A method for in situ inhibition of hydrogen sulfide in a coal bed gas well

Abstract

The application discloses a method for in-situ inhibition of hydrogen sulfide in a coalbed methane well, comprising the following steps: S1, periodically tracking and detecting the hydrogen sulfide already generated in the coalbed, performing isotope testing on the hydrogen sulfide, and finding out the causes of the hydrogen sulfide; S2, on the basis of finding out the causes of the hydrogen sulfide, performing targeted treatment on the hydrogen sulfide with different causes, and realizing in-situ inhibition of the hydrogen sulfide in the coalbed; and S3, periodically tracking and detecting the coalbed methane well, and evaluating the inhibition effect. The application analyzes the causes of the hydrogen sulfide in the coalbed methane well, performs targeted treatment, adopts the synergistic inhibition effect of the hydrogen sulfide inhibitor and the alkaline solution, processes the hydrogen sulfide of the coalbed primary and secondary organisms under the in-situ condition, better reduces the corrosion influence caused by the hydrogen sulfide, periodically track and detects the coalbed methane well after the treatment, evaluates the inhibition effect, and thus ensures the safety in the process of mining the high-sulfur coalbed methane well, and simultaneously avoids air pollution after combustion.

Description

Technical Field

[0001] This invention belongs to the field of energy and environmental protection technology, and specifically relates to a method for in-situ suppression of hydrogen sulfide in coalbed methane wells. Background Technology

[0002] For a long time, many coal mines have been threatened by hydrogen sulfide to varying degrees, especially in the mining of high-sulfur coal. Abnormal outbursts of hydrogen sulfide from coal seams are becoming more and more frequent. This not only threatens the health of personnel, but also causes severe corrosion of drainage equipment. At the same time, coalbed methane containing hydrogen sulfide will cause pipeline corrosion during transportation, and will produce sulfur dioxide after combustion, causing air pollution.

[0003] Biogenic hydrogen sulfide can be divided into two categories: primary and secondary biogenic. Primary biogenic hydrogen sulfide occurs during the diagenetic stage in the early stages of coal formation, and such biogenic hydrogen sulfide is relatively rare. Secondary biogenic hydrogen sulfide is more common. Recent studies have shown that a large amount of secondary biogenic gas is generated during the drainage stage of coalbed methane wells. This biogenic gas is called secondary biogenic gas, and the hydrogen sulfide within it is called secondary hydrogen sulfide. The generation of this biogenic gas is widespread. With the continuous development of coal mining and coalbed methane, especially the large-scale generation of secondary hydrogen sulfide during the drainage stage of coalbed methane wells, the prevention and control of coalbed methane sulfide is becoming increasingly important.

[0004] The two main coalbed methane desulfurization technologies widely used both domestically and internationally are dry desulfurization and wet desulfurization. Dry desulfurization includes activated carbon adsorption, molecular sieve adsorption, and catalytic oxidation technologies using iron oxide, zinc oxide, and manganese oxide. The key to dry desulfurization technology is its solid desulfurizing agent, which requires good porosity and permeability. While the process is simple and requires low investment, it is limited by the sulfur capacity of the desulfurizing agent, necessitating frequent replacement. Therefore, it is necessary to develop desulfurizing agents with high sulfur capacity and low cost. Molecular sieve desulfurizing agents are inexpensive and regenerable, but their desulfurization effect is poor, and regeneration requires high temperatures, resulting in high regeneration costs. Some small and medium-sized natural gas processing plants generally use the iron oxide method for dry desulfurization of natural gas, but this method requires a large land area, frequent packing, and difficult waste disposal, making it economically unfeasible. Wet desulfurization utilizes the contact between the desulfurizing agent and the coalbed methane to remove hydrogen sulfide. Currently, chemical absorption is the most widely used method, as it has a large H2S absorption capacity and high removal precision. Common desulfurizing agents include methyl diethanolamine and sodium carbonate (Na2CO3) alkaline solution. Some factories install multiple atomizing nozzles along the coalbed methane transport direction in the pipeline to spray desulfurizing liquid. During transportation, the coalbed methane comes into contact with the liquid sprayed from each atomizing nozzle in sequence, thus achieving desulfurization.

[0005] Existing desulfurization technologies for natural gas and coalbed methane wells are mainly post-processing technologies performed after gas extraction, rather than direct processing under in-situ underground conditions. Summary of the Invention

[0006] The purpose of this invention is to provide a method for in-situ suppression of hydrogen sulfide in coalbed methane wells. This method utilizes the synergistic inhibitory effect of hydrogen sulfide inhibitors and alkaline solutions to treat both primary and secondary biogenic hydrogen sulfide in the coal seam under in-situ conditions, thereby better reducing the corrosive effects of hydrogen sulfide.

[0007] To solve the above-mentioned technical problems, the present invention adopts the following technical solution: a method for in-situ suppression of hydrogen sulfide in coalbed methane wells, comprising the following steps: S1. Regularly monitor and detect hydrogen sulfide that has been generated in the coal seam, conduct isotope testing on the hydrogen sulfide, and determine the cause of hydrogen sulfide formation. S2. Based on identifying the causes of hydrogen sulfide, targeted treatments are carried out for hydrogen sulfide of different causes to achieve in-situ suppression of hydrogen sulfide in coal seams. S3. Regularly monitor and test coalbed methane wells to evaluate their suppression effect.

[0008] The causes of hydrogen sulfide in step S1 include: (1) primary causes: protozoan and thermogenetic; (2) generated during the later drainage process: epigenetic; (3) both primary causes and generated during the later drainage process.

[0009] Regarding the cause (1), the targeted treatment method in step S2 is to directly inject alkaline solution into the coal reservoir to dissolve and absorb the generated hydrogen sulfide. The alkaline solution injection method is to use small-volume injection or large-volume hydraulic fracturing.

[0010] Regarding the cause (2), the targeted treatment method in step S2 is to inject an inhibitor into the fracturing fluid into the coal reservoir in a small-volume injection or a large-volume hydraulic fracturing manner to inhibit the generation of post-generated hydrogen sulfide.

[0011] Regarding the cause (3), the targeted treatment method in step S2 is as follows: First, add alkaline solution to the hydraulic fracturing fluid to absorb the generated hydrogen sulfide. If bio-fracturing fluid and inhibitor are used for injection or fracturing, liquid CO2 or various acid solutions are first used for injection or fracturing to reduce the pH to about 7, and then fracturing is carried out using fracturing fluid containing inhibitor. If bio-fracturing fluid is not used, fracturing or injection is carried out directly using fracturing fluid containing inhibitor to inhibit the generation of bio-hydrogen sulfide after the drainage stage.

[0012] The specific operation process of step S3 is as follows: Regularly sample the gas and water from the coalbed methane well; detect the main gas component, hydrogen sulfide, in the gas sample; and analyze the H2S of the water sample. - S 2- The inhibitory effect was evaluated by detecting it in conjunction with elemental S.

[0013] The alkaline solution is a potassium hydroxide solution with a pH of approximately 10.

[0014] The inhibitor is tungstate, and the recommended addition level is 10 mM / L.

[0015] Compared with the prior art, the present invention has the following technical effects by adopting the above technical solution: The present invention analyzes the causes of hydrogen sulfide generation in coalbed methane wells and implements targeted treatment methods. It uses the synergistic inhibitory effect of hydrogen sulfide inhibitors and alkaline solutions to treat the primary and secondary biological hydrogen sulfide in the coal seam under in-situ conditions, thereby better reducing the corrosive effects of hydrogen sulfide. After treatment, the coalbed methane wells are regularly monitored to evaluate the inhibition effect, thereby ensuring the safety of high-sulfur coalbed methane well mining and avoiding air pollution after combustion. Attached Figure Description

[0016] Figure 1 This is a schematic diagram showing the methane production and cumulative production of the control group and after tungstate injection; Figure 2 This is a schematic diagram showing the gas production and cumulative gas production during the hydrogen sulfide stage in the control group and after tungstate injection; Figure 3 This is a schematic diagram of methane production and gaseous hydrogen sulfide without the addition of tungstate inhibitors; Figure 4 This is a schematic diagram showing the methane production and gaseous hydrogen sulfide after adding tungstate inhibitors; Figure 5 Hydrogen sulfide gas is continuously bubbled into KOH solutions of different pH values ​​until the solutions are saturated with dissolved hydrogen sulfide. The H₂S in the solutions... - and S 2- A schematic diagram of the test for the sum of concentrations. Detailed Implementation

[0017] The embodiments of the present invention will be described in further detail below with reference to the accompanying drawings and examples.

[0018] A method for in-situ suppression of hydrogen sulfide in coalbed methane wells includes the following steps: S1. Regularly monitor and detect hydrogen sulfide that has been generated in the coal seam, conduct isotope testing on the hydrogen sulfide, and determine the cause of hydrogen sulfide formation. S2. Based on identifying the causes of hydrogen sulfide, targeted treatments are carried out for hydrogen sulfide of different causes to achieve in-situ suppression of hydrogen sulfide in coal seams. S3. Regularly monitor and test coalbed methane wells to evaluate their suppression effect.

[0019] The causes of hydrogen sulfide in step S1 include: (1) primary causes: protozoan and thermogenetic; (2) generated during the later drainage process: epigenetic; (3) both primary causes and generated during the later drainage process.

[0020] Regarding the cause (1), the targeted treatment method in step S2 is to directly inject alkaline solution into the coal reservoir to dissolve and absorb the generated hydrogen sulfide. The alkaline solution injection method is to use small-volume injection or large-volume hydraulic fracturing.

[0021] Regarding the cause (2), the targeted treatment method in step S2 is to inject an inhibitor into the fracturing fluid into the coal reservoir in a small-volume injection or a large-volume hydraulic fracturing manner to inhibit the generation of post-generated hydrogen sulfide.

[0022] Regarding the cause (3), the targeted treatment method in step S2 is as follows: First, add alkaline solution to the hydraulic fracturing fluid to absorb the generated hydrogen sulfide. If bio-fracturing fluid and inhibitor are used for injection or fracturing, liquid CO2 or various acid solutions are first used for injection or fracturing to reduce the pH to about 7, and then fracturing is carried out using fracturing fluid containing inhibitor. If bio-fracturing fluid is not used, fracturing or injection is carried out directly using fracturing fluid containing inhibitor to inhibit the generation of bio-hydrogen sulfide after the drainage stage.

[0023] The specific operation process of step S3 is as follows: Regularly sample the gas and water from the coalbed methane well; detect the main gas component, hydrogen sulfide, in the gas sample; and analyze the H2S of the water sample. - S 2- The inhibitory effect was evaluated by detecting it in conjunction with elemental S.

[0024] The alkaline solution is a potassium hydroxide solution with a pH of approximately 10.

[0025] The inhibitor is tungstate, and the recommended addition level is 10 mM / L.

[0026] The technical solution of the present invention will be further described below with reference to the accompanying drawings and specific experimental examples.

[0027] Experimental Example 1: Determining the Optimal Dosage of Tungstate Inhibitor In the laboratory, high-sulfur coal from Jincheng was used as the fermentation substrate, and the enriched original microbial community of the coal seam was used as the fermentation microbial community. Tungstate was added at concentrations of 6 mM / L, 8 mM / L, 10 mM / L, and 12 mM / L, respectively. A fermentation system without added tungstate was used as a control group. The methane production during the fermentation phase and the cumulative methane production were compared between the two systems. Figure 1 (as shown) and the stage gas production and cumulative gas production of hydrogen sulfide (as shown) Figure 2 As shown in the figure, when 10 mM / L of tungstate inhibitor is added, it has little effect on the methane production of the system and has a significant inhibitory effect on hydrogen sulfide. Therefore, the amount of tungstate added is selected as 10 mM / L.

[0028] Experimental Example 2: Experiment on the Inhibitory Effect of Tungstate Inhibitors on Hydrogen Sulfide In the laboratory, Jincheng high-sulfur coal was still used as the fermentation substrate, and the enriched original microbial community of the coal seam was used as the fermentation community. One fermentation system was supplemented with 10 mM / L tungstate, and one group was used as a control group without tungstate. The methane production after adding tungstate inhibitors was ( Figure 3 (as shown) and control group ( Figure 4 Compared to the figure shown, the change was not significant, but it had a significant inhibitory effect on hydrogen sulfide, reducing the cumulative production of hydrogen sulfide (dissolved in water + gas) by 52.4%. The inhibitory effect on gaseous hydrogen sulfide was even more significant, especially after the system had been running for 15 days, gaseous hydrogen sulfide could no longer be detected.

[0029] Experimental Example 3: Experiment on the Solubility of Hydrogen Sulfide with KOH at Different pH Values In the laboratory, KOH solutions with pH values ​​of 7, 8, 9, and 10 were prepared, and hydrogen sulfide gas was continuously bubbled through each solution until the solution was saturated. The H₂S content in the solutions was then tested. - and S 2- Concentration, calculate the solubility of hydrogen sulfide in KOH at different pH values, from Figure 5 It can be seen that the KOH solution with pH 10 has the greatest solubility for hydrogen sulfide.

[0030] Through the above three experimental examples, the inhibition system provided by this invention, during the verification process, simulated the growth environment of sulfate-reducing bacteria in coal seams using a fermentation system, including temperature, pH, and electron donor and acceptor conditions in the metabolic process of sulfate-reducing bacteria; simultaneously, the bacterial community in the coal seam was also cultured on a larger scale. Based on the identification of the causes of hydrogen sulfide, a technique of synergistic inhibition of hydrogen sulfide inhibitors and alkaline solutions was adopted to better treat both primary and secondary biogenic hydrogen sulfide in coal seams.

[0031] The above embodiments illustrate the basic principles and features of the present invention, but are merely preferred embodiments and are not limited to these embodiments. Those skilled in the art, inspired by this patent, can make many modifications and improvements without departing from the spirit and scope of the claims, all of which fall within the scope of protection of the present invention. Therefore, the scope of this patent and its protection should be determined by the appended claims.

Claims

1. A method for in-situ suppression of hydrogen sulfide in coalbed methane wells, characterized in that: Includes the following steps: S1. Regularly monitor and detect hydrogen sulfide that has been generated in the coal seam, conduct isotope testing on the hydrogen sulfide, and determine the cause of hydrogen sulfide formation. S2. Based on identifying the causes of hydrogen sulfide, targeted treatments are carried out for hydrogen sulfide of different causes to achieve in-situ suppression of hydrogen sulfide in coal seams. S3. Regularly monitor and test coalbed methane wells to evaluate their suppression effect; The causes of hydrogen sulfide in step S1 include: (1) primary causes: protozoan causes and thermogenic causes; (2) Generated during the later stages of extraction: metagenetic origin; (3) It has both primary origin and generation during the later stages of extraction; Regarding the cause (1), the targeted treatment method in step S2 is to dissolve and absorb the generated hydrogen sulfide by directly injecting alkaline solution into the coal reservoir. The alkaline solution injection method is to use small-volume injection or large-volume hydraulic fracturing. Regarding the cause (2), the targeted treatment method in step S2 is to inject an inhibitor into the fracturing fluid into the coal reservoir in a small-volume injection or a large-volume hydraulic fracturing manner to inhibit the generation of post-generated hydrogen sulfide. Regarding the cause (3), the targeted treatment method in step S2 is as follows: First, add alkaline solution to the hydraulic fracturing fluid to absorb the generated hydrogen sulfide. If bio-fracturing fluid and inhibitors are used for injection or fracturing, liquid CO2 or various acids are first used for injection or fracturing to reduce the pH to about 7, and then fracturing is carried out using fracturing fluid containing inhibitors. If bio-fracturing fluid is not used, fracturing or injection is carried out directly using fracturing fluid containing inhibitors to inhibit the generation of bio-hydrogen sulfide during the drainage stage. The inhibitor is tungstate, and the addition amount is 10 mM / L.

2. The method for in-situ suppression of hydrogen sulfide in coalbed methane wells according to claim 1, characterized in that: The specific operation process of step S3 is as follows: Regularly sample the gas and water from the coalbed methane well; detect the main gas component, hydrogen sulfide, in the gas sample; and analyze the H2S of the water sample. - S 2- The inhibitory effect was evaluated by detecting it in conjunction with elemental S.

3. The method for in-situ suppression of hydrogen sulfide in coalbed methane wells according to claim 1, characterized in that: The alkaline solution is a potassium hydroxide solution with a pH of approximately 10.

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