In-depth article ‖ An overview of residue hydrogenation units and their operational principles; worth saving!

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I. Overview of the Unit
1. Introduction to the Unit
The nominal capacity of the unit is 1.7 million tons per year, with an annual operating time of 8,000 hours. The unit uses a blend of vacuum residue from Shengli pipeline crude oil and Omani crude oil (in a 4:6 ratio), as well as straight-run heavy gas oil and coker gas oil as feedstock. Hydrogen is supplied by a hydrogen production unit. Through catalytic hydrogenation reactions, impurities such as sulfur, nitrogen, and metals are removed, and the residual carbon content is reduced. The treated feedstock serves as raw material for a heavy oil catalytic cracking unit; meanwhile, some diesel fuel is produced, along with small amounts of naphtha and dry gas as by-products. The operational flexibility of the device is 60% to 110%. This unit is mainly composed of a feedstock section, a reaction section (including a fresh hydrogen compressor, a recycled hydrogen compressor, and a recycled hydrogen desulfurization section), a distillation section, and utility sections. The facility is located on the north side of the new plant area, covering an area of 83×196=16,268 square meters, with the hydrogen production equipment situated to its east. 2. Technical features: To prevent excessive pressure drops in the reactor due to blockage by solid particles in the feed, which could affect the long-term operation of the plant, automatic backwash filters are installed for both the plant’s raw materials and the coking wax oil feed, to remove solid particles larger than 25 microns. To prevent the feed oil, lean amine solution, and reaction water from coming into contact with air, which could cause some of the feed materials to oxidize and form polymers and gums leading to system scaling and affecting catalyst performance, dry gas or nitrogen is used for gas sealing in these systems. Injecting an anti-scaling agent into the crude oil slows down the scaling process and improves heat transfer efficiency. Scaling of the feed oil in the hydrogenation unit causes a rapid decline in the heat transfer coefficient of the feed oil heat exchangers, which in turn increases the cooling load on the reaction effluents as well as the heating load on the reaction furnaces; in severe cases, this can shorten the operating cycle. At the same time, during the shutdown for medium replacement, the maintenance workload on heat exchangers and other equipment is also reduced. The reactor is designed with a single bed layer, which facilitates the loading and unloading of the catalyst, especially its removal. Based on the field production experience of similar units, it is relatively difficult to remove the catalyst from the reactor; therefore, the reactor in this unit is designed with a single bed layer. To fully recover energy, a hydraulic turbine is installed between the hot high-pressure separator and the hot low-pressure separator to drive the hydrogen feed pumps; one of these pumps is driven jointly by the hydraulic turbine and an explosion-proof asynchronous motor, while the other is driven solely by an explosion-proof asynchronous motor. The reaction section adopts a thermal high-pressure process, which reduces energy consumption and saves heat exchange area. The crude oil utilizes a heat exchange network with atmospheric residue, hot high-pressure separator gas, and reaction product oil, thereby increasing the inlet temperature of the reaction feed heating furnace, reducing the furnace load, improving energy utilization efficiency, and lowering the energy consumption of the unit. The reaction section adopts a pre-furnace hydrogen mixing scheme to improve heat transfer efficiency and reduce coking. To ensure a proper temperature distribution within the reactor and prevent the reactor temperature from rising too high, thereby avoiding damage to the catalyst, quenched hydrogen is used to regulate the inlet temperature of each reactor, thus ensuring long-term operation of the facility. To prevent H2S and NH3 generated during the hydrogenation process from forming NH4HS crystals at certain temperatures, which would deposit in the air-cooled tube bundles and cause an increase in system pressure drop, deoxygenated water is injected before the reaction effluent enters the air cooler. A circulating hydrogen desulfurization tower is installed to reduce corrosion of equipment and pipelines and improve the purity of circulating hydrogen. The fractionation section employs a dual-tower process; the H₂S removal stripper utilizes 3.5 MPa superheated steam for stripping, while the product fractionator is heated by a feed heating furnace. A mid-stage reflux is provided in the distillation column to generate low-pressure steam, thereby reducing the cooling load at the tower top and improving energy efficiency. A corrosion inhibitor injection facility is installed at the top of the hydrogen sulfide stripping tower to reduce the corrosion caused by hydrogen sulfide in the tower effluent to the tower system. The heat exchange process of the device is optimized to utilize energy step by step, with the excess energy from the solid slag product being used to generate low-pressure steam. To ensure the safety of the catalyst, high-pressure equipment, and operators, emergency pressure relief devices are installed on the compressor inlet pipeline. II. Process principle: Due to factors such as limited oil resources, the increasing heaviness and deterioration of crude oil, rising demand for middle distillates, and ever-stricter environmental regulations, residue lightening technologies have been continuously developed. After being hydrotreated, the residue is fed into a catalytic cracking unit, where large quantities of qualified light oils are produced. Reduced-pressure residue is the oil with the highest density and the greatest content of impurities after crude oil processing; it contains significant amounts of metals, sulfur, nitrogen, and carbon residue. These impurity metals and nitrogen can render the catalysts in downstream units inactive, severely affecting their operational cycle ； Sulfides can corrode the equipment and pipelines in production facilities ； During the further processing in the downstream catalytic cracking unit, the residue is highly unstable and prone to coking, which affects the long-term operation of the catalytic cracking unit ； The incorporation of vacuum heavy paraffin oil and coker wax oil into the feedstock of the unit effectively reduces the viscosity and impurity content of the residue feed, facilitating the catalytic hydrogenation reaction and enabling smoother operation and longer operational cycles for the unit. This unit employs a fixed-bed hydrogenation process; under appropriate temperature, pressure, hydrogen-to-oil ratio, and space velocity conditions, the feed oil and hydrogen react in the presence of a catalyst. This reaction converts the impurities present in the oil – namely sulfur, nitrogen, and oxides – into H2S, NH3, and H2O, which are easier to remove. Heavy metal impurities react with H2S to form metal sulfides that deposit on the catalyst. Polycyclic aromatic hydrocarbons and some unsaturated hydrocarbons are hydrogenated and saturated, thereby producing qualified feed oil for downstream processes, while also generating some diesel and naphtha as by-products. During the hydroprocessing of residue, many complex chemical reactions take place, but the main ones include the following: 1) Hydrodesulfurization reaction 2) Hydrodemetallization reaction 3) Hydrodenitrogenation reaction 4) Hydrodecarbonization reaction 5) Hydrodeoxygenation reaction 6) Aromatic saturation reaction 7) Olefin saturation reaction 8) Hydrocracking reaction 9) Condensation and coking reaction. 1. Hydrodesulfurization reaction (HDS): The hydrodesulfurization of residue is the most important chemical reaction that occurs during its hydroprocessing. Under the action of a catalyst and hydrogen, various sulfur-containing compounds are converted into sulfur-free hydrocarbons and H2S through this reaction. Hydrocarbons remain in the product, while H2S is removed from the reactants. Most of the sulfur in crude oil is present in residue, and the sulfur in residue is mainly distributed in aromatics, resins, and asphaltenes, with the vast majority of this sulfur existing in the form of thiophenes and thiophene derivatives. The C-S bonds in this macromolecule are broken through a hydrogenolysis reaction, converting S into H2S. Taking thiophene and benzothiophene as examples, the hydrodesulfurization reaction equation is: Sulfur present in non-asphaltenes can be readily removed under hydrogenation conditions, achieving a high degree of conversion. However, sulfur contained in asphaltenes is difficult to remove due to the large molecular structure of asphaltenes. Therefore, there is a certain limit to the desulfurization rate in the hydrodesulfurization process of residue oil. The desulfurization reaction is a highly exothermic reaction, with a heat of reaction of approximately 550 kcal/m3 of hydrogen consumed. Since the desulfurization reaction achieves the highest degree of conversion among various hydrogenation reactions, it contributes the most to the total heat generated in the reactor. 2. Hydrodesulfurization and demetallization reactions (HDM): The majority of the metals present in various crude oils are found in residue. Although the concentration of metals in residue (mainly Ni, V, etc.) is very low, at the parts-per-million level, they can still cause permanent poisoning and deactivation of HDS, HDN, and FCC catalysts. Therefore, trace amounts of metal compounds in the residue feedstock must be removed. The hydrodesulfurization reaction of residue is also one of the important chemical reactions that occur during the hydroprocessing of residue. Under the action of a catalyst, various metal compounds react with H2S to form metal sulfides, which then deposit on the catalyst, thereby enabling the removal of sulfur. The metals Ni and V in residual oil primarily exist in the form of porphyrin compounds and asphaltenes (as shown in Figure 2-1). Both of these compounds have rather complex structures; within these large molecular structures, there are not only metals but also impurities such as S and N. In hydrogenation reactions, compounds of Ni and V undergo hydrogenation and hydrodesorption processes, eventually depositing on the catalyst particles in the form of metal sulfides. The sulfides of metal Ni have a strong ability to penetrate the catalyst particles, resulting in relatively uniform deposition both inside and on the outer surface of these particles. In contrast, the sulfides of metal V have a weaker ability to penetrate the catalyst particles, and they mainly deposit near the pores of the catalyst particles as well as on their outer surface. When metal sulfides deposit inside the catalyst particles, two negative effects occur: one is the poisoning of the catalyst’s active sites, but this poisoning effect is not as severe as we had estimated ； Secondly, it causes the pores of the catalyst to become blocked, restricting the diffusion of reactants into these pores and thereby reducing the apparent reaction activity. When metal sulfides deposit on the outer surface of the catalyst, they block the openings of the catalyst’s micropores and reduce the porosity of the catalyst bed, ultimately leading to an increase in the pressure drop across the bed. When metal sulfides are unevenly distributed in the bed volume, the rate of increase in bed pressure drop accelerates. Figure 2-1: Schematic diagram of the asphaltenic structure determined by X-ray diffraction. 3. Hydrodenitrogenation reaction (HDN): Approximately 70% to 90% of the nitrogen in crude oil is present in residue, and about 80% of the nitrogen in residue is concentrated in gums and asphaltenes. The majority of this nitrogen exists in cyclic structures. The nitrogen compounds in residue can be divided into basic and non-basic types; typical non-basic nitrogen compounds include pyrrole, indole, and carbazole, while typical basic nitrogen compounds include pyridine, quinoline, acridine, and dibenzacridine. Their structural formulas are shown below. During the hydroprocessing of residue, various nitrogen-containing compounds undergo hydrogenation in the presence of a catalyst, resulting in the formation of ammonia and hydrocarbons. Ammonia is removed from the reaction products, while the hydrocarbons remain in the final product. The main reaction equation for the hydrodenitrogenation process is as follows: To remove nitrogen from its compounds, it is necessary to break the C-N bonds, and the energy required to break these bonds is much higher than that needed to break C-S bonds. Therefore, the hydrodenitrogenation of residue oil is more difficult to carry out, resulting in a lower removal rate of nitrogen compared to that of sulfur. At the same time, HDN catalysts are required to have strong acidity, but excessive acidity can easily lead to intense coking reactions, thereby poisoning the active sites of the catalyst. The hydrodenitrogenation of residue is also a highly exothermic reaction, with a heat of reaction of approximately 650 kcal/m3 of hydrogen consumed; however, due to its low degree of reaction, its contribution to the total heat release is less than that of the desulfurization reaction. 4. Hydrodecarbonization of Residues Reaction (HDCR): The hydrodecarbonization of residues reaction is also an important reaction in the hydrotreatment of residue oil; the conversion rate of residues is an important indicator in this process. Unlike impurities such as S, N, and metals, the amount of residue in oil indicates the coking tendency of high-boiling-point components in the oil, such as polycyclic aromatic hydrocarbons, resins, and asphaltenes, during processing; this is generally expressed by the residue value. According to chemical analysis, condensed aromatic hydrocarbons with five rings or more are precursors to the formation of char. The residue values of resins and asphaltenes in residue are the highest, which is consistent with the high content of polycyclic aromatic hydrocarbons and heterocyclic aromatic hydrocarbons in these compounds. During the residue hydrogenation process, the polycyclic aromatics, which serve as precursors to char, are gradually hydrogenated and saturated, resulting in a decrease in their polycyclicity; some of them turn into aromatics with fewer than five rings and thus are no longer considered precursors to char. 5. Hydrodeoxidation reaction (HDO): The organic oxygen-containing compounds in petroleum fractions mainly fall into two categories: phenols (derivatives of phenol and naphthol) and oxygenated heterocyclic compounds (derivatives of furans). In addition, there are small amounts of alcohols, carboxylic acids, and similar compounds. Alcohols, carboxylic acids, and similar compounds can be easily hydrogenated and deoxygenated to yield the corresponding hydrocarbons and water, whereas carboxylic acid compounds undergo decarboxylation or have their carboxyl groups converted into methyl groups under hydrogenation conditions. Phenolic hydrodeoxygenation involves both direct hydrodeoxygenation and a process in which the ring is first hydrogenated and saturated prior to hydrodeoxygenation. The hydrodeoxygenation mechanism of dibenzofuran-based polycyclic oxygen-containing compounds is similar to that of dibenzothiophene-based polycyclic sulfur-containing compounds; that is, deoxygenation can occur directly via hydrogenation, or it can proceed after the rings are first saturated by hydrogenation. 6. Aromatic hydrodesaturation reaction: The aromatic hydrodesaturation of residue oil mainly involves the hydrogenation of polycyclic aromatics. This type of reaction is the most difficult among all the hydrogenation reactions that take place during the hydroprocessing of residue oil. Monocyclic aromatics are also difficult to hydrodesaturate. Taking the hydrodesaturation reactions of naphthalene and phenanthrene as examples, their reaction equations along with the chemical equilibrium constants at 327°C and 427°C are available at: http://mmbiz.qpic.cn/mmbiz/35JHtweQnntuvGKt9kw95ia9GCLhroeYZj06yh5YQk0sjO1wl3miblr6c32n5IZVGQW9922bMuB1GYlJMPsib59aw/0?wx_fmt=jpeg. The characteristics of the hydrogenation of polycyclic aromatics are as follows: (1) Hydrodesaturation occurs ring by ring, with the difficulty of hydrogenation increasing with each additional ring ； (2) The hydrogenation reaction in each ring is a reversible reaction and is at equilibrium ； (3) The degree of hydrogenation of polycyclic aromatic hydrocarbons is often limited by chemical equilibrium ； (4) If substituents are attached to the benzene ring, the hydrogenation saturation of aromatic compounds becomes more difficult, and as the number of substituents increases, the difficulty of such hydrogenation saturation grows further. At higher hydrogen partial pressures and lower reaction temperatures, the chemical equilibrium of the hydrogenation saturation of aromatics shifts to the right, facilitating the progress of this reaction. Conversely, at lower hydrogen partial pressures and higher reaction temperatures, the chemical equilibrium of aromatic saturation shifts to the left, which favors the dehydrogenation and condensation of naphthenes to form polycyclic aromatics; these compounds further condense to form coke, which deposits on the catalyst and reduces its activity. Therefore, during the hydrotreatment of residue, it is advisable to maintain a high hydrogen partial pressure, while the temperature of the HDN catalyst should not be too high, in order to facilitate the hydrogenation saturation of aromatics. 7. Hydrogenation saturation of olefins: Among all hydrotreating reactions involving residue oil, the hydrogenation saturation reaction of olefins occurs at a relatively fast rate; it is second only to the rate of hydrodemetallization. At the temperature used for hydrodesulfurization, the hydrogenation reaction of olefins essentially reaches complete saturation. The typical reaction equation for the hydrogenation of olefins is as follows: http://mmbiz.qpic.cn/mmbiz/35JHtweQnntuvGKt9kw95ia9GCLhroeYZceTVmQxrcm5PKDgCH9htKLC8wDIWqP0aZ1icKojTSROeCFl6lOawlXw/0?wx_fmt=jpeg Hydrogenation of olefins is a highly exothermic reaction; however, due to the low content of olefins in residue, although the hydrogenation reaction proceeds rapidly and generates a lot of heat, its contribution to the total heat released is not significant. 8. Hydrocracking reaction: Hydrocracking is a reaction in which larger hydrocarbon molecules in the feed are converted into smaller molecules in the presence of hydrogen and a catalyst. Taking alkanes and alkenes as examples, a typical hydrocracking reaction equation is: CnH2n+2 + 2 H2 → CmH2m+2 + Cn-mH2(n-m). The extent of hydrocracking is measured by the conversion rate. Under normal operating conditions, the residue conversion rate is 30% to 38%, with VGO being the main product, followed by diesel, along with a small percentage of naphtha and gases. The hydrocracking reaction is an exothermic reaction; the heat of reaction is approximately 450 kcal/m3 of hydrogen consumed, contributing significantly to the total heat of reaction. The conversion rate increases as the reaction temperature rises, but toward the end of operation, this temperature-increasing effect diminishes due to severe catalyst deactivation. Furthermore, hydrocracking at high temperatures exacerbates coking reactions on the catalyst and reverses the aromatics saturation reaction, which hinders the progress of denitration and desulfurization reactions; therefore, the temperature increase range is limited. 9. Condensation coking reaction: During the hydroprocessing of residue oil, various condensation coking reactions occur as different reactions take place. Coke deposits on the outer and inner surfaces of the catalyst particles, leading to catalyst poisoning and deactivation. The deposition of carbonaceous deposits on the catalyst mainly occurs within 15 days after the completion of catalyst presulfurization and the switch to residue feedstock. In subsequent operation, the deposition of carbon deposits on the catalyst will tend to level off. Therefore, when switching the feedstock during the start-up of a residue hydrotreating unit, it must be done gradually to fully utilize the catalyst’s activity and stability. 10. Characteristics of the residue hydrogenation process. By studying and summarizing the fixed-bed hydrogenation process for residues, the following characteristics were identified: First, there are differences between different reaction beds or different sections within the same bed. 1) The hydrogenation reaction is an exothermic reaction; in industrial reactors, a temperature rise occurs within the same bed, meaning that the reaction temperature is higher in the lower part of the bed. 2) Easily reactive substances react first in the upper part of the bed or in the first bed, while poorly reactive substances react in the lower part of the bed or in subsequent beds. 3) The reactant concentration is higher at the upper part of the bed, while it is lower at the lower part of the bed. That is, the reaction conversion in the upper part of the bed layer is higher, and the load is greater. 4) The hydrogenation reaction consumes hydrogen to produce hydrogen sulfide and ammonia; therefore, the concentrations of H2, H2S, and NH3 differ between the upper and lower parts of the bed. Secondly, residue contains a relatively large amount of impurities and undesirable components. It has a high average molecular weight and viscosity, resulting in poor reaction performance and easy catalyst deactivation. Therefore, the operating conditions for the hydrotreating of residue are stringent, involving high pressure and temperature, as well as low space velocity. Thirdly, during the fixed-bed hydrotreating process of residue, a significant amount of solids such as coke and metal sulfides are generated. The deposition of these solids in the bed leads to an increase in the pressure drop across the bed until it reaches the design limit, forcing the unit to be shut down. Fourth, a catalyst combination loading technique must be employed in the residue hydroprocessing process. 11. Residue hydrogenation catalysts: 1) Composition and principles of the catalysts; 2) Catalyst combination packing (CCS); 3) Protection of catalysts; 4) Demetallization catalysts; 5) Desulfurization catalysts; 6) Denitration catalysts; 7) Impact of quality changes in catalysts during use on production and methods for adjustment; 8) Processes required for treating fresh catalysts; 9) Catalyst deactivation. 12. Main factors affecting residue hydrogenation. The purpose of determining and adjusting process parameters is to convert raw materials into qualified products. A change in one process parameter often necessitates adjustments to several other parameters; therefore, it is essential to understand the interactions between various process parameters and their effects on product properties. 1) Properties of the feed oil 2) Reaction pressure 3) Hydrogen partial pressure 4) Feed rate 5) Circulating hydrogen 6) Reaction temperature III. Brief description of the process flow 1. Reaction section The mixed feed oil enters the feed oil buffer tank V101 under cascade control of level and flow rate. The crude oil emerges from the bottom of the crude oil buffer tank V101; after being pressurized by the crude oil booster pump P101, it enters the distillation section where it exchanges heat with the hydrogenated residue/crude oil heat exchangers E101A/B/C/D. Subsequently, it passes through the crude oil filter SR101 to remove impurities in the crude oil that are larger than 25μm in size. The filtered crude oil enters the post-filter crude oil buffer tank V102. After coming out from the bottom of V102, the crude oil is pressurized by the hydrogenation feed pump P102. The pressurized crude oil is then mixed with the hydrogen that has been preheated by E104. Subsequently, it passes through the heat high-pressure gas/mixed feed heat exchanger E103 and the reaction effluent/reaction feed heat exchanger E102 to be preheated, before entering the reaction heating furnace F101 where it is heated to the temperature required for the reaction. It then enters the first reactor R101. The inlet temperature of this first reactor is controlled by adjusting the amount of fuel used in the reaction heating furnace. After that, the fluid proceeds to the other three reactors, R102, R103, and R104, where catalytic hydrogenation reactions take place to remove sulfur, nitrogen, metals, and other impurities. The inlet temperature of each reactor is controlled by adjusting the amount of cold hydrogen injected into the piping between the reactors. The reaction products coming out of R104 enter the hot high-pressure separator V103 after being heat-exchanged in the reaction effluent/reaction feed heat exchanger E102. The reaction effluent is separated into gas and liquid in the thermal high-pressure separator V103. The hot high-pressure gas emerging from the top passes through the thermal high-pressure gas/mixed feed heat exchanger E103 and the thermal high-pressure gas/mixed hydrogen heat exchanger E104 before entering the thermal high-pressure gas air cooler A101; after cooling, it enters the cold high-pressure separator V105 for the separation of gas, oil, and water. The hot high-pressure liquid stream coming from the bottom of the hot high-pressure separator, under level control, is fed into the hydraulic turbine HT101 to recover energy, and then enters the hot low-pressure separator V104 for gas-liquid separation. To prevent the precipitation of ammonium salts at low temperatures from blocking the pipelines, deoxygenated water pressurized by the feed pump P103 is injected in front of the hot high-pressure gas air cooler A101 to dissolve the ammonium salts. The cold high-pressure gas (cyclic hydrogen) coming out of the top of the cold high-pressure separator enters the liquid separation tank V107 at the inlet of the cyclic hydrogen desulfurization tower to remove the liquid hydrocarbons it contains, thereby reducing the tendency for foaming in the cyclic hydrogen desulfurization tower. The desulfurization solvent used in the circulating hydrogen desulfurization tower T101 is a methyl diethanolamine (MDEA) solution. The lean amine solution is drawn from the lean amine buffer tank V113, pressurized by the high-pressure lean amine pump P104, and then fed into the top of the circulating hydrogen desulfurization tower. The rich amine solution that emerges from the bottom of the tower enters the rich amine flash tank V114 where it is degassed before being sent out of the plant. After H2S removal, the recycle hydrogen enters the knock-out drum V108 at the inlet of the recycle hydrogen compressor to remove any entrained liquid droplets. The recycle hydrogen exiting from the top of the drum is then pressurized by the recycle hydrogen compressor C101. The pressurized recycle hydrogen is divided into two streams; one stream is mixed with the fresh hydrogen coming from the fresh hydrogen compressor C102 and then recycled back to the reaction section ； Another portion is used as quench hydrogen to control the reactor inlet temperature (some waste hydrogen needs to be discharged to the low-pressure desulfurization section toward the end of operation). The cycle hydrogen compressor is a centrifugal compressor driven by a back-pressure turbine. The cold high-pressure separator liquid coming from the bottom of V105 is depressurized under level control; it is then mixed with the cooled hot low-pressure separator gas from V104. The resulting mixture enters the cold low-pressure separator V109 for gas-liquid separation. The cold low-pressure separator liquid is discharged from the lower part of the tank under level control, passes through the heat exchanger E105 for hot low-pressure gas/cold low-pressure oil and the heat exchanger E201/ABC for diesel/cold low-pressure oil, and finally enters the stripper T201. The cold low-pressure off-gas coming from the top of V109 is, under pressure control, mixed with the gas from the reflux tank V201 at the top of the stripping tower, and then sent to the gas desulfurization section of the 2.4 million tons per year diesel and gasoline hydrogenation plant. Acidic water containing H2S and NH3 enters the acidic water degassing tank V115 for centralized degassing before being sent out of the system. The hot low-boiling fraction is discharged from the bottom of tank V104 under level control and then sent to the distillation section. The hot light gas undergoes heat exchange in the hot light gas/cold light oil heat exchanger E105, then enters the hot light gas air cooler A102 for cooling before proceeding to the cold low-pressure separator V109 for gas-liquid separation. To prevent the precipitation of ammonium salts at low temperatures, which could block the pipelines, intermittent water injection is carried out before the hot light gas air cooler to dissolve the ammonium salts. New hydrogen is supplied from the plant’s hydrogen network and enters the new hydrogen compressor C102, where it is compressed in three stages to increase its pressure. This compressed hydrogen then mixes with the recycled hydrogen coming from the outlet of the recycled hydrogen compressor, and the resulting mixture is sent back to their respective reaction units. Two new hydrogen compressors are installed, one in service and one as a standby. Each compressor features three stages of compression. An inlet knock-out drum is provided at the inlet of the first stage for each compressor, while interstage coolers and knock-out drums are installed between the stages. 2. Fractionation section: The fractionation section consists of three towers and one furnace, namely the hydrogen sulfide removal stripping tower, the fractionation tower, the diesel stripping tower, and the fractionation tower feed heating furnace. The hot light ends from the reaction section, together with the preheated cold light ends, enter the hydrogen sulfide removal stripping tower T201. Stirring at the bottom of the tower is carried out using medium-pressure steam. The vapor at the top of the tower is condensed by the overhead cooler A201 in the stripping tower, and then enters the reflux tank V201 at the top of the stripping tower for gas-liquid separation. The gas from V201 is sent to the gas desulfurization unit of the 2.4 million tons per year diesel and gasoline hydrogenation plant ； The liquid coming out from the bottom of V201 is pressurized by the reflux pump P201 at the top of the stripping tower, and then divided into two parts: one part is returned to the top of the tower as tower top reflux, while the other part is sent out of the unit under the control of the liquid level in the reflux tank. To reduce corrosion in the overhead pipes and heat exchangers, a corrosion inhibitor is pumped to a higher pressure and then injected into the overhead pipes of the stripping tower. The oil from the bottom of the stripping tower is heated to an appropriate temperature in the feed heater F201 before entering the distillation tower T202. This distillation tower is equipped with a diesel extraction side stream as well as a mid-stage reflux stream. The gaseous phase at the top of the tower is cooled by the overhead cooler A202 before entering the reflux tank V202 for gas-liquid separation; the reflux tank utilizes fuel gas as a seal ； The liquid coming from the bottom of the reflux tank V202 is pressurized by the reflux pump P202 at the top of the distillation tower, and then divided into two parts: one part is returned to the top of the tower as tower top reflux, while the other part is cooled by E206 under the control of the liquid level in the reflux tank before being sent out of the plant. The oily wastewater discharged from the bottom water pocket of the reflux tank is pressurized by the oily wastewater pump P203 and then fed as process water into the water injection tank V106. The side-line diesel is drawn from the distillation tower and fed into the diesel stripping tower T203. A reboiler E203 is installed at the bottom of the diesel stripping tower; the oil from the bottom of the distillation tower serves as the heat source, while the gas from the top of the tower is returned to the distillation tower. The diesel is drawn from the bottom of the tower, pressurized by the diesel pump P204, and then cooled to 50°C through the diesel/cold light fraction heat exchanger E201, the water-cooled unit E208, and the diesel air cooler A203 before being sent out of the plant. The mid-stage reflux oil is drawn out from the fractionator oil collection tank using the mid-stage reflux pump P206; after being pressurized, it passes through the mid-stage reflux oil steam generator E202 to absorb heat before returning to the fractionator. The distillation column bottom oil (hydrogenation residue) is pumped out of the bottom of the column using pump P205. After pressure is increased, it passes through the reboiler E203 of the hydrogenation residue/diesel stripping tower, then through the heat exchanger E101 between the hydrogenation residue and the feed oil. Subsequently, it enters the hydrogenation residue steam generator E204 and is cooled to 170°C by the water cooler E209 before being sent to the heavy oil catalytic cracking unit. It can also be cooled to 90°C by the water cooler E210 before being discharged from the unit to the storage area. 3. Gas desulfurization section: The external lean amine liquid from the unit enters the lean amine liquid buffer tank V113, is pressurized to P104 by the high-pressure lean amine liquid pump, and then enters the cyclohydrogen desulfurization tower T101 ； The light gas coming out of the cold low-pressure separator V109 is mixed with the overhead gas from the stripping tower top reflux tank V201, the overhead gas from the amine-rich liquid flash tank V114, and the acidic gas from the acidic water degassing tank V115; this mixture is then sent to the dry gas desulfurization unit of the 2.4 million tons per year diesel and gasoline hydrogenation plant