (21) and upon contact with the amine, almost all of the hydrogen sulfide is removed from the hydrogen-rich stream (47). After removing hydrogen sulfide, the gas is sent to a circulating gas compressor (23) for compression. The compressed circulating gas (24) is divided into flows 25 and 26. The flow 26 is further divided into a first stage circulating gas supply (27) and a flow 28 for supplying the coolant to the first stage. Dangerous amines leave the amine absorber as stream 48.

The bottom of the high temperature and high pressure separator, and the flow 12, after the pressure is reduced and cooled by process heat exchange, the hydrocracking reaction is completed, and the unconverted material in the flow 12 is further diesel fuel and more. It is fed to a second stage reactor (30) that is converted to a light effluent. High-purity replenished hydrogen (31) is supplied to the second stage reactor from the intermediate stage of the replenished hydrogen compressor (49). Preferably, hydrogen flows upward through the reactor in a countercurrent manner to maximize the benefit of hydrogen partial pressure. The present invention should also work by introducing supplemental hydrogen as a parallel stream. The gas supply criteria for the second stage reactor, taking into account a sufficient gas-to-oil ratio, shall be met by introducing the total amount of replenishment hydrogen required in all reaction stages in front of the second stage reactor. Can be done. However, the present invention is based on the premise that circulating hydrogen is introduced from the circulating gas compressor by the flow 35.

The second reaction stage operates in a clean environment free of ammonia and hydrogen sulfide, and therefore the hydrocracking rate constant is much higher. Catalytic deactivation is greatly reduced. Due to these factors, the catalyst requirement can be reduced and operated at a lower hydrogen partial pressure.

The lower one-stage or multi-stage layer of the second-stage reactor (30) can be filled with a hydrorefining catalyst, into which the material (16) in the diesel fuel range from the hydrogen stripper (14) is introduced. The aromatic saturation can be completed and other hydrotreating reactions can be carried out. Alternatively, the flow 16 can be directed directly to the sorting sector if the quality as diesel fuel is sufficient.

In the reactor 30, there are at least two layers, preferably three to four layers of hydrogenation catalyst layers. The catalyst may be a base metal or noble metal hydrogenation catalyst.

The flow 33 coming from the top of the reactor is some H₂S and ammonia may be present, but mainly contain hydrogen. The flow is cooled by process heat exchange (50) before being sent to the second low temperature and high pressure separator (17.5). The steam above the second cryogenic high pressure separator goes to the replenishing hydrogen compressor (49) and then to the final stage of compression.

The liquid effluent from the reactor 30, flow 34, contains light gas, naphtha, intermediate fractions and hydrorefined gas oil, cooled by heat exchange for the process (51), low temperature and high pressure separator N0. Sent to 2 (17.5).

The bottom (line 37) from the low-temperature high-pressure separator No. 2 is sent separately.

The replenishment hydrogen compressor (49) is a multi-stage machine generally having 3 to 4 compression stages. After each compression stage, the gas is cooled and any condensate is knocked out in a knockout drum (KOD). In the present invention, the gas heading for the second reaction stage is recovered after the intermediate stage of compression. The gas flow (31) is sent to the second reaction stage (30) and returned to the final compression stage of the replenishing hydrogen compressor via the second cryogenic high-pressure separator (flow 36).

After the final compression stage, the high pressure replenishing hydrogen is sent to the first reaction stage, flow 39 and high temperature separator.

Here, reference is made to FIG. 2, which discloses a preferred embodiment of the present invention. Although the figure does not include various auxiliary devices such as heat exchangers, condensers, pumps and compressors, they are not essential to the present invention.

In FIG. 2, two downflow reaction vessels 5 and 15 are depicted. There is a heat exchanger 20 between them. There is at least one reaction zone in each vessel. The first stage reaction, hydrocracking, is carried out in vessel 5. The second stage reaction, hydrorefining, is carried out in vessel 15. Each container is depicted as having three catalyst layers. The first reaction vessel 5 is for decomposing the first essential oil apparatus flow 1. The second reaction vessel 15 is for removing nitrogen-containing and aromatic molecules from the second essential oil apparatus flow 17. The appropriate ratio of the catalyst volume in the first reaction vessel to the catalyst volume in the second reaction vessel is extensive and depends on the ratio of the first essential oil device flow to the second essential oil device flow. The usual ratio is generally between 20: 1 and 1:20. The preferred volume range is between 10: 1 and 1:10. A more preferred volume range is between 5: 1 and 1: 2.

In the integrated method, the first essential oil stream 1 is combined with the hydrogen-rich gas stream 4 to form the first feedstock 12. The flow from the furnace 30, the flow 13, is sent to the first reaction vessel 5. The hydrogen-rich gas stream 4 contains more than 50% hydrogen, the rest being various amounts of light gas, including hydrocarbon gas. The hydrogen-rich gas stream 4 shown in the figure is a mixture of supplemental hydrogen 3 and circulating hydrogen 26. The use of circulating hydrogen is generally preferred for economic reasons, but is not always required. The first feedstock 1 is one and more heat exchangers, such as the heat exchanger 10 coming out as a stream 12, and (flow), preferably before being introduced into the first reaction vessel 5, where hydrocracking takes place. It can be heated by one or more heaters such as heater 30 (which comes out as 13). Hydropurification is preferably carried out in container 15.

Hydrogen is also added as a cooling stream through pathways 6 and 7, and 9 and 11 (which also come from hydrogen stream 4) to cool the first and second reaction stages, respectively. Can be done. The flow 14 which is the effluent from the hydrocracking is cooled by the flow 2 in the heat exchanger 20. Stream 2 is boiled in the diesel fuel range and may be light cycle oil, light gas oil, atmospheric gas oil, or a mixture thereof. The flow 2 exits from the heat exchanger 20 as a flow 16 and merges with the flow 14 coming out of the heat exchanger 20 to form the mixed feedstock oil 17. The hydrogen in the stream 8 merges with the mixed feedstock 17 before entering the vessel 15. Stream 17 enters vessel 15 for hydrorefining and exits as stream 18.

The second reaction stage found in vessel 15 contains at least one catalyst layer, such as a hydrorefining catalyst, which is at least a portion of the nitrogen compound in the second feedstock and at least in the aromatic compound. The conditions are maintained sufficient to convert some.

The hydrogen flow 4 may be circulating hydrogen from the compressor 40. Alternatively, stream 4 may be a new stream of hydrogen coming from a hydrogen source outside the method.

The effluent in the flow 18 and the second reaction region contains heat energy that may be recovered by heat exchange in the heat exchanger 10. The second stage effluent 18 appears as a flow 19 from the heat exchanger 10 and is sent to the high temperature and high pressure separator 25. The liquid effluent from the high-temperature and high-pressure separator 25, the flow 22, is sent separately. The overhead gas flow from the separator 25, the flow 21, merges with the water from the flow 23 for cooling. The freshly cooled stream 21 enters the low temperature and high pressure separator 35. The light liquid is sent separately in stream 27 (which joins stream 22) and sour water is removed through stream 34. The gaseous overhead flow 24 goes to the amine absorber 45 to remove hydrogen sulfide. The purified hydrogen then travels through stream 26 to compressor 40, is recompressed, and is sent to one or more reaction vessels as a recirculation and as a cooling stream that cools the reaction zone. The use of hydrogen is well known in the art.

An exemplary segregation of the hydroconversion method is taught in US Pat. No. 5,082,551, the disclosure of which patent is incorporated herein by reference in its entirety.

The absorption device 45 uses the gas component of the reaction effluent 19 as an alkaline aqueous solution in order to remove contaminants such as hydrogen sulfide and ammonia that may be generated in the reaction stage and may be present in the reaction effluent 19. Includes means of contact with the solution. The hydrogen-rich gas stream 24 is preferably removed from the separation zone at a temperature in the range of 100 ° F to 300 ° F or 100 ° F to 200 ° F.

The liquid stream 22 is further separated by the rectification column 50 to produce an overhead gasoline stream 28, a naphtha stream 29, a kerosene fraction 31, diesel fuel 32 and a rectification column bottom 33. Preferred distillate products have a boiling range in the temperature range of 250 ° F to 700 ° F. C₅Gasoline or naphtha fractions with a boiling range in the temperature range of ~ 400 ° F are also desirable.

Two downflow reactor vessels 5 and 15 are depicted in FIG. The first stage reaction, hydrocracking, is carried out in vessel 5. The second stage, hydrorefining, is carried out in container 15. Each vessel has at least one reaction zone. Each container is depicted as having a three-stage catalyst layer. The first reaction vessel 5 is for decomposing the first essential oil apparatus flow 1. The second reaction vessel 15 is for removing nitrogen-containing and aromatic molecules from the second essential oil apparatus flow 43. The appropriate volume ratio of the catalyst volume in the first reaction vessel to the catalyst volume in the second reaction vessel is widespread and depends on the ratio of the first essential oil device flow to the second essential oil device flow. Normal ratios are generally between 20: 1 and 1:20. The preferred volume ratio range is between 10: 1 and 1:10. A more preferred volume ratio is between 5: 1 and 1: 2.

In the integrated method, the first essential oil apparatus flow 1 merges with the hydrogen-rich gas flow 4 to form the first raw material oil 12, and is sent to the first reaction vessel 5. The hydrogen-rich gas stream 4 contains more than 50% hydrogen and the remainder is various amounts of light gas, including hydrocarbon gas. The hydrogen-rich gas stream 4 shown in the figure is a mixture of supplemental hydrogen 3 and recirculated hydrogen 26. In general, utilizing the flow of recirculated hydrogen is preferable for economic reasons, but it is not essential. The first feedstock oil 1 can also be heated by one or more heat exchangers or one or more heaters before forming the stream 12 together with the hydrogen-rich gas stream 4. The flow 12 is then introduced into a first reaction vessel 5 in which a first stage, preferably where hydrocracking takes place, is installed. The second stage is installed in the container 15, where hydrorefining is preferably carried out.

The flow 14, which is the effluent from the first stage, is heated by the heat exchanger 20. The flow 14 emerges from the heat exchanger 20 as a flow 17 towards the "high temperature / high temperature" high pressure separator 55. The liquid stream 36 exits the "hot / hot" high pressure separator 55 and heads for the rectification tower 60. Flow 37 represents the flow of gasoline and naphtha effluent, flow 38 represents the distillate that has recirculated and returned to the entrance of the hydrorefining apparatus 15, and flow 39 represents the clean bottom material. Represent.

The gas stream 34 exits the "hot / hot" high pressure separator 55 and merges with stream 2, which can be a light cycle oil, light gas oil, atmospheric gas oil, or a mixture thereof, boiling in the diesel fuel range. The stream further merges with the hydrogen-rich stream 4 and exits as stream 18 before entering vessel 15 for hydrorefining.

The second reaction zone found in vessel 15 contains at least one catalyst layer of a catalyst such as a hydrorefining catalyst, which is at least a portion of the nitrogen compound in the second feedstock and an aromatic compound. It is kept under sufficient conditions to convert at least a part of.

The hydrogen flow 4 may be recirculated hydrogen from the compressor 40. Alternatively, stream 4 may be a new stream of hydrogen from a hydrogen source outside the method.

The flow 18, which is the second-stage effluent, contains heat energy that can be recovered by heat exchange such as in the heat exchanger 10. The second-stage effluent 18 exits the heat exchanger 10 as a flow 19 and is sent to the high-temperature and high-pressure separator 25. The flow 22, which is the liquid effluent of the high-temperature and high-pressure separator 25, is sent separately. The stream 21, which is the upper gas stream from the separator 25, joins the water from the stream 23 for cooling. The freshly cooled stream 21 enters the low temperature and high pressure separator 35. The light liquid is sent separately in stream 27 (which merges with stream 22) and sour water is removed through stream 41. The gaseous upper stream 24 goes to the amine absorber 45 to remove the hydrogen sulfide gas. The purified hydrogen then travels through stream 26 to compressor 40, is recompressed, and is sent to one or more reaction vessels as a cooling stream to cool the recirculated product and reaction zone. The use of hydrogen is well known in the art.

The absorber 45 uses the gas component of the reaction effluent 19 to remove contaminants such as hydrogen sulfide and ammonia that may be generated in the reaction stage and may be present in the reaction effluent 19 (flow 24). Includes means of contacting with a solution such as an aqueous alkaline solution. The hydrogen-rich gas stream 24 is preferably removed from the separation zone at a temperature in the range of 100 ° F to 300 ° F or 100 ° F to 200 ° F.

The liquid stream 22 is further separated by the rectification column 50 to produce an upper gasoline stream 28, a naphtha stream 29, a kerosene fraction 31, diesel fuel 32 and a rectification column bottom 33. Preferred distillate products have a boiling range in the temperature range of 250 ° F to 700 ° F. C₅Gasoline or naphtha fractions with a boiling range in the temperature range of ~ 400 ° F are also desirable.

Raw material In the first embodiment of the present invention, a wide variety of hydrocarbon feedstocks are used. Conventional feedstocks include heavy or synthetic oil streams or process streams having boiling points above 392 ° F (200 ° C). Such feedstocks are decompressed gas oil, heavy atmospheric gas oil, decompressed residual oil, delayed coker gas oil, visbreaker gas oil demetallized oil, Includes atmospheric residual oil, diesel fuel, Fisher-Tropsch flow, and FCC flow.

In the case of the second embodiment, one suitable first essential oil device feed feed stream starts at a temperature above 500 ° F (260 ° C) and typically 500 ° F to 1100 ° F (260 ° C to). It is a VGO with a boiling range in the temperature range of 593 ° C). The stream in which 75% by volume of the essential oil stream boils in the temperature range of 650 ° F to 1050 ° F (343 ° C to 565 ° C) is an exemplary feedstock in the first reaction zone. The first essential oil device stream may contain nitrogen, which is usually present as an organic nitrogen compound. The VGO supply stream in the first reaction zone contains less than about 200 ppm nitrogen and less than 0.25 wt% sulfur, but up to 0.5 wt% and above nitrogen, and up to 5 wt% sulfur and more sulfur. Feeding materials with higher levels of nitrogen and sulfur, including feedstocks containing, can be treated by this method. The first essential oil device flow is preferably a low asphaltene flow. A suitable first essential oil device stream comprises less than about 500 ppm asphaltene, preferably less than about 200 ppm asphaltene, more preferably less than about 100 ppm asphaltene. Illustrative streams include light gas oil, heavy fuel oil, staight run gas oil, deasphalted oil, and the like. The first essential oil apparatus flow may be treated prior to this method by, for example, a hydrorefining method, in order to reduce or substantially eliminate the heteroatom content. The first essential oil device stream may also contain recirculating components.

In the hydrocracking reaction step, nitrogen and sulfur are removed from the flow of raw materials supplied by the first refinery in the first hydrocracking reaction region, and the boiling range is converted. 1 Refinery equipment Has a standard boiling range below the normal boiling range of raw material oil. "Normal" means the boiling point or boiling range based on distillation at 1 atm, as measured by D1160 distillation. Unless otherwise stated, all distillation temperatures described herein refer to temperatures in the standard boiling point and standard boiling range. The process in the first hydrocracking reaction zone can be controlled for constant decomposition conversion, and / or sulfur and nitrogen levels of the desired product. Generally, the conversion is related to a reference temperature such as, for example, the minimum boiling point of the feedstock of the hydrocracking apparatus. The degree of conversion is related to the rate at which the feedstock that boils above the reference temperature is converted to a product that boils below the reference temperature.

The effluent in the hydrocracking reaction region is a component that is normally in the liquid phase, such as reaction products and unreacted components in the flow of the first refinery, and components that are usually in the gas phase, such as the gas phase reaction product and unreacted. Contains reactive hydrogen. In this method, the hydrocracking reaction zone is maintained under sufficient conditions to result in a boiling range conversion of at least 25% of the flow of the first essential oil apparatus based on a reference temperature of 650 ° F. Therefore, at least 25% of the components of the flow of the first essential oil device that boils at a temperature above about 650 ° F to the components that boil at a temperature below about 650 ° F in the first hydrocracking reaction region. Will be converted. Operation at a high conversion level of 100% is also within the scope of the present invention. An exemplary boiling range conversion is in the range of about 30% to 90% or about 40% to 80%. The effluent from the hydrocracking reaction zone is further reduced in nitrogen and sulfur content, and at least about 50% of the nitrogen-containing molecules in the flow of the first refinery are converted in the hydrocracking reaction zone. Preferably, the normally liquid effluent in the hydrocracking reaction zone effluent contains less than about 1000 ppm sulfur and less than about 200 ppm nitrogen, more preferably less than about 250 ppm sulfur and less than about 100 ppm nitrogen. ..

catalyst Each hydrogenation region in either embodiment comprises a single catalyst, or several combination catalysts. In a preferred embodiment, hydrocracking continues in the first region and hydropurification continues in the second region.

Generally, hydrocracking catalysts include degrading components, hydrocracking components, and binders. Such catalysts are well known in the art. Degrading components may include amorphous silica / alumina, phase and / or zeolites such as Y or USY zeolites. Highly decomposed active catalysts often use REX, REY and USY zeolites. The binder is generally silica or alumina. The hydrogenated component is a Group VI, Group VII, or Group VIII metal, or an oxide or sulfide thereof, preferably iron, chromium, molybdenum, tungsten, cobalt, or nickel, or a sulfide thereof or a sulfide thereof. One or more oxides. When present in the catalyst, these components generally make up about 5% to about 40% of the catalyst by weight. Alternatively, noble metals, especially platinum and / or palladium, are present alone or in combination with base metal hydrogenating components: iron, chromium, molybdenum, tungsten, cobalt, or nickel as hydrogenating components. If present, platinum group metals make up about 0.1% to about 2% of the catalyst by weight.

Hydrodesulfurization catalysts are usually designed to remove sulfur and nitrogen and saturate some aromatics. Generally, the catalyst is a composite material of a group VI metal or a compound thereof and a group VIII metal or a compound thereof supported on a porous heat-resistant substrate such as alumina. Examples of hydrorefining catalysts are cobalt-molybdenum, nickel sulfide, nickel-tungsten, cobalt-tungsten and nickel-molybdenum supported on alumina. Usually, such hydrorefining catalysts are pre-sulfided.

The choice of catalyst is dictated by process requirements and product specifications. Especially a small amount of H₂When S is present, the noble metal catalyst can be used in the second stage. The low acidity catalyst may be used at the bottom of the second stage hydrocracker to avoid over-decomposing the distillate into gas and naphtha.

Conditions-Hydrogen decomposition stage The reaction conditions in the hydrocracking reaction region are a reaction temperature of about 250 ° C to about 500 ° C (482 ° F to 932 ° F), a pressure of about 3.5 MPa to about 24.2 MPa (500 to 3500 psi), and about 0.1. ~ 20hr^-1Has a feed rate (oil volume / catalyst volume / time). The circulation rate of hydrogen is generally about 350 standard liters H.₂/ kg oil ~ 1780 standard liter H₂It is in the range of / kg oil (2310-11750 standard cubic feet / barrel). Preferred reaction temperatures range from about 340 ° C to about 455 ° C (644 ° F to 851 ° F). Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1000 to 3000 psi). In a preferred catalyst system, the preferred process conditions are a pressure of about 13.8Mpa to about 20.7MPa (2000 to 3000psi), about 379 to 909 standard liters H.₂Gas ratio of / kg oil (2500-6000 standard cubic feet / barrel) to oil, about 0.5-1.5hr^-1LHSV, and hydrocracking conditions involving temperatures in the range 360 ° C to 427 ° C (680 ° F to 800 ° F), were found to involve contacting petroleum feedstock with hydrogen.

Characteristics of feedstock and effluent-hydrorefining stage The flow of the feedstock of the second essential oil device generally has a lower boiling point range than the stream of the feedstock of the first essential oil device. In fact, a significant portion of the flow of raw materials supplied by the second essential oil device has a standard boiling point within the intermediate distillate range, and as a result, no decomposition is required to lower the boiling point, which is a feature of this method. Therefore, at least about 75% by volume of the flow of a suitable second essential oil device has a standard boiling point of less than about 1000 ° F. An essential oil device flow in which at least about 75% by volume of its components has a standard boiling point in the range of 250 ° F to 700 ° F is an example of a preferred second essential oil device feed feedstock flow.

The method of the present invention is particularly suitable for treating intermediate fraction flows that are not suitable for high grade fuels. For example, the method treats a stream of a second essential oil apparatus containing a large amount of nitrogen and / or a large amount of aromatic compound, including a stream containing up to 90% aromatic compounds and higher amounts of aromatic compounds. Suitable for An exemplary second refinery feed feed stream suitable for processing in this manner is crude oil distillation, atmospheric tower bottoms, or coker gas oil, light cycle oil. Alternatively, it contains straight-running vacuum gas oil, including straight-running diesel fractions, from synthetic decomposition materials such as heavy cycle oil.

After the raw material flow supplied by the first refinery is processed in the hydrocracking stage, the effluent from the first hydrocracking region is combined with the second raw material oil, and the combination is hydrogen on the catalyst in the hydrorefining stage. Passed with. Since the hydrodesulfurized effluent already contains relatively no pollutants to be removed by hydrorefining, the hydrodesulfurized effluent passes through the hydrorefining apparatus with almost no change. To do. The unreacted or incomplete reaction feedstock remaining in the effluent from the hydrorefining apparatus is effectively separated from the hydrocracking region to prevent contamination of the catalyst contained therein.

However, the presence of hydrocracker effluent provides important and unexpected economic benefits in this integrated method. While leaving the hydrocracking device, the effluent carries considerable thermal energy. This energy can be used to heat the second reactor feed stream in the heat exchanger before the second feed stream enters the hydrorefining apparatus. This allows a cooler second feed stream to be added to the integrated system compared to what would otherwise be required, saving furnace volume and heating costs.

When the second feedstock passes through the hydrorefining apparatus, the temperature tends to rise again due to heating by the exothermic reaction in the second region. The hydrodesulfurization effluent in the second feedstock acts as a heat sink to mitigate temperature rise throughout the hydrorefining system. The energy contained in the liquid reaction product leaving the hydrorefining apparatus can also be used to exchange heat with other streams that require heating. Generally, the outlet temperature of the hydrorefining apparatus is higher than the outlet temperature of the hydrocracking apparatus. In this case, the present invention provides a further heat transfer advantage of raising the feedstock temperature of the first hydrocracking apparatus in order to perform more effective heat transfer. The effluent from the hydrodesulfurization can also carry unreacted hydrogen for use in the first stage hydrorefining equipment without the need for heating or pumps to increase the pressure.

Conditions-Hydrodesulfurization stage The hydrorefining apparatus is maintained under sufficient conditions to remove at least a portion of nitrogen and at least a portion of aromatic compounds coming from the stream of the second essential oil apparatus. Unless a temperature gradient is created by heating in the reaction region due to heat generation and is alleviated by adding a relatively cooled flow to one or more reaction regions, the hydrorefining apparatus is more than a hydrocracking apparatus. Operates at low temperatures. The supply rate of the reaction liquid flow through the reaction region is 0.1 to 20 hr.^-1It is the range of liquid space velocity. The rate of the feedstock passing through the hydrorefining apparatus increases by the amount of liquid supplied in the flow of the feedstock of the second essential oil apparatus compared to the rate of the feedstock passing through the hydrocracker, and is also 0.1 to 20 hr.^-1It is in the range of liquid space velocity. These process conditions selected for the first reaction zone may be considered to be more stringent than those normally selected for the hydrorefining process.

Anyway, the hydrorefining conditions usually used in hydrorefining equipment are reaction temperature of about 250 ° C to about 500 ° C (482 ° F to 932 ° F), about 3.5MPa to about 24.2MPa (500 to 3500psi). Pressure, and about 0.1 ~ 20hr^-1Has a feed rate (oil volume / catalyst volume / time). The circulation rate of hydrogen is generally about 350 standard liters H.₂/ kg oil ~ 1780 standard liter H₂It is in the range of / kg oil (2310-11750 standard cubic feet / barrel). Preferred reaction temperatures range from about 340 ° C to about 455 ° C (644 ° F to 851 ° F). Preferred total reaction pressures range from about 7.0 MPa to about 20.7 MPa (1000 to 3000 psi). In a preferred catalyst system, the preferred process conditions are a pressure of about 16.0 Mpa (2300 psi), about 379-909 standard liters H.₂Gas to oil ratio of / kg oil (2500 standard cubic feet / barrel ~ 6000 standard cubic feet / barrel), approx. 0.5 ~ 1.5hr^-1Petroleum feedstock in the presence of a layered catalytic system under hydrocracking conditions, including liquid space velocity (LHSV) and temperatures in the range 360 ° C to 427 ° C (680 ° F to 800 ° F). Was found to include contacting with hydrogen. Under these conditions, at least about 50% of the aromatic compounds are removed from the secondary oil refinery stream in the hydrorefining apparatus. It is expected that 30-70% or more of the nitrogen in the second essential oil apparatus stream will be removed in this step. However, the decomposition conversion within the hydrorefining apparatus is generally small, usually less than 20%. Standard methods can be used to measure the aromatic and nitrogen content of the essential oil stream. These include ASTM D5291 for measuring the nitrogen content of streams containing nitrogen above approximately 1500 ppm. ASTM D5762 can be used to measure the nitrogen content of streams containing less than about 1500 ppm nitrogen. ASTM D2007 can also be used to measure the aromatic content of the essential oil stream.

Product Embodiments of the present invention are particularly useful for the production of intermediate fractions that boil in the range of about 250-700 ° F (121-371 ° C). Intermediate fractions are defined as having an approximate boiling range of about 250-700 ° F. At least 75% by volume, preferably 85% by volume, of the intermediate fraction component has a standard boiling point above 250 ° F. At least about 75% by volume, preferably 85% by volume, of the intermediate fraction component has a standard boiling point of less than 700 ° F. The term "intermediate fraction" includes diesel fuel, jet fuel and kerosene boiling range fractions. The boiling point range of kerosene or jet fuel is in the range of 280 to 525 ° F (38 to 274 ° C).

Gasoline or naphtha can also be produced by the method of the invention. Gasoline or naphtha is typically less than 400 ° F (204 ° C), or C₅Boil in the range of. The boiling range of the various product fractions recovered by any refinery will vary due to factors such as the characteristics of the crude oil source, the local refinery market and the price of the product.

The other product of the present invention, heavy hydrorefined gas oil, usually boils in the range of 550 to 700 ° F.

These are the conditions and results obtained using the method depicted in FIG.<tables num="1"><img file="JP4672000B2_D0001.tif" /></tables>

In general, the increase in cetane is 20-45 and the improvement in kerosene smoke point is 7-27 mm.

<figref num="1">It is a figure which shows the use of the interstage high temperature stripper and the interstage high temperature separator.</figref><figref num="2">It is a figure which shows the hydrocracking apparatus and the hydrorefining apparatus in series in a single hydrogen loop separated by a heat exchanger. Light and heavy substances are separated from each other. Hydrogen and hydrogen sulfide can be separated from the light products. Hydrogen is compressed and recirculated. The product is sent to the rectification tower.</figref><figref num="3">It is a figure which shows the hydrocracking step which involves separation and fractionation after that. The material removed from the top is hydrorefined with a stream of light aromatics. Hydrogen is separated from the hydrorefined effluent and recirculated. The product is sent to the rectification tower.</figref>