Single sulfur deposition dissolving method for gas recovery string of high sulfur gas well

Abstract

This invention discloses a method for dissolving elemental sulfur deposits in gas well production tubing for high-sulfur gas wells, belonging to the field of gas well desulfurization technology. Addressing the problems of uneven distribution of existing chemical desulfurizing agents and the high cost and well-condition dependence of physical desulfurization techniques, this method innovatively proposes using CO2 as a carrier to carry a vaporizable alkylalkoxysilane compound desulfurizing agent with a specific structure, forming a gaseous composite system. Injecting this system into the wellbore and allowing it to circulate within the tubing string efficiently dissolves and removes elemental sulfur deposited on the tubing wall. Furthermore, this system can modify the rock surface, making it hydrophobic and sulfur-repellent, thereby effectively preventing sulfur redeposition.

Description

Technical Field

[0001] This invention belongs to the field of gas well desulfurization technology, specifically relating to a method for dissolving elemental sulfur deposits in a gas production tubing string of a high-sulfur gas well. Background Technology

[0002] When the H2S content in a gas well exceeds 30%, sulfur deposition will occur in most gas wells. When the gas flow rate is too high, the content and transport efficiency of elemental sulfur in the gas flow will increase, making sulfur deposition more likely. Currently, there are three main methods to address sulfur deposition: chemical reaction, heating and melting, and solvent dissolution.

[0003] Heating and melting: Currently, heating and melting methods include steam circulation and hot solvent circulation. However, this method is not commonly used because it causes more severe corrosion to pipes. Chemical reaction: Phillips Oil Company in the United States proposed injecting air into gas wells with sulfur deposits. The air oxidizes the H2S or elemental sulfur in the well, generating heat that keeps the sulfur in a molten state, which is then carried out by the gas flow. Petrolite Company in the United States proposed adding substances that can react with sulfur (such as olefins) to the petroleum fraction injected into the well. The reaction products disperse or dissolve in the gas well fluid and are carried out. While the chemical reaction method has its unique concept, it is not very practical. Solvents are mainly divided into physical solvents that do not react chemically with sulfur but only dissolve it, and chemical solvents that react chemically with sulfur. Physical solvents have a lower sulfur-carrying capacity than chemical solvents. Heptane and toluene have low sulfur-dissolving capacity and are suitable for wells with less severe sulfur deposits. Carbon disulfide has a higher sulfur-dissolving capacity, but it has a strong odor, is highly toxic, and flammable. Chemical sulfur solvents mainly react with H2S and elemental sulfur to form easily flowing substances, resulting in a large amount of sulfur dissolved.

[0004] Currently, the main methods for wellbore desulfurization are chemical desulfurization and physical-mechanical desulfurization. However, these technologies have limitations and are not universally applicable. Limitations of chemical desulfurizers: uneven distribution of the agent within the wellbore (e.g., concentration fluctuations due to differences in hydrodynamics between flowing wells and pumped wells), requiring excessive dosage to maintain effectiveness; and some desulfurizers (such as LJ-1 containing triethylenetetramine) pose risks of equipment corrosion and environmental pollution. Furthermore, their long-term compatibility with demulsifiers and flocculants still needs verification. Physical desulfurization technologies have insufficient applicability: automated desulfurization units rely on natural gas energy, which is insufficient for low-production wells, while high-cost operations such as coiled tubing flushing have limited desulfurization efficiency in deep and complex wellbores. Summary of the Invention

[0005] In view of the above-mentioned prior art, the present invention provides a method for dissolving elemental sulfur deposition in gas production tubing of high sulfur-containing gas wells, which solves the problems of uneven distribution of existing chemical sulfur dissolving agents, reliance on excessive chemical addition, and high cost of physical and mechanical methods due to high dependence on well conditions.

[0006] To achieve the above objectives, the technical solution adopted by this invention is: to provide a method for dissolving elemental sulfur deposits in a high-sulfur gas well production tubing, comprising the following steps:

[0007] S1: Mix the gasifiable sulfur solvent with CO2 to obtain a gaseous composite system;

[0008] S2: Inject the gaseous composite system into the gas well's production pipe or casing and allow it to circulate within the pipe;

[0009] S3: Finally, the gaseous composite system is discharged through reflux to complete the desulfurization process.

[0010] Furthermore, a vaporizable sulfur solvent is available as shown in Formula I:

[0011]

[0012] (I);

[0013] The molecule of the vaporizable sulfur solvent is C 10 H 13 F 11 O3Si.

[0014] Furthermore, the vaporizable sulfur solvent is prepared through the following steps:

[0015] Under nitrogen protection, perfluoropentylethylene is added to toluene and stirred until homogeneous. Then, a solution of trimethoxysilane and chloroplatinic acid in isopropanol is added dropwise at 80°C. Once the reaction is complete, a vaporizable sulfur solvent is obtained.

[0016] Furthermore, the molar ratio of perfluoropentylethylene to trimethoxysilane is 1:1, and the concentration of perfluoropentylethylene in toluene is 0.6 mol / L.

[0017] Furthermore, the concentration of chloroplatinic acid in the isopropanol solution of chloroplatinic acid is 0.1 mol / L.

[0018] Furthermore, the CO2 is supercritical CO2.

[0019] Furthermore, the temperature during injection of the gaseous composite system is 40~90 degrees Celsius, and the pressure is 1~8 MPa.

[0020] Furthermore, the method for removing elemental sulfur deposition in gas production tubing for high-sulfur gas wells also includes using a gaseous composite system to modify the interface inside the tubing.

[0021] The beneficial effects of this invention are as follows: This invention creatively constructs a gaseous synergistic sulfur dissolving system of "vaporizable special sulfur dissolving agent + supercritical CO2". Experiments show that supercritical CO2 can dissolve a large amount of the vaporizable sulfur dissolving agent (e.g., up to 436 g / m³ at 90℃ and 7.5 MPa), while the vaporizable sulfur dissolving agent can significantly improve the solubility of elemental sulfur in CO2, while pure CO2 or N2 carriers have little effect. Therefore, this synergistic effect brings excellent sulfur dissolving ability. Moreover, this composite system is gaseous, which can effectively enter complex wellbore structures and achieve uniform distribution of the agent in the tubing, overcoming the problem of uneven distribution caused by gravity differentiation and flow pattern changes of liquid agents. At the same time, the sulfur dissolving system of this invention can modify the rock surface in situ during the treatment process, changing its wettability from hydrophilic to strongly hydrophobic (contact angle can reach 120°~130°). This surface can effectively reduce the adhesion ability of sulfur particles, thereby removing existing deposits while inhibiting new sulfur deposits, achieving long-term protection of "treatment and prevention combined". Finally, compared to other sulfur solvents that pose risks of corroding equipment and polluting the environment, the sulfur solvent provided by this invention is more controllable, uses CO2 as a carrier, has environmentally friendly potential, and is in line with the concept of green development. Attached Figure Description

[0022] Figure 1 This is a graph showing the solubility of a vaporizable sulfur solvent in CO2 as a function of temperature and pressure.

[0023] Figure 2 A graph showing the change in the solubility of elemental sulfur by CO2 carrying a saturated, vaporizable sulfur solvent as a function of pressure (compared to the N2 system).

[0024] Figure 3 For different single-layer mass, the 1m 3 Curve showing the effect of supercritical CO2 on sulfur dissolution.

[0025] Figure 4 For different monohydrophobic concentrations, the effect on 1m 3 Curve showing the effect of supercritical CO2 on sulfur dissolution.

[0026] Figure 5 A graph showing the effect of different masses of vaporizable sulfur dissolving agents on the contact angle of the water phase in the core.

[0027] Figure 6 This is a graph showing the relationship between core samples treated with different concentrations of vaporizable sulfur dissolving agents and the amount of sulfur dissolved. Detailed Implementation

[0028] The specific embodiments of the present invention will be described in detail below with reference to examples.

[0029] Example 1

[0030] Synthesis of a vaporizable sulfur solvent: Under nitrogen protection, perfluoropentylethylene and toluene solvent were added to a dry reaction flask (to achieve a perfluoropentylethylene concentration of 0.6 mol / L in toluene). The mixture was then stirred thoroughly at 80°C, and trimethoxysilane, in an equimolar ratio to perfluoropentylethylene, was slowly added dropwise using a constant-pressure dropping funnel. Simultaneously, 0.27 mL of isopropanol chloroplatinic acid solution (chloroplatinic acid concentration of 0.1 mol / L) was added as a catalyst. After the addition was complete, the reaction continued at 80°C. Upon completion of the reaction, the solvent was removed by vacuum distillation to obtain the vaporizable sulfur solvent C. 10 H 13 F 11 O3Si, its structural formula is as follows:

[0031] .

[0032] Example 2

[0033] Solubility test of vaporizable sulfur solvent in CO2: At constant temperatures (40℃ and 90℃ respectively), a certain amount of vaporizable sulfur solvent was added to a high-pressure reactor of known volume, and then CO2 was introduced to different pressures. Based on the pressure change, the mass concentration (g / m³) of the vaporizable sulfur solvent dissolved in CO2 at dissolution equilibrium was calculated. 3 The result is as follows: Figure 1 As shown, the higher the pressure, the greater the solubility; especially at 90℃ and 7.5 MPa (supercritical conditions), the solubility reaches as high as 436 g / m³. 3 This proves that supercritical CO2 is an excellent carrier medium.

[0034] Example 3

[0035] Sulfur dissolution performance test of gaseous composite system: in a high temperature and high pressure reactor (internal space volume approximately 1m³) 3 In a solution containing excess elemental sulfur and a vaporizable sulfur solvent, CO2 is introduced to different pressures (1-8 MPa). The solution is then heated to 90°C and stirred at this temperature for a sufficient time to reach dissolution equilibrium. Finally, the gas phase is sampled and analyzed to determine the concentration of dissolved sulfur (g / m³). 3 In contrast, experiments were conducted under the same conditions using N2 instead of CO2.

[0036] The results are as follows Figure 2 As shown, under saturated conditions of vaporizable sulfur solvent, the sulfur-dissolving capacity of the CO2 system is significantly enhanced, and increases with increasing pressure, reaching a maximum value of 10~14 g / m³. 3 The improvement of the N2 system is very limited (only 2~3 g / m³). 3 This demonstrates the unique synergistic sulfur-dissolving effect between CO2 and gasifiable sulfur-dissolving agents.

[0037] Example 4

[0038] Sulfur dissolving performance test of supercritical CO2: Based on the results of the above examples, under a fixed temperature of 90°C and a pressure of 7.5 MPa (supercritical state), the amount of CO2 added to the high-temperature and high-pressure reactor (internal space volume approximately 1 m³) was varied. 3 The mass of elemental sulfur in the sample is 0.005 g to 0.03 g (equivalent to a concentration of 5 to 20 g / m³). 3 The test system was used to determine the solubility of elemental sulfur; the results are as follows: Figure 3 and Figure 4 As shown, it can significantly improve the solubility of elemental sulfur in CO2 gas, reaching 4.5 g / m³. 3 ~7.0g / m 3 .

[0039] Example 5

[0040] Sulfur deposition prevention performance test of the gaseous composite system: Hydrophilic core samples were placed in an autoclave with different masses of gasifiable sulfur dissolving agent. CO2 was introduced to 7.5 MPa, the temperature was raised to 90℃, and the reaction was maintained at this temperature for a period of time. After the reaction was completed, the core samples were removed, the surface was cleaned, and the water phase contact angle was measured. The results are as follows: Figure 5 As shown, with the increase of the amount of gasifiable sulfur dissolving agent, the water phase contact angle of the core slice increases significantly, and can be transformed from a hydrophilic state (contact angle <90°) to a strongly hydrophobic state (contact angle 120°~130°). This indicates that the system can form a hydrophobic modification layer on the rock surface.

[0041] Furthermore, core samples treated with gaseous composite systems of gaseous sulfur-soluble agents at different concentrations were placed in a sulfur-containing supercritical CO2 environment to test their surface sulfur deposition tendency. The results are as follows: Figure 6 As shown, the amount of sulfur adhering to the surface of the modified core with a larger contact angle is significantly reduced, proving its anti-deposition effect.

[0042] Example 6

[0043] Simulated desulfurization operation: The gasifiable sulfur dissolving agent prepared in Example 1 is mixed with liquid CO2, and the mixture is brought to a supercritical state through a pressurization and heating device to obtain a gaseous composite system. The gaseous composite system is injected into the gas production pipe or casing of the simulated well through a high-pressure injection pump, so that it flows along the gas production pipe or casing to the simulated sulfur deposition section at the bottom of the well. At the bottom of the well, the gaseous composite system flows back through the bottom of the wellbore, and dissolves the sulfur on the pipe wall when it flows through the simulated sulfur deposition section. Finally, the change in sulfur content in the backflowed gaseous composite system is monitored until its concentration reaches a stable low value, indicating that the desulfurization operation is basically completed.

[0044] Simulation results show that the method can effectively remove sulfur deposits on the simulated pipe section, and the pipe wall surface becomes hydrophobic after the operation.

[0045] Although specific embodiments of the present invention have been described in detail with reference to examples, they should not be construed as limiting the scope of protection of this patent. Various modifications and variations that can be made by those skilled in the art without inventive effort within the scope described in the claims are still within the scope of protection of this patent.

Claims

1. A method for dissolving elemental sulfur deposits in a gas production tubing string of a high-sulfur gas well, characterized in that, Includes the following steps: S1: Mix the gasifiable sulfur solvent with CO2 to obtain a gaseous composite system; S2: Inject the gaseous composite system into the gas well's production pipe or casing and allow it to circulate within the pipe; S3: Finally, the gaseous composite system is discharged through reflux to complete the desulfurization process; The structural formula of the vaporizable sulfur solvent is as shown in Formula I: （Ⅰ）； The molecule of the vaporizable sulfur solvent is C 10 H 13 F 11 O3Si.

2. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to claim 1, characterized in that, The vaporizable sulfur solvent is prepared by the following steps: Under nitrogen protection, perfluoropentylethylene is added to toluene and stirred until homogeneous. Then, a solution of trimethoxysilane and chloroplatinic acid in isopropanol is added dropwise at 80°C. Once the reaction is complete, a vaporizable sulfur solvent is obtained.

3. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to claim 2, characterized in that: The molar ratio of perfluoropentylethylene to trimethoxysilane is 1:1, and the concentration of perfluoropentylethylene in toluene is 0.6 mol / L.

4. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to claim 2, characterized in that: The concentration of chloroplatinic acid in the isopropanol solution of chloroplatinic acid is 0.1 mol / L.

5. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to claim 1, characterized in that: The CO2 mentioned is supercritical CO2.

6. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to claim 1, characterized in that: The temperature during injection of the gaseous composite system is 40~90 degrees Celsius, and the pressure is 1~8 MPa.

7. The method for removing elemental sulfur deposition from gas production tubing in high-sulfur gas wells according to any one of claims 1 to 6, characterized in that: The method also includes using a gaseous composite system to modify the interface inside the column.

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