WO2024099095A1 - 一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用 - Google Patents

一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用 Download PDF

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WO2024099095A1
WO2024099095A1 PCT/CN2023/126786 CN2023126786W WO2024099095A1 WO 2024099095 A1 WO2024099095 A1 WO 2024099095A1 CN 2023126786 W CN2023126786 W CN 2023126786W WO 2024099095 A1 WO2024099095 A1 WO 2024099095A1
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desulfurizer
organic sulfur
hydrogen sulfide
sterically hindered
hindered amine
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French (fr)
Inventor
杨超越
李金金
李林峰
朱雯钊
何金龙
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Petrochina Co Ltd
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Petrochina Co Ltd
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/77—Liquid phase processes
    • B01D53/78—Liquid phase processes with gas-liquid contact
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/48—Sulfur compounds
    • B01D53/52—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/46—Removing components of defined structure
    • B01D53/62—Carbon oxides
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/40—Mixing liquids with liquids; Emulsifying
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/40—Mixing liquids with liquids; Emulsifying
    • B01F23/405—Methods of mixing liquids with liquids
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/40—Mixing liquids with liquids; Emulsifying
    • B01F23/43—Mixing liquids with liquids; Emulsifying using driven stirrers
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/40—Mixing liquids with liquids; Emulsifying
    • B01F23/48—Mixing liquids with liquids; Emulsifying characterised by the nature of the liquids
    • B01F23/483—Mixing liquids with liquids; Emulsifying characterised by the nature of the liquids using water for diluting a liquid ingredient, obtaining a predetermined concentration or making an aqueous solution of a concentrate
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/104—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2251/00—Reactants
    • B01D2251/80—Organic bases or salts
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/304—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/306—Organic sulfur compounds, e.g. mercaptans
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel

Definitions

  • the invention relates to a desulfurizing agent capable of absorbing hydrogen sulfide and organic sulfur under normal pressure, a preparation method and application thereof, and belongs to the technical field of desulfurization.
  • the amine-based natural gas purification unit mainly includes desulfurization, dehydration, sulfur recovery and tail gas treatment.
  • the tail gas treatment part plays an important role in improving the sulfur yield and protecting the environment.
  • tail gas treatment processes such as reduction absorption, reduction direct conversion, and oxidation absorption.
  • the reduction absorption tail gas treatment process is the most widely used.
  • most of the sulfur recovery units in large natural gas purification plants and refineries are equipped with reduction absorption tail gas treatment devices. This process currently mainly uses amine desulfurizer to treat the sulfur recovery tail gas after hydrogenation.
  • Sulfur recovery hydrogenation tail gas contains a certain amount of organic sulfur, which is usually above 10ppm, and some devices even reach above 50ppm. Since the pressure of sulfur recovery hydrogenation tail gas is very low, close to normal pressure, the conventional alcohol amine desulfurizer currently used has poor removal effect on H2S and organic sulfur in hydrogenation tail gas.
  • the H2S content in the purified tail gas is usually above 100mg/ m3 , and the removal rate of organic sulfur (COS) is usually only 5% to 10%. This not only causes a decrease in sulfur recovery rate, but also leads to an increase in the SO2 content in the exhaust gas, causing pollution to the environment. With the increasingly stringent environmental protection regulations, the requirements for SO2 content in exhaust gas are getting lower and lower.
  • GB 31570-2015 stipulates that the emission limit of SO2 in acid gas recovery devices in general areas is 400mg/ m3 , and the emission limit in particularly sensitive areas is 100mg/ m3 . Therefore, new technologies must be developed to solve the problem that conventional alcohol amine desulfurizers have poor removal effects on H 2 S and organic sulfur at low pressures, so as to achieve ultra-low emissions of tail gas SO 2 and achieve the purpose of protecting the environment.
  • the purpose of the present invention is to provide a desulfurizer for absorbing hydrogen sulfide and organic sulfur under normal pressure, and its preparation method and application.
  • the desulfurizer of the present invention has a high H2S removal rate under normal pressure and can effectively remove organic sulfur, while not completely removing CO2 , so it can reduce the acid gas load in the desulfurizer.
  • the first aspect of the present invention provides a desulfurization agent for absorbing hydrogen sulfide and organic sulfur under normal pressure, wherein the desulfurization agent comprises the following components by mass percentage: 20 to 35% of a sterically hindered amine, 5 to 20% of an organic sulfur absorption promoter, 5 to 20% of an auxiliary agent, and the remainder of water;
  • the organic sulfur absorption promoter includes piperazine carboxylic acid compounds; and the auxiliary agent includes amide compounds.
  • the sterically hindered amine includes one or a combination of 4-tert-butylamino-1-butanol, 5-tert-butylamino-1-pentanol and 6-tert-butylamino-1-hexanol.
  • the organic sulfur absorption promoter includes one or a combination of 2-(1,4-dimethylpiperazine-2-yl)acetic acid, (3-oxo-1-piperazine)acetic acid and (3-oxopiperazine-2-yl)acetic acid.
  • the auxiliary agent includes one or a combination of N,N-dimethylacetamide, N,N-dimethyl-2,2-dimethoxyacetamide and 2-amino-N-pyridin-3-yl-acetamide.
  • the water content therein is greater than 20%.
  • the desulfurizer of the present invention uses three substances, namely, sterically hindered amine, piperazine carboxylic acid and amide, to cooperate with each other.
  • the three substances produce a synergistic effect and can promote the absorption of H2S and organic sulfur in the acidic gas.
  • the higher the concentration of a certain amine the better the removal effect of the acidic gas. Too high an amine concentration will lead to a decrease in the dissociation degree of the solute in the desulfurizer, a decrease in the autotransfer constant of the desulfurizer, and difficulty in the dissociation of the amine, which is not conducive to the removal of the acidic gas.
  • R 1 and R 2 are substituent groups (the same below). Although the reaction rates of different alcohol amines and H 2 S are different, the reaction between them can be considered as an instantaneous proton reaction. The H 2 S entering the liquid phase is absorbed by the alcohol amine instantly. The reaction rate is much faster than the diffusion rate of gas phase H 2 S. The absorption process belongs to the gas film control process.
  • the desulfurizer of the present invention introduces an organic sulfur absorption promoter with a special structure, which can effectively reduce the activation energy of the reaction between the sterically hindered amine and the organic sulfur (COS), thereby accelerating the hydrolysis rate of COS and improving the desulfurization efficiency.
  • the removal rate of COS by the agent under low pressure makes the desulfurizer have the ability to remove COS significantly while maintaining excellent H 2 S removal performance.
  • an amide auxiliary agent is added to the desulfurizer of the present invention to improve its performance.
  • Amide compounds are a kind of non-protonic polar solvents, which have a physical dissolving effect on organic sulfur and hydrogen sulfide.
  • the amide selected in the present invention has a steric effect, and synergistically acts with the sterically hindered amine of the present invention, thereby increasing the hindering effect on CO2 and improving the selectivity.
  • a three-molecule reaction can occur between the amide auxiliary agent used in the present invention and COS and the sterically hindered amine used in the present invention, generating a complex body frozen by loose bonds, forming a three-molecule structure, thereby enhancing the removal of COS; the generated complex body exists instantaneously, and the complex body is regenerated by breaking the bonds when heated.
  • the desulfurizer is prepared by the following steps: adding the sterically hindered amine, the organic sulfur absorption promoter and the auxiliary agent into water according to the mass percentage of each component, and stirring for a period of time to obtain the desulfurizer.
  • the temperature at which the sterically hindered amine, the organic sulfur absorption accelerator and the auxiliary agent are added to water and stirred is 20 to 30°C.
  • the sterically hindered amine, the organic sulfur absorption accelerator and the auxiliary agent are added to water and stirred for 10 to 40 minutes.
  • the stirring speed is 30 to 50 r/min.
  • the second aspect of the present invention provides a method for preparing the above-mentioned desulfurizer for absorbing hydrogen sulfide and organic sulfur under normal pressure, which comprises the following steps: adding the sterically hindered amine, the organic sulfur absorption promoter and the auxiliary agent into water according to the mass percentage of each component, and stirring for a period of time to obtain the desulfurizer.
  • the temperature at which the sterically hindered amine, the organic sulfur absorption accelerator and the auxiliary agent are added to water and stirred is 20 to 30°C.
  • the sterically hindered amine, the organic sulfur absorption promoter and the auxiliary agent are added to water and stirred for 10 to 40 minutes.
  • the stirring speed is 30 to 50 r/min.
  • the third aspect of the present invention provides the use of the above-mentioned desulfurizing agent for absorbing hydrogen sulfide and organic sulfur under normal pressure as a desulfurizing agent for sulfur recovery hydrogenation tail gas in a natural gas purification plant and/or an oil refinery.
  • the desulfurizing agent provided by the invention can be used for deep and large-scale removal of H2S and organic sulfur in sulfur recovery hydrogenation tail gas in natural gas purification plants and oil refineries.
  • the desulfurizer provided by the present invention can reduce the H 2 S content in the purified gas to less than 10 mg/m 3 and achieve a removal rate of organic sulfur of more than 55% under typical gas conditions of sulfur recovery hydrogenation tail gas in refineries, achieving the excellent technical effect of deep removal of H 2 S and organic sulfur at normal pressure.
  • the inventors of the present invention conducted research from aspects such as promoting H 2 S absorption and strengthening COS hydrolysis, and developed the desulfurizing agent of the present invention.
  • the desulfurizer of the present invention adopts a sterically hindered amine with high steric hindrance effect and high pKa value, which not only increases the alkalinity of the desulfurizer, but also helps to enhance the ability of the desulfurizer to absorb H2S , and at the same time improves the selectivity of the desulfurizer, reduces the competitive absorption of CO2 by the desulfurizer, and increases the removal depth of H2S by the desulfurizer under low pressure; at the same time, an organic sulfur absorption promoter with a special structure is introduced, which can effectively reduce the activation energy of the reaction between the sterically hindered amine and COS, thereby accelerating the hydrolysis rate of COS, and improving the removal rate of COS by the desulfurizer under low pressure, so that the desulfurizer maintains excellent H
  • the desulfurizer provided by the present invention is a desulfurizer that absorbs H2S and organic sulfur under normal pressure, which solves the problem that conventional alcohol amine desulfurizers have poor removal effects on H2S and organic sulfur under low pressure, and is particularly suitable for the characteristics of low pressure, high temperature, high CO2 content, and organic form of COS in the hydrogenation tail gas of the sulfur recovery device, as a desulfurizer for sulfur recovery hydrogenation tail gas.
  • the desulfurizer of the present invention Compared with conventional desulfurizers, the desulfurizer of the present invention has a higher removal rate of H2S under normal pressure, and can effectively remove organic sulfur, while not completely removing CO2 , so it can reduce the acid gas load in the desulfurizer, thereby ensuring the removal of H2S and organic sulfur under low circulation conditions.
  • the desulfurizer of the present invention is suitable for desulfurizing hydrogenation tail gas of purification plants and refineries, and effectively reducing tail gas SO2 emissions.
  • FIG. 1 is a schematic diagram of the structure of a desulfurization effect evaluation device for a desulfurizer provided in an embodiment and a comparative example.
  • Gas mixing tank 1 gas preheating tank 2, absorption tower 3, purified gas separator 4, lean liquid preheating tank 5, lean liquid storage tank 6, lean liquid cooling tank 7, buffer tank 8, rich liquid preheating tank 9, regeneration tower 10 and acid gas separator 11.
  • This embodiment provides a desulfurizing agent for absorbing H 2 S and organic sulfur under normal pressure.
  • the desulfurizing agent comprises the following components by mass percentage: 30% 4-tert-butylamino-1-butanol, 10% 2-(1,4-dimethylpiperazine-2-yl)acetic acid, 10% N,N-dimethylacetamide, and 50% deionized water.
  • the desulfurizer is prepared by the following steps: according to the mass percentage of each component, 4-tert-butylamino-1-butanol, 2-(1,4-dimethylpiperazine-2-yl)acetic acid and N,N-dimethylacetamide are added to the mixture, and the mixture is stirred at 20-30° C. and 30-50 r/min for 10-40 minutes to obtain the desulfurizing agent.
  • the desulfurization effect of the desulfurizer of this embodiment was evaluated using the device shown in Figure 1.
  • the process parameters and evaluation results of 5 evaluation tests are shown in Table 1, wherein the temperature of the preheated raw gas is 25-28°C, the top temperature of the regeneration tower is controlled at 105°C, and the absorption tower packing height refers to the height of the lean liquid feed.
  • the desulfurization effect evaluation device mainly includes: a gas mixing tank 1, a gas preheating tank 2, an absorption tower 3, a purified gas separator 4, a lean liquid preheating tank 5, a lean liquid storage tank 6, a lean liquid cooling tank 7, a buffer tank 8, a rich liquid preheating tank 9, a regeneration tower 10 and an acid gas separator 11, etc.;
  • nitrogen or natural gas pipelines, hydrogen sulfide pipelines, carbon dioxide pipelines and organic sulfur pipelines from the outside are connected to the inlet of the gas mixing tank 1, and the outlet of the gas mixing tank 1 is connected to the inlet of the gas preheating tank 2 through pipelines; the raw gas for evaluation test is mixed in the gas mixing tank 1 and then enters the gas preheating tank 2 for preheating;
  • the outlet of the gas preheating tank 2 is connected to the raw gas inlet at the lower part of the absorption tower 3 through a pipeline, and the gas outlet at the top of the absorption tower 3 is connected to the inlet of the purified gas separator 4 through a pipeline;
  • the liquid outlet at the bottom of the absorption tower 3 is connected to the inlet of the rich liquid preheating tank 9 through a pipeline and the buffer tank 8, and the outlet of the rich liquid preheating tank 9 is connected to the inlet of the regeneration tower 10 through a pipeline
  • the liquid outlet at the bottom of the regeneration tower 10 is connected to the inlet of the lean liquid cooling tank 7 through a pipeline, and the gas outlet at the top of the regeneration tower 10 is connected to the acid gas separator 11 through a pipeline;
  • the outlet of the lean liquid cooling tank 7 is connected to the inlet of the lean liquid storage tank 6 through a pipeline, and the outlet of the lean liquid storage tank 6 is connected to the inlet of the lean liquid preheating tank 5 through a pipeline, and the le
  • the gas obtained after desulfurization flows out from the top of the absorption tower 3 and enters the purified gas separator 4 for separation to obtain purified gas;
  • the used desulfurizing agent flows out from the liquid outlet at the bottom of the absorption tower 3 and is preheated by the rich liquid preheating tank 9, and then enters the regeneration tower 10 for regeneration.
  • the gas generated after regeneration is separated by the acid gas separator 11 to obtain acid gas.
  • the liquid obtained after regeneration enters the lean liquid cooling tank 7, the lean liquid storage tank 6, and the lean liquid preheating tank 5 in turn, and then enters the absorption tower 3 again for recycling as a desulfurizing agent.
  • the regeneration tower, the absorption tower and other equipment are conventional in the art and can be commercially available.
  • the desulfurizer of this embodiment was evaluated using a lower gas-liquid ratio, a higher packing height and a higher regeneration tower top temperature.
  • the process parameters and evaluation results of 5 evaluation tests are shown in Table 2, wherein the regeneration tower top temperature was controlled at 107°C.
  • This embodiment provides a desulfurizing agent for absorbing H 2 S and organic sulfur under normal pressure.
  • the desulfurizing agent comprises the following components by mass percentage: 32% of 6-tert-butylamino-1-hexanol, 5% of (3-oxopiperazine-2-yl)acetic acid, 13% of N,N-dimethyl-2,2-dimethoxyacetamide, and 50% of deionized water.
  • the desulfurization effect of the desulfurizer of this embodiment was evaluated by using the device shown in Figure 1, wherein the absorption filler height was 1m, the lean liquid temperature was 39-40°C, the absorption was performed at normal pressure, the gas-liquid ratio was 100, and the other process parameters were the same as those in Table 1 of Example 1; the H2S content in the raw gas was 2.0%-2.3%, the CO2 content was 30-32%, the COS was 100-120mg/ m3 , and the mercaptan was 50-60mg/ m3 ; the H2S in the purified gas was 7-9mg/ m3 ; the CO2 removal rate was 8-12%, the COS removal rate was 62-71%, and the mercaptan removal rate was 39-42%.
  • This embodiment provides a desulfurizing agent for absorbing H 2 S and organic sulfur under normal pressure.
  • the desulfurizing agent includes the following components by mass percentage: 28% of 4-tert-butylamino-1-butanol, 11% of (3-oxo-1-piperazine)acetic acid, 9% of 2-amino-N-pyridin-3-yl-acetamide, and 52% of deionized water.
  • the desulfurization effect of the desulfurizer of this embodiment was evaluated by using the device shown in Figure 1, wherein the absorption filler height was 1m, the lean liquid temperature was 39-40°C, the absorption was performed at normal pressure, the gas-liquid ratio was 100, and the other process parameters were the same as those in Table 1 of Example 1; the H2S content in the raw gas was 2.0%-2.5%, the CO2 content was 28-32%, the COS was 100-120mg/ m3 , and the mercaptan was 50-60mg/ m3 ; the H2S in the purified gas was 3-7mg/ m3 ; the CO2 removal rate was 6-11%, the COS removal rate was 62-69%, and the mercaptan removal rate was 50-59%.
  • This comparative example provides a conventional N-methyldiethanolamine (MDEA) aqueous solution with a mass concentration of 50% as a desulfurizing agent.
  • MDEA N-methyldiethanolamine
  • the desulfurization effect of the desulfurizing agent of this comparative example is evaluated using the device shown in Figure 1.
  • the process parameters and evaluation results of 5 evaluation tests are shown in Table 3, wherein the temperature of the preheated raw gas is 25-28°C, and the temperature of the top of the regeneration tower is controlled at 105°C.
  • This comparative example provides a desulfurizer, which uses the sterically hindered amine and auxiliary agent of Example 1, but does not use an organic sulfur absorption promoter.
  • the desulfurizer includes the following components by mass percentage: 40% of 4-tert-butylamino-1-butanol, 10% of N,N-dimethylacetamide, and 50% of deionized water.
  • the desulfurization effect of the desulfurizer of this comparative example was evaluated by using the device shown in FIG1 , wherein the absorption filler height was 1 m, the lean liquid temperature was 39-40° C., the absorption was carried out at normal pressure, the gas-liquid ratio was 100, and the other process parameters were the same as those in Table 1 of Example 1; the H 2 S content in the raw gas was 2.0%-2.3%, the CO 2 content was 29-32%, the COS was 100-120 mg/m 3 , and the mercaptan was 50-55 mg/m 3 ; the H 2 S in the purified gas was 20-22 mg/m 3 ; the CO 2 removal rate was 5-7%, the COS removal rate was 13-18%, and the mercaptan removal rate was 26-30%.
  • This comparative example provides a desulfurizing agent, which comprises the following components by mass percentage: 35% of 4-tert-butylamino-1-butanol, 10% of N,N-dimethylacetamide, 5% of N,N-dihydroxyethylpiperazine, and 50% of deionized water.
  • the desulfurization effect of the desulfurizer of this comparative example was evaluated by using the device shown in FIG1 , wherein the absorption filler height was 1 m, the lean liquid temperature was 39-40° C., the absorption was carried out at normal pressure, the gas-liquid ratio was 100, and the other process parameters were the same as those in Table 1 of Example 1; the H 2 S content in the raw gas was 2.0%-2.3%, the CO 2 content was 29-32%, the COS content was 100-120 mg/m 3 , and the mercaptan content was 50-55 mg/m 3 ; the H 2 S content in the purified gas was 18-25 mg/m 3 ; the CO 2 removal rate was 17-22%, the COS removal rate was 10-13%, and the mercaptan removal rate was 29-33%.
  • This comparative example provides a desulfurizing agent, which includes the following components by mass percentage: 35% of 4-tert-butylamino-1-butanol, 10% of 2-(1,4-dimethylpiperazine-2-yl)acetic acid, 5% of piperazine, and 50% of deionized water.
  • the desulfurization effect of the desulfurizer of this comparative example was evaluated by using the device shown in FIG1 , wherein the absorption filler height was 1 m, the lean liquid temperature was 39-40° C., the absorption was carried out at normal pressure, the gas-liquid ratio was 100, and the other process parameters were the same as those in Table 1 of Example 1; the H 2 S content in the raw gas was 2.0%-2.3%, the CO 2 content was 29-32%, the COS was 100-120 mg/m 3 , and the mercaptan was 50-54 mg/m 3 ; the H 2 S in the purified gas was 87-93 mg/m 3 ; the CO 2 removal rate was 98%-99%, the COS removal rate was 48-55%, and the mercaptan removal rate was 34-40%.
  • MDEA has poor organic sulfur removal effect under normal pressure, and the organic sulfur removal rate is less than 8%.
  • Piperazine is a dibasic secondary amine, and its alkalinity is significantly stronger than MDEA. As an activator, piperazine can react quickly with COS. However, piperazine also brings the problem of reaction with CO2 , resulting in a significant increase in the acid gas load in the solution, which affects the removal effect of hydrogen sulfide. If H2S is to be deeply removed at the same time, the circulation volume needs to be greatly increased.
  • the desulfurizer of the present invention adopts a sterically hindered amine with a high steric hindrance effect and a high pKa value, which not only increases the alkalinity of the desulfurizer, which is conducive to enhancing the ability of the desulfurizer to absorb H 2 S, but also improves the selectivity of the desulfurizer, reduces the competitive absorption of CO 2 by the desulfurizer, and increases the removal depth of H 2 S by the desulfurizer under low pressure.
  • the desulfurizer of the present invention introduces an organic sulfur absorption promoter with a special structure, which can effectively reduce the activation energy of the reaction between the sterically hindered amine and COS, thereby accelerating the hydrolysis rate of COS and improving the removal rate of COS by the desulfurizer under low pressure, so that the desulfurizer maintains excellent H 2 S removal performance while also having a significant ability to remove COS.
  • an amide auxiliary agent is added to the desulfurizer of the present invention to improve its performance.
  • Amide compounds are a kind of non-protonic polar solvents that have a physical dissolving effect on organic sulfur and hydrogen sulfide.
  • the amide selected in the present invention has a steric hindrance effect, which synergizes with the sterically hindered amine of the present invention, increases the hindering effect on CO 2 , and improves the selectivity.
  • a three-molecule reaction can occur between the amide additives used in the present invention, COS, and the sterically hindered amine used in the present invention.
  • the reaction generates a complex body frozen by loose bonds, forming a three-molecule structure, thereby enhancing the removal of COS; the generated complex body exists instantaneously, and when heated, the complex body breaks the bonds and regenerates.
  • the desulfurizer of the present invention will not completely remove CO 2 , so it can reduce the acid gas load in the desulfurizer, thereby ensuring the removal of hydrogen sulfide under low circulation volume and normal pressure conditions, and can also effectively remove organic sulfur.

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Abstract

本发明提供了一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用。该脱硫剂包括：20～35％空间位阻胺、5～20％有机硫吸收促进剂、5～20％助剂以及水余量，有机硫吸收促进剂包括哌嗪基羧酸类化合物，助剂包括酰胺类化合物。该脱硫剂的制备方法包括：按照各组分的质量百分比，在水中加入空间位阻胺、有机硫吸收促进剂以及助剂并搅拌后，得到该脱硫剂。本发明的脱硫剂在常压下对H2S的脱除率高，并且可以有效脱除有机硫，同时不会完全脱除CO2，故可以降低脱硫剂中酸气负荷。

Description

一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用 技术领域
本发明涉及一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用，属于脱硫技术领域。
背景技术
在醇胺法天然气净化装置中，主要包括脱硫、脱水、硫磺回收和尾气处理等部分，其中尾气处理部分对于提高硫的收率，保护环境具有重要的作用。目前主要有还原吸收、还原直接转化、氧化吸收等尾气处理工艺。其中还原吸收法尾气处理工艺应用最为广泛，目前大型天然气净化厂和炼油厂的硫磺回收装置大都设有还原吸收法尾气处理装置。该工艺目前主要采用醇胺脱硫剂对加氢后的硫磺回收尾气进行处理。
硫磺回收加氢尾气中均含有一定量的有机硫，其含量通常在10ppm以上，有的装置甚至达到50ppm以上。由于硫磺回收加氢尾气压力非常低，接近常压，因此现用的常规醇胺脱硫剂对加氢尾气中H2S和有机硫的脱除效果差，净化尾气中H2S含量通常在100mg/m3以上，对有机硫(COS)的脱除率通常只有5％～10％。这不仅造成硫磺回收率的降低，而且也导致排放尾气中的SO2含量升高，对环境造成污染。随着环保相关规定的日益严格，对排放尾气中的SO2含量要求越来越低。如GB 31570-2015规定：一般地区酸性气回收装置SO2的排放限值为400mg/m3，特别敏感地区排放限值为100mg/m3。因此，必须开发新的技术，解决常规的醇胺脱硫剂在低压下对H2S和有机硫的脱除效果差的问题，以实现尾气SO2的超低排放，达到保护环境的目的。
发明内容
为解决上述技术问题，本发明的目的在于提供一种常压下吸收硫化氢和有机硫的脱硫剂及其制备方法与应用。本发明的脱硫剂在常压下对H2S的脱除率高，并且可以有效脱除有机硫，同时不会完全脱除CO2，故可以降低脱硫剂中酸气负荷。
为了实现上述目的，本发明第一方面提供了一种常压下吸收硫化氢和有机硫的脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：20～35％的空间位阻胺、5～20％的有机硫吸收促进剂、5～20％的助剂以及水余量；
其中，所述有机硫吸收促进剂包括哌嗪基羧酸类化合物；所述助剂包括酰胺类化合物。
在上述的脱硫剂中，优选地，所述空间位阻胺包括4-叔丁胺基-1-丁醇、5-叔丁胺基-1-戊醇以及6-叔丁胺基-1-己醇等中的一种或几种的组合。
在上述的脱硫剂中，优选地，所述有机硫吸收促进剂包括2-(1,4-二甲基哌嗪-2-基)乙酸、(3-氧代-1-哌嗪)乙酸以及(3-氧代哌嗪-2-基)乙酸等中的一种或几种的组合。
在上述的脱硫剂中，优选地，所述助剂包括N,N-二甲基乙酰胺、N,N-二甲基-2,2-二甲氧基乙酰胺以及2-氨基-N-吡啶-3-基-乙酰胺等中的一种或几种的组合。
在上述的脱硫剂中，优选地，以所述脱硫剂的总质量为100％计，其中的水的含量为20％以上。
本发明的脱硫剂使用空间位阻胺、哌嗪基羧酸、酰胺三种物质相互配合，三者之间产生协同作用，可相互促进酸性气体中的H2S、有机硫的吸收。但并非某一种胺的浓度越高对酸性气体的脱除效果越好。胺浓度过高会导致脱硫剂中溶质的离解程度降低，脱硫剂的自递常数变小，胺的离解变得困难，反而不利于酸性气体的脱除。
本发明的脱硫剂所采用的空间位阻胺为仲醇胺，它们对原料气H2S的吸收反应过程为：
R1R2NH(空间位阻胺)+H2S＝R1R2NH2 ++HS-         (1-1)
其中R1、R2为取代基团(下同)，虽然不同醇胺与H2S的反应速率有所差别，但它们之间的反应都可认为是瞬间质子反应，进入液相的H2S均在瞬间被醇胺吸收，其反应速率比气相H2S的扩散速率快得多，吸收过程属于气膜控制过程。
本发明所采用的空间位阻胺对CO2的吸收反应过程主要为：
H2O＝H++OH-                                    (1-2)
CO2+H2O＝HCO3-+H+                             (1-3)
CO2+OH-＝HCO3-                                 (1-4)
R1R2NH(空间位阻胺)+H+＝R1R2NH2+               (1-5)
R1R2NH(空间位阻胺)+HCO3-＝R1R2NCOO-+H2O     (1-6)
总反应方程式：
2R1R2NH(空间位阻胺)+CO2＝R1R2NH2++R1R2NCOO-  (1-7)
空间位阻胺对CO2的吸收反应过程较为复杂，空间位阻胺与CO2反应由于受到基团空间位阻的影响，形成的＝NCOO-基团稳定性较差。根据双膜理论，式(1-7)反应受液膜控制，因此其选择性脱硫性能优于醇胺(MDEA)。
空间位阻胺吸收H2S和CO2的反应均是可逆反应，在较低的温度及较高的压力下反应向右进行，而在较高的温度及较低的压力下反应则向左进行。
本发明的脱硫剂另一方面引入了具有特殊结构的有机硫吸收促进剂，可有效降低空间位阻胺与有机硫(COS)反应的活化能，从而加快了COS的水解速率，提高了脱硫 剂在低压下对COS的脱除率，使脱硫剂在保持优良脱除H2S性能的同时，又兼具明显的脱除COS的能力。
并且，本发明的脱硫剂中还加入了酰胺类助剂，以改善其性能。酰胺类化合物是一种非质子极性溶剂，对有机硫和硫化氢具有物理溶解的作用。且本发明中所选用的酰胺具有位阻效应，与本发明的空间位阻胺协同作用，增加了对CO2的阻碍作用，提高了选择性。同时，本发明所采用的酰胺类助剂与COS以及本发明所采用的空间位阻胺之间，可发生三分子反应，生成由疏松键冻结的络合体，构成一种三分子结构，从而加强脱除COS；生成的络合体瞬时存在，加热时络合体成键断裂而再生。
根据本发明的具体实施方式，优选地，所述的脱硫剂是通过以下步骤制备得到的：按照各组分的质量百分比，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂，并搅拌一段时间后，得到所述的脱硫剂。
其中，更优选地，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的温度为20～30℃。
更优选地，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的时间为10～40分钟。
更优选地，所述搅拌的转速为30～50r/min。
本发明第二方面提供了一种上述的常压下吸收硫化氢和有机硫的脱硫剂的制备方法，其包括以下步骤：按照各组分的质量百分比，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂，并搅拌一段时间后，得到所述的脱硫剂。
在上述的制备方法中，优选地，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的温度为20～30℃。
在上述的制备方法中，优选地，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的时间为10～40分钟。
在上述的制备方法中，优选地，所述搅拌的转速为30～50r/min。
本发明第三方面提供了上述的常压下吸收硫化氢和有机硫的脱硫剂作为天然气净化厂和/或炼油厂的硫磺回收加氢尾气的脱硫剂的应用。
本发明提供的脱硫剂可用于天然气净化厂和炼油厂的硫磺回收加氢尾气中H2S、有机硫的深度和大量脱除。
与现有技术相比，本发明提供的脱硫剂在炼油厂硫磺回收加氢尾气的典型气质条件下，可使净化气中H2S含量＜10mg/m3，对有机硫的脱除率＞55％，达到了常压下即可深度脱除H2S又可脱除有机硫的优异技术效果。
本发明的发明人从促进H2S吸收，加强COS水解等方面进行研究，研发了本发明的脱硫剂。本发明的脱硫剂采用空间位阻效应高、pKa值较高的空间位阻胺，既增加了脱硫剂的碱性，有利于增强脱硫剂吸收H2S的能力，同时又提高了脱硫剂的选择性，降低了脱硫剂对CO2的竞争吸收，增加了脱硫剂在低压下对H2S的脱除深度；同时引入了具有特殊结构的有机硫吸收促进剂，可有效降低空间位阻胺与COS反应的活化能，从而加快了COS的水解速率，提高了脱硫剂在低压下对COS的脱除率，使脱硫剂在保持优良脱除H2S性能的同时，又兼具明显的脱除COS的能力；还引入了酰胺类助剂，其对有机硫和硫化氢具有物理溶解的作用，且本发明中所选用的酰胺具有位阻效应，与本发明的空间位阻胺协同作用，增加了对CO2的阻碍作用，进一步提高了脱硫剂的选择性，同时加强了COS的脱除。因此，本发明提供的脱硫剂是一种常压下吸收H2S和有机硫的脱硫剂，其解决了常规醇胺脱硫剂在低压下对H2S和有机硫脱除效果差的问题，尤其适合于硫磺回收装置加氢尾气压力低、温度高、CO2含量高、有机形态主要为COS的气质特点，作为硫磺回收加氢尾气的脱硫剂。与常规的脱硫剂相比较，本发明的脱硫剂在常压下对H2S的脱除率更高，并且可以有效脱除有机硫，同时不会完全脱除CO2，故可以降低脱硫剂中酸气负荷，从而在低循环量条件下保障H2S和有机硫的脱除。本发明的脱硫剂适用于对净化厂及炼厂的加氢尾气进行脱硫，有效降低尾气SO2排放。
附图说明
图1为实施例和对比例提供的脱硫剂的脱硫效果评价装置的结构示意图。
附图标号说明：
气体混合罐1、气体预热罐2、吸收塔3、净化气分离器4、贫液预热罐5、贫液贮罐6、贫液冷却罐7、缓冲罐8、富液预热罐9、再生塔10以及酸气分离器11。
具体实施方式
为了对本发明的技术特征、目的和有益效果有更加清楚的理解，现对本发明的技术方案进行以下详细说明，但不能理解为对本发明的可实施范围的限定。
实施例1
本实施例提供了一种常压下吸收H2S和有机硫的脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：4-叔丁胺基-1-丁醇30％，2-(1,4-二甲基哌嗪-2-基)乙酸10％，N,N-二甲基乙酰胺10％，以及去离子水50％。
所述的脱硫剂是通过以下步骤制备得到的：按照各组分的质量百分比，在去离子水 中加入4-叔丁胺基-1-丁醇、2-(1,4-二甲基哌嗪-2-基)乙酸以及N,N-二甲基乙酰胺，并在20～30℃以30～50r/min的转速搅拌10～40分钟后，得到所述的脱硫剂。
采用图1所示的装置对本实施例的脱硫剂的脱硫效果进行评价，5次评价试验的工艺参数和评价结果如表1所示，其中，预热后的原料气温度为25～28℃，再生塔塔顶温度控制在105℃，吸收塔填料高度是指贫液进料的高度。
如图1所示，脱硫效果评价装置主要包括：气体混合罐1、气体预热罐2、吸收塔3、净化气分离器4、贫液预热罐5、贫液贮罐6、贫液冷却罐7、缓冲罐8、富液预热罐9、再生塔10以及酸气分离器11等；
其中，来自外界的氮气或天然气管线、硫化氢管线、二氧化碳管线以及有机硫管线连接于所述气体混合罐1的入口，所述气体混合罐1的出口通过管线连接于所述气体预热罐2的入口；进行评价试验的原料气在气体混合罐1中混合后，进入气体预热罐2进行预热；
所述气体预热罐2的出口通过管线连接于所述吸收塔3下部的原料气入口，所述吸收塔3塔顶的气体出口通过管线连接于所述净化气分离器4的入口；所述吸收塔3塔底的液体出口通过管线与所述缓冲罐8连接于所述富液预热罐9的入口，所述富液预热罐9的出口通过管线连接于所述再生塔10的入口，所述再生塔10塔底的液体出口通过管线连接于所述贫液冷却罐7的入口，所述再生塔10塔顶的气体出口通过管线连接于所述酸气分离器11；所述贫液冷却罐7的出口通过管线连接于所述贫液贮罐6的入口，所述贫液贮罐6的出口通过管线连接于所述贫液预热罐5的入口，所述贫液预热罐5的出口通过管线连接于所述吸收塔3的脱硫剂入口；预热后的原料气从吸收塔3的下部进入吸收塔3，脱硫剂经贫液预热罐5进行预热后进入吸收塔3，预热后的原料气自下而上与预热后的脱硫剂接触并反应后，脱硫后得到的气体从吸收塔3塔顶流出并进入净化气分离器4进行分离后，得到净化气；使用后的脱硫剂从吸收塔3塔底的液体出口流出并经过富液预热罐9进行预热后，进入再生塔10进行再生，再生后产生的气体经酸气分离器11进行分离后得到酸气，再生后得到的液体依次进入贫液冷却罐7、贫液贮罐6、贫液预热罐5后，再次进入吸收塔3作为脱硫剂循环使用。其中，再生塔、吸收塔等设备均为本领域常规的，均可商购获得。
表1实施例1的脱硫剂脱除H2S和有机硫试验数据

采用更低的气液比、更高的填料高度以及更高的再生塔顶温度，对本实施例的脱硫剂进行评价，5次评价试验的工艺参数和评价结果如表2所示，其中再生塔塔顶温度控制在107℃。
表2实施例1的脱硫剂脱除H2S和有机硫试验数据

实施例2
本实施例提供了一种常压下吸收H2S和有机硫的脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：6-叔丁胺基-1-己醇32％，(3-氧代哌嗪-2-基)乙酸5％，N,N-二甲基-2,2-二甲氧基乙酰胺13％，以及去离子水50％。
采用图1所示的装置对本实施例的脱硫剂的脱硫效果进行评价，其中，吸收填料高度为1m，贫液温度为39～40℃，常压吸收，气液比为100，其他工艺参数与实施例1的表1中工艺参数相同；原料气中H2S含量为2.0％～2.3％，CO2含量为30～32％，COS为100～120mg/m3，硫醇为50～60mg/m3；净化气中的H2S为7～9mg/m3；CO2脱除率为8～12％，COS脱除率为62～71％，硫醇脱除率为39～42％。
实施例3
本实施例提供了一种常压下吸收H2S和有机硫的脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：4-叔丁胺基-1-丁醇28％，(3-氧代-1-哌嗪)乙酸11％，2-氨基-N-吡啶-3-基-乙酰胺9％，以及去离子水52％。
采用图1所示的装置对本实施例的脱硫剂的脱硫效果进行评价，其中，吸收填料高度为1m，贫液温度为39～40℃，常压吸收，气液比为100，其他工艺参数与实施例1的表1中工艺参数相同；原料气中H2S含量为2.0％～2.5％，CO2含量为28～32％，COS为100～120mg/m3，硫醇为50～60mg/m3；净化气中的H2S为3～7mg/m3；CO2脱除率为6～11％，COS脱除率为62～69％，硫醇脱除率为50～59％。
对比例1
本对比例提供了常规的质量浓度为50％的N-甲基二乙醇胺(MDEA)水溶液作为脱硫剂。采用图1所示的装置对本对比例的脱硫剂的脱硫效果进行评价，5次评价试验的工艺参数和评价结果如表3所示，其中，预热后的原料气温度为25～28℃，再生塔塔顶温度控制在105℃。
表3 MDEA水溶液脱除H2S和有机硫试验数据
由表1和表3可以看出，在同等评价条件下，本发明的脱硫剂对H2S和有机硫的脱除情况远优于MDEA。
对比例2
本对比例提供了一种脱硫剂，其采用实施例1的空间位阻胺和助剂，但不采用有机硫吸收促进剂。以质量百分比计，所述脱硫剂包括以下组分：4-叔丁胺基-1-丁醇40％，N,N-二甲基乙酰胺10％，以及去离子水50％。
采用图1所示的装置对本对比例的脱硫剂的脱硫效果进行评价，其中，吸收填料高度为1m，贫液温度为39～40℃，常压吸收，气液比为100，其他工艺参数与实施例1的表1中工艺参数相同；原料气中H2S含量为2.0％～2.3％，CO2含量为29～32％，COS为100～120mg/m3，硫醇为50～55mg/m3；净化气中的H2S为20～22mg/m3；CO2脱除率为5～7％，COS脱除率为13～18％，硫醇脱除率为26～30％。
对比例3
本对比例提供了一种脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：4-叔丁胺基-1-丁醇35％，N,N-二甲基乙酰胺10％，N,N-二羟乙基哌嗪5％，以及去离子水50％。
采用图1所示的装置对本对比例的脱硫剂的脱硫效果进行评价，其中，吸收填料高度为1m，贫液温度为39～40℃，常压吸收，气液比为100，其他工艺参数与实施例1的表1中工艺参数相同；原料气中H2S含量为2.0％～2.3％，CO2含量为29～32％，COS为100～120mg/m3，硫醇为50～55mg/m3；净化气中的H2S为18～25mg/m3；CO2脱除率为17～22％，COS脱除率为10～13％，硫醇脱除率为29～33％。
对比例4
本对比例提供了一种脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：4-叔丁胺基-1-丁醇35％，2-(1,4-二甲基哌嗪-2-基)乙酸10％，哌嗪5％，以及去离子水50％。
采用图1所示的装置对本对比例的脱硫剂的脱硫效果进行评价，其中，吸收填料高度为1m，贫液温度为39～40℃，常压吸收，气液比为100，其他工艺参数与实施例1的表1中工艺参数相同；原料气中H2S含量为2.0％～2.3％，CO2含量为29～32％，COS为100～120mg/m3，硫醇为50～54mg/m3；净化气中的H2S为87～93mg/m3；CO2脱除率为98％～99％，COS脱除率为48～55％，硫醇脱除率为34～40％。
由上述的实施例和对比例可以看出，MDEA常压下对有机硫脱除效果差，有机硫脱除率＜8％；哌嗪是一种二元仲胺，碱性明显要强于MDEA。哌嗪作为一种活化剂，与COS可以快速反应。但是哌嗪同样会带来与CO2反应的问题，导致溶液中酸气负荷大大增加，影响硫化氢的脱除效果。若要同时深度脱除H2S，则需大大提高循环量。
而本发明的脱硫剂采用空间位阻效应高、pKa值较高的空间位阻胺，既增加了脱硫剂的碱性，有利于增强脱硫剂吸收H2S的能力，同时又提高了脱硫剂的选择性，降低了脱硫剂对CO2的竞争吸收，增加了脱硫剂在低压下对H2S的脱除深度。而且，本发明的脱硫剂引入了具有特殊结构的有机硫吸收促进剂，可有效降低空间位阻胺与COS反应的活化能，从而加快了COS的水解速率，提高了脱硫剂在低压下对COS的脱除率，使脱硫剂在保持优良脱除H2S性能的同时，又兼具明显的脱除COS的能力。并且，本发明的脱硫剂中还加入了酰胺类助剂，以改善其性能。酰胺类化合物是一种非质子极性溶剂，对有机硫和硫化氢具有物理溶解的作用。且本发明中所选用的酰胺具有位阻效应，与本发明的空间位阻胺协同作用，增加了对CO2的阻碍作用，提高了选择性。同时，本发明所采用的酰胺类助剂与COS以及本发明所采用的空间位阻胺之间，可发生三分子 反应，生成由疏松键冻结的络合体，构成一种三分子结构，从而加强脱除COS；生成的络合体瞬时存在，加热时络合体成键断裂而再生。因此，本发明脱硫剂不会完全脱除CO2，故可以降低脱硫剂中的酸气负荷，从而在低循环量、常压条件下保障硫化氢的脱除，还可以有效脱除有机硫。

Claims (10)

  1. 一种常压下吸收硫化氢和有机硫的脱硫剂，以质量百分比计，所述脱硫剂包括以下组分：20～35％的空间位阻胺、5～20％的有机硫吸收促进剂、5～20％的助剂以及水余量；
    其中，所述有机硫吸收促进剂包括哌嗪基羧酸类化合物；所述助剂包括酰胺类化合物。
  2. 根据权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂，其中，所述空间位阻胺包括4-叔丁胺基-1-丁醇、5-叔丁胺基-1-戊醇以及6-叔丁胺基-1-己醇中的一种或几种的组合。
  3. 根据权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂，其中，所述有机硫吸收促进剂包括2-(1,4-二甲基哌嗪-2-基)乙酸、(3-氧代-1-哌嗪)乙酸以及(3-氧代哌嗪-2-基)乙酸中的一种或几种的组合。
  4. 根据权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂，其中，所述助剂包括N,N-二甲基乙酰胺、N,N-二甲基-2,2-二甲氧基乙酰胺以及2-氨基-N-吡啶-3-基-乙酰胺中的一种或几种的组合。
  5. 根据权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂，其中，所述的脱硫剂是通过以下步骤制备得到的：按照各组分的质量百分比，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂，并搅拌一段时间后，得到所述的脱硫剂。
  6. 一种权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂的制备方法，其包括以下步骤：按照各组分的质量百分比，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂，并搅拌一段时间后，得到所述的脱硫剂。
  7. 根据权利要求6所述的制备方法，其中，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的温度为20～30℃。
  8. 根据权利要求6所述的制备方法，其中，在水中加入所述空间位阻胺、所述有机硫吸收促进剂以及所述助剂并搅拌的时间为10～40分钟。
  9. 根据权利要求6所述的制备方法，其中，所述搅拌的转速为30～50r/min。
  10. 权利要求1所述的常压下吸收硫化氢和有机硫的脱硫剂作为天然气净化厂和/或炼油厂的硫磺回收加氢尾气的脱硫剂的应用。
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