A method for processing various liquefied gases using a product refining apparatus

Abstract

This invention belongs to the field of petrochemical technology and relates to a method for processing various liquefied petroleum gases (LPGs) in a product refining unit. The method includes: LPG feedstocks from multiple different production units; simultaneous pressure regulation of several LPGs for mixed feeding; the LPG desulfurization tower in the desulfurization unit using high-efficiency packing, with random packing at the bottom and top and structured packing in the middle to avoid bottom packing blockage; and a three-stage mercaptan removal unit with two-stage water washing of the LPG. Simultaneously, the addition of solid mercaptan removal catalyst is stopped and replaced with liquid desulfurization enhancer, solving the scaling and blockage problem between fiber membrane fibers, significantly improving feedstock adaptability and operational flexibility, ensuring long-term stable operation of the unit and downstream product quality, and achieving a mercaptan content of ≤1 mg / m³ in the refined LPG. 3 .

Description

Technical Field

[0001] This invention belongs to the field of petrochemical technology and relates to a method for processing various liquefied gases using a product refining device. Background Technology

[0002] Product refining units are crucial for desulfurization and desulfurization in oil refineries. They typically receive sulfur-containing liquefied petroleum gas (LPG) from upstream catalytic cracking units. Their desulfurization and desulfurization efficiency directly impacts the quality of feedstock supplied to downstream units. Excessive hydrogen sulfide levels cause equipment corrosion, while excessive mercaptan levels lead to excessive sulfur content in downstream gas-separated propylene or methyl tert-butyl ether (MTBE) products. Currently, product refining units in the industry are generally designed to match the LPG production capacity of upstream catalytic cracking units. However, this traditional approach has several inherent drawbacks: (1) Problem of limited raw material processing: In traditional refinery practices, the processing capacity of liquefied petroleum gas (LPG) in the product refining unit is determined based on the LPG production capacity of the upstream catalytic cracking unit. Because catalytic LPG has a low sulfur content and coking LPG has a high sulfur content, catalytic LPG and coking LPG are fed into different desulfurization towers separately. Traditional units have not yet achieved the simultaneous feeding of catalytic LPG, coking LPG, or LPG from multiple units into a single LPG desulfurization tower. Under the traditional design, the product refining unit processes a limited variety of raw materials and has a simple process flow. With the trend of integrated refining and chemical production, as the number of new LPG production units increases and the variety of LPG increases, the product refining unit originally designed for a single catalytic cracking unit is unable to meet the processing needs of multiple LPG varieties. (2) Problem of low risk resistance of product quality of equipment: The liquefied gas produced by the product refining unit is supplied to downstream units. The quality of the liquefied gas after hydrogen sulfide removal is related to whether the mercaptan removal unit of the product refining unit can operate stably for a long period of time. The quality of the liquefied gas after mercaptan removal is related to the sulfur content of propylene in the gas separation unit and the sulfur content of MTBE product in the MTBE unit. The mercaptan removal process of the product refining unit of the traditional catalytic cracking unit is short, with only one and two mercaptan removal reactors. The liquefied gas is sent out of the unit after only one water washing. When processing liquefied gas of multiple varieties of raw materials, the process is too short and the mercaptan content of the product is high, which affects the quality of raw materials of downstream units. (3) Problem of clogging of desulfurization fiber membrane: In conventional desulfurization units, solid desulfurization catalyst (sulfonated cobalt phthalocyanine) is added. As the solid powder dissolves and adheres to the gaps in the fiber membrane with the alkali solution, the contact area between thiols in liquefied gas and alkali solution is reduced, resulting in poor desulfurization effect and seriously restricting the long-term operation of the unit.

[0003] Therefore, developing a product refining unit capable of processing liquefied petroleum gas from multiple feedstocks, improving the unit's operational flexibility, and solving the problem of catalyst deposition in desulfurization fiber membranes have become urgent technical challenges for product refining units in the oil refining industry. Summary of the Invention

[0004] The purpose of this invention is to overcome the problems of existing product refining equipment being unable to adapt to the processing needs of multiple types of liquefied petroleum gas (LPG), poor desulfurization effect, and solid catalyst powder causing fiber membrane blockage. This invention provides a method for processing multiple types of LPG using a product refining equipment, capable of processing LPG produced by 10 different sets of equipment. At the same time, it changes the process flow to ensure stable quality of LPG products from the equipment and improves the operational flexibility of the equipment, thereby overcoming the shortcomings of the prior art.

[0005] To achieve the above objectives, the present invention provides a method for processing various liquefied gases using a product refining apparatus, the method comprising the following steps: (1) The raw material liquefied gas of multiple different production units is classified and collected into the raw material liquefied gas tank. The mixed liquefied gas is pressurized and transported to the liquefied gas desulfurization tower. (2) The mixed liquefied gas and lean amine liquid are contacted countercurrently in the desulfurization tower to remove hydrogen sulfide; the liquefied gas after hydrogen sulfide removal passes through the first-stage desulfurization tank and the second-stage desulfurization tank in sequence. In the desulfurization tank, the mercaptan in the liquefied gas after hydrogen sulfide removal reacts with the alkaline liquid under the catalysis of the liquid desulfurization enhancer to remove mercaptan; then it is washed with water in the first stage and hydrolyzed to remove the alkaline liquid and carbonyl sulfide carried by the liquefied gas. After the third-stage desulfurization treatment, it is washed with water in the second stage. The obtained product liquefied gas is sent to the downstream gas separation unit for further separation. (3) Collect the rich alkali solution from the desulfurization tank and perform heating, oxidation regeneration, disulfide separation and stripping treatment in sequence; return the regenerated alkali solution to the desulfurization tank for recycling, and replenish the desulfurization system with fresh alkali solution regularly to maintain the concentration.

[0006] The liquefied gas mentioned in this invention refers to liquefied petroleum gas produced during the petroleum refining process. It is used as a raw material for desulfurization and desulfurization in this process and can be sent into the raw material liquefied gas tank after pressure regulation.

[0007] The feedstock liquefied gas tank can receive feedstock liquefied gas from multiple different production units, including: liquefied gas from catalytic cracking units, liquefied gas from delayed coking units, liquefied gas from wax catalytic cracking units, liquefied gas from atmospheric and vacuum distillation units, liquefied gas from diesel hydrocracking units, liquefied gas from diesel hydrotreating units, liquefied gas from wax oil hydrocracking units, liquefied gas from C1C2 units, and liquefied gas from slurry bed units, two or more of these.

[0008] The liquefied petroleum gas (LPG) in the catalytic cracking unit is LPG produced by the catalytic cracking unit; the LPG in the delayed coking unit is LPG produced by the delayed coking unit; the LPG in the wax catalytic cracking unit is LPG produced by the wax oil catalytic cracking unit; the LPG in the atmospheric and vacuum distillation unit is LPG produced by the atmospheric and vacuum distillation unit; the LPG in the diesel hydrocracking unit is LPG produced by the diesel hydrocracking unit; the LPG in the diesel hydrotreating unit is LPG produced by the diesel hydrorefining unit; the LPG in the wax oil hydrocracking unit is LPG produced by the wax oil hydrocracking unit; the LPG in the C1C2 unit is LPG produced by the C1C2 unit; and the LPG in the slurry bed unit is LPG produced by the slurry bed hydrotreating unit. (Units C1 and C2 are production units of Zhejiang Petrochemical Co., Ltd. These units primarily use the products from the product refining unit—purified catalytic dry gas, purified coking dry gas, reformed dry gas, isomerized and xylene dry gas, disproportionated fuel gas, isobutane, stabilized gasoline, and hydrogen—as feedstock to separate methane hydrogen, ethylene-rich gas, ethane-rich gas, light hydrocarbons, crude hydrogen, fuel gas, and gasoline. Units C3 and C4 use diesel cracking liquefied petroleum gas (LPG), light hydrocarbon recovery LPG, and reformed LPG as feedstock to separate propane, isobutane, and n-butane LPG.) The pressure of liquefied petroleum gas (LPG) in catalytic cracking units is 1.1~1.3 MPa, and the temperature is 30~40℃; the pressure of LPG in delayed coking units, wax catalytic cracking units, and atmospheric and vacuum distillation units is 1.0~1.8 MPa, and the temperature is 30~40℃; the pressure of LPG in diesel hydrocracking units, diesel hydrotreating units, wax oil hydrocracking units, and C1C2 units is 1.2~1.5 MPa, and the temperature is 30~40℃; the pressure of LPG in slurry bed units is 1.2~1.68 MPa, and the temperature is 30~40℃.

[0009] The method for classifying and summarizing various liquefied petroleum gas (LPG) feedstocks is as follows: LPG from delayed coking units, wax catalytic cracking units, and atmospheric and vacuum distillation units with pressures of 1.0~1.8 MPa is combined and fed into the feedstock tank; LPG from diesel hydrocracking units, diesel hydrotreating units, wax oil hydrocracking units, and C1C2 units with pressures of 1.2~1.5 MPa is combined and fed into the feedstock tank; LPG from catalytic cracking units with pressures of 1.1~1.3 MPa is fed into a separate tank; LPG from slurry bed units with pressures of 1.2~1.68 MPa is fed into a separate feedstock tank. Due to the high feedstock pressure of LPG from slurry bed units, a pressure control valve is installed between the two valves on the LPG line in the tank area, controlling the pressure after the valve to be 0.7~1.2 MPa, and it is fed into the feedstock tank separately.

[0010] Preferably, the packing design of the desulfurization tower in step (2) is as follows: The middle of the tower is filled with structured packing, while the upper and lower parts are filled with random packing. The structured packing is a structured corrugated metal packing, neatly and regularly stacked in a uniform geometric pattern within the tower. An example is the structured packing of KY-GD40, jointly developed by the State Key Laboratory of Chemical Engineering of Tianjin University and Wuxi Kaiyuan Petrochemical Equipment Co., Ltd. The random packing is stacked in a disordered, random, and bulk manner within the desulfurization tower. An example is the random packing of KY-2.5G, jointly developed by the State Key Laboratory of Chemical Engineering of Tianjin University and Wuxi Kaiyuan Petrochemical Equipment Co., Ltd.

[0011] Preferably, in step (2), the lean amine solution is an aqueous solution of N-methyldiethanolamine (MDEA), and the concentration of N-methyldiethanolamine is 20~40wt%. The flow ratio (liquid-liquid ratio) of the lean amine solution and the liquefied gas feedstock in the liquefied gas desulfurization tower is controlled at 1.08 to fully remove hydrogen sulfide from the liquefied gas. A liquefied gas amine solution separator is set before the desulfurized liquefied gas enters the mercaptan removal unit, and the separator is equipped with a special filter element.

[0012] The alkaline solution mentioned in the text is a sodium hydroxide solution. The rich alkaline solution refers to the aqueous solution of sodium thiolate produced by the chemical reaction between thiols in the liquefied gas and some of the alkaline solution, which is the alkaline solution to be regenerated discharged from the bottom of the desulfurization tank.

[0013] Preferably, in step (3), after heating the alkaline solution, the addition of the solid desulfurization catalyst is stopped, and oxidation regeneration is carried out directly. The fresh alkaline solution is mixed with the liquid desulfurization enhancer added to the top of the fresh alkaline solution tank, and then replenished into the system. A blower is inserted into the liquid desulfurization enhancer tank and sent to the top of the fresh alkaline solution tank to form an alkaline solution of a certain concentration, which is then replenished into the system.

[0014] Liquid desulfurization enhancers can be exemplified by ZHQDS-01, a model produced by Qingdao Zhonghaiquan Environmental Protection New Materials Co., Ltd. This is a blue-green transparent liquid with a density of 950~1050 kg / m³. 3With a pH of 7-14 and a freezing point of -30 to 0 ℃, it is miscible with alkaline solutions in any proportion. Differences in its properties can be adjusted according to production conditions, season, and other factors. ZHQDS-01 desulfurization enhancer is a composite solution of an alkaline thiol oxidation catalyst, phase transfer agent, thiols solubilizer, and colloidal stabilizer. It is miscible with alkaline solutions in any proportion. Because it contains a small amount of colloidal stabilizer, the catalytic oxidation activity cycle of thiols is significantly extended, which is beneficial for production stability and reduces alkaline residue emissions. The addition of a phase transfer catalyst reduces the interfacial tension between oil and water, increasing both the contact area and contact time between the two phases. This allows thiols in liquefied petroleum gas to accelerate their transfer from the oil phase to the aqueous phase and dissolve in the aqueous phase, achieving a high thiol removal rate. To improve the removal rate of carbonyl sulfide by alkaline solutions, components that can undergo irreversible reactions with carbonyl sulfide can also be added to the agent as needed, thereby reducing the load on subsequent carbonyl sulfide removal units.

[0015] Preferably, in step (2), before entering the desulfurization system, the pressure of the liquefied gas is 1.3~1.8MPa and the temperature is 30~40℃.

[0016] The desulfurization system in step (3) includes a primary desulfurization tank, a secondary desulfurization tank, a tertiary desulfurization tank, a primary water washing tank, a secondary water washing tank, and a hydrolysis tower. This desulfurization system is connected to a fresh alkali tank, which can periodically replenish fresh alkali to maintain a stable alkali concentration in the system. After hydrogen sulfide removal, the liquefied petroleum gas (LPG) sequentially enters the primary and secondary desulfurization tanks. The thiols in the oil phase of the LPG react with the aqueous phase of the alkali solution under the catalysis of the liquid desulfurization enhancer to generate sodium thiolate, which is then transferred to the aqueous phase, achieving the stepwise removal of thiols. The LPG after desulfurization is washed by the primary water tank to remove the free alkali and sodium ions it carries, and then enters the hydrolysis tower to hydrolyze carbonyl sulfur into hydrogen sulfide and carbon dioxide. Subsequently, it enters the tertiary desulfurization tank for deep removal of residual thiols and acidic components generated by hydrolysis, and finally, after secondary water washing and purification, it is sent out of the device. The rich alkali solution from the desulfurization tank is collected and sequentially subjected to heating, oxidation regeneration, disulfide separation, and stripping. The regenerated high-concentration alkali solution is preferentially sent to the secondary desulfurization tank. After a small amount of consumption, the concentration of the alkali solution in the secondary desulfurization tank is still higher than that of the circulating alkali solution in the primary desulfurization tank. The excess alkali solution in the secondary desulfurization tank is replenished to the primary desulfurization tank through the alkali solution transfer pipeline from the secondary desulfurization tank to the primary desulfurization tank to balance the alkali solution concentration in the primary desulfurization tank and further balance the desulfurization capacity of the primary desulfurization tank.

[0017] The primary, secondary, and tertiary desulfurization tanks are all fiber membrane contact reactors. The operating pressure inside the tank is controlled at 1.3~1.8MPa, the operating temperature is controlled at 30~42℃, and the oil-water interface is controlled at 11%~50%. The materials inside the tank are liquefied petroleum gas oil phase and sodium hydroxide alkaline solution water phase. The alkaline solution concentration decreases step by step in the order of tertiary, primary, and secondary desulfurization tanks.

[0018] Preferably, in step (3), the temperature of the alkali solution before entering the heater is controlled at 30~42℃ and the pressure is 1.3~1.45MPa. After heating, the temperature of the alkali solution is 49~50℃ and the pressure is 1.3~1.45MPa. Then, it enters the oxidation tower, disulfide tower, stripping tower and alkali solution back-extraction tank system to achieve regeneration.

[0019] Fresh alkali solution is mixed with liquid desulfurization enhancer added to the top of the fresh alkali solution tank before being added to the system. Preferably, it is added to the desulfurization system via a stripping tower, or via a tertiary desulfurization tank, or simultaneously via both the stripping tower and the tertiary desulfurization tank.

[0020] Preferably, the fresh alkali solution is added to the stripping tower or the three-stage desulfurization tank at a temperature of 30~42℃ and a pressure of 1.3~1.4MPa.

[0021] To ensure the long-term stable operation of the product refining unit, the following optimization measures were implemented: (1) The first and second stage desulfurization tanks should be kept at a low interface level. The oil-water interface level inside the tank should be stably controlled at 11%~30% to avoid the high interface level causing the alkali solution to submerge the fiber membrane fibers, resulting in a small contact area between the liquefied gas and the alkali solution, which reduces the desulfurization effect of the liquefied gas. Low interface level operation is conducive to accelerating the separation of alkali solution and liquefied gas and reducing the alkali solution entrainment in liquefied gas. (2) Regularly backwash the fiber membrane of the desulfurization reactor to reduce the adhesion and entrainment of impurities and increase the flow area of ​​the fiber membrane filaments; (3) Regularly replace the water quality in the primary and secondary liquefied gas washing tanks to reduce the sodium ions carried by the liquefied gas, slow down the deactivation rate of the etherification resin catalyst in the downstream MTBE unit, and extend the service life of the catalyst. (4) The disulfide tower regularly discharges disulfide and performs back-extraction separation of disulfide in alkaline solution based on the principle of like dissolves like, thereby improving the quality of regenerated alkaline solution; (5) The hydrolysis tower is regularly cut off to remove the free water carried by the liquefied gas and settled in time, thereby reducing the amount of water carried by the liquefied gas into the hydrolysate and extending the service life of the hydrolysate. (6) Coordinate with upstream and downstream to regularly drain oil from the amine flash tank, remove heavy hydrocarbon components entrained in the amine liquid, and ensure stable operation of the downstream solvent regeneration unit.

[0022] Compared with the prior art, the present invention has the following beneficial effects: 1. The refining unit for processing various liquefied petroleum gases (LPGs) offers high operational flexibility, adapting to different LPG types produced by different units. It can accept both low-sulfur LPG and LPG from wax oil hydrocracking with hydrogen sulfide content as high as 142,000 mg / m³. 3High-sulfur liquefied petroleum gas (LPG) improves the flexibility of LPG feedstock processing and solves the problem of a single process for LPG from upstream units. 2. By switching to a proprietary liquid desulfurization enhancer and discontinuing the addition of solid sulfonated cobalt phthalocyanine, the problems of scaling and clogging between fiber membrane fibers, resulting in poor mercaptan removal efficiency, short operating cycles, and high maintenance costs, are improved. Simultaneously, the manual addition of solid sulfonated cobalt phthalocyanine is eliminated, and the liquid agent can be completely extracted using a blower, reducing the risk of powdered solid agent contamination of the equipment and the risk of inhalation harming employee health. This significantly improves the removal rate of carbonyl sulfide by the alkali solution, resulting in a mercaptan content of ≤1 mg / m³ in the refined liquefied gas. 3 The pressure drop of the primary desulfurization fiber membrane is reduced to 5~10 kPa; 3. The tower adopts a high-efficiency packing design. The middle part of the tower is filled with high-efficiency structured packing, and the upper and lower parts are filled with high-efficiency random packing. The packing flow area is increased, and impurities carried by the liquefied gas are carried out of the tower with the liquefied gas, avoiding accumulation and blockage. The impurities are discharged in the liquefied gas amine liquid separator, ensuring the long-term stable operation of the product refining unit. 4. Appropriately modify the process flow, increase the amount of lean amine solution injected, increase the liquid-liquid ratio of the tower, and add a three-stage desulfurization unit and a two-stage water washing unit for liquefied gas to ensure stable and long-term operation of the liquefied gas product quality leaving the unit. Attached Figure Description

[0023] Figure 1 This is a schematic diagram of the liquefied gas feedstock tank, desulfurization, and desulfurization process in this invention.

[0024] Figure 2 This is a schematic diagram of the alkali regeneration and additive process in this invention.

[0025] In the picture: 1: LPG pipeline for Unit 1 (catalytic cracking unit); 2: LPG pipelines for Unit 1 (delayed coking unit), Unit 2 (wax catalytic cracking unit), Unit 3 (atmospheric and vacuum distillation unit), and Unit 4 (atmospheric and vacuum distillation unit); 3: LPG pipelines for Unit 1 (diesel hydrocracking unit), Unit 2 (diesel hydrocracking unit), Unit 1 (wax oil hydrocracking unit), and Unit 1 (C1C2 unit); 4: LPG pipeline for Unit 3 (slurry bed unit); 5: LPG feedstock pump inlet pipeline; 6: LPG feedstock pump; 7: LPG feedstock pump outlet pipeline; 8: Amine-rich liquid at the bottom of the LPG desulfurization tower. 9: LPG pipeline at the top outlet of the LPG desulfurization tower; 10: Amine-rich liquid line at the bottom of the amine liquid separator; 11: LPG line after hydrogen sulfide removal; 12: LPG line at the outlet of the first-stage desulfurization tank; 13: LPG line at the outlet of the second-stage desulfurization tank; 14: LPG line at the inlet of the hydrolysis tower; 15: LPG line at the outlet of the hydrolysis tower; 16: LPG line at the outlet of the third-stage desulfurization tank; 17: LPG line at the product outlet; 18: Raw material LPG tank; 19: LPG desulfurization tower; 20: Amine liquid separator; 21: First-stage desulfurization tank; 22: Second-stage desulfurization tank. Tank; 23: Primary LPG washing tank; 24: Hydrolysis tower; 25: Tertiary desulfurization tank; 26: Secondary LPG washing tank; 27: Lean amine liquid line from LPG desulfurization tower; 28: Rich alkali liquid line from primary and tertiary desulfurization tanks; 29: Alkali liquid line from alkali heater outlet; 30: Solid desulfurization catalyst filling line; 31: Alkali liquid line from catalyst filling tank outlet; 32: Alkali liquid line from oxidation tower outlet; 33: Alkali liquid line from disulfide tower outlet; 34: Alkali liquid line from stripping tower outlet; 35: Alkali liquid line from alkali back-extraction tank outlet; 37 38: Alkali solution line at the outlet of the primary desulfurization tank; 39: Fresh alkali solution line at the outlet of the tertiary desulfurization tank; 40: Liquid desulfurization enhancer injection line; 41: Fresh alkali solution tank outlet line; 42: Fresh alkali solution pump; 43: Alkali solution line at the inlet of the tertiary desulfurization tank; 44: Fresh alkali solution line replenished by the stripping tower; 45: Alkali solution heater; 46: Catalyst injection tank; 47: Oxidation tower; 48: Disulfide tower; 49: Stripping tower; 50: Alkali solution back-extraction tank; 51: Secondary desulfurization tank outlet alkali solution line; 52: Fresh alkali solution tank. Detailed Implementation

[0026] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0027] Example 1 The method for processing various liquefied gases using the product refining apparatus of this embodiment includes the following steps: Step (1): Removal of hydrogen sulfide from raw material liquefied petroleum gas (LPG): LPG from Unit 1 enters separately through pipeline 1; LPG from Unit 1 (delayed coking), Unit 2 (wax catalytic cracking), Unit 3 (atmospheric and vacuum distillation), and Unit 4 (atmospheric and vacuum distillation) are combined and enter raw material LPG tank 18 through pipeline 2; LPG from Unit 1 (diesel hydrocracking), Unit 2 (diesel hydrocracking), Unit 1 (wax oil hydrocracking), and Unit 1 (C1C2) are combined and enter raw material LPG tank 18 through pipeline 3; LPG from Unit 3 (slurry bed unit) enters raw material LPG tank 18 separately through pipeline 4. Because the incoming pressure of LPG from Unit 3 (slurry bed unit) is high, a pressure control valve (control valve pressure 1.2~1.68MPa before control valve, control valve pressure 0.7~1.2MPa after control valve) is installed between the two valves of the LPG line in the tank area, and enters the raw material tank separately. The liquefied gas in the raw material liquefied gas tank 18 enters the liquefied gas raw material pump 6 through the liquefied gas raw material pump inlet pipeline 5, and then is sent to the liquefied gas desulfurization tower 19 through the liquefied gas raw material pump outlet pipeline 7. The liquefied gas desulfurization tower 19 adopts a high-efficiency packing design, with high-efficiency structured packing (specification model KY-GD40) in the middle of the tower, and high-efficiency random packing (specification model KY-2.5G) in the upper and lower parts. Lean amine solution enters from the top of the tower via lean amine solution line 27, contacting liquefied petroleum gas (LPG) countercurrently. Rich amine solution, after absorbing hydrogen sulfide, exits from the bottom of the tower via rich amine solution outlet line 8. LPG from the top of the tower enters the amine solution separator tank 20 via LPG pipeline 9 at the top outlet of the LPG desulfurization tower. The amine solution separator tank uses Beijing Purry Nylon filter elements to separate the amine solution carried by the LPG, reducing the amount of amine solution entering the subsequent desulfurization unit and preventing a rapid decrease in the alkali concentration in the desulfurization system. Rich amine solution exiting from the bottom of the amine solution separator tank via rich amine solution line 10 and rich amine solution exiting from the bottom of the tower via rich amine solution outlet line 8 are both sent to downstream units. LPG from the top of the amine solution separator tank, after hydrogen sulfide removal, enters the desulfurization system via LPG pipeline 11 at the top outlet of the amine solution separator tank. Before entering the desulfurization system, the LPG pressure is 1.3~1.8 MPa and the temperature is 30~40 ℃.

[0028] Step (2): Removal of thiols from raw liquefied petroleum gas (LPG): After hydrogen sulfide removal, the LPG enters the primary mercaptan tank 21. The thiols carried by the LPG react with the alkaline solution under the action of a catalyst, removing some of the thiols and generating sodium thiolate. The LPG after primary mercaptan removal passes through pipeline 12 into the secondary mercaptan tank 22 for further removal of thiols. The LPG after secondary mercaptan removal passes through pipeline 13 into the primary LPG water washing tank 23 to remove sodium ions carried by the LPG. After primary water washing, the liquefied petroleum gas (LPG) enters the hydrolysis tower 24 via pipeline 14 to remove carbonyl sulfide from the LPG. The LPG after carbonyl sulfide removal enters the tertiary mercaptan tank 25 via pipeline 15 to remove carbon dioxide and hydrogen sulfide from the hydrolyzed LPG, as well as the remaining mercaptan. The LPG after tertiary mercaptan removal enters the secondary LPG water washing tank 26 via pipeline 16. The product LPG is sent out of the unit via pipeline 17 to the downstream No. 1 gas separator for further separation.

[0029] Step (3): The rich alkali solution from the primary and tertiary desulfurization tanks enters the alkali solution heater 45 through pipeline 28. After the alkali solution is heated, the rich alkali solution 29 enters the solid desulfurization catalyst filling tank 46 through pipeline. In order to prevent the primary and secondary desulfurization fiber membranes from sticking and clogging, the solid desulfurization catalyst filling line 30 has been stopped and no more solid sulfonated cobalt phthalocyanine catalyst is added. The heated alkali solution enters the alkali oxidation tower 47 through the alkali solution line 31 at the outlet of the catalyst injection tank. Sodium thiolate is oxidized to sodium hydroxide to regenerate the alkali solution. The oxidized alkali solution enters the disulfide tower 48. The alkali solution after removing disulfide enters the stripping tower 49 through the alkali solution line 33 at the outlet of the disulfide tower. The alkali solution at the outlet of the stripping tower 49 passes through the alkali back-extraction tank 50, and the regenerated alkali solution enters the secondary desulfurization tank 22. The alkali solution in the secondary desulfurization tank is sent to the primary desulfurization tank 21. The alkali solution at the outlet of the primary desulfurization tank goes to the alkali heater 45. The alkali solution at the outlet of the tertiary desulfurization tank 25 is then combined with... The alkali solution outlet of the primary desulfurization tank goes to the alkali solution heater 45, and then passes through the oxidation tower 47, disulfide tower 48, stripping tower 49, and alkali solution back-extraction tank 50 to achieve alkali solution regeneration. The regenerated alkali solution is recycled. A small amount of fresh alkali solution is periodically added to the fresh alkali solution tank 52 to the stripping tower 49. The temperature of the alkali solution before entering the heater 45 is 30~42℃, and the pressure is 1.3~1.45MPa. After heating, the temperature of the alkali solution is 49~50℃, and the pressure is 1.3~1.45MPa. It then enters the oxidation tower, disulfide tower, stripping tower, and alkali solution back-extraction tank system for regeneration. Fresh alkali solution 39 enters the fresh alkali solution tank 52, and liquid desulfurization enhancer is added to the top of the tank to replace the solid desulfurization catalyst added to the catalyst addition tank 46, preventing adhesion and clogging of the fiber membrane in the desulfurization reactor. The alkaline solution mixed with liquid desulfurization enhancer is pumped by fresh alkaline solution pump 42 and injected into stripping tower 49 through fresh alkaline solution line 44, or injected into tertiary desulfurization tank 25 through alkaline solution line 43 at the inlet of tertiary desulfurization tank. The pressure is 1.3~1.4MPa and the temperature is 30~42℃.

[0030] The liquefied petroleum gas (LPG) sources in this embodiment include: LPG from the No. 1 catalytic cracking unit, LPG from the No. 1 delayed coking unit, LPG from the No. 2 wax catalytic cracking unit, LPG from the No. 3 atmospheric and vacuum distillation unit, LPG from the No. 4 atmospheric and vacuum distillation unit, LPG from the No. 1 diesel hydrocracking unit, LPG from the No. 2 diesel hydrocracking unit, LPG from the No. 1 wax oil hydrocracking unit, LPG from the No. 1 C1C2 unit, and LPG from the No. 3 slurry bed unit. All of the above LPG originates from the corresponding production units of Zhejiang Petrochemical Co., Ltd. Since the same unit is equipped with multiple sets of identical production equipment, the designations "1#", "2#", "3#", and "4#" are company designations used to distinguish LPG produced by multiple sets of parallel production equipment of the same specifications under the same process type. For example, LPG from the No. 3 atmospheric and vacuum distillation unit represents LPG produced by the third set of atmospheric and vacuum distillation equipment in the atmospheric and vacuum distillation unit, and LPG from the No. 4 atmospheric and vacuum distillation unit represents LPG produced by the fourth set of atmospheric and vacuum distillation equipment in the atmospheric and vacuum distillation unit. The fourth set of atmospheric and vacuum distillation equipment is the same equipment connected in parallel with the third set.

[0031] The pressure of liquefied petroleum gas (LPG) in Unit 1 is 1.1~1.3 MPa, and the temperature is 30~40℃; the pressure of LPG in Unit 1 (delayed coking), Unit 2 (wax catalytic cracking), Unit 3 (atmospheric and vacuum distillation), and Unit 4 (atmospheric and vacuum distillation) is 1.0~1.8 MPa, and the temperature is 30~40℃; the pressure of LPG in Unit 1 (diesel hydrocracking), Unit 2 (diesel hydrocracking), Unit 1 (wax oil hydrocracking), and Unit 1 (C1C2) (light hydrocarbons) is 1.2~1.5 MPa, and the temperature is 30~40℃; the pressure of LPG entering the feed tank in Unit 3 (slurry bed unit) is 0.7~1.2 MPa, and the temperature is 30~40℃.

[0032] The lean amine solution used in this embodiment comes from a sulfur solvent regeneration unit, with a hydrogen sulfide content of less than or equal to 0.8 g / L. Its main component is N-methyldiethanolamine (MDEA), and the amine concentration is controlled at approximately 30 wt%, with 70 wt% being water. The active components of the rich amine solution are the same as those of the lean amine solution. After absorbing hydrogen sulfide and carbon dioxide, the lean amine solution becomes rich amine solution. After stripping, the rich amine solution can be converted back into lean amine solution for reuse.

[0033] The liquefied gas desulfurization tower adopts a high-efficiency packing design. The middle part of the tower is filled with high-efficiency structured packing, which was jointly developed by the State Key Laboratory of Chemical Engineering of Tianjin University and Wuxi Kaiyuan Petrochemical Equipment Co., Ltd., with the specification model KY-GD40. The upper and lower parts are filled with high-efficiency random packing, which was jointly developed by the State Key Laboratory of Chemical Engineering of Tianjin University and Wuxi Kaiyuan Petrochemical Equipment Co., Ltd., with the specification model KY-2.5G.

[0034] The liquid desulfurization enhancer used in step (2) is model ZHQDS-01 desulfurization enhancer produced by Qingdao Zhonghaiquan Environmental Protection New Materials Co., Ltd. It is a blue-green transparent liquid with a density of 1020 kg / m³. 3It has a pH of 8, a freezing point of -10 ℃, and is miscible with alkaline solutions.

[0035] The primary, secondary, and tertiary desulfurization tanks are all fiber membrane contact reactors. The operating pressure inside the tank is controlled at 1.3~1.8MPa, the operating temperature is controlled at 30~42℃, and the oil-water interface is controlled at 11%~50%. The materials inside the tank are liquefied petroleum gas oil phase and sodium hydroxide alkaline solution water phase. The alkaline solution concentration decreases step by step in the order of tertiary, primary, and secondary desulfurization tanks.

[0036] The mercaptan content of the liquefied gas produced by the product refining unit in Example 1 is ≤1 mg / m³. 3 The pressure drop of the primary desulfurization fiber membrane is 5-10 kPa.

[0037] Comparative Example 1 The difference from Example 1 is that the bottom of the liquefied gas desulfurization tower 19 uses structured packing (KY-GD40) and the top uses random packing (KY-2.5G), while the other steps are the same as in Example 1.

[0038] The unsaturated liquefied petroleum gas (LPG) produced by the unit has unstable thiols with high thiols content, sometimes exceeding the upper limit of 15 mg / m³ at the distillation outlet. 3 The sulfur content of MTBE products in downstream gas separation units (propylene and MTBE units) increases, affecting the quality of finished products. The high impurity content in the raw material liquefied petroleum gas (LPG) easily clogs the bottom structured packing, leading to unstable operation of the rich amine solution at the bottom of the LPG desulfurization tower. The LPG at the top of the tower easily carries the rich amine solution into the desulfurization system. The hydrogen sulfide absorbed by the rich amine solution reacts chemically with the alkali solution to generate non-renewable sodium sulfide, excessively consuming the system's alkali solution and resulting in a large amount of alkali residue discharge.

[0039] Comparative Example 2 The difference from Example 1 is that, instead of adding liquid desulfurization enhancer, the traditional method of adding solid sulfonated cobalt phthalocyanine catalyst is used. Solid sulfonated cobalt phthalocyanine catalyst is manually added in the catalyst addition tank 46 set after the alkaline heater 45. The molar concentration of the effective active component of the solid catalyst is the same as the concentration of the active component of the liquid desulfurization enhancer in Example 1. Other steps are the same as in Example 1.

[0040] Solid powder dissolves poorly in alkaline solution and is unevenly distributed, leading to scaling and blockage between the fiber membrane filaments in the primary mercaptan removal tank 21. This increases the pressure difference between the inlet and outlet liquefied gas, reaching a maximum of 50 kPa; the mercaptan content in the unsaturated liquefied gas exiting the unit rises to a maximum of 18 mg / m³. 3 Exceeding the distillation outlet limit of 15 mg / m 3 Increased consumption of alkali solution leads to increased material consumption in the equipment and higher production costs.

[0041] Finally, it should be noted that the specific embodiments described herein are merely illustrative examples of the invention and are not intended to limit the implementation of the invention. Those skilled in the art can make various modifications or additions to the described specific embodiments or use similar methods to replace them; it is neither necessary nor possible to exemplify all embodiments here. However, these obvious variations or modifications derived from the essential spirit of the invention still fall within the scope of protection of the invention, and interpreting them as any additional limitation would contradict the spirit of the invention.

Claims

1. A method for processing various liquefied gases using a product refining apparatus, characterized in that, Includes the following steps: (1) The raw material liquefied gas of multiple different production units is classified and collected into the raw material liquefied gas tank. The mixed liquefied gas is pressurized and transported to the liquefied gas desulfurization tower. (2) The mixed liquefied gas and lean amine liquid are contacted countercurrently in the desulfurization tower to remove hydrogen sulfide; the liquefied gas after hydrogen sulfide removal passes through the first-stage desulfurization tank and the second-stage desulfurization tank in sequence. In the desulfurization tank, the mercaptan in the liquefied gas after hydrogen sulfide removal reacts with the alkaline liquid in the presence of liquid desulfurization enhancer to remove mercaptan; then it is washed with water in the first stage and hydrolyzed to remove the alkaline liquid and carbonyl sulfide carried by the liquefied gas. After the third-stage desulfurization treatment, it is washed with water in the second stage. The obtained product liquefied gas is sent to the downstream gas separation unit for further separation. (3) Collect the rich alkali solution from the desulfurization tank and perform heating, oxidation regeneration, disulfide separation and stripping treatment in sequence; return the regenerated alkali solution to the desulfurization tank for recycling, and at the same time periodically replenish fresh alkali solution to the desulfurization system to maintain the concentration.

2. The method according to claim 1, characterized in that, The liquefied gas feedstock tank can receive liquefied gas including two or more of the following: liquefied gas from catalytic cracking units, liquefied gas from delayed coking units, liquefied gas from wax catalytic cracking units, liquefied gas from atmospheric and vacuum distillation units, liquefied gas from diesel hydrocracking units, liquefied gas from diesel hydrotreating units, liquefied gas from wax oil hydrocracking units, liquefied gas from C1C2 units, and liquefied gas from slurry bed units.

3. The method according to claim 2, characterized in that, The pre-feeding classification and pressure control methods include: The LPG pressure of the delayed coking unit, the wax catalytic cracking unit, and the atmospheric and vacuum distillation unit is 1.0~1.8MPa, and they are combined into the feedstock tank; the LPG pressure of the diesel hydrocracking unit, the diesel hydrotreating unit, the wax oil hydrocracking unit, and the C1C2 unit is 1.2-1.5MPa, and they are combined into the feedstock tank; the LPG pressure of the catalytic cracking unit is 1.1~1.3MPa and it is fed into a separate tank; the LPG pressure of the slurry bed unit is 0.7~1.2MPa and it is fed into a separate feedstock tank.

4. The method according to claim 1, characterized in that, The primary, secondary, and tertiary desulfurization tanks are all fiber membrane contact reactors. The operating pressure inside the tanks is controlled at 1.3~1.8MPa, the operating temperature is controlled at 30~42℃, and the oil-water interface level inside the tanks is controlled at 11%~50%.

5. The method according to claim 1, characterized in that, The desulfurization system in step (3) includes a primary desulfurization tank, a secondary desulfurization tank, a tertiary desulfurization tank, a primary water washing tank, a secondary water washing tank, and a hydrolysis tower. The desulfurization system is connected to a fresh alkali tank, and fresh alkali can be replenished periodically through the fresh alkali tank to maintain a stable alkali concentration in the system. The fresh alkali is mixed with the liquid desulfurization enhancer added to the top of the fresh alkali tank before being added into the desulfurization system.

6. The method according to claim 5, characterized in that, The method for adding the liquefied petroleum gas desulfurization liquid enhancer is as follows: a blower is inserted into the liquid desulfurization enhancer tank and sent to the top of the fresh alkali tank for addition. The alkali is then mixed with the fresh alkali to form an alkali solution of a certain concentration, which is then added to the desulfurization system.

7. The method according to claim 1, characterized in that, Before entering the desulfurization system in step (2), the liquefied gas pressure is 1.3~1.8 MPa and the temperature is 30~40 ℃.

8. The method according to claim 1, characterized in that, The liquid enhancer for liquefied gas desulfuration in step (2) is ZHQDS-01 desulfuration enhancer produced by Qingdao Zhonghaiquan Environmental Protection New Material Co., Ltd., which is a blue-green transparent liquid with a density of 950-1050 kg / m 3 , pH 7-14, freezing point -30-0 ℃, and can be mutually soluble with alkali solution.

9. The method according to claim 1, characterized in that, The liquefied gas desulfurization tower in step (2) adopts a high-efficiency packing design. The middle section of the tower is filled with structured packing, and the top and bottom sections are filled with random packing. The structured packing is a metal structured packing with a regular geometric arrangement, and the random packing is a metal random packing stacked in a random manner.

10. The method according to claim 1, characterized in that, The mercaptan content of the product liquefied gas obtained in step (2) is ≤1 mg / m 3 The pressure drop of the primary sweetening fiber membrane filament is 5~10 kPa.

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