A nanoemulsion treating agent for realizing coal bed gas surface wetting reverse

Abstract

The application discloses a kind of nanoemulsion treating agent for realizing coalbed gas surface wetting reverse, belong to coalbed gas exploitation technical field.The nanoemulsion treating agent has the characteristics of small amount of surfactant, small amount of surfactant adsorption loss, can realize the change of coalbed surface wettability and improve coalbed gas well production.Nanoemulsion treating agent is prepared by microemulsion dilution method, the principle is: microemulsion has excellent stability, easy to store.When using, a certain amount of microemulsion is added into well fluid according to mass fraction.The amount of nanoemulsion prepared by microemulsion dilution method is 0.2%-1% at this time, the surfactant content in the formed nanoemulsion is 0.04%-0.2%, which can reduce the use of surfactant.

Description

Technical Field

[0001] This invention belongs to the field of coalbed methane extraction technology, specifically relating to a nanoemulsion treatment agent that achieves surface wetting reversal in coalbed methane. Background Technology

[0002] With the increasing depletion of traditional energy sources such as oil and natural gas, new energy sources such as coalbed methane and shale gas are attracting more and more attention. Currently, fracturing, such as hydraulic fracturing, is widely used for the development of geological energy reservoirs. There is strong support for producing gas before coal to improve gas extraction efficiency. However, due to the extremely low permeability and poor gas permeability of coal, the gas recovery rate is very low. To increase the permeability of coal and the production of coalbed methane wells, hydraulic fracturing is often used. However, since most coal seams are hydrophilic, the surface of the coal sample is often wet, causing the water injected into the coal seam during hydraulic fracturing to not be completely drained, forming a so-called "water lock" phenomenon. This means that water blocks the flow of gas, hindering subsequent gas production and drainage. The wetting reversal method can change the wettability of the coal seam near the bottom of the well, changing it from hydrophilic to gas-loving. The capillary pressure will change from resistance to driving force, reducing or eliminating the "water lock" phenomenon, increasing water drainage, reducing damage to the coal seam, and thus increasing the production of coalbed methane wells.

[0003] Existing technology provides a method for achieving gas wetting reversal on core surfaces using cationic fluorocarbon surfactants. This method uses a wetting reversal treatment agent comprising a cationic fluorocarbon surfactant FC911, a quaternary ammonium salt surfactant, and a polar fluid. Preferably, the wetting reversal treatment agent is a mixture of FC911, hexadecyltrimethylammonium bromide, and water. This method can transform the gas reservoir rock surface into a state with strong gas hygroscopicity and good stability. Coalbed methane differs from conventional natural gas reservoirs in terms of reservoir characteristics, seepage characteristics, development mechanisms, and extraction methods.

[0004] Existing technology provides a method for achieving gas wetting reversal on coal and rock surfaces using cationic fluorocarbon surfactants. The wetting reversal treatment agent used contains the cationic fluorocarbon surfactant perfluorooctyl sulfamethoxypropylamine oxide, the nonionic surfactant fatty alcohol polyoxyethylene ether, and a polar fluid; preferably, the wetting reversal treatment agent is composed of perfluorooctyl sulfamethoxypropylamine oxide, fatty alcohol polyoxyethylene ether, and water. This invention can transform the surface of gas reservoir rocks into a gas-wet state and exhibits good stability. However, the amount of surfactant used is relatively high, resulting in high economic costs. Simultaneously, the surfactant has a large adsorption capacity on the coal seam surface, and after entering the coal seam, it undergoes significant adsorption, leading to a shallow effective penetration depth of the surfactant within the coal seam. Furthermore, the permeability of the original pores is very low, and coal dust and rich clay minerals in the coal seam are easily hydrated upon contact with water. Additionally, after adsorbing a large amount of surfactant, the coal seam matrix is ​​prone to expansion, causing blockage and damage to the coal seam pores. Summary of the Invention

[0005] This invention addresses the shortcomings of existing surfactant-based wetting reversal treatment agents, such as large adsorption losses on coal seam surfaces, shallow effective penetration depths, and high surfactant usage. The aim is to provide a nanoemulsion treatment agent that achieves wetting reversal on coalbed methane surfaces. This nanoemulsion treatment agent has the characteristics of low surfactant usage and low surfactant adsorption losses, and can change the wettability of coal seam surfaces to improve coalbed methane well production.

[0006] This invention is achieved through the following technical solution:

[0007] A nanoemulsion treatment agent for achieving surface wetting reversal in coalbed methane, wherein the nanoemulsion treatment agent is obtained by diluting a microemulsion with water containing additives; the nanoemulsion treatment agent is an oil-in-water emulsion formulation.

[0008] The microemulsion has a mass fraction of 0.2 wt% to 1 wt%.

[0009] Preferably, the surfactant content in the nanoemulsion treatment agent is 0.04wt%-0.2wt%.

[0010] Preferably, the microemulsion is prepared mainly from the following raw materials in parts by weight:

[0011] Nonionic surfactant 6wt%-12wt%, anionic surfactant 6wt%-12wt%, co-surfactant 7wt%-15wt%, oil phase 8wt%-15wt%, balance water;

[0012] The additives include pH adjusters, antibacterial agents, preservatives, scale inhibitors, and penetrants.

[0013] The additives mentioned above mainly include: pH adjusters, used to adjust the acidity or alkalinity of the fracturing fluid to meet specific geological conditions and rock characteristics; antibacterial agents, to prevent microbial contamination of the fracturing fluid during use; anticorrosive agents, to prevent corrosion of the wellbore and equipment by the fracturing fluid; scale inhibitors, to prevent the formation of scale on the wellbore and equipment; and penetrants, to increase the permeability of the fluid in the formation and improve the wetting reversal effect. These additives are also components commonly found in conventional wellbore fluids.

[0014] Emulsions generally consist of an aqueous phase, an oil phase, and an emulsifier. In the above-mentioned raw materials, surfactants and co-surfactants act as emulsifiers, water is the aqueous phase, and n-heptane is the oil phase. Simultaneously, surfactants and co-surfactants exhibit synergistic effects. Co-surfactants can improve the compatibility of surfactants between the oil and aqueous phases. They can reduce the hydrophilicity or hydrophobicity of surfactants, allowing them to be better dispersed in the continuous phase. This helps prevent phase separation and precipitation, improving the stability of the microemulsion. Furthermore, microemulsions are prone to phase separation and micelle aggregation during preparation; co-surfactants can form an amorphous colloidal layer at the microemulsion interface, preventing phase separation and micelle aggregation.

[0015] Preferably, the microemulsion is prepared by selecting nonionic surfactant, anionic surfactant, co-surfactant and oil phase according to the corresponding mass proportions, adding them to water in sequence, mixing and stirring to form a microemulsion.

[0016] Nanoemulsions are prepared using a microemulsion dilution method. The principle is that microemulsions possess excellent stability and are easy to store. During use, a specific mass fraction of the microemulsion is added to the well fluid. Simultaneously, when preparing nanoemulsions using this method, the addition amount is 0.2%-1%, resulting in a surfactant content of 0.04%-0.2% in the formed nanoemulsion, thus reducing the need for surfactants. However, if the amount of nanoemulsion added is too low, the nanoemulsion will be unstable; if the amount added is too high, the performance improvement of the nanoemulsion will be limited.

[0017] The aforementioned in-well fluid is predominantly water, with the remainder consisting of additives. These additives primarily include: pH adjusters to adjust the acidity or alkalinity of the fracturing fluid to meet specific geological conditions and rock characteristics; antibacterial agents to prevent microbial contamination of the fracturing fluid during use; anticorrosive agents to prevent corrosion of the wellbore and equipment by the fracturing fluid; scale inhibitors to prevent the formation of scale on the wellbore and equipment; and penetrants to increase the fluid's permeability in the formation and improve wetting reversal effects.

[0018] The positive effects and value ranges of each technical means in the above technical solution are explained as follows:

[0019] Nonionic surfactants function as emulsifiers and wetting reversal agents. The reason for controlling the mass fraction of nonionic surfactants to 6.00%-12.00% is that sufficient surfactant is needed to prepare well-performing and stable microemulsions, and the surfactant content can be adjusted according to actual conditions to achieve different wetting reversal effects. Nonionic surfactants have good emulsifying and dispersing properties. They can form a surfactant molecular layer between the aqueous and oil phases and promote the dispersion and stabilization of oil phase particles by reducing interfacial tension. This helps to uniformly disperse the oil phase in the aqueous phase, forming a stable micelle or microemulsion structure. An excessively high mass fraction results in high surfactant usage and economic costs, while an excessively low mass fraction results in poor microemulsion performance and low wetting reversal effect.

[0020] Anionic surfactants function as emulsifiers. The reason for controlling the mass fraction of anionic surfactants to 6.00%-12.00% is that they effectively reduce the surface tension at the liquid interface. Anionic surfactants can reduce the interfacial tension between oil phase particles (or micelles) and the aqueous phase, making it easier for oil phase particles to disperse in the aqueous phase and form a stable micelle structure. This helps reduce the energy consumption of the microemulsion and improve the system's stability. Simultaneously, anionic surfactants in microemulsions typically carry a negative charge. These negative charges can form an attractive charge with positive ions or other ions in the aqueous phase, thereby preventing micelle aggregation and phase separation in the microemulsion. The presence of anionic surfactants can form an electrical bilayer structure, and the repulsive forces between charges play a crucial role in the stability of the microemulsion.

[0021] The role of co-surfactants is that of adjuvants. The reason for controlling the mass fraction of co-surfactants to 7.00%-15.00% is that an appropriate amount of co-surfactant can increase the number and size of micelles in the emulsion, enhancing the emulsification effect. The presence of co-surfactants helps the main surfactant to better encapsulate and disperse the oil and water phases, forming a uniformly dispersed emulsion. An excessively high mass fraction may cause deemulsification or emulsion instability. Too high a concentration of co-surfactant may damage the micelle structure, leading to phase separation and precipitation. An excessively low concentration results in poor emulsification.

[0022] Nonpolar solvents form the oil phase of the emulsion. They play a crucial role in microemulsion formation. They are typically used as the base of the oil phase, combining with the aqueous phase and surfactants to form a stable emulsion structure. Nonpolar solvents have lower polarity and weaker intermolecular forces, resulting in better compatibility with polar components in the aqueous phase, which is beneficial for micelle formation and stable micelle structures. The oil phase mass fraction is controlled between 7.00% and 15.00% because the amount of oil added affects the formation and stability of the emulsion. Generally, a shorter carbon chain is preferred for the oil phase. Shorter carbon chain lengths facilitate molecular diffusion and interactions, allowing the oil phase to better compatibility with the aqueous phase and form a microemulsion structure. A carbon number between 6 and 12 is a common range, as shorter carbon chain lengths promote molecular diffusion and interactions, enabling the oil phase to better compatibility with the aqueous phase and form an emulsion structure. Meanwhile, excessively short carbon chains may result in low oil phase solubility, while excessively long carbon chains may restrict molecular movement and diffusion, affecting the formation and stability of microemulsions. Furthermore, the amount of oil added affects emulsification efficiency. Too little oil added may lead to incomplete emulsification, resulting in unstable microemulsions. Too much oil added may cause emulsification difficulties or decreased emulsion stability.

[0023] Preferably, the nonionic surfactant includes any one of dodecylphenol polyoxyethylene ether, Tween-80, and fluorocarbon surfactants.

[0024] Preferably, the fluorocarbon surfactant is fluorocarbon surfactant JH-501.

[0025] Preferably, the anionic surfactant includes sodium fatty alcohol polyoxyethylene ether sulfate and / or sodium dodecyl sulfate.

[0026] Preferably, the co-surfactant includes any one of n-propanol, n-butanol, and isobutanol.

[0027] Preferably, the oil phase includes any one of n-heptane, n-hexane, and cyclohexane.

[0028] Compared with the prior art, the present invention has at least the following technical effects:

[0029] (I) This invention provides a nanoemulsion treatment agent for reversing the surface wetting of coalbed methane. The nanoemulsion treatment agent has the characteristics of small surfactant dosage and small surfactant adsorption loss, which can realize the change of coal seam surface wettability and improve coalbed methane well production.

[0030] (II) This nanoemulsion treatment agent emulsifies a surfactant into a nanoemulsion. The principle is as follows: 1. The nanoemulsion is an oil-in-water emulsion with a spherical structure. The surfactant, acting as an emulsifier, is distributed at the oil-water interface of the emulsion. In this state, the surfactant exhibits good stability. Compared to surfactant solutions, emulsion droplets can reduce surfactant adsorption on the coal surface, decrease adsorption loss, and increase the effective penetration depth of the surfactant. 2. The nanoemulsion has a lower surface tension than the surfactant. According to the definition of capillary action, under the same wetting conditions and pore diameter, the lower the surface tension, the smaller the capillary force. Therefore, under the same pressure, the nanoemulsion penetrates deeper into the pores of the coal seam than a surfactant solution. 3. Simultaneously, the magnitude of surface tension directly affects the spread of droplets on a solid surface. When the surface tension is high, the internal cohesive force on the droplet is greater, making it difficult to overcome the surface tension resistance and thus hindering spread. Conversely, when the surface tension is low, the internal cohesive force on the droplet is smaller, making it easier to overcome the surface tension resistance and spread more effectively on the solid surface. Because nanoemulsions have lower surface tension than surfactants, they have a higher spreading coefficient, making it easier to overcome the resistance of coal seam surface tension and spread more effectively on the coal seam surface.

[0031] (III) Nanoemulsions are prepared via a microemulsion dilution method. The principle is that microemulsions have excellent stability and are easy to store. During use, a certain mass fraction of the microemulsion is added to the well fluid. Simultaneously, when preparing nanoemulsions via microemulsion dilution, the addition amount is 0.2%-1%, resulting in a surfactant content of 0.04%-0.2% in the formed nanoemulsion, thus reducing the use of surfactants. However, if the amount of nanoemulsion added is too low, the nanoemulsion will be unstable; if the amount added is too high, the performance improvement of the nanoemulsion will be limited. Attached Figure Description

[0032] Figure 1 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 1;

[0033] Figure 2 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 2;

[0034] Figure 3 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 3;

[0035] Figure 4 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 4;

[0036] Figure 5 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 5;

[0037] Figure 6A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 6;

[0038] Figure 7 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 7;

[0039] Figure 8 A schematic diagram of the contact angle of the water / air / coal sample system for processing sample 8;

[0040] Figure 9 This is a schematic diagram of the surface tension of a 0.5% TW-80 solution in Example 9 of Experiment 1.

[0041] Figure 10 This is a schematic diagram of the surface tension of a 0.5% fluorocarbon surfactant JH-501 solution in Example 9 of Experiment 1, which verifies the surface tension of the solution.

[0042] Figure 11 This is a schematic diagram illustrating the surface tension of a 0.5% AES solution in Example 9 of Experiment 1.

[0043] Figure 12 This is a schematic diagram of the surface tension of 0.5% fluorocarbon-AES nanoemulsion in Example 9 of Experiment 1.

[0044] Figure 13 This is a schematic diagram showing the unit adsorption capacity of 0.5% AES nanoemulsion on coal powder in the adsorption capacity experiment verification. Detailed Implementation

[0045] The embodiments of the present invention will be described in detail below with reference to the examples. However, those skilled in the art will understand that the following examples are only for illustrating the present invention and should not be regarded as limiting the scope of the present invention. Specific conditions not specified in the examples shall be carried out according to conventional conditions or conditions recommended by the manufacturer. Reagents or instruments whose manufacturers are not specified are all conventional products that can be purchased commercially.

[0046] The process of injecting fluid into a coal seam can be summarized in two stages: the seepage stage and the absorption stage. In the seepage stage, the fluid injected into the coal seam flows along the fractures under external pressure. Subsequently, under the action of capillary force, the water is spontaneously absorbed into the micropores, penetrating deeper into the pores. Lower surface tension can improve the fluid absorption effect within the pores.

[0047] Example 1:

[0048] Add 10.00% dodecylphenol polyoxyethylene ether (OP-10), 10.00% sodium dodecyl sulfate (SDS), 20% n-butanol, and 10% n-heptane to water in sequence, mix and stir. This will form an OP10-SDS composite microemulsion.

[0049] Take 1g of OP10-SDS microemulsion and add it to 199g of water. Stir and a 0.5% OP10-SDS nanoemulsion is formed. This nanoemulsion is a fluid with wetting reversal properties.

[0050] Example 2:

[0051] Add 10.00% fluorocarbon surfactant JH-501, 10.00% sodium fatty alcohol polyoxyethylene ether sulfate (AES), 20% n-butanol, and 10% n-heptane to water in sequence, mix and stir. This will form a fluorocarbon surfactant JH-501-AES compound microemulsion.

[0052] Take 1g of fluorocarbon surfactant JH-501-AES microemulsion and add it to 199g of water. Stir and a 0.5% OP10-AES nanoemulsion is formed. This nanoemulsion is a fluid with wetting reversal properties.

[0053] Example 2 above was selected as an experimental example for experimental verification.

[0054] Experiment 1: Verifying the effect of the sample from Example 2 above on the coal-rock contact angle.

[0055] The contact angle is used to demonstrate the effect of wetting reversal. As shown in the contact angle image, the droplet and the coal surface will produce two contact angles, left and right. CA represents their average value. Generally, CA is sufficient to describe the contact angle.

[0056] Method for wetting reversal test on coal seam surface: First, polish the surface of the coal sample to a smooth finish, then clean it with ethanol and water, and then dry it. Immerse the dried coal sample in the wetting reversal treatment agent and treat it at 25°C for 3 hours, then dry it at room temperature.

[0057] Treatment 1: The contact angle of the coal and rock sample after treatment in Example 2 was selected. The contact angle of the water / air / coal sample system was: CA: 104.174. See the illustration below. Figure 1 As shown.

[0058] Treatment 2: The contact angle of the coal and rock sample after treatment in Example 2 was not selected. The contact angle of the water / air / coal sample system was: CA: 48.188. See the illustration below. Figure 2 As shown.

[0059] Example 3:

[0060] Add 10.00% fluorocarbon surfactant JH-501 (wetting and reversal treatment agent), 10.00% sodium fatty alcohol polyoxyethylene ether sulfate (AES) (surfactant), 20% n-butanol (co-surfactant), and 10% n-hexane (oil phase) to water in sequence and mix and stir. This will form a fluorocarbon surfactant JH-501AES compound microemulsion.

[0061] Take 1g of fluorocarbon surfactant JH-501-AES microemulsion and add it to 199g of water. Stir and a 0.5% OP10-AES nanoemulsion is formed. This nanoemulsion is a fluid with wetting reversal properties.

[0062] Example 3 above was selected as an experimental case for verification.

[0063] The method for the coal seam surface wetting reversal experiment is the same as in Example 2.

[0064] Treatment 3: The contact angle of the coal and rock sample after treatment in Example 3 was selected. The contact angle of the water / air / coal sample system was: CA: 102.482°. See the illustration below. Figure 3 As shown.

[0065] Example 4:

[0066] The difference is that the wetting reversal treatment agent is Tween-80 (TW-80), the surfactant is SDS, and the rest is the same as in Example 3.

[0067] Treatment 4: The contact angle of the coal and rock sample after treatment in Example 4 was selected. The contact angle of the water / air / coal sample system was: CA: 101.924°. See the illustration below. Figure 4 As shown.

[0068] Example 5:

[0069] The difference is that the wetting reversal treatment agent is Tween-80 and the surfactant is sodium fatty alcohol polyoxyethylene ether sulfate (AES), while the rest is the same as in Example 3.

[0070] Treatment 5: The contact angle of the coal and rock sample after treatment in Example 5 was selected. The contact angle of the water / air / coal sample system was: CA: 96.225°. See the illustration below. Figure 5 As shown.

[0071] Example 6:

[0072] The difference is that the wetting reversal treatment agent is fluorocarbon surfactant JH-501, and the surfactant is sodium fatty alcohol polyoxyethylene ether sulfate (AES). The rest is the same as in Example 4.

[0073] Treatment 6: The contact angle of the coal and rock sample after treatment in Example 6 was selected. The contact angle of the water / air / coal sample system was: CA: 104.174°. See the illustration below. Figure 6 As shown.

[0074] In Examples 3-6 above, the amount of surfactant added in each example is constant because even if the types of surfactants are different, the total amount of surfactant added is 20% when formulating the microemulsion. Therefore, when diluted to 0.5% and 1% nanoemulsions, the amount of surfactant added is 0.1%-0.2%.

[0075] Example 7:

[0076] The difference is that the amount of nanoemulsion wetting reversal treatment agent is 1%, and the rest is the same as in Example 3.

[0077] Treatment 7: The contact angle of the coal and rock sample after treatment in Example 7 was selected. The contact angle of the water / air / coal sample system was: CA: 107.981°. See the illustration below. Figure 7 As shown.

[0078] Example 8:

[0079] The difference is that 0.5% of the fluorocarbon surfactant JH-501 and 1% of the surfactant are sodium fatty alcohol polyoxyethylene ether sulfate (AES), while the rest are the same as in Example 4.

[0080] Process 8: The contact angle of the coal and rock sample after treatment in Example 8 was selected. The contact angle of the water / air / coal sample system was: CA: 78.558°. See the illustration below. Figure 8 As shown.

[0081]

[0082]

[0083] Example 9:

[0084] 0.5% TW-80 solution, 0.5% AES solution, 0.5% fluorocarbon surfactant JH-501 solution, and 0.5% fluorocarbon-AES nanoemulsion were prepared, and their surface tensions were measured respectively.

[0085] Example 9 demonstrates that nanoemulsions use fewer surfactants to achieve the same surface tension.

[0086] The purpose of the tension test is to compare the surface tension data of surfactant solutions and nanoemulsions to demonstrate that nanoemulsions can achieve lower surface tension with less surfactant content.

[0087] The surface tensions of 0.5% TW-80 solution, 0.5% AES solution, and 0.5% fluorocarbon surfactant JH-501 solution were 38.729, 35.621, and 36.788, respectively. See the diagram below for details. Figure 9 , 11 As shown in Figure 10.

[0088] The surface tension of a 0.5% fluorocarbon-AES nanoemulsion is 28.430. See the diagram below for details. Figure 12 As shown.

[0089] The above conclusions demonstrate that nanoemulsions have lower surface tension than surfactants, resulting in a larger spreading coefficient. This allows them to easily overcome the resistance of coal seam surface tension and spread more effectively on the coal seam surface.

[0090] Adsorption capacity experimental verification:

[0091] Dynamic adsorption experiments were conducted using a displacement device.

[0092] 140g of coal powder, passed through a 60-mesh sieve, was packed into a sand-filled tube. A nanoemulsion was used as the displacing fluid, and the displacing flow rate was fixed at 0.1mL / min. Pressure changes at the injection end were recorded using a pressure gauge during the displacing process. At regular intervals, the effluent from the outlet of the sand-filled tube was collected, and the concentration of surfactant in the effluent was measured using a UV-Vis diffuse reflectance spectrophotometer. The amount of surfactant adsorbed per unit volume on the coal powder was calculated.

[0093] Take, for example, a 0.1% AES surfactant solution (containing 0.1% AES surfactant) and a 0.5% AES nanoemulsion (diluted with a microemulsion containing 20% ​​AES, 20% n-butanol, and 10% n-hexane).

[0094] The 0.5% AES nanoemulsion is prepared by microemulsion containing 20% ​​AES surfactant. Therefore, the 0.1% AES surfactant solution and the 0.5% AES nanoemulsion contain the same surfactant.

[0095] Result: As Figure 13 As shown, the horizontal axis represents the volume of the coal body (45 mL equals 1 PV), and the vertical axis represents the amount of coal powder adsorbed per unit volume.

[0096] The 0.5% AES nanoemulsion has a lower adsorption capacity on coal powder and less surfactant loss in the fluid.

[0097] Finally, it should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A nanoemulsion treatment agent for achieving coalbed methane surface wettability reversal, characterized by, The nanoemulsion treatment agent is obtained by diluting the microemulsion in water containing additives; the nanoemulsion treatment agent is an oil-in-water emulsion preparation; The mass fraction of the microemulsion is 0.2wt%-1wt%; The content of the surfactant in the nanoemulsion treatment agent is 0.04wt%-0.2wt%; The microemulsion is mainly prepared from the following raw materials in mass fraction: Nonionic surfactant 6wt%-12wt%, anionic surfactant 6wt%-12wt%, co-surfactant 7wt%-15wt%, oil phase 8wt%-15wt%, and the rest is water; The additives include pH adjuster, fungicide, preservative, antifouling agent and penetrant; The nonionic surfactant is Tween-80 or fluorocarbon surfactant; The fluorocarbon surfactant is fluorocarbon surfactant JH-501; The anionic surfactant is sodium dodecyl sulfate or sodium fatty alcohol polyoxyethylene ether sulfate; The co-surfactant is n-butanol; The oil phase is n-heptane.

2. The nanoemulsion treating agent for reversing the surface wettability of coalbed gas according to claim 1, characterized in that, The preparation method of the microemulsion is as follows: nonionic surfactant, anionic surfactant, co-surfactant and oil phase are selected according to the corresponding mass fraction, and then are sequentially added into water for mixing and stirring to form the microemulsion.

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