Process for the refining of liquefied petroleum gas

Abstract

The present application relates to a method for refining liquefied petroleum gas, comprising the following steps: S1) contacting crude liquefied petroleum gas with a first desulfurizer to obtain primary desulfurized liquefied petroleum gas; S2) mixing the primary desulfurized liquefied petroleum gas obtained in step S1 with a second desulfurizer, and then contacting the mixture with a carbonyl sulfur hydrolysis catalyst to obtain secondary desulfurized liquefied petroleum gas; S3) contacting the secondary desulfurized liquefied petroleum gas obtained in step S2 with a third desulfurizer to obtain refined liquefied petroleum gas; wherein the first, second and third desulfurizers are the same desulfurizer. The method only uses one kind of desulfurizer to remove sulfur-containing impurities, and has the advantages of simple process flow and safety, high desulfurization depth, low energy consumption, clean and environmentally friendly refining process, etc.

Description

Technical Field

[0001] This application pertains to the refining and processing of liquefied petroleum gas (LPG) during petroleum refining, specifically relating to a method for deep desulfurization of LPG, particularly a method for removing sulfur-containing impurities such as hydrogen sulfide, carbonyl sulfide, and mercaptans from LPG. Background Technology

[0002] High-sulfur crude oil and residual oil are processed by refineries using catalytic cracking and other units to produce liquefied petroleum gas (LPG), which contains a high total sulfur content. Sulfur-containing LPG typically contains toxic and harmful components such as hydrogen sulfide (H2S), carbonyl sulfide (COS), carbon disulfide, mercaptans, sulfides, and disulfides. Hydrogen sulfide, carbonyl sulfide (COS), and mercaptans (such as methanethiol and ethyl mercaptan) are particularly hazardous; if not removed, they will pollute the environment and affect subsequent processing.

[0003] Currently, the main refining processes for desulfurizing liquefied petroleum gas (LPG) include the following: LPG from the refinery first enters an alkanolamine scrubbing tower, where a large amount of hydrogen sulfide is removed using a regenerable alkanolamine solution. Then, it undergoes pre-alkali scrubbing with sodium hydroxide solution to remove residual hydrogen sulfide. Finally, it enters an extraction tower where mercaptans are extracted with an alkaline solution (sodium hydroxide solution containing sulfonated cobalt phthalocyanine). After water washing, neutral LPG is obtained, and then oxidized and regenerated using an alkaline solution. The disadvantages of this process are: the entire process uses a large amount of liquid caustic alkali (sodium hydroxide), requiring frequent alkali replacement, resulting in large emissions of alkali residue and waste alkali solution, as well as cumbersome post-treatment processes. These are detrimental to environmental protection, increase production costs, and lead to high consumption of materials and energy. Furthermore, the desulfurization depth of LPG is not high, as the removal of COS, one of the main pollutants, is not considered. Moreover, disulfides in the oxidizing agent alkali solution are difficult to completely separate, often resulting in excessive total sulfur content in the refined LPG product, and the oxidant used in the oxidizing regeneration process poses an explosion hazard.

[0004] Therefore, there is still a need to provide a method for refining liquefied petroleum gas that can remove sulfur-containing impurities such as H2S, COS, and thiols from liquefied petroleum gas in a low-cost and efficient manner. Summary of the Invention

[0005] In view of the above objectives, the present invention provides a method for refining liquefied petroleum gas, comprising the following steps: S1) The crude liquefied petroleum gas is brought into contact with the first desulfurizing agent to obtain primary desulfurized liquefied petroleum gas; S2) The primary desulfurized liquefied petroleum gas obtained in step S1 is mixed with the second desulfurizing agent, and then the mixture is contacted with the carbonyl sulfur hydrolysis catalyst to obtain the secondary desulfurized liquefied petroleum gas. S3) The secondary desulfurized liquefied petroleum gas obtained in step S2 is contacted with the third desulfurizing agent to obtain refined liquefied petroleum gas; The first, second, and third desulfurizing agents are the same desulfurizing agent; the desulfurizing agent contains aminocarboxylate, alkanolamine and water. Based on the total mass of the desulfurizing agent, the total mass concentration of aminocarboxylate and alkanolamine is 40~85%, and the mass concentration ratio of aminocarboxylate to alkanolamine is (0.45~2.2):1.

[0006] The technical advantages of the method of this invention are as follows: First, when removing hydrogen sulfide, carbonyl sulfide, and mercaptans from liquefied petroleum gas (LPG), deep desulfurization can be achieved by using only one identical desulfurizing agent. The total sulfur content (based on elemental sulfur) of the refined LPG product can be reduced to 2.5 μg·g. -1 Below that, it can even reach 1 μg·g -1 Moreover, it eliminates the need for frequent replacement of desulfurizing agents, resulting in a simple process flow, convenient operation, and applicability to the refining of raw materials such as natural gas, dry gas, and liquefied petroleum gas.

[0007] Secondly, when removing carbonyl sulfide from liquefied petroleum gas (LPG), the carbonyl sulfide hydrolysis catalyst and desulfurizing agent are used in combination in the second step, so that the catalytic hydrolysis of carbonyl sulfide and the desulfurization of LPG can be carried out simultaneously. This ensures the thoroughness of the catalytic hydrolysis reaction and achieves the goal of deep removal of carbonyl sulfide. At the same time, the LPG that has undergone primary desulfurization in reaction with the carbonyl sulfide hydrolysis catalyst has already undergone primary desulfurization, thus maintaining an appropriate catalyst load and extending the catalyst's service life.

[0008] Third, when removing mercaptan from liquefied petroleum gas, the efficiency of mercaptan removal is significantly improved by using a combination of aminocarboxylate and alcohol amine components of the desulfurizing agent.

[0009] Fourth, since the desulfurizer does not contain inorganic alkaline solutions such as sodium hydroxide, and the desulfurizer can be regenerated by heating and stripping without the need for oxidation regeneration, the desulfurizer can be recycled, with no alkaline residue discharge, significantly reducing the environmental pressure on refineries and eliminating the safety hazards caused by oxidants. Attached Figure Description

[0010] Figure 1 A schematic diagram of the process flow for the refined liquefied petroleum gas method of the present invention is shown. Detailed Implementation

[0011] In this invention, "hydrogen sulfide sulfur" refers to sulfur element existing in the form of hydrogen sulfide, the content of which in liquefied petroleum gas is expressed in μg·g. -1 This indicates the mass of sulfur in the form of hydrogen sulfide contained in each gram of liquefied petroleum gas.

[0012] In this invention, "carbonyl sulfide sulfur" refers to sulfur element existing in the form of carbonyl sulfide, and its content in liquefied petroleum gas is expressed in μg·g. -1 This indicates the mass of sulfur in carbonyl sulfur contained in each gram of liquefied petroleum gas.

[0013] In this invention, "thiol sulfur" refers to sulfur element existing in the form of thiols, the content of which in liquefied petroleum gas is expressed in μg·g. -1 This indicates the mass of sulfur in the form of thiols contained in each gram of liquefied petroleum gas (LPG). For example, if LPG contains methanethiol and ethanethiol, then the thiol sulfur content is the sum of the sulfur content of methanethiol and ethanethiol.

[0014] In this invention, the first, second and third desulfurizing agents are desulfurizing agents with the same composition, and the ordinal numbers "first, second and third" are used only to more clearly express the desulfurizing agents used in different desulfurization steps.

[0015] In this invention, "rich desulfurizer" refers to a substance with a high sulfur content obtained by chemically absorbing sulfur-containing compounds.

[0016] Unless otherwise specified, the substances used in this invention are commercially available products that can be used without further processing; the equipment, processes and testing methods used are all commonly used in the field.

[0017] In this invention, unless otherwise stated, the relevant operations are performed under normal temperature and pressure conditions.

[0018] In this invention, unless otherwise stated, the sum of the percentage contents of each component in the composition, mixture, etc., by weight is 100%.

[0019] This invention provides a method for refining liquefied petroleum gas, comprising the following steps: S1) The crude liquefied petroleum gas is brought into contact with the first desulfurizing agent to obtain primary desulfurized liquefied petroleum gas; S2) The primary desulfurized liquefied petroleum gas obtained in step S1 is mixed with the second desulfurizing agent, and then the mixture is contacted with the carbonyl sulfur hydrolysis catalyst to obtain the secondary desulfurized liquefied petroleum gas. S3) The secondary desulfurized liquefied petroleum gas obtained in step S2 is contacted with the third desulfurizing agent to obtain refined liquefied petroleum gas; The first, second and third desulfurizing agents are the same desulfurizing agents; the desulfurizing agents contain aminocarboxylate, alkanolamine and water. Based on the total mass of the desulfurizing agents, the total mass concentration of aminocarboxylate and alkanolamine is 40~85%, and the mass concentration ratio of aminocarboxylate to alkanolamine is (0.45~2.2):1.

[0020] In some embodiments, the volume ratio of crude liquefied petroleum gas to the first, second, and third desulfurizing agents is 1:(0.1~2):(0.05~1):(0.1~3), preferably 1:(0.1~0.4):(0.05~0.3):(0.2~1.0); more preferably 1:(0.2~0.25):(0.1~0.15):(0.5~0.75), calculated based on the unit time flow rate of crude liquefied petroleum gas (ml / hour) and the unit time flow rate of the first, second, and third desulfurizing agents (ml / hour).

[0021] Desulfurizing agent In this invention, the desulfurizing agent comprises an aminocarboxylate, an alkanolamine, and water; wherein the aminocarboxylate is selected from at least one compound of formulas (I-1), (I-2), and (I-3): (I-1) R1 and R2 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n1 is an integer from 3 to 5, preferably 3 or 4; M is selected from alkali metal ions, preferably Na. + or K + ; (I-2) R1 and R2 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n2 is an integer from 3 to 6, preferably 3 or 4; n3, in each occurrence, can be the same or different, and is an integer from 3 to 5 independently of each other, preferably 3 or 4; M is selected from alkali metal ions, preferably Na. + or K + ; (I-3) Among them, R1, R2, and R3 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n4 is an integer from 3 to 6, preferably 3 or 4; n5 is an integer from 3 to 5, preferably 3 or 4; M is selected from alkali metal ions, preferably Na. + or K + ;as well as, The alkanolamine is selected from at least one of compounds of formula (II-1), (II-2), and (II-3): (II-1) Among them, R4 and R5 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl, where m1 is an integer from 3 to 6; m2 is an integer from 1 to 3, preferably 1 or 2; (II-2) Among them, R4 and R5 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl, m3 is an integer from 3 to 6; m4, in each case, can be the same or different, and is an integer from 2 to 4 independently of each other; m5, in each case, can be the same or different, and is 0, 1, or 2 independently of each other. (II-3) Among them, R4, R5, and R6 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; m6 is an integer from 3 to 6, preferably 3, 4, or 5; m7 is an integer from 2 to 4, preferably 2 or 3; m8 is 0, 1, or 2, preferably 0.

[0022] In some embodiments, the aminocarboxylate is selected from at least one of the following compounds: potassium 4-(dimethylamino)butyrate, potassium 5-(diethylamino)valerate, N,N-dimethyl-N',N'-di(4-butanoyl)propanediamine, N,N-dimethyl-N',N'-di(5-valerate)propanediamine, potassium 4-[N-(N,N',N'-trimethylbutyldiamino)]butyrate, potassium 4-[N-(N,N',N'-triethylbutyldiamino)]butyrate.

[0023] In some embodiments, the alkanolamine is selected from at least one of the following compounds: 2-[(3-dimethylamino)propyl]oxyethanol, N,N-dimethyl-N',N'-di[2-(2-hydroxyethoxy)ethyl]propanediamine, N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine, N,N,N'-triethyl-N'-(2-hydroxyethyl)butanediamine, N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine, and N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine.

[0024] In some embodiments, the aminocarboxylate is selected from at least one of the following compounds (1) to (6): In some embodiments, the alkanolamine is selected from at least one of the following compounds (7) to (12): In some embodiments, the total mass concentration of aminocarboxylate and alkanolamine is 50-80%, preferably 60-70%, based on the total mass of the desulfurizing agent; preferably, the mass concentration ratio of aminocarboxylate to alkanolamine is (0.5-2):1, more preferably (0.8-1.8):1, and even more preferably (1.2-1.5):1.

[0025] In some embodiments, the desulfurizing agent is an aqueous solution of an aminocarboxylate and an alkanolamine, wherein the concentration of the aminocarboxylate is 25% to 45% by weight, preferably 30% to 45% by weight, more preferably 35% to 40% by weight; the concentration of the alkanolamine is 25% to 40% by weight, preferably 30% to 35% by weight; water is the balance; and the total mass percentage of the aminocarboxylate, alkanolamine and water is 100%.

[0026] In a preferred embodiment, the aminocarboxylate is selected from compounds of formula (I-1) or (I-3), the alcoholamine is selected from compounds of formula (II-3), and the mass concentration ratio of the aminocarboxylate to the alcoholamine is (0.8~1.8):1, more preferably (1.2~1.5):1, for example 1:1, 4:3.

[0027] In one specific embodiment of the present invention, the desulfurizing agent is an aqueous solution of 4-(dimethylamino)butyric acid N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine; in another specific embodiment of the present invention, the desulfurizing agent is an aqueous solution of potassium 5-(diethylamino)valerate and N,N,N'-triethyl-N'-(2-hydroxyethyl)butanediamine; in yet another specific embodiment of the present invention, the desulfurizing agent is potassium 4-[N-(N,N',N'-trimethylbutanediamine)]butyrate and N,N,N'-triethyl-N'-(2-hydroxyethyl)butanediamine. An aqueous solution of N,N,N'-(3-hydroxypropyl)butanediamine; in yet another embodiment of the invention, the desulfurizing agent is an aqueous solution of potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine; in yet another embodiment of the invention, the desulfurizing agent is an aqueous solution of potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine.

[0028] The desulfurizing agent of the present invention is obtained by uniformly mixing at least one aminocarboxylate, at least one alkanolamine and water.

[0029] In some embodiments, the method of the present invention can be used for total sulfur content (calculated as elemental sulfur, the same below) not exceeding 8500 μg·g -1 The preferred value is 2000~7500 μg·g -1 More preferably, 3000~6500 μg·g -1 More preferably 3300~6200 μg·g -1 The raw material, liquefied petroleum gas, is processed.

[0030] In some embodiments, the method of the present invention can be used for sulfur elements present in the form of hydrogen sulfide with a content not exceeding 7500 μg·g. -1 The preferred value is 2000~7000 μg·g -1 More preferably, 3000~6000 μg·g -1 The raw material, liquefied petroleum gas, is processed.

[0031] In some embodiments, the method of the present invention can be used for sulfur elements present in the form of carbonyl sulfide with a content not exceeding 45 μg·g. -1 The preferred value is 5~40 μg·g -1 More preferably, 10~30 μg·g -1 The raw material, liquefied petroleum gas, is processed.

[0032] In some embodiments, the method of the present invention can be used to reduce the content of sulfur, which is present in the form of thiols (e.g., methanethiol, ethanethiol), to no more than 500 μg·g. -1 The preferred value is 80~450 μg·g. -1 More preferably, 100~400 μg·g -1 The raw material, liquefied petroleum gas, is processed.

[0033] This invention utilizes a combination of specific aminocarboxylate salts and alkanolamines (where all amino groups are tertiary amino groups) at specific mass concentration ratios to remove hydrogen sulfide, carbonyl sulfide, and mercaptans from liquefied petroleum gas, achieving deep desulfurization with desulfurization efficiencies exceeding 99.9%. Furthermore, the total sulfur content of the product can be stably reduced to 2.5 μg·g⁻¹. -1 Below that, it even reaches 1 μg·g -1 .

[0034] <Step S1> According to the method for refining liquefied petroleum gas of the present invention, the crude liquefied petroleum gas used in step S1 mainly consists of hydrocarbons containing 2 to 4 carbon atoms, such as alkanes or alkenes, and small amounts of sulfur-containing compounds, particularly hydrogen sulfide, carbonyl sulfide, and thiols; in some embodiments, the total sulfur content in the crude liquefied petroleum gas used in step S1 is not greater than 8500 μg·g -1 The preferred value is 2000~7500 μg·g -1 More preferably, 3000~6500 μg·g -1 More preferably 3300~6200 μg·g -1 The content of sulfur, present in the form of hydrogen sulfide, is 2000~7000 μg·g. -1 The preferred concentration is 3000~6000 μg·g. -1 The content of sulfur in the form of carbonyl sulfur is 5~40 μg·g. -1 Preferred concentration: 10~30 μg·g -1 The content of sulfur in the form of thiols is 80~450 μg·g. -1 Preferred concentration: 100~400 μg·g -1 .

[0035] According to the method for refining liquefied petroleum gas of the present invention, the first desulfurizing agent used in step S1 is the desulfurizing agent described herein.

[0036] In some embodiments, in step S1, the volume ratio of the first desulfurizing agent to crude liquefied petroleum gas is (0.1~2):1, preferably (0.1~0.4):1, more preferably (0.2~0.25):1, for example 1:5 or 1.2:5.

[0037] In some embodiments, the ratio of the volumetric flow rate of the first desulfurizing agent in step S1 to the volumetric flow rate of the second desulfurizing agent in step S2 is (1.2~3):1, preferably (1.5~2.5):1.

[0038] In some embodiments, in step S1, the volumetric flow rate of the first desulfurizing agent is 100~800 ml / h, preferably 200~700 ml / h, and more preferably 300~500 ml / h.

[0039] In some embodiments, in step S1, the temperature at which the crude liquefied petroleum gas comes into contact with the first desulfurizing agent is 10–50°C, preferably 20–40°C, more preferably 25–35°C; the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa. Preferably, the crude liquefied petroleum gas comes into contact with the first desulfurizing agent in reverse.

[0040] In one specific embodiment of the present invention, in step S1, crude liquefied petroleum gas enters from the lower part of the first desulfurization device, and the first desulfurizing agent enters from the upper part of the first desulfurization device. Thus, the crude liquefied petroleum gas and the first desulfurizing agent come into countercurrent contact, so that the hydrogen sulfide in the liquefied petroleum gas is chemically absorbed by the first desulfurizing agent, thereby removing the hydrogen sulfide in the liquefied petroleum gas and obtaining primary desulfurized liquefied petroleum gas and rich desulfurizing agent. The primary desulfurized liquefied petroleum gas is discharged from the top of the first desulfurization device, and the rich desulfurizing agent flows out from the bottom of the first desulfurization device.

[0041] In some embodiments, the first desulfurization device is a plate tower or a packed tower. In some specific embodiments of the present invention, the first desulfurization device is a packed tower using structured or random packing, with the packing selected from Pall rings, wire mesh, corrugated plates, or grids. The height of the packed tower and packing layer is mainly determined by the separation requirements and is adjusted according to actual needs.

[0042] <Step S2> According to the method for refining liquefied petroleum gas of the present invention, the second desulfurizing agent used in step S2 is the desulfurizing agent described herein. In some embodiments, the volume ratio of the second desulfurizing agent to the second desulfurized liquefied petroleum gas is (0.05~1.0):1, preferably (0.05~0.3):1, more preferably (0.1~0.15):1, for example 0.6:6, 0.6:5 ​​or 0.8:6.

[0043] In some implementation schemes, the total sulfur content in the primary desulfurized liquefied petroleum gas used in step S2 is no more than 500 μg·g. -1 The preferred value is 50~500 μg·g -1 More preferably 80~450 μg·g -1More preferably 110~430 μg·g -1 The content of sulfur in the form of carbonyl sulfur is 5~40 μg·g. -1 Preferred concentration: 10~30 μg·g -1 The content of sulfur in the form of thiols is 80~450 μg·g. -1 Preferred concentration: 100~400 μg·g -1 .

[0044] In some embodiments, in step S2, the carbonyl sulfide hydrolysis catalyst comprises an active component and a support, wherein the active component is selected from at least one of SrO, BaO, CaO, MgO, ZnO, Fe2O3, MoO3, Ce2O3, PbS or pyridine-containing nitrogen-carbon materials, the support is selected from γ-Al2O3 or a mixture of γ-Al2O3 and TiO2, and the active component is 1 to 40% by weight, preferably 5 to 20% by weight, based on the total weight of the carbonyl sulfide hydrolysis catalyst.

[0045] Optionally, in the carbonyl sulfide hydrolysis catalyst, the active component is at least one selected from SrO, BaO, CaO, MgO, ZnO, Fe2O3, MoO3, Ce2O3, or PbS, and the active component is 8-15% by weight. Such carbonyl sulfide hydrolysis catalysts are obtained by impregnation methods known to those skilled in the art, i.e., impregnating the support in a solution containing the active component. The amount of the active component in the carbonyl sulfide hydrolysis catalyst is obtained by methods commonly used in the art for determining the amount of the active component in a catalyst. For example, the amount of MgO as the active component in the carbonyl sulfide hydrolysis catalyst MgO / (γ-Al2O3+TiO2) can be determined using a Rigaku ZSX100E X-ray fluorescence spectrometer (40 kV, 250 mA). Elemental analysis is performed based on the proportionality between the intensity of the fluorescence rays of each element and its concentration to obtain the amount of the active component MgO (e.g., 10% by weight), based on the weight of the catalyst.

[0046] Optionally, in the carbonyl sulfur hydrolysis catalyst, the active component is a pyridine nitrogen-carbon material, wherein the active component is 8-15% by weight; wherein the pyridine nitrogen-carbon material includes pyridine nitrogen, and the amount of pyridine nitrogen is 1.5-3.0% by weight, preferably 1.7-2.8% by weight, for example 1.8% by weight, 2.0% by weight, 2.2% by weight, 2.5% by weight, or 2.73% by weight, based on the total weight of the catalyst. Using the above-mentioned carbonyl sulfur hydrolysis catalyst containing pyridine nitrogen-carbon material can better facilitate the hydrolysis of carbonyl sulfur to generate hydrogen sulfide, thereby achieving deep removal of carbonyl sulfur.

[0047] In some embodiments, the carbonyl sulfur hydrolysis catalyst with pyridine-containing nitrogen-carbon material as the active component is prepared by calcining a mixture of components (A) and (B) with guar gum powder at a temperature of 550°C-950°C, preferably 650°C-850°C, for 2-8 hours under nitrogen or helium atmosphere; wherein, component (A) is selected from one or more of urea, melamine, hexamethylenetetramine, diethylenetriamine, triethylenetetramine, tri(2-aminoethyl)amine, quinoline, phthalazine, phenanthroline, or purine, preferably melamine, and component (B) is selected from alumina and / or its precursor (calculated as Al2O3), alumina and / or its precursor and titanium dioxide precursor and / or its precursor (calculated as Al2O3). (Total weight of TiO2); wherein, the weight content of components (A), (B) and guar gum powder is based on the total weight of components (A) and (B), the content of component (A) is 5-40% by weight, preferably 10-40% by weight, more preferably 10-20% by weight, the content of component (B) is 60-95% by weight, preferably 60-90% by weight, more preferably 80-90% by weight, for example 80-85% by weight (if an Al2O3 precursor is used, the amount of Al2O3 precursor used should be based on the required amount of Al2O3, for example, using boehmite, whose weight percentage after calcination is 68%, this is the Al2O3 weight percentage, therefore, for example, when the required amount of Al2O3 is 82.01%). When g, the amount of pseudoboehmite is 120.6g; if TiO2 precursor is used, the amount of TiO2 precursor used should be based on the amount of TiO2 required. For example, if metatitanic acid is used, its weight percentage after calcination is 55%, which is the weight percentage of TiO2. Therefore, for example, when the amount of TiO2 required is 14.85 g, the amount of metaaluminic acid is 18.2 g). The amount of guar gum powder is 2-5% by weight. The weight ratio of the components (A) and (B) to guar gum powder is (0.1~0.3): 1: (0.02~0.05), preferably (0.15~0.25): 1: (0.03~0.04).

[0048] In some embodiments, the pore volume of the alumina and / or alumina precursor and the titanium dioxide and / or titanium dioxide precursor is 0.8~1.5 cm³. 3 / g, preferably 0.9~1.35 cm 3 / g, more preferably 1.0~1.2 cm 3 / g; specific surface area is 265~310 m² 2 / g, preferably 275~300 m 2 / g, more preferably 280~290 m 2 / g.

[0049] In this invention, for the carbonyl sulfide hydrolysis catalyst using pyridine-containing nitrogen-carbon material as the active component, the content of the active component is obtained as follows: First, a certain weight (M1) of the catalyst is weighed and calcined at 650°C for 2 hours under air circulation conditions, and the weight is measured as M2; the value of (M1-M2) is the amount of active component in the weighed carbonyl sulfide hydrolysis catalyst, and the amount of M2 is the amount of support. The weight percentage of the active component in the carbonyl sulfide hydrolysis catalyst = [(M1-M2) / M1]×100%, and the weight percentage of the support = M2 / M1×100%.

[0050] In this invention, for the carbonyl sulfur hydrolysis catalyst using pyridine-containing nitrogen-carbon material as the active component, the pyridine-containing nitrogen-carbon material refers to a material in which the total content of carbon, nitrogen, and hydrogen elements is 99% or more. In this invention, the pyridine-containing nitrogen-carbon material includes nitrogen in various forms such as pyridine nitrogen (N-6), pyridone nitrogen or pyrrole nitrogen (N-5), graphite nitrogen (NQ), and oxidized nitrogen (NX). The total amount of nitrogen is 3.00~6.00% by weight, preferably 3.20~5.80% by weight, more preferably 5.10~5.50% by weight. Based on the weight of the carbonyl sulfur hydrolysis catalyst, nitrogen in the form of pyridine nitrogen accounts for 40.00~55.00% of the total nitrogen element, preferably 43.00~53.00%. The amount of nitrogen present in the form of pyridine nitrogen was obtained as follows: First, the total nitrogen content in the carbonyl sulfide hydrolysis catalyst was determined using an organic elemental analyzer (Vario MACRO cube, manufactured by Elementar Trading (shanghai) Co., Ltd., Analytical Instruments (Shanghai) Co., Ltd.); then, the content of each type of nitrogen was determined: each carbonyl sulfide hydrolysis catalyst sample was characterized using a Thermo Fisher ESCLAB 250Xi X-ray photoelectron spectrometer (XPS), with monochromatic Al Kα X-rays as the radiation source (h = 1486.74 eV), a resolution of 0.5 eV, and a narrow scan transmission energy of 30 eV. Before testing, the carbonyl sulfide hydrolysis catalyst samples were ground and pressed into sheets. A small sheet of each type of carbonyl sulfide hydrolysis catalyst sample was placed in the vacuum chamber of the instrument, and the samples were subjected to vacuum treatment (1×10⁻⁶). -7Afterwards, tests were conducted. The binding energy was corrected using the C1s standard peak of contaminated carbon (binding energy 284.8 eV) as an internal standard. To analyze the chemical environment of different elements in each sample, XPSPEAK software (Version 4.1) was used to perform peak fitting analysis on the XPS spectra. The N1s main peak of each carbonyl sulfur hydrolysis catalyst sample could be fitted into four peaks, which belong to different nitrogen-containing functional groups on the surface of the carbonyl sulfur hydrolysis catalyst, namely: N-6 (pyridine nitrogen), N-5 (pyridone nitrogen or pyrrole nitrogen), NQ (graphite nitrogen), and NX (oxidized nitrogen). Based on the ratio of the peak areas of different nitrogen-containing functional groups fitted by the main N1s peak, the relative weight content of different nitrogen-containing functional groups and the ratio of pyridine nitrogen to total nitrogen (relative content of pyridine nitrogen / sum of the relative contents of each nitrogen-containing functional group) can be calculated. The binding energies of various nitrogen types were compared with those in existing literature (Effect of nitrogen-containing groups on methane adsorption behaviors of carbon spheres; Yanyan Feng, WenYang, Ning Wang, Wei Chu, Daijun Liu; Journal of Analytical and Applied Pyrolysis 107(2014) 204-210). The binding energies of each nitrogen type were as follows: N-6: 398.7±0.3 eV; N-5: 400.3±0.3 eV; NQ: 401.2±0.5 eV; NX: 402-405 eV. The pyridine nitrogen content in the catalyst was calculated by the ratio of pyridine nitrogen to total nitrogen and the content of total nitrogen in the carbonyl sulfur hydrolysis catalyst.

[0051] In some embodiments, the specific surface area of ​​the carbonyl sulfur hydrolysis catalyst is 110 to 250 m². 2 / g, preferably 140 to 210 m 2 / g, more preferably 170 to 200 m 2 / g; pore size of 8 to 16 nm, preferably 11.30 to 14.50 nm; pore volume of 0.50 to 0.80 cm³. 3 / g, preferably 0.60 to 0.70 cm 3 / g, with a bulk density of 0.50 to 0.80 g / cm³. 3 Preferably, the concentration is 0.60 to 0.70 g / cm³. 3The specific surface area, pore size, and pore volume of the carbonyl sulfide hydrolysis catalyst were determined by physical adsorption-desorption methods, such as using a Tristar II 3030 adsorption analyzer from Micromeritics (USA) for nitrogen adsorption-desorption analysis of the carbonyl sulfide hydrolysis catalyst samples. Before analysis, each carbonyl sulfide hydrolysis catalyst sample was degassed at 300℃ for 4 h under dynamic vacuum. The total specific surface area of ​​the samples was analyzed using the BET method, the external specific area was analyzed using the t-plot method, the micropore volume was identified using the t-plot method, and the pore size distribution and mesopore volume were analyzed using the BJH method.

[0052] In some embodiments, in step S2, the contact is carried out in a carbonyl sulfide hydrolysis reactor, and the contact is by means of passage. In this invention, the carbonyl sulfide hydrolysis reactor is also referred to as a second desulfurization unit.

[0053] In some embodiments, the carbonyl sulfur hydrolysis reactor may be a fixed-bed reactor, wherein a fixed bed is filled with a particulate carbonyl sulfur hydrolysis catalyst; the mixture comprising primary desulfurized liquefied petroleum gas and a secondary desulfurizing agent enters from the top of the carbonyl sulfur hydrolysis reactor, passes axially through the fixed bed, and exits from the bottom.

[0054] In some embodiments, in step S2, the carbonyl sulfur hydrolysis catalyst can be packed to form a carbonyl sulfur hydrolysis catalyst bed using methods commonly used in the art.

[0055] In some embodiments, in step S2, when the mixture of primary desulfurized liquefied petroleum gas and secondary desulfurizing agent comes into contact with the carbonyl sulfur hydrolysis catalyst, the contact temperature is 10–50°C, preferably 20–40°C, more preferably 25–35°C; the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa; and the volume hourly space velocity is 1–10 h⁻¹. -1 3-8 hours is preferred. -1 More preferably 5-6 hours -1 This refers to the ratio of the volumetric flow rate of liquefied petroleum gas (measured at 20°C and the pressure at the contact point, for example, at 20°C and 1.0 MPa, in ml / h or l / h) to the volume (ml or l) of the carbonyl sulfide hydrolysis catalyst. The ratio of the volumetric flow rate (ml / h or l / h) of the second desulfurizing agent to the volume (ml or l) of the carbonyl sulfide hydrolysis catalyst is 0.1~2.0 h. -1 Preferably, 0.4~1.0 h -1 More preferably 0.6~0.8 h -1 .

[0056] In one specific embodiment of the present invention, the desulfurizing agent is an aqueous solution containing 40 wt% potassium 4-(dimethylamino)butyrate and 30 wt% N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine, and the carbonyl sulfur hydrolysis catalyst is MgO / (γ-Al2O3+TiO2), with the active component MgO comprising 10 wt%; in another specific embodiment, the desulfurizing agent is an aqueous solution containing 35 wt% potassium 4-[N-(N,N',N'-trimethylbutanediamine)]butyrate and 35 wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine, and the carbonyl sulfur hydrolysis catalyst is BaO / (γ-Al2O3+TiO2), with the active component BaO comprising 10 wt%; in yet another specific embodiment, the desulfurizing agent contains 40 wt% potassium 4-(dimethylamino)butyrate and 30 wt% N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine, and the carbonyl sulfur hydrolysis catalyst is BaO / (γ-Al2O3+TiO2), with the active component BaO comprising 10 wt%; The desulfurizing agent is an aqueous solution of 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 30 wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine, wherein the carbonyl sulfur hydrolysis catalyst is (containing pyridine nitrogen and carbon material) / γ-Al2O3, wherein the active component contains carbon and nitrogen material at 12.6 wt% based on the total weight of the catalyst; in yet another specific embodiment, the desulfurizing agent is an aqueous solution containing 40 wt% 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 30 wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine, wherein the carbonyl sulfur hydrolysis catalyst is (containing pyridine nitrogen and carbon material) / (γ-Al2O3+TiO2), wherein the active component contains carbon and nitrogen material at 10 wt% based on the total weight of the catalyst. By using a combination of a specific desulfurizing agent with a specific carbonyl sulfur hydrolysis catalyst in the above-mentioned specific ratio, it is beneficial to further improve the efficiency of carbonyl sulfur removal.

[0057] In some embodiments, in step S2, when the mixture of primary desulfurized liquefied petroleum gas and the second desulfurizing agent comes into contact with the carbonyl sulfide hydrolysis catalyst, on the one hand, the carbonyl sulfide hydrolysis catalyst catalytically hydrolyzes the carbonyl sulfide (COS) in the liquefied petroleum gas to generate hydrogen sulfide and carbon dioxide; on the other hand, these products are simultaneously chemically absorbed in situ by the second desulfurizing agent, thereby achieving the goal of removing carbonyl sulfide from the liquefied petroleum gas in one step. Through this "catalytic conversion + in-situ absorption" strategy, especially with the second desulfurizing agent having the dual function of providing moisture for the catalytic hydrolysis reaction and absorbing the products of catalytic hydrolysis, the catalytic hydrolysis reaction of carbonyl sulfide is ensured to continue to the right until complete, achieving the goal of deep removal of carbonyl sulfide (COS), with a desulfurization efficiency of over 96.5%.

[0058] <Step S3> According to the method for refining liquefied petroleum gas of the present invention, the third desulfurizing agent used in step S3 is the desulfurizing agent described herein. In some embodiments, the volume ratio of the third desulfurizing agent to the secondary desulfurized liquefied petroleum gas is (0.1~3.0):1, preferably (0.2~1.0):1, more preferably (0.5~0.75):1, for example 1:2, 2:3, 3:4 or 3:5.

[0059] In some implementation schemes, the total sulfur content in the secondary desulfurized liquefied petroleum gas used in step S3 is no more than 500 μg·g. -1 The preferred value is 50~450 μg·g -1 More preferably, 100~400 μg·g -1 The content of sulfur in the form of carbonyl sulfur is no more than 2 μg·g. -1 Preferably, the content is no more than 1 μg·g -1 More preferably 0~0.6 μg·g -1 The amount of sulfur present in the form of thiols is 80~450 μg·g. -1 Preferred concentration: 100~400 μg·g -1 .

[0060] In some embodiments, in step S3, the temperature at which the secondary desulfurized liquefied petroleum gas contacts the third desulfurizing agent is 10–50°C, preferably 20–40°C, more preferably 25–35°C, and the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa; preferably, the secondary desulfurized liquefied petroleum gas and the third desulfurizing agent are in reverse contact.

[0061] In one specific embodiment of the present invention, in step S3, the secondary desulfurized liquefied petroleum gas enters from the lower part of the third desulfurization unit, and the third desulfurizing agent enters from the upper part of the third desulfurization unit. Thus, the secondary desulfurized liquefied petroleum gas and the third desulfurizing agent come into countercurrent contact, so that the mercaptans in the secondary desulfurized liquefied petroleum gas are chemically absorbed by the third desulfurizing agent, thereby removing the mercaptans and obtaining tertiary desulfurized liquefied petroleum gas and rich desulfurizing agent. The tertiary desulfurized liquefied petroleum gas is discharged from the top of the third desulfurization unit, and the rich desulfurizing agent flows out from the bottom of the third desulfurization unit.

[0062] In some implementations, the tertiary desulfurized liquefied petroleum gas is liquefied petroleum gas obtained after removing hydrogen sulfide, carbonyl sulfide and mercaptan.

[0063] In some embodiments, the third desulfurization device is a plate tower or a packed tower, such as the first desulfurization device described in step S1 above.

[0064] In some embodiments, step S3 further includes a water washing step. In a specific embodiment of the invention, step S3 further includes a water washing step on the tertiary desulfurized liquefied petroleum gas obtained from the third desulfurization unit, thereby obtaining refined liquefied petroleum gas. In this process, no oxidant or alkali solution is used; thus, there is no discharge of alkali residue and waste alkali solution, significantly reducing environmental pressure and eliminating the safety hazards posed by oxidants.

[0065] In some embodiments, the washing step is completed using demineralized water. The demineralized water is water that has undergone deep desalination and purification, and is virtually free of impurity ions such as calcium, magnesium, sodium, chloride, sulfate, and silica. The demineralized water can be obtained using conventional methods in the art, such as ion exchange. In one specific embodiment of the invention, the demineralized water is added to tertiary desulfurized liquefied petroleum gas (LPG), and after mixing in a mixer, it enters a settling tank. The refined LPG product is discharged from the top of the settling tank, and the wastewater flows out from the bottom.

[0066] In step S3, the combined use of aminocarboxylate and alcohol amine components in the third desulfurizing agent is beneficial to improving the efficiency of mercaptan removal and has a synergistic effect.

[0067] <Step S4> The method for refining liquefied petroleum gas according to the present invention may further include a step of S4) regenerating the desulfurizing agent, that is, stripping and regenerating the rich desulfurizing agent produced by the first, second and third desulfurizing agents in steps S1, S2 and S3 to obtain a desulfurizing agent, wherein no oxidant is used in this step; the stripping temperature is 120~150°C, preferably 130~145°C; the pressure is 0.05 MPa~0.5 MPa, preferably 0.08 MPa~0.3 MPa, more preferably 0.1 MPa~0.2 MPa.

[0068] In some embodiments, during step S1, when the crude liquefied petroleum gas is subjected to desulfurization treatment, the hydrogen sulfide in the liquefied petroleum gas is chemically absorbed by the first desulfurizing agent, and the resulting rich desulfurizing agent flows out from the bottom of the first desulfurization unit.

[0069] In some embodiments, during step S2, when the carbonyl sulfur is removed from the primary desulfurized liquefied petroleum gas, the hydrolysis products of carbonyl sulfur (hydrogen sulfide and carbon dioxide) in the liquefied petroleum gas are chemically absorbed by a second desulfurizing agent, and the resulting rich desulfurizing agent flows out from the bottom of the separation device. The separation device is preferably a settling tank.

[0070] In some embodiments, during step S3, when the liquefied petroleum gas undergoes desulfurization treatment for secondary desulfurized liquefied petroleum gas, the mercaptans in the liquefied petroleum gas are chemically absorbed by the third desulfurizing agent, and the resulting rich desulfurizing agent flows out from the bottom of the third desulfurization unit.

[0071] In some embodiments, in step S4, the desulfurizing agent produced in steps S1, S2, and S3 is fed into a stripping tower for stripping regeneration, and the resulting desulfurizing agent is returned to steps S1, S2, and S3 for recycling. Optionally, stripping regeneration can be carried out by heating the bottom reboiler to generate the vapor phase.

[0072] In some embodiments, in step S4, the operating conditions are that the bottom pressure of the stripping tower is 0.1~0.2 MPa, preferably 0.15~0.18 MPa, the top temperature is 115~125℃, preferably 118~125℃, and the outlet temperature of the reboiler is 135~145℃.

[0073] In some embodiments, the stripping tower is a plate tower or a packed tower. In some specific embodiments of the present invention, the stripping tower is a packed tower using structured or random packing, with packing materials such as Pall rings, wire mesh, corrugated plates, or grids. The height of the packed tower and packing layer is mainly determined by the separation requirements and is adjusted according to actual needs.

[0074] In one specific embodiment of the present invention, in step S4, the desulfurizing agent produced in steps S1, S2 and S3 is heated to 85~95°C by a heat exchanger, and then enters a stripping tower. The vapor phase generated by the reboiler is heated to achieve a stripping temperature of 130°C~145°C and a pressure of 0.1MPa~0.2MPa. The sulfur-containing mixed gas stripped out is discharged from the top of the stripping tower, cooled to below 40°C by a cooler, and enters a reflux tank. The sulfur-containing tail gas separated from the reflux tank is sent to a sulfur recovery system. The mixture of water and desulfurizing agent separated from the reflux tank is returned to the stripping tower as reflux liquid by a reflux pump. The desulfurizing agent after stripping is cooled to below 40°C and sent to a desulfurizing agent storage tank, and then recycled by a desulfurizing agent pump.

[0075] In one specific embodiment of the present invention, the process flow of the liquefied petroleum gas refining method is as follows: (a) The crude liquefied petroleum gas enters from the bottom of the desulfurization extraction tower and comes into countercurrent contact with the first desulfurizing agent entering from the top of the extraction tower to desulfurize the crude liquefied petroleum gas, thereby obtaining primary desulfurized liquefied petroleum gas and rich desulfurizing agent. The primary desulfurized liquefied petroleum gas is discharged from the top of the extraction tower, and the rich desulfurizing agent flows out from the bottom of the extraction tower. (b) The second desulfurizing agent is added to the primary desulfurized liquefied petroleum gas obtained in step (a) through the input pipeline. After passing through the mixer, it enters the reactor filled with carbonyl sulfur hydrolysis catalyst. Under the combined action of carbonyl sulfur hydrolysis catalyst and the second desulfurizing agent, carbonyl sulfur is removed from the primary desulfurized liquefied petroleum gas to obtain secondary desulfurized liquefied petroleum gas and rich desulfurizing agent. When entering the desulfurizing agent settling tank, the secondary desulfurized liquefied petroleum gas is discharged from the top of the desulfurizing agent settling tank, and the rich desulfurizing agent flows out from the bottom of the desulfurizing agent settling tank. (c) The secondary desulfurized liquefied petroleum gas obtained in step (b) enters the extraction tower from the bottom of the desulfurization extraction tower and comes into countercurrent contact with the third desulfurizing agent entering from the top of the desulfurization extraction tower to desulfurize the secondary desulfurized liquefied petroleum gas, thereby obtaining tertiary desulfurized liquefied petroleum gas and rich desulfurizing agent. The tertiary desulfurized liquefied petroleum gas is discharged from the top of the extraction tower, and the rich desulfurizing agent flows out from the bottom of the extraction tower. (d) Demineralized water is added to the three-stage desulfurized liquefied petroleum gas obtained in step (c) through an input pipeline. After passing through a mixer, it enters a water washing settling tank. The liquefied petroleum gas obtained after water washing is discharged from the top of the water washing settling tank, thus obtaining the refined liquefied petroleum gas of the present invention, wherein the total sulfur content can be reduced to 2.5 μg·g -1 the following; (e) The desulfurizing agent flowing out from steps (a), (b), and (c) is heated together by a heat exchanger and then flows into a stripping tower to regenerate desulfurizing agent and sulfur-containing mixed gas. The sulfur-containing mixed gas is discharged from the top of the stripping tower and sent to the sulfur recovery system for processing. The desulfurizing agent flows out from the bottom of the stripping tower and is returned to steps (a), (b), and (c) for recycling.

[0076] For multiple devices of the same type, in order to clarify the meaning and avoid confusion, a prefix indicating their function and purpose is added before the device name. For example, "hydrogen sulfide extraction tower" and "methanol extraction tower"; "desulfurizing agent settling tank" and "water washing settling tank" are mentioned above.

[0077] In the above-mentioned process flow of liquefied petroleum gas refining method, the first, second and third desulfurizing agents are the same desulfurizing agents.

[0078] In some implementations, the volumetric flow rates of crude liquefied petroleum gas, primary desulfurized liquefied petroleum gas, and secondary desulfurized liquefied petroleum gas are the same.

[0079] Compared with the prior art, the method of the present invention has the following beneficial technical effects: First, the method of refining liquefied petroleum gas of the present invention completely abandons the traditional alkaline treatment process. It only requires one desulfurizing agent and one carbonyl sulfur hydrolysis catalyst to sequentially remove hydrogen sulfide, carbonyl sulfide and mercaptans from liquefied petroleum gas, reducing the total sulfur content in liquefied petroleum gas to 2.5 μg·g-1 First, this invention achieves deep desulfurization. Specifically, the combined use of aminocarboxylate and alkanolamine components in the desulfurizing agent improves the efficiency of mercaptan removal. Furthermore, the entire process of refining liquefied petroleum gas (LPG) eliminates the need for alkaline solutions, resulting in zero alkaline residue emissions and environmental benefits. Second, in the decarbonyl sulfide removal process for LPG, this invention combines a carbonyl sulfide hydrolysis catalyst with the desulfurizing agent in a reactor, enabling simultaneous catalytic hydrolysis and desulfurization to achieve deep removal of carbonyl sulfide (COS). Third, in the regeneration of the rich desulfurizing agent, regeneration can be completed solely through heating and stripping, eliminating the need for oxidative regeneration and thus avoiding accidents such as combustion and explosion caused by the introduction of oxidants.

[0080] The method of this invention can be used to produce ultra-low sulfur natural gas, dry gas, liquefied petroleum gas (LPG), and light gasoline, especially LPG. In the refined LPG, the total sulfur content can be reduced to 2.5 μg·g⁻¹. -1 Below that, it can even reach 1 μg·g -1 .

[0081] Example The following embodiments are merely illustrative of the present invention and do not limit the scope of the invention.

[0082] I. Raw Materials and Reagents 1. Crude liquefied petroleum gas The hydrocarbon content and sulfur content in crude liquefied petroleum gas (LPG) in the form of sulfur-containing compounds are shown in Table 1 below. The hydrocarbon content was determined using the following method: The composition of liquefied petroleum gas (excluding sulfur-containing compounds) was detected using a Shimadzu GC-2014 gas chromatograph. The specific settings were as follows: Detectors: 2 thermal conductivity detectors (TCDs), 1 flame ionization detector (FID); Columns: 13X molecular sieve column, Al2O3 capillary column 30 m × 0.53 mm; Column oven temperature: 60℃ for 6 min, increased to 140℃ at a rate of 10℃ / min, then increased to 170℃ at a rate of 20℃ / min, held for 8 min; Detector temperatures: TCD 150℃, FID 250℃.

[0083] The sulfur content in various sulfur-containing compound forms was determined according to NB / SH / T 0919-2015 "Determination of Sulfur Compounds in Gaseous Fuels and Natural Gas - Gas Chromatography and Chemiluminescence Detection Method". An Agilent 7890B gas chromatograph was used for detection, with the following settings: Detector: Sulfur detector (SCD); Polar capillary column (Agilent 19095P-S25); Chromatographic conditions: Initial temperature 60℃, hold for 2.5 min, heating rate 5℃ / min, then 250℃, hold for 10 min; Injector temperature 250℃, helium as carrier gas, split ratio 50:1; Injection volume 1... L.

[0084] 2. Desulfurizing agent The composition of the desulfurizing agent is as follows: Desulfurizer A1: An aqueous solution containing 40wt% potassium 4-(dimethylamino)butyrate and 30wt% N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine; Desulfurizer A2: An aqueous solution containing 35wt% potassium 5-(diethylamino)valerate and 35wt% N,N,N'-triethyl-N'-(2-hydroxyethyl)butanediamine; Desulfurizer A3: An aqueous solution containing 35wt% potassium 4-[N-(N,N',N'-trimethylbutanediamine)]butyrate and 35wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine; Desulfurizer A4: An aqueous solution containing 35wt% potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 35wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine; Desulfurizer A5: An aqueous solution containing 40wt% potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 30wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine; Desulfurizer A6: An aqueous solution containing 40wt% potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 30wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine; Desulfurizer A7: An aqueous solution containing 30wt% potassium 4-[N-(N,N',N'-triethylbutanediamine)]butyrate and 30wt% N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine.

[0085] 3. Carbonyl sulfur hydrolysis catalyst <Preparation of Catalyst H1> Catalyst H1 is MgO / (γ-Al2O3+TiO2), wherein MgO, as the active component, accounts for 10% by weight based on the total weight of the catalyst; the bulk density is 0.62 g / cm³. 3 The preparation method is as follows: 12.2 g of metatitanic acid (6.71 g by weight, 55% of which was purchased from Jiangxi Yizhong Chemical Co., Ltd., industrial grade, brand: Yizhong YZ-001) and 110.5 g of pseudoboehmite (75.14 g by weight, 68% of which was purchased from Shandong Hengyi Chemical Technology Co., Ltd., industrial grade, with a pore volume of 1.113 cm⁻¹) were mixed. 3 / g, with a specific surface area of ​​285.1 m². 2 Mix γ-Al₂O₃ and TiO₂ (g, the same below), add 3g of guar gum powder and stir evenly. Then add 68g of dilute nitric acid (5wt%), mix, extrude into strips, and dry in a muffle furnace at 100℃ for 8 hours, then calcine at 550℃ for 4 hours. Crush the calcined mixture of γ-Al₂O₃ and TiO₂ in a mortar and sieve to 20-40 mesh. Then, using the equal volume impregnation method, impregnate 100g of the support in a 45.5wt% magnesium nitrate aqueous solution at room temperature for 8 hours, then dry in a muffle furnace at 110℃ for 8 hours, and then calcine at 550℃ for 4 hours to obtain MgO / (γ-Al₂O₃+TiO₂) as a carbonyl sulfur hydrolysis catalyst with a specific surface area of ​​220 m². 2 / g, pore size 10.71 nm, pore volume 0.61 cm³ 3 / g.

[0086] <Preparation of catalyst H2> The catalyst H2 is composed of CaO / (γ-Al2O3+TiO2), with CaO as the active component comprising 10% by weight based on the total weight of the catalyst; the bulk density is 0.63 g / cm³. 3 The preparation method is as follows: 12.2 g of metatitanic acid and 110.5 g of pseudoboehmite were mixed, and 3 g of guar gum powder was added and stirred evenly. Then, 68 g of dilute nitric acid (5 wt%) was added, and the mixture was extruded into strips. The strips were dried in a muffle furnace at 100 °C for 8 hours, and then calcined at 550 °C for 4 hours. The calcined support γ-Al₂O₃ and TiO₂ mixture was crushed in a mortar and sieved to 20-40 mesh. Then, using the equal-volume impregnation method, 100 g of the support was impregnated in a 53.4 wt% calcium nitrate aqueous solution at room temperature for 8 hours, followed by drying in a muffle furnace at 110 °C for 8 hours, and then calcined at 550 °C for 4 hours to obtain CaO / (γ-Al₂O₃+TiO₂) as a carbonyl sulfide hydrolysis catalyst with a specific surface area of ​​225 m². 2 / g, pore size 10.06 nm, pore volume 0.62 cm³ 3 / g.

[0087] <Preparation of catalyst H3> Catalyst H3 is BaO / (γ-Al2O3+TiO2), wherein BaO, as the active component, accounts for 10% by weight based on the total weight of the catalyst; the bulk density is 0.64 g / cm³. 3 The preparation method is as follows: 12.2 g of metatitanic acid and 112.5 g of pseudoboehmite were mixed, and 3 g of guar gum powder was added and stirred evenly. Then, 70 g of dilute nitric acid (5% by weight) was added, and the mixture was extruded into strips. The strips were dried in a muffle furnace at 100 °C for 8 hours, and then calcined at 550 °C for 4 hours. The calcined mixture of γ-Al₂O₃ and TiO₂ was crushed in a mortar and sieved to 20-40 mesh. Then, using the equal-volume impregnation method, 100 g of the support was impregnated in a 20.82 wt.% barium nitrate aqueous solution at 60 °C for 8 hours, followed by drying in a muffle furnace at 110 °C for 8 hours, and then calcined at 550 °C for 4 hours to obtain BaO / (γ-Al₂O₃+TiO₂) as a carbonyl sulfur hydrolysis catalyst with a specific surface area of ​​230 m². 2 / g, pore size 9.58 nm, pore volume 0.63 cm³ 3 / g.

[0088] <Preparation of catalyst H4> Catalyst H4 is (MgO + Ce2O3) / (γ-Al2O3 + TiO2), wherein the active components MgO + Ce2O3 account for 10% by weight, based on the total weight of the catalyst; the bulk density is 0.64 g / cm³. 3 The preparation method is as follows: 12.2 g of metatitanic acid and 110.5 g of pseudoboehmite were mixed, and 3 g of guar gum powder was added and stirred evenly. Then, 69 g of dilute nitric acid (5% by weight) was added, and the mixture was extruded into strips. The strips were dried in a muffle furnace at 100 °C for 8 hours, and then calcined at 550 °C for 4 hours. The calcined support γ-Al₂O₃ and TiO₂ mixture was crushed in a mortar and sieved to 20-40 mesh. Then, using an equal-volume impregnation method, 100 g of the support was impregnated in a 24.2% by weight magnesium nitrate aqueous solution at room temperature for 8 hours. The magnesium nitrate-impregnated support was then impregnated in a 13% by weight cerium nitrate solution for 8 hours. The mixture was then dried in a muffle furnace at 110 °C for 8 hours, and then calcined at 550 °C for 4 hours to obtain (MgO + Ce₂O₃) / (γ-Al₂O₃ + TiO₂) as a carbonyl sulfur hydrolysis catalyst with a specific surface area of ​​228 m². 2 / g, pore size 9.78 nm, pore volume 0.6 cm³ 3 / g.

[0089] <Preparation of Catalyst H5> Catalyst H5 was prepared from (pyridine-containing nitrogen-carbon material) / γ-Al₂O₃, wherein the active component was 12.6% by weight, based on the total weight of the catalyst; the bulk density was 0.65 g / cm³. 3 The preparation method is as follows: 120.6 g of pseudoboehmite powder, 3 g of guar gum powder, and 18 g of melamine (industrial grade, purchased from Luxi Chemical Group) were mixed, followed by the addition of 70 g of dilute nitric acid (3% by weight). The mixture was then extruded into strips and dried in an oven at 100 °C for 12 h. Subsequently, it was calcined at 750 °C for 5 h under nitrogen to obtain a carbonyl sulfur hydrolysis catalyst (pyridine nitrogen-carbon material) / γ-Al₂O₃. This catalyst was crushed and sieved to 20-40 mesh for later use. The catalyst contained 2.73% by weight of pyridine nitrogen and had a specific surface area of ​​180.8 m². 2 / g, pore size 13.71 nm, pore volume 0.63 cm³ 3 / g.

[0090] <Preparation of Catalyst H6> Catalyst H6 was prepared as (pyridine-containing nitrogen-carbon material) / (γ-Al₂O₃+TiO₂), wherein the active component was 10% by weight, based on the total weight of the catalyst; the bulk density was 0.65 g / cm³. 3 The preparation method is as follows: 120.6 g of pseudoboehmite powder, 18.2 g of metatitanic acid, 3 g of guar gum powder, and 18 g of melamine were mixed, followed by the addition of 70 g of dilute nitric acid (3% by weight). The mixture was then extruded into strips and dried in an oven at 100 °C for 12 h, followed by calcination at 750 °C for 4 h under nitrogen atmosphere to obtain a carbonyl sulfur hydrolysis catalyst (pyridine nitrogen-carbon material) / (γ-Al₂O₃+TiO₂). This catalyst was crushed and sieved to 20-40 mesh for later use. The catalyst contained 1.72% by weight of pyridine nitrogen and had a specific surface area of ​​198.61 m². 2 / g, pore size 12.27 nm, pore volume 0.66 cm³ 3 / g.

[0091] II. Refined Liquefied Petroleum Gas The following embodiments employ the method for refining liquefied petroleum gas according to the present invention, and its process flow is shown in the attached figure. Figure 1 As shown, the equipment used is all existing technology and well known to those skilled in the art. Its process parameters can be adjusted according to actual needs and in accordance with the equipment manual.

[0092] In this specific embodiment and comparative example, both the extraction tower and the stripping tower are packed towers, using metal Pall rings as packing. The extraction tower has a tower height of 3660 mm, a tower diameter of 30 mm, a packing layer height of 1700 mm, and a liquefied petroleum gas feed volumetric flow rate of 2000 ml / h. The stripping tower has a tower height of 2500 mm, a tower diameter of 30 mm, and a packing layer height of 1200 mm.

[0093] Example 1 In Example 1, the first desulfurizing agent 4, the second desulfurizing agent 7, and the third desulfurizing agent 14 are the same, and the above-mentioned desulfurizing agent A1 is used.

[0094] S1) Steps for removing hydrogen sulfide: Crude liquefied petroleum gas 1 (LPG1) enters the extraction tower 2 from the bottom. In addition, a portion of the desulfurizing agent 5 delivered by the desulfurizing agent pump 3 enters the extraction tower 2 from the top as the first desulfurizing agent 4. The liquefied petroleum gas and the desulfurizing agent 4 are in countercurrent contact in the hydrogen sulfide extraction tower 2 to obtain desulfurized liquefied petroleum gas 6 (i.e., first-stage desulfurized LPG) and rich desulfurizing agent 21. The desulfurized liquefied petroleum gas 6 is discharged from the top of the hydrogen sulfide extraction tower 2, and the rich desulfurizing agent 21 flows out from the bottom of the hydrogen sulfide extraction tower 2. The operating conditions of the desulfurization hydrogen extraction tower 2 are as follows: temperature is 30℃, pressure is 1.0 MPa, and the volume ratio (i.e. volume flow ratio) of the first desulfurizing agent 4 to crude liquefied petroleum gas is 1:5.

[0095] S2) Step for removing carbonyl sulfide: The liquefied petroleum gas 6 obtained from step S1) above, which has been desulfurized, is mixed with a portion of the desulfurizing agent 5 delivered by the desulfurizing agent pump 3 as a second desulfurizing agent 7 and then mixed in a static mixer 8 and fed into a carbonyl sulfide hydrolysis reactor 9. Under the combined action of the carbonyl sulfide hydrolysis catalyst and the second desulfurizing agent 7, the carbonyl sulfide in the liquefied petroleum gas is hydrolyzed and catalyzed. The hydrolysis catalyst product reacts with the desulfurizing agent to obtain product 10 (containing liquefied petroleum gas with carbonyl sulfide removed and rich desulfurizing agent). This product is then fed into a desulfurizing agent settling tank 11 for separation. The liquefied petroleum gas 12 with carbonyl sulfide removed (i.e., secondary desulfurized LPG) is discharged from the top of the desulfurizing agent settling tank 11, and the rich desulfurizing agent 22 is discharged from the bottom of the desulfurizing agent settling tank 11. The operating conditions for the carbonyl sulfur hydrolysis reactor 9 are as follows: temperature 30℃, pressure 1.0 MPa, and volumetric space velocity 6 h⁻¹. -1 The volume ratio of the second desulfurizing agent 7 to the liquefied petroleum gas 6 after hydrogen sulfide removal is 0.6:6, and the volumetric flow rate of the second desulfurizing agent 7 is 0.6 times the volume of the catalyst.

[0096] S3) Step for removing mercaptan: The liquefied petroleum gas 12 obtained from step S2) above, which has been decarbonylated, enters the extraction tower 13 from the bottom. The third desulfurizing agent 14, which is delivered by the desulfurizing agent pump 3, enters the extraction tower 13 from the top. The liquefied petroleum gas and the desulfurizing agent come into countercurrent contact in the extraction tower 13 to obtain liquefied petroleum gas 15 with desulfurization and desulfurizing agent 23. The liquefied petroleum gas 15 with desulfurization is discharged from the top of the extraction tower 13, and the desulfurizing agent 23 flows out from the bottom of the extraction tower 13. The operating conditions of the desulfurization extraction tower 13 are as follows: temperature is 30℃, pressure is 1.0 MPa, and the volume ratio of the third desulfurizing agent 14 to the liquefied petroleum gas 12 with carbonyl sulfur removed is 1:2.

[0097] The liquefied petroleum gas 15 obtained above and the demineralized water 16 are mixed in a static mixer 17 and then fed into a water washing settling tank 18. The refined liquefied petroleum gas 19 is discharged from the top of the water washing settling tank 18, and the wastewater 20 is discharged from the bottom of the water washing settling tank 18. S4) Step for regenerating the desulfurizing agent: The rich desulfurizing agent 21 discharged from the bottom of the hydrogen sulfide extraction tower 2 in step S1), the rich desulfurizing agent 22 discharged from the bottom of the desulfurizing agent settling tank 11 in step S2), and the rich desulfurizing agent 23 discharged from the bottom of the mercaptan extraction tower 13 in step S3) are combined into desulfurizing agent 24. After being heated to 90°C by heat exchanger 41, it enters stripping tower 25 at a flow rate of 1600 ml / h. The stripping temperature is 138°C and the pressure is 0.15 MPa. The sulfur-containing mixed gas 26 stripped out comes out from the top of stripping tower 25, is cooled to below 40°C by cooler 27 using cooling water 28, and enters reflux tank 29. The sulfur-containing tail gas 30 separated from reflux tank 29 is sent to sulfur treatment plant. In the recovery system, the mixture 31 of water and desulfurizing agent separated from the reflux tank 29 is returned to the stripping tower 25 as reflux liquid 33 by the reflux pump 32 (the volume flow rate of which is 1:50 with the volume flow rate of the desulfurizing agent entering the stripping tower 25). After stripping, a portion of the desulfurizing agent 34 exits from the bottom of the stripping tower and enters the reboiler 35 heated by steam 36. After being heated, the heat is carried to the bottom of the stripping tower 25 by reflux 37. The other portion of the desulfurizing agent 38 (the volume flow rate of which is the same as that of the desulfurizing agent 34) enters the pump 39. The pumped desulfurizing agent 40 is cooled by the heat exchanger 41 and the cooler 42 using cooling water 43. When cooled to below 40°C, it is sent to the desulfurizing agent storage tank 44 and then recycled by the desulfurizing agent pump 3.

[0098] The operating conditions for stripping tower 25 are as follows: bottom pressure of 0.15 MPa, top temperature of 118℃; and outlet temperature of reboiler of 138℃.

[0099] Examples 2-7 The process flow of Examples 2-7 is basically the same as that of Example 1, except that the different materials and operating conditions used are shown in Table 2 below.

[0100] III. Performance Testing for Removing Thiols Further research was conducted on the effect of the combined use of aminocarboxylate and alcohol amine components in the desulfurizing agent of the present invention on the efficiency of mercaptan removal.

[0101] Example 8 The removal of thiols (S3) as described in Example 1 is carried out, specifically as follows: Liquefied petroleum gas (LPG4) enters the extraction tower from the bottom, while desulfurizing agent pumped in by the desulfurizing agent enters the extraction tower from the top. The LPG4 and desulfurizing agent come into countercurrent contact within the extraction tower to obtain desulfurized LPG4 and desulfurized agent-rich LPG4. The desulfurized LPG4 is discharged from the top of the extraction tower and mixed with demineralized water via a static mixer before entering a water washing settling tank. The refined LPG4 is discharged from the top of the water washing settling tank, while the wastewater is discharged from the bottom of the water washing settling tank.

[0102] The desulfurizing agent is the aforementioned desulfurizing agent A6. The operating conditions of the desulfurization extraction tower are as follows: temperature is 30℃, pressure is 1.0MPa, and the volume ratio of desulfurizing agent to liquefied petroleum gas is 3:5.

[0103] Comparative Examples 1-2 The process flow of Comparative Examples 1 and 2 is basically the same as that of Example 8, except for the desulfurizing agent, as shown in Table 3 below.

[0104] IV. Results of Sulfur Content Measurement of Products The sulfur content in liquefied petroleum gas (LPG) in the form of various sulfur compounds was determined according to NB / SH / T 0919-2015 "Determination of Sulfur Compounds in Gaseous Fuels and Natural Gas by Gas Chromatography and Chemiluminescence Detection" (the specific procedure is as described in the determination method under "Raw Materials and Reagents" in "Crude LPG" above). The sulfur content in the products of Examples 1-8 and Comparative Examples 1-2 in the form of hydrogen sulfide, carbonyl sulfide, and thiols was determined respectively, and the results are shown in Tables 2-3 below. As shown in Table 2 above, the method of this invention achieves the goal of removing hydrogen sulfide, carbonyl sulfide, and mercaptan from liquefied petroleum gas using a desulfurizing agent. In the resulting refined liquefied petroleum gas, hydrogen sulfide is completely removed, and the hydrogen sulfide content is 0 μg·g⁻¹. -1 The carbonyl sulfur content is 0~0.6 μg·g. -1 The thiol sulfur content is 1.0~2.3 μg·g.-1 The total sulfur content decreased to 2.5 μg·g -1 Below that, it even reaches 1 μg·g -1 This achieves the goal of deep desulfurization.

[0105] As shown in Table 3 above, Comparative Examples 1 and 2, using aminocarboxylate or alkanolamine alone as desulfurizing agents, achieved mercaptan removal efficiencies of 76.5% and 73.5%, respectively. In contrast, Example 8, using a combination of aminocarboxylate and alkanolamine as a desulfurizing agent, achieved a mercaptan removal efficiency of 98.3%. This demonstrates that the mercaptan-poor desulfurizing agent of the present invention exhibits excellent mercaptan removal performance, and the combination of the aminocarboxylate and alkanolamine it contains produces an unexpected synergistic effect.

Claims

1. A method for refining liquefied petroleum gas, characterized in that, The method includes the following steps: S1) The crude liquefied petroleum gas is brought into contact with the first desulfurizing agent to obtain primary desulfurized liquefied petroleum gas; S2) The primary desulfurized liquefied petroleum gas obtained in step S1 is mixed with the second desulfurizing agent, and then the mixture is contacted with the carbonyl sulfur hydrolysis catalyst to obtain the secondary desulfurized liquefied petroleum gas. S3) The secondary desulfurized liquefied petroleum gas obtained in step S2 is contacted with the third desulfurizing agent to obtain refined liquefied petroleum gas; The first, second and third desulfurizing agents are the same desulfurizing agents; the desulfurizing agents contain aminocarboxylate, alkanolamine and water. Based on the total mass of the desulfurizing agents, the total mass concentration of aminocarboxylate and alkanolamine is 40~85%, and the mass concentration ratio of aminocarboxylate to alkanolamine is (0.45~2.2):

1.

2. The method according to claim 1, characterized in that, The volume ratio of crude liquefied petroleum gas to the first, second, and third desulfurizing agents is 1:(0.1~2):(0.05~1):(0.1~3); preferably 1:(0.1~0.4):(0.05~0.3):(0.2~1.0), calculated based on the unit time flow rate of crude liquefied petroleum gas (ml / hour) and the unit time flow rate of the first, second, and third desulfurizing agents (ml / hour).

3. The method according to claim 1, characterized in that, The desulfurizing agent comprises aminocarboxylate, alcohol amine, and water. The aminocarboxylate is selected from at least one of the compounds of formula (I-1), (I-2), and (I-3): （I-1） R1 and R2 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n1 is an integer from 3 to 5; M is selected from alkali metal ions, preferably Na. + or K + ; （I-2） R1 and R2 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n2 is an integer from 3 to 6, preferably 3 or 4; n3, in each occurrence, can be the same or different, and is an integer from 3 to 5 independently of each other, preferably 3 or 4; M is selected from alkali metal ions, preferably Na. + or K + ; （I-3） Among them, R1, R2, and R3 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl; n4 is an integer from 3 to 6, preferably 3 or 4; n5 is an integer from 3 to 5, preferably 3 or 4; M is selected from alkali metal ions, preferably Na. + or K + ;as well as The alkanolamine is selected from at least one of compounds of formula (II-1), (II-2), and (II-3): (II-1) Among them, R4 and R5 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl, where m1 is an integer from 3 to 6; and m2 is an integer from 1 to 3. (II-2) Among them, R4 and R5 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl, m3 is an integer from 3 to 6; m4, in each case, can be the same or different, and is an integer from 2 to 4 independently of each other; m5, in each case, can be the same or different, and is 0, 1, or 2 independently of each other. (II-3) Among them, R4, R5, and R6 can be the same or different, and are independently selected from C. 1-6 Alkyl, preferably C 1-4 Alkyl groups, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, and tert-butyl, m6 is an integer from 3 to 6, preferably 3 or 4; m7 is an integer from 2 to 4, preferably 2 or 3; m8 is 0, 1, or 2, preferably 0.

4. The method according to claim 3, characterized in that, The aminocarboxylate is selected from at least one of the following compounds: potassium 4-(dimethylamino)butyrate, potassium 5-(diethylamino)valerate, N,N-dimethyl-N',N'-di(4-butanoyl)propanediamine, N,N-dimethyl-N',N'-di(5-valerate)propanediamine, potassium 4-[N-(N,N',N'-trimethylbutyldiamino)]butyrate, potassium 4-[N-(N,N',N'-triethylbutyldiamino)]butyrate; or... The alkanolamine is selected from at least one of the following compounds: 2-[(3-dimethylamino)propyl]oxyethanol, N,N-dimethyl-N',N'-di[2-(2-hydroxyethoxy)ethyl]propanediamine, N,N,N'-trimethyl-N'-(2-hydroxyethyl)propanediamine, N,N,N'-triethyl-N'-(2-hydroxyethyl)butanediamine, N,N,N'-triethyl-N'-(3-hydroxypropyl)butanediamine, and N,N,N'-triethyl-N'-(3-hydroxypropyl)propanediamine.

5. The method according to claim 3, characterized in that, Based on the total mass of the desulfurizing agent, the total mass concentration of aminocarboxylate and alkanolamine is 50-80%, preferably 60-70%; preferably, the mass concentration ratio of aminocarboxylate to alkanolamine is (0.5-2):1, more preferably (0.8-1.8):1, and even more preferably (1.2-1.5):

1.

6. The method according to claim 1, characterized in that, In step S1, the temperature at which the crude liquefied petroleum gas comes into contact with the first desulfurizing agent is 10–50°C, preferably 20–40°C, more preferably 25–35°C; the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa; preferably, the crude liquefied petroleum gas comes into contact with the first desulfurizing agent in a reverse manner.

7. The method according to claim 1, characterized in that, In step S2, the carbonyl sulfide hydrolysis catalyst comprises an active component and a support, wherein the active component is selected from at least one of SrO, BaO, CaO, MgO, ZnO, Fe2O3, MoO3, Ce2O3, PbS or pyridine-containing nitrogen-carbon materials, the support is selected from γ-Al2O3 or a mixture of γ-Al2O3 and TiO2, and the active component is 1 to 40% by weight, preferably 5 to 20% by weight, based on the total weight of the carbonyl sulfide hydrolysis catalyst; Preferably, the volumetric flow rate ratio of the second desulfurizing agent to the carbonyl sulfur hydrolysis catalyst is 0.1~2.0 h⁻¹. -1 Preferably, 0.4~1.0 h -1 More preferably 0.6~0.8 h -1 .

8. The method according to claim 1, characterized in that, In step S2, the temperature at which the mixture contacts the carbonyl sulfur hydrolysis catalyst is 10–50°C, preferably 20–40°C, more preferably 25–35°C, and the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa.

9. The method according to claim 1, characterized in that, In step S3, the temperature at which the secondary desulfurized liquefied petroleum gas contacts the third desulfurizing agent is 10–50°C, preferably 20–40°C, more preferably 25–35°C, and the pressure is 0.8–2.0 MPa, preferably 0.9–1.2 MPa; preferably, the secondary desulfurized liquefied petroleum gas and the third desulfurizing agent are in reverse contact.

10. The method according to claim 1, characterized in that, It also includes the step of regenerating the desulfurizing agent: S4) stripping regeneration of the rich desulfurizing agent produced by the first, second and third desulfurizing agents in steps S1, S2 and S3, in which no oxidant is used, the stripping temperature is 120~150℃, preferably 130~145℃, and the pressure is 0.05 MPa~0.5 MPa, preferably 0.08 MPa~0.3 MPa.

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