Natural gas selective desulfurization solvent system, and preparation method therefor and desulfurization method therefor

Abstract

Provided in the present invention are a natural gas selective desulfurization solvent system, and a preparation method therefor and a desulfurization method therefor. The natural gas selective desulfurization solvent system comprises a basic solvent, a bicyclic amine component and an isoamyl secondary amine component, wherein the isoamyl secondary amine component has a structure as represented by formula I: in formula I, R1, R2 and R3 are each independently selected from H, a C1-C5 alkyl and a derivative thereof; and the bicyclic amine component has a structure as represented by formula II or formula III. The natural gas selective desulfurization solvent system can be used for the deep removal of hydrogen sulfide and thiol from natural gas, while reserving carbon dioxide in purified gas to the maximum possible extent and improving the commodity gas rate and the acid gas concentration.

Description

A natural gas selective desulfurization solvent system and its preparation method and desulfurization method Technical Field

[0001] The present invention belongs to the technical field of natural gas desulfurization, and in particular relates to a natural gas selective desulfurization solvent system and a preparation method and a desulfurization method thereof. Background Art

[0002] Natural gas mostly contains acidic components such as hydrogen sulfide, carbon dioxide, and organic sulfur (carbonyl sulfide, mercaptans, and sulfides). The concentration of organic sulfur in sour natural gas is mostly below 1000ppm. Compared with hydrogen sulfide and carbon dioxide, organic sulfur has a low concentration, low partial pressure, and weak mass transfer driving force. At the same time, organic sulfur has low sulfuric acidity and is difficult to react chemically with alkaline solvents. GB17820-2018 "Natural Gas" sets index requirements for natural gas entering the long-distance pipeline network, which stipulates that the purified gas H2S ≤ 6mg / m 3 , CO2≤3%, total sulfur≤20mg / m 3 , which mainly makes strict requirements on hydrogen sulfide and total sulfur.

[0003] For organic sulfur in raw gas, especially mercaptan content exceeding 500mg / m 3 In this case, it is difficult for the existing desulfurization technology to achieve total sulfur ≤ 20mg / m 3 In addition, existing solvents need to remove almost all carbon dioxide when removing hydrogen sulfide and mercaptans, resulting in low acid gas concentration in the sulfur recovery unit, high solution acid gas load, increased circulation volume, increased steam consumption, and increased operating energy consumption. Summary of the Invention

[0004] In order to solve the above problems, the purpose of the present invention is to provide a natural gas selective desulfurization solvent system and its preparation method and desulfurization method, which can be used to deeply remove hydrogen sulfide and mercaptans from natural gas, while maximally retaining carbon dioxide in the purified gas, thereby increasing the commercial gas rate and acid gas concentration.

[0005] In order to achieve the above object, the present invention provides a natural gas selective desulfurization solvent system, which comprises a base solvent, a bicyclic amine component and an isopentyl secondary amine component, wherein the isopentyl secondary amine component has a structure shown in Formula I:

[0006] In Formula I, R 1 、R 2 、R 3 Each independently selected from H, C1-C5 alkyl and derivatives thereof; the bicyclic amine component has a structure shown in Formula II or Formula III:

[0007] The two ends of the molecular structure of the isopentyl secondary amine component of the present invention all have amino groups with active hydrogen atoms, and the solvent has strong alkalinity, can chemically react with hydrogen sulfide and mercaptan, reach good removal effect, and improve removal depth. Under this alkaline condition, conventional solvents will also remove CO in a large number , but there is isopentyl in the isopentyl secondary amine molecular structure of the present invention, and isopentyl is a steric hindered group with extremely strong steric hindrance effect. Two isopentyl groups are introduced in the isopentyl secondary amine molecular structure of the present invention, to CO Produce hindering effect, can reduce CO under high alkalinity condition Removal. Secondly, this isopentyl secondary amine contains a hydroxyl, and is highly water-soluble. The dicyclic amine component in the desulfurization solvent system helps to provide the required H ion of nucleophilic substitution reaction, and under the strongly alkaline condition that the isopentyl secondary amine provides, the-NH in the dicyclic amine The nitrogen atom in the group attacks the sulphur atom in the mercaptan, and nucleophilic reaction occurs, and sulphur atom and nitrogen atom generate thiourea radical, which can realize the deep removal of mercaptan.

[0008] According to a specific embodiment of the present invention, preferably, in Formula I, R 1 、R 2 、R 3 Each is independently selected from H, methyl, and ethyl.

[0009] According to a specific embodiment of the present invention, preferably, the base solvent comprises water.

[0010] According to a specific embodiment of the present invention, preferably, based on the mass of the natural gas selective desulfurization solvent system being 100%, the composition of the natural gas selective desulfurization solvent system includes 20%-50% of isopentyl secondary amine components, 5%-10% of bicyclic amine components, and the remainder is base solvent.

[0011] According to a specific embodiment of the present invention, preferably, the composition of the natural gas selective desulfurization solvent system further includes an ether component.

[0012] According to a specific embodiment of the present invention, preferably, the ether component includes diethylene glycol ethyl ether and / or triethylene glycol ethyl ether.

[0013] Ether components play a dual role in the desulfurization solvent system. On the one hand, ether solvents have a greater solubility for organic sulfur than water, which helps dissolve organic sulfur. On the other hand, both water and ether are neutral solvents. The autotransfer constant and dielectric constant of the solvent itself determine the ease with which the compound dissociates in it. A large dielectric constant can weaken the attraction between opposite charges, which helps the compound dissociate in the solvent. Water autotransfer constant: K 自 =[OH - ][H + ]=10 -14 mol·L -2, the dielectric constant is 78.39. The dielectric constant of ether solvents is less than 10, which is much smaller than the dielectric constant of water. Therefore, amine compounds are easy to dissociate in water, but not easy to dissociate in ether compounds. The present invention adds an ether solvent to isopentyl secondary amine to reduce the dissociation of isopentyl secondary amine to a certain extent, thereby reducing the concentration of amine ions in the solution. Compared with carbon dioxide, hydrogen sulfide is more acidic and more likely to react with amines. When the concentration of amine ions in the solution is reduced, it will first react with H2S and then with CO2. Therefore, the concentration of amine ions is reduced and the removal rate of CO2 by the solvent is reduced. After the ether compound is added to the solvent system, it not only plays a role in improving the removal rate of organic sulfur, but also plays a role in improving selectivity and reducing the removal rate of CO2 under the synergistic effect with isopentyl secondary amine, achieving unexpected results.

[0014] According to a specific embodiment of the present invention, preferably, based on the mass of the natural gas selective desulfurization solvent system as 100%, the composition of the natural gas selective desulfurization solvent system includes 20%-50% of isopentyl secondary amine components, 5%-10% of bicyclic amine components, 10%-40% of ether components, and the balance is base solvent.

[0015] The present invention also provides a method for preparing the above-mentioned natural gas selective desulfurization solvent system, which comprises the following steps: mixing the components at 20-30° C. at 30-50 r / min for 10-40 minutes.

[0016] The present invention also provides a natural gas selective desulfurization method, comprising the following steps: contacting the natural gas to be desulfurized with the natural gas selective desulfurization solvent system for desulfurization treatment, and then separating the desulfurized natural gas.

[0017] According to a specific embodiment of the present invention, preferably, the method for selective desulfurization of natural gas comprises the following steps:

[0018] (1) compressing the natural gas to be desulfurized to a predetermined pressure, and then entering an absorption tower, where the natural gas is countercurrently contacted with the natural gas selective desulfurization solvent system inside the absorption tower for desulfurization, thereby obtaining desulfurized natural gas and rich liquid;

[0019] (2) The rich liquid is subjected to pressure reduction, flash evaporation, and analysis to separate natural gas;

[0020] (3) The rich liquid obtained after the analytical treatment enters the regeneration tower for regeneration treatment;

[0021] (4) The lean liquid obtained after the regeneration treatment enters the absorption tower circulation step (1).

[0022] According to a specific embodiment of the present invention, preferably, the conditions of the natural gas selective desulfurization method meet one or a combination of two or more of the following conditions (1) to (5):

[0023] (1) The predetermined pressure is 2-7 MPa;

[0024] (2) The flow rate of the natural gas to be desulfurized entering the absorption tower is 400-2500 L / h;

[0025] (3) The temperature of the natural gas selective desulfurization solvent system is 18-40° C.;

[0026] (4) The circulation rate of the natural gas selective desulfurization solvent system is 1.0-2.5 L / h;

[0027] (5) The packing height of the absorption tower is 0.75-1.5m.

[0028] According to a specific embodiment of the present invention, preferably, the mercaptan content of the desulfurized raw gas is ≥500 mg / m 3 .

[0029] The present invention has the following beneficial effects:

[0030] (1) The isopentyl secondary amine in the natural gas selective desulfurization solvent system of the present invention has a strong steric hindrance effect on CO2, which can improve the removal effect of hydrogen sulfide; it contains two secondary amine groups, provides active H atoms, and the solvent has strong alkalinity, which can react chemically with hydrogen sulfide and mercaptans to achieve the purpose of deep removal of hydrogen sulfide and organic sulfur;

[0031] (2) The nitrogen atom in the -NH2 group of the dicyclic amine in the natural gas selective desulfurization solvent system of the present invention attacks the sulfur atom in the mercaptan with the help of the H ion provided by the isopentyl secondary amine, resulting in a nucleophilic reaction to generate a thiourea group, thereby further improving the removal depth of the mercaptan;

[0032] (3) The ether compound in the natural gas selective desulfurization solvent system of the present invention, on the one hand, improves the solubility of the solvent for organic sulfur, and on the other hand, reduces the concentration of amine ions ionized by isopentyl secondary amine, thereby reducing the absorption of CO2 and helping to retain CO2 in the purified gas;

[0033] (4) The natural gas selective desulfurization solvent system of the present invention can selectively remove hydrogen sulfide and mercaptans from the raw gas and minimize the absorption of carbon dioxide. It is suitable for raw gas mainly composed of mercaptans, especially mercaptans up to 500 mg / m 3 The above temperament. BRIEF DESCRIPTION OF THE DRAWINGS

[0034] Figure 1 is a process flow chart of the desulfurization effect evaluation device.

[0035] Figure 2 is the NMR spectrum of isopentyl secondary amine. DETAILED DESCRIPTION

[0036] In order to have a clearer understanding of the technical features, objectives and beneficial effects of the present invention, the technical solution of the present invention is now described in detail below, but it should not be understood as limiting the scope of implementation of the present invention.

[0037] The following evaluation method for removing hydrogen sulfide, carbon dioxide, and mercaptans is shown in Figure 1. The process flow of the desulfurization evaluation device is as follows: Natural gas, H2S, CO2, and organic sulfur are mixed in a mixing tank and then compressed by a compressor to the required test pressure. The purified gas exiting the top of the absorption tower is separated in a separator and measured by a gas meter. The rich liquid exiting the bottom of the absorption tower is flashed in a rich liquid flash tank and preheated in a preheating tank before entering the regeneration tower for regeneration. The regenerated lean liquid is pumped into the absorption tower for recycling. Sampling is performed and the components of the raw gas and purified gas are analyzed by chromatography. Purified natural gas at a pressure of 6 MPa and a temperature of 20°C is mixed with H2S, CO2, and organic sulfur from gas cylinders in a feed gas mixing tank before entering a feed gas preheating tank. The feed gas is compressed to the test pressure by a natural gas compressor and then enters the bottom of the absorption tower. The natural gas flows upward at a rate of 400 L / h, coming into contact with the desulfurization solution flowing downward. The desulfurization solution enters the absorption tower at a packing height of 1.0 meter. The lean liquid temperature is 40°C, and the circulation rate is 2.0 L / h, removing H2S, CO2, and organic sulfur. The lean liquid enters the absorption tower through the lean liquid inlet. The purified natural gas, free of all H2S and some CO2, flows from the top of the tower, passes through a purified gas separator to separate any entrained liquid droplets, and then enters the natural gas pressure regulating device. After being depressurized, it returns to the intake system. The rich liquid flowing from the bottom of the absorber is depressurized to 0.5-0.6 MPa by a level control valve and then enters a flash tank. Partially dissolved natural gas flashes out of the rich liquid in the flash tank. The rich liquid then enters a rich liquid preheater, where it is heated to 90°C. It then enters the upper portion of the regeneration tower. The rich liquid flows downward, countercurrently contacting the rising steam, desorbing H2S, CO2, and organic sulfur. Heat required for regeneration is provided by an electric heating element at the bottom of the regeneration tower. The regenerated lean liquid, at a temperature of 120-140°C, is drawn from the bottom of the regeneration tower and heat exchanged with fresh water in a lean liquid cooler. After cooling to 40°C, it flows into a lean liquid buffer tank. A circulating pump boosts the pressure, preheating it in the lean liquid preheater, and then pumps it into the upper portion of the absorber, completing the entire solution cycle. Acid gas is condensed and cooled to 40°C at the top of the regeneration tower. It then enters an acid gas separator, where a small amount of acid water is separated. The acid gas is then transported from the separator to an incineration system for incineration and released into the atmosphere.

[0038] Isoamyl secondary amine (C 14 H 32ON2) Preparation method: 1,4-dichloro-2-butanol and 2-aminopentane are reacted in a reactor at a molar ratio of 1:3 at 140-200°C for 2-4 hours. The reaction solvent is ethanol, and the molar ratio of ethanol to 1,4-dichloro-2-butanol is 1.5:1. After the reaction, aqueous sodium hydroxide solution is added, and the reaction is refluxed at 70-90°C for 4-6 hours. The molar ratio of sodium hydroxide to 1,4-dichloro-2-butanol is 2.5:1. After the reflux reaction is completed, the filtrate is filtered under atmospheric pressure, collected, and subjected to vacuum distillation. The fractions are collected to obtain the desired product in an approximately 65% ​​yield. The product's NMR spectrum is shown in Figure 2. Other secondary isopentyl amines were synthesized using the same method.

[0039] Example 1

[0040] This embodiment provides a natural gas selective desulfurization solvent system. The solvent system of this embodiment includes the following components by mass percentage: isopentyl secondary amine C 14 H 32 ON2 50% (R1, R2, and R3 are all H), 10% 1-azabicyclo[2.2.1]-3-heptylamine (cas: 773056-73-8), and 40% deionized water. The desulfurization solvent system was prepared by mixing the components at 40 rpm for 20 minutes at 25°C. The effectiveness of this solvent system in removing hydrogen sulfide, carbon dioxide, and mercaptans is evaluated, as shown in Table 1.

[0041] Table 1 Desulfurization effect of Example 1

[0042] Example 2

[0043] This embodiment provides a natural gas selective desulfurization solvent system. The solvent system of this embodiment includes the following components by mass percentage: isopentyl secondary amine C 14 H 32 ON2 50% (R1, R2, and R3 are all H), 10% 1-azabicyclo[2.2.1]-3-heptylamine, 20% triethylene glycol ethyl ether, and 20% deionized water. The desulfurization solvent system was prepared by mixing the components at 40 rpm for 20 minutes at 25°C. The effectiveness of this solvent system in removing hydrogen sulfide, carbon dioxide, and mercaptans is evaluated, as shown in Table 2.

[0044] Table 2 Desulfurization effect of Example 2

[0045] Example 3

[0046] This embodiment provides a natural gas selective desulfurization solvent system. The solvent system of this embodiment includes the following components by mass percentage: isopentyl secondary amine C 16 H36 ON2 50% (in this structure, R1 and R3 are CH3, and R2 is H), 10% 1-azabicyclo[2.2.1]-3-heptylamine, 20% triethylene glycol ethyl ether, and 20% deionized water. The desulfurization solvent system was prepared by mixing the components at 25°C for 20 minutes at 40 rpm. The effectiveness of this solvent system in removing hydrogen sulfide, carbon dioxide, and mercaptans is evaluated, as shown in Table 3.

[0047] Table 3 Desulfurization effect of Example 3

[0048] Comparative Example 1

[0049] Shell developed Sulfinol-X solution specifically for the removal of organic sulfur. Based on the Sulfinol-X solution formulation, the comparative solvent system consisted of the following components, calculated by weight: 40% MDEA, 7% piperazine, 30% sulfolane, and 23% deionized water. The effectiveness of this solvent system in removing hydrogen sulfide, carbon dioxide, and mercaptans was evaluated, as shown in Table 4.

[0050] Table 4 Desulfurization effect of comparative example 1

[0051] Comparative Example 2

[0052] This comparative example provides a natural gas selective desulfurization solvent system. The solvent system of this comparative example comprises the following components by mass percentage: isopentyl secondary amine C 14 H 32 ON2 50% (R1, R2, and R3 are all H), deionized water 50%. The desulfurization solvent system was prepared by mixing the components at 40 rpm at 25°C for 20 minutes. The effectiveness of this solvent system in removing hydrogen sulfide, carbon dioxide, and mercaptans is evaluated, as shown in Table 5 below.

[0053] Table 5 Desulfurization effect of comparative example 2

[0054] As can be seen from the above, the natural gas selective desulfurization solvent system of the present invention can selectively remove hydrogen sulfide and mercaptans from the feed gas and minimize the absorption of carbon dioxide.

Claims

1. A natural gas selective desulfurization solvent system, the composition of which includes a base solvent, a bicyclic amine component, and an isoamyl secondary amine component, and the isoamyl secondary amine component has a structure shown in Formula I: In Formula I, R 1 , R 2 , R 3 are each independently selected from H, C1-C5 alkyl and its derivatives; The bicyclic amine component has a structure represented by Formula II or Formula III:

2. The natural gas selective desulfurization solvent system according to claim 1, wherein In Formula I, R 1 , R 2 , R 3 are each independently selected from H, methyl, and ethyl.

3. The natural gas selective desulfurization solvent system according to claim 1, wherein The base solvent includes water.

4. The natural gas selective desulfurization solvent system according to claim 1, wherein Calculated based on the mass of the natural gas selective desulfurization solvent system being 100%, the composition of the natural gas selective desulfurization solvent system includes 20%-50% of isoamyl secondary amine components, 5%-10% of bicyclic amine components, and the balance is the base solvent.

5. The natural gas selective desulfurization solvent system according to claim 1, wherein The composition of the natural gas selective desulfurization solvent system further includes ether components.

6. The natural gas selective desulfurization solvent system according to claim 5, wherein The ether components include diethylene glycol ethyl ether and / or triethylene glycol ethyl ether.

7. The natural gas selective desulfurization solvent system according to claim 5, wherein, Calculated based on the mass of the natural gas selective desulfurization solvent system being 100%, the composition of the natural gas selective desulfurization solvent system includes 20%-50% of isoamyl secondary amine components, 5%-10% of bicyclic amine components, 10%-40% of ether components, and the balance is the base solvent.

8. A method for preparing the natural gas selective desulfurization solvent system according to any one of claims 1-7, comprising the following steps: Mix each component at 30-50 r / min at 20-30 °C for 10-40 min.

9. A natural gas selective desulfurization method, which is carried out by using the natural gas selective desulfurization solvent system described in any one of claims 1-7, and includes the following steps: Contact the natural gas to be desulfurized with the natural gas selective desulfurization solvent system for desulfurization treatment, and then separate the desulfurized natural gas.

10. The natural gas selective desulfurization method according to claim 9, wherein, The natural gas selective desulfurization method includes the following steps: (1) Compress the natural gas to be desulfurized to a predetermined pressure, then enter the absorption tower, and contact countercurrently with the natural gas selective desulfurization solvent system inside the absorption tower for desulfurization to obtain desulfurized natural gas and rich liquid; (2) The rich liquid undergoes pressure reduction, flash evaporation, and stripping treatment to separate natural gas; (3) The rich liquid obtained after stripping treatment enters the regeneration tower for regeneration treatment; (4) The lean liquid obtained after regeneration treatment enters the absorption tower to recycle the operation in step (1).

11. The natural gas selective desulfurization method according to claim 10, wherein, The conditions of the natural gas selective desulfurization method satisfy one or more combinations of the following conditions (1)-(5): (1) The predetermined pressure is 2-7 MPa; (2) The flow rate of the natural gas to be desulfurized entering the absorption tower is 400-2500 L / h; (3) The temperature of the natural gas selective desulfurization solvent system is 18-40 °C; (4) The circulation rate of the natural gas selective desulfurization solvent system is 1.0-2.5 L / h; (5) The packing height of the absorption tower is 0.75-1.5 m.

12. The natural gas selective desulfurization method according to claim 9, wherein, The mercaptan content of the desulfurized raw gas ≥ 500 mg / m 3 .

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