Preparation method and application of oil-based emulsification system for selective water plugging

Abstract

The invention discloses a preparation method and application of an oil-based emulsion system for selective water plugging, relating to the technical field of oilfield chemistry. The invention specifically comprises, by mass fraction, 5% to 10% of amphiphilic Janus nanoparticles, 0.3% to 0.5% of an oil-soluble nonionic surfactant, 0.2% to 0.5% of a water-soluble anionic surfactant, 0.1% to 0.2% of an oil-soluble emulsifier, 0.1% to 0.2% of a water-soluble emulsifier, and the remaining components are oil phase components, the sum of all components being 100%. The preparation method comprises the following steps: uniformly stirring the above components; the oil-based emulsion system has low viscosity and good injectability; after being injected into an oil and gas reservoir formation and contacting with a water phase, it is emulsified and thickened in situ; the amphiphilic Janus nanoparticles are irreversibly adsorbed at the oil-water interface to form a strong and highly elastic interface film; the formed emulsion has excellent stability, effectively plugs water production channels, reduces the relative permeability of the water phase, causes little damage to the oil phase, and has the characteristic of selective plugging.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield chemistry, in particular to a preparation method and application of an oil-based emulsified system for selective water plugging. Background Art

[0002] In the later stages of oilfield waterflooding development, the entire block enters a high water-cut phase. Due to capillary forces, injected water flows along flow channels into production wells, resulting in severe reservoir flooding, a low swept coefficient of the injected water, and poor utilization of the remaining oil in the reservoir. Furthermore, water production from gas wells can severely impact well production. Foam drainage and gas recovery are currently key measures for gas well water management. However, drainage measures can only mitigate further contamination of the gas reservoir by water production. Gas well water plugging measures can suppress water production at the point of water production, or even at the source, ultimately restoring gas well production capacity. Currently, water plugging technology has evolved into a landscape dominated by chemical water plugging, with mechanical water plugging, injection well profile control, and deep flooding coexisting. Chemical water plugging technologies can be categorized as polymer gels, foams, microemulsions, inorganic salts, and resins. Based on the water plugging process, they can be divided into selective and non-selective water plugging technologies. Non-selective plugging agents can block both oil and water layers simultaneously without selectivity. The most common type of plugging agent is cement. Due to their lack of selectivity, these plugging agents may block the oil layer during application, causing a sharp drop in oil well production or even complete cessation of production. Selective plugging agents react only with water, not oil or gas. Therefore, they block only the water layer and have minimal impact on oil and gas layers. They significantly reduce water permeability, effectively blocking water while minimizing oil production. During oil and gas reservoir development, the ability to effectively block water production pathways while not affecting oil and gas production pathways, achieving selective profile control and water blocking, is key to improving reservoir recovery.

[0003] Selective water plugging does not require the isolation of the oil layer and the water layer, and the process is relatively simple. Selective plugging agents can be divided into water-based, oil-based, and alcohol-based according to the dispersion medium, and can be divided into granular, precipitated, emulsion, foam, and polymer types according to the water plugging material. Granular plugging agents have the characteristics of high plugging strength and long plugging time, but their injectability is poor and they are only suitable for near-wellbore areas. Precipitation plugging agents have high requirements for the reservoir environment and formation water components. Foam and polymer plugging agents perform poorly in high-temperature environments. In high-temperature and high-salt environments, polymers are prone to water loss, which reduces the plugging strength and ultimately leads to plugging failure. Emulsion plugging agents have the characteristics of strong injectability and good plugging effect.

[0004] In research related to emulsion flooding, W / O emulsions have been shown to have excellent oil displacement capabilities and can significantly increase crude oil recovery. In cores with varying permeabilities, emulsion droplets can aggregate at pore throats, forming a Jamin effect that effectively seals the pores and improves reservoir heterogeneity. This not only has an oil displacement effect but also a profile control effect. Pu Wanfen prepared an anionic-nonionic in-situ emulsifier that can form a W / O emulsion with the oil phase. Using nuclear magnetic resonance technology, the changes in oil and water distribution in the core during emulsifier flooding were studied. The experimental results showed that crude oil in the "large, medium, and small" pores in the core was significantly mobilized, indicating that the emulsifier has a significant emulsification profile control and flooding effect. Chinese patent document CN113122208A discloses an ethylene tar-based water-in-oil emulsion water plugging agent. Ethylene tar is used as the oil phase component of the emulsion, and a surfactant is added and stirred with water to produce a W / O emulsion. This invention can increase the economic added value of ethylene tar, but the system has a high viscosity and lacks selective water plugging capability. It also has poor injection capacity, and after injection into the oil layer, while blocking water channeling, it increases the flow resistance of the oil phase, which is not conducive to crude oil extraction.

[0005] Adding nanoparticles to emulsions can significantly improve their stability. However, due to the presence of a large number of silanol groups on their surfaces, the nanoparticles are polar and highly hydrophilic, resulting in poor solubility in the oil phase. These particles aggregate in the aqueous phase due to interactions, especially in high-temperature, high-salt environments, where the agglomeration effect becomes more pronounced due to the reduced zeta potential. As oilfield exploitation deepens, new requirements are placed on the stability of emulsions in high-temperature, high-salt environments. Existing research on W / O emulsion flooding primarily focuses on heavy oil recovery, the Jamin effect of emulsion droplets, and the entrainment and capture of crude oil by emulsions. Research on emulsion viscosity and stability in high-temperature, high-salt environments is limited. Therefore, based on the current research on emulsion-based selective plugging agents, it is urgent to develop a water channeling plugging system that is selective, highly stable, has good injectability, is highly resistant to heat and salt, and is low-cost and applicable to both oil and gas reservoirs. Summary of the Invention

[0006] In view of this, in order to solve the deficiencies of existing technical conditions, the present invention proposes a preparation method and application of an oil-based emulsified system for selective water plugging.

[0007] The oil-based emulsified system for selective water plugging disclosed in the present invention has the following raw material composition by mass fraction:

[0008] Amphiphilic Janus nanoparticles: 5% to 10%,

[0009] Oil-soluble nonionic surfactant: 0.3% to 0.5%,

[0010] Water-soluble anionic surfactant: 0.2% to 0.5%,

[0011] Oil-soluble emulsifier: 0.1% to 0.2%,

[0012] Water-soluble emulsifier: 0.1% to 0.2%,

[0013] The remaining components are oil phase components;

[0014] The total of the components is 100%.

[0015] One embodiment of the present invention is that the preparation of the amphiphilic Janus nanoparticles comprises the following steps:

[0016] Step S1: treating the silane coupling agent with acid, dividing the acid-treated silane coupling agent into two equal parts, selecting one of the acid-treated silane coupling agent, mixing it with the activated nanoparticles and a solvent, stirring at room temperature at a speed of 500 r / min for 2 hours, adding the other acid-treated silane coupling agent, adjusting the pH to 10, stirring at 60-90° C. for 22 hours, and vacuum drying to obtain modified nanoparticles, wherein the ratio of nanoparticles: solvent: silane coupling agent is 1:8-10:2-6 in parts by weight;

[0017] Step S2: dispersing the obtained modified nanoparticles into liquid paraffin at 70° C., adding distilled water and stirring at a speed of 2500 r / min-3500 r / min for 1 hour, cooling and solidifying the solution, drying the solidified paraffin solution, and adding it to a 0.7%-1% perfluorooctanoic acid ethanol solution to react for 48 hours. After completion, using chloroform to dissolve the paraffin, centrifuging and collecting the nanoparticles and vacuum drying to obtain amphiphilic Janus nanoparticles, wherein the ratio of modified nanoparticles: paraffin: distilled water: perfluorooctanoic acid is 1:4-6:25-35:0.3-0.5 in parts by weight.

[0018] Furthermore, the nanoparticles in step S1 are one of SiO2 nanoparticles, Al2O3 nanoparticles, Ni2O3 nanoparticles, and TiO2 nanoparticles.

[0019] Furthermore, the solvent in step S1 is one of dimethyl sulfoxide, n-butanol, and n-hexane.

[0020] Furthermore, the silane coupling agent is one of silane coupling agent KH-550, silane coupling agent A-151, and silane coupling agent A-710.

[0021] One embodiment of the present invention is that the oil-soluble nonionic surfactant is one of lauramidopropyl betaine LAB-35, alkyl polyglycoside APG-1214, alkyl polyglycoside APG-0810, and alkyl polyglycoside APG-0814, and the water-soluble anionic surfactant is one of fatty alcohol polyoxyethylene ether sodium sulfate AES and fatty alcohol polyoxyethylene ether carboxylic acid AEC9H.

[0022] In one embodiment of the present invention, the oil-soluble emulsifier is one of glyceryl monostearate and Triton X-15, and the water-soluble emulsifier is one of sodium oleate, polyethylene glycol PEG-600, and Tween 80.

[0023] One embodiment of the present invention is that the oil phase component is one of naphtha, kerosene, industrial grade 5# white oil, and low-viscosity crude oil.

[0024] Among them, the preparation method of the oil-based emulsification system for selective water plugging has the following specific preparation steps: taking the oil phase component at 50°C, adding the amphiphilic Janus nanoparticles in the amount shown in the formula ratio, stirring at a speed of 2000r / min-3000r / min until uniform, and then adding the oil-soluble nonionic surfactant, water-soluble anionic surfactant, oil-soluble emulsifier, and water-soluble emulsifier respectively according to the formula ratio, maintaining the speed and temperature and stirring for 4 hours to obtain the oil-based emulsification system.

[0025] In addition, the present invention also provides an application method of an oil-based emulsion system for selective water plugging, wherein the oil-based emulsion system for selective water plugging is injected into oil reservoirs and gas reservoirs in different ways according to different conditions of the oil field. For oil fields with production profile test data, a fixed-point injection method is adopted, and water plugging is achieved after entering the water production channel. For oil fields without production profile test data, it can be injected directly from the oil pipeline channel. By utilizing the selectivity of the oil-based emulsion system itself, after entering the water-containing channel, due to the shear and stretching of the formation, the oil-based emulsion system can be emulsified and thickened in situ with the water phase to generate a W / O emulsion, thereby achieving the plugging of the water production channel. After the emulsion system enters the oil-containing channel and contacts the oil phase, the oil-based emulsion system can undergo a miscible phase effect with the crude oil, improving the fluidity of the crude oil in the pores and reducing the plugging effect on the oil phase. After the emulsified system enters the gas channel, due to the system's low viscosity and volatility under high temperature conditions, it has little impact on the gas channel. The oil-based emulsified system of the present invention can be applied to both oil reservoir water plugging operations and gas reservoir water plugging operations, and has selective water plugging performance, which can achieve better water plugging effects.

[0026] The technical effects of the present invention are:

[0027] (1) The oil-based emulsion system prepared by the present invention has low viscosity and good injectability.

[0028] (2) The oil-based emulsion system prepared by the present invention is injected into the oil and gas reservoir formation and contacts the water phase, where it is emulsified and thickened in situ. The amphiphilic Janus nanoparticles are irreversibly adsorbed at the oil-water interface to form a strong and highly elastic interfacial film. The formed emulsion has excellent stability, effectively blocks the water production channel, and reduces the relative permeability of the water phase.

[0029] (3) After entering the oil-containing channel, the oil-based emulsified system prepared by the present invention can be dissolved in the crude oil, thereby improving the fluidity of the crude oil in the channel, causing less damage to the oil phase, and having the characteristics of selectively blocking water without blocking oil.

[0030] (4) After the oil-based emulsion system prepared by the present invention enters the gas production channel, it has low viscosity, good fluidity and certain volatility under high temperature environment, which causes less damage to the gas phase and has the characteristics of selectively blocking water without blocking gas.

[0031] (5) The oil-based emulsion system prepared by the present invention can be used in both oil and gas reservoirs to plug water channeling operations. DETAILED DESCRIPTION

[0032] The present invention will be further described in detail below with reference to the examples, but the embodiments of the present invention are not limited thereto. The experimental methods used in the following examples are conventional methods unless otherwise specified; the materials, reagents, etc. used therein are all commercially available unless otherwise specified.

[0033] Example 1

[0034] (1) Weigh 200 g of silane coupling agent KH-550 and add it to 1000 g of 0.01 mol / L hydrochloric acid at a mass ratio of 1:5, stir at 500 r / min for 2 min to perform acid treatment, weigh 50 g of pretreated activated SiO2 nanoparticles, add the activated nanoparticles and 600 g of acid-treated silane coupling agent to 400 g of n-butanol under stirring conditions of 500 r / min, stir at room temperature for 2 h, add the remaining 600 g of acid-treated silane coupling agent, adjust the pH to 10 with sodium hydroxide solution, then heat to 60°C and continue stirring for 22 h. After stirring, the reaction solution is centrifuged, washed and dried under vacuum at 40°C to obtain modified SiO2 nanoparticles grafted with hydrophilic amino groups.

[0035] (2) 10 g of modified nanoparticles grafted with hydrophilic amino groups were mixed with 50 g of liquid paraffin at 70 ° C, 300 g of distilled water was added, and the mixture was stirred at 3000 r / min for 1 h. After the stirring was completed, the mixture was immediately cooled and solidified to obtain a solidified paraffin solution. After vacuum drying at 40 ° C, the solution was added to 500 g of 0.7% perfluorooctanoic acid ethanol solution and reacted at room temperature for 48 h. After the reaction was completed, the paraffin droplets were filtered out, the paraffin was completely dissolved with chloroform, and the nanoparticles were collected by centrifugation. After vacuum drying, the amphiphilic Janus nanoparticles were obtained.

[0036] (3) 5 g of amphiphilic Janus nanoparticles were added to 94.3 g of crude oil with a viscosity of 12.6 mPa.s, and stirred at a speed of 2000 r / min at 50 ° C. Then, 0.3 g of alkyl polyglycoside APG-1214, 0.2 g of fatty alcohol polyoxyethylene ether sodium sulfate AES, 0.1 g of monostearate, and 0.1 g of sodium oleate were added respectively. The speed was kept constant and the temperature was stirred for 4 h to obtain the oil-based emulsification system for selective water plugging.

[0037] Example 2

[0038] (1) Weigh 300 g of silane coupling agent A-151 and add it to 1500 g of 0.01 mol / L hydrochloric acid at a mass ratio of 1:5, stir at 500 r / min for 2 min to perform acid treatment, weigh 50 g of pretreated activated TiO2 nanoparticles, add the activated nanoparticles and 900 g of acid-treated silane coupling agent to 500 g of dimethyl sulfoxide under stirring conditions of 500 r / min, stir at room temperature for 2 h, add the remaining 900 g of acid-treated silane coupling agent, adjust the pH to 10 with sodium hydroxide solution, then heat to 60°C and continue stirring for 22 h. After stirring, the reaction solution is centrifuged, washed and dried under vacuum at 40°C to obtain modified TiO2 nanoparticles grafted with hydrophilic amino groups.

[0039] (2) 10 g of modified nanoparticles grafted with hydrophilic amino groups were mixed with 60 g of liquid paraffin at 70° C., 270 g of distilled water was added, and the mixture was stirred at 2700 r / min for 1 h. After the stirring was completed, the mixture was immediately cooled and solidified to obtain a solidified paraffin solution. After vacuum drying at 40° C., the solution was added to 600 g of a 0.7% perfluorooctanoic acid ethanol solution and reacted at room temperature for 48 h. After the reaction was completed, the paraffin droplets were filtered out, the paraffin was completely dissolved with chloroform, and the nanoparticles were collected by centrifugation. After vacuum drying, the amphiphilic Janus nanoparticles were obtained.

[0040] (3) 5 g of amphiphilic Janus nanoparticles were added to 94.3 g of industrial grade 5# white oil, and stirred evenly at a speed of 2000 r / min at 50 ° C. Then, 0.3 g of alkyl polyglycoside APG-0810, 0.2 g of fatty alcohol polyoxyethylene ether sodium sulfate AES, 0.1 g of monostearate, and 0.1 g of Tween 80 were added respectively. The speed was kept constant and the temperature was stirred for 4 hours to obtain the oil-based emulsification system for selective water plugging.

[0041] Example 3

[0042] (1) Weigh 200 g of silane coupling agent A-710 and add it to 1000 g of 0.01 mol / L hydrochloric acid at a mass ratio of 1:5, and stir at 500 r / min for 2 min to perform acid treatment. Weigh 50 g of pretreated activated Ni2O3 nanoparticles, add the activated nanoparticles and 600 g of acid-treated silane coupling agent to 500 g of n-hexane under stirring at 500 r / min, and stir at room temperature for 2 h. Add the remaining 600 g of acid-treated silane coupling agent, adjust the pH to 10 with sodium hydroxide solution, then heat to 90°C and continue stirring for 22 h. After stirring, the reaction solution is centrifuged, washed and dried under vacuum at 40°C to obtain modified Ni2O3 nanoparticles grafted with hydrophilic amino groups.

[0043] (2) 10 g of modified nanoparticles grafted with hydrophilic amino groups were mixed with 60 g of liquid paraffin at 70°C, 350 g of distilled water was added, and the mixture was stirred at 3000 r / min for 1 h. After the stirring was completed, the mixture was immediately cooled and solidified to obtain a solidified paraffin solution. After vacuum drying at 40°C, the solution was added to 400 g of a 1% perfluorooctanoic acid ethanol solution and reacted at room temperature for 48 h. After the reaction was completed, the paraffin droplets were filtered out, the paraffin was completely dissolved with chloroform, and the nanoparticles were collected by centrifugation. After vacuum drying, the amphiphilic Janus nanoparticles were obtained.

[0044] (3) 10 g of amphiphilic Janus nanoparticles were added to 88.6 g of naphtha, and stirred at 2000 r / min at 50 ° C. Then, 0.5 g of lauramide propyl betaine LAB-35, 0.5 g of fatty alcohol polyoxyethylene ether carboxylic acid AEC9H, 0.2 g of Triton X-15, and 0.2 g of polyethylene glycol PEG-600 were added respectively. The speed was kept constant and the temperature was stirred for 4 hours to obtain the oil-based emulsification system for selective water plugging.

[0045] Comparative Example 1

[0046] The raw material dosage and specific operation steps of this comparative example are basically the same as those of Example 1, except that glyceryl monostearate and sodium oleate are not added in step (3), and the amount of crude oil added is adjusted to 94.5 g.

[0047] To further illustrate the product effect, the performance of the product of the present invention will be evaluated in conjunction with the examples below.

[0048] 1. Evaluation of emulsification and viscosity increasing performance

[0049] 100 ml of solution of each of the above-mentioned embodiments and comparative examples was prepared in a beaker according to a water content of 30%, 40%, 50%, 60%, 70%, and 80%. The beaker was placed in a DF-101S heat-collecting constant temperature heating magnetic stirrer, the temperature was set to 90° C., and stirring was carried out at a speed of 500 r / min for 0.5 h. The viscosity of the solution was measured at 90° C. using a Brookfield DV-Ⅲ+Pro rotational viscometer. The viscosity of the simulated formation water was 3.6 mPa.s, the viscosity of the crude oil in Example 1 was 12.6 mPa.s, the viscosity of the industrial grade 5# white oil in Example 2 was 5.7 mPa.s, and the viscosity of the naphtha in Example 3 was 6.7 mPa.s. The viscosity of the crude oil in Comparative Example 1 was the same as that in Example 1. The overall test results are shown in Table 1:

[0050] Table 1 Emulsification and viscosity increasing performance test results

[0051]

[0052]

[0053] The viscosity increase rate Z is calculated based on formula (1). The greater the viscosity increase rate, the higher the emulsion strength:

[0054]

[0055] In formula (1), Z is the viscosity increase rate (%), μ e is the viscosity of the emulsion, μ0 is the viscosity of the simulated formation water, mPa.s.

[0056] The above data show that the viscosity of the emulsion formed by the emulsion system in Example 1 and water is significantly improved compared to both simulated formation water and crude oil. When the water content is less than 60%, the emulsion exhibits pseudoplastic fluid properties, and the apparent viscosity increases with increasing water content. When the water content exceeds 60%, it exhibits dilatant fluid properties, and the apparent viscosity gradually decreases with increasing water content. The W / O emulsion with a water content of 60% has the highest viscosity and the best emulsification and thickening effect. The W / O emulsion formed by the oil-based emulsion system in Example 1 when it meets water has a sufficiently strong plugging ability. After entering the water production channel, the emulsion system formed with water has a high viscosity and can effectively block the water channel.

[0057] The viscosity of the emulsion generated by the emulsion system in Example 2 and water is also significantly improved compared with the simulated formation water and 5# white oil. When the water content is 60%, the viscosity increase rate reaches 302.8%. The viscosity of the emulsion formed is higher than that of formation water, which proves that the W / O emulsion formed by the oil-based emulsion system in Example 2 when it meets water has a sufficiently strong blocking ability. After entering the water production channel, the emulsion system formed with water has a high viscosity and can effectively block the water channel. However, compared with the emulsion system in Example 1, the emulsion system with crude oil as the oil phase in Example 1 has better performance.

[0058] As for the emulsification system in Example 3, the viscosity increase rate of the configured emulsification system is also lower than that of the emulsification system with crude oil as the oil phase component in Example 1. When the water content of the W / O emulsion is 60%, the viscosity is the highest and the emulsification and viscosity increase effect is good. This shows that the W / O emulsion formed by the oil-based emulsion system of this embodiment when it comes into contact with water also has good blocking ability and can effectively block water channeling channels.

[0059] For Comparative Example 1, the viscosity of the emulsion generated by the emulsification system and water is significantly improved compared with both the simulated formation water and crude oil. However, compared with Example 1, since no corresponding emulsifier is added, the overall viscosity increase rate of the system in Comparative Example 1 is poor compared with the emulsification system containing an emulsifier.

[0060] 2. Emulsion stability evaluation

[0061] 100 ml of the emulsified systems in the above examples and comparative examples were prepared at water contents of 30%, 40%, 50%, 60%, 70%, and 80% in beakers and placed in a DF-101S heat-collecting constant-temperature magnetic stirrer. The temperature was set at 90°C and stirred at 500 r / min for 0.5 h. The mixture was poured into a graduated cylinder and placed in a constant-temperature oven at 90°C. The amount of water precipitated from the emulsion was recorded at different times. The water precipitate rate (%) of the emulsions with different water contents under high-temperature conditions is shown in Table 2:

[0062] Table 2 Emulsion water separation rate test results

[0063]

[0064] Among them, the water separation rate R is calculated based on formula (2): w Among them, the smaller the water separation rate, the higher the stability of the emulsion.

[0065]

[0066] In formula (2), R w is the water separation rate (%), V t V is the amount of water separated from the emulsion at a certain moment, mL. w is the total volume of water in the emulsion, mL.

[0067] Based on the above data, the water extraction rate of the W / O emulsion gradually increases at 90°C, with the rate increasing with prolonged heating. In Example 1, the emulsion system with a water content of 30% had a water extraction rate of 14.3% after 15 days of heating. The system with a water content of 60% showed the best stability, with a water extraction rate of 12.1% after 15 days of heating. In Example 2, the emulsion system with a water content of 30% showed the best stability, with a water extraction rate of 17.8% after 15 days of heating. The system with a water content of 60% showed the best stability, with a water extraction rate of 14.4% after 15 days of heating. This demonstrates that the oil-based emulsion system in Example 1, when exposed to water, forms an emulsion with good stability at high temperatures. The water-in-oil emulsion formed after injection into the formation and into the water-bearing channel can maintain long-term stability.

[0068] In Example 3, the water content of the emulsion system was 30%, and the water separation rate was 16.6% after heating for 15 days. The stability of the system with a water content of 60% was the best, and the water separation rate was 13.5% after heating for 15 days. Compared with the emulsification system in Example 1, the emulsification system in Example 3 had a poorer stability effect. The emulsification system with crude oil as the oil phase had better stability under high temperature environment.

[0069] The stability of the system in the comparative example with a water content of 60% is the best, and the water extraction rate is 15.4% after heating for 15 days. The stability of the system in comparative example 1 is poor under high temperature environment, and the water extraction rate increases to a certain extent. This shows that the system with the addition of emulsifier in Example 1 can enhance the stability of the system under high temperature environment.

[0070] 3. Sealing performance test

[0071] Three cores with different permeabilities, namely 500mD, 50mD and 5mD, were selected and dried in a 90℃ oven, and the pore volume and porosity of the cores were calculated respectively. The cores were placed in a core holder and nitrogen flooding, water flooding and oil flooding experiments were carried out on the three cores with different permeabilities in a constant temperature oven at 90℃.

[0072] The initial gas permeability was calculated in the gas flooding experiment, and then 0.7 PV of the emulsion system in each of the above-mentioned embodiments and comparative examples was injected into the core, and the gas flooding was continued. The gas permeability after the addition of the emulsion system was calculated;

[0073] In a water flooding experiment, the core was flooded with water, and the initial water permeability was calculated after the pressure stabilized. 0.7 PV of the emulsified system of each of the above-mentioned embodiments and comparative examples was injected into the core, and then water flooding was continued. After the pressure stabilized, the water permeability of the core was calculated;

[0074] In the oil displacement experiment, crude oil was injected into the core, and the initial oil phase permeability was calculated after the pressure stabilized. Then, 0.7 PV of the emulsion system of each of the above-mentioned embodiments and comparative examples was injected into the core, and crude oil was continued to be injected. After the pressure stabilized, the oil phase permeability was calculated. The plugging effect of the oil-based emulsion system in the oil, gas, and water channels and the plugging strength under different permeabilities were investigated. The test results are shown in Tables 3 to 5 respectively:

[0075] Table 3 Core flow test results with a permeability of 500 mD

[0076]

[0077]

[0078] Table 4 Core flow test results with a permeability of 50 mD

[0079]

[0080] Table 5 Core flow test measurement results with a permeability of 5 mD

[0081]

[0082]

[0083] The above results show that for three cores with different permeabilities of 500mD, 50mD and 5mD, the oil-based emulsification system can maintain a plugging efficiency of more than 50% while maintaining a low impact on the permeabilities of gas phase channels and oil phase channels, thereby achieving efficient selective plugging of water phase channels. In addition, combined with the comparative examples, it can be seen that for the system in the comparative example without using an emulsifier, its plugging efficiency is significantly lower than the plugging efficiency of the system using an emulsifier in the present invention, further proving that the oil-based emulsification system proposed in the present invention has a good plugging effect.

[0084] Based on the above experimental data, it can be seen that the oil-based emulsion system can effectively block the water phase, with the blocking rate for cores with different permeabilities exceeding 60%. Depending on the specific conditions of the oilfield, different injection methods are used in oil and gas reservoirs. For oilfields with production profile test data, a fixed-point injection method is used, and water blocking is achieved after entering the water production channel. For oilfields without production profile test data, direct injection through the oil pipeline channel can be used. Utilizing the selectivity of the oil-based emulsion system, after entering the water-bearing channel, due to the shear and stretching effects of the formation, the oil-based emulsion system can emulsify and increase viscosity with the water phase in situ, forming a W / O emulsion, which can block the water production channel.

[0085] At the same time, it has minimal impact on the permeability of gas and oil phase channels, achieving the effects of blocking water without blocking gas, and blocking water without blocking oil. Its mechanism of action is as follows: Because the particle size of the oil-based emulsion system is at the nanoscale, it can enter channels with smaller pore sizes. Upon contact with the water phase, the emulsifier undergoes in-situ emulsification and viscosity increase, and the modified nanoparticles can be stably dispersed in the oil phase components. Amphiphilic Janus nanoparticles undergo irreversible adsorption at the oil-water interface, forming a strong, highly elastic interfacial film. The resulting emulsion has excellent stability, effectively blocking water-producing channels. Due to the high stability of the formed W / O emulsion, it can still achieve long-term blocking of water flow channels in high-temperature, high-salt environments. Once the oil-based emulsion system enters the oil-containing channel, it can dissolve with the crude oil, improving its fluidity and minimizing damage to the oil phase channel, thus achieving the effect of blocking water without blocking oil in the reservoir. When the oil-based emulsion system enters the gas channel, since the system has low viscosity, strong fluidity and the oil phase components can volatilize under high temperature environment, it has little impact on the gas channel. After being injected into the gas reservoir for water blocking operation, it has little impact on the gas production channel, achieving the effect of blocking water without blocking gas. The oil-based emulsion system in each embodiment can be applied to both oil reservoirs and gas reservoirs.

[0086] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any changes or substitutions that can be easily conceived by a person skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included in the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be based on the scope of protection of the claims.

Claims

1. An oil-based emulsified system for selective water plugging, characterized in that: The raw material composition is as follows in terms of mass fraction: Amphiphilic Janus nanoparticles: 5% to 10%, Oil-soluble nonionic surfactant: 0.3% to 0.5%, Water-soluble anionic surfactant: 0.2% to 0.5%, Oil-soluble emulsifier: 0.1% to 0.2%, Water-soluble emulsifier: 0.1% to 0.2%, The remaining components are oil phase components; The sum of all components is 100%; The preparation of the amphiphilic Janus nanoparticles comprises the following steps: Step S1: treating the silane coupling agent with acid, dividing the acid-treated silane coupling agent into two equal parts, selecting one of the acid-treated silane coupling agent, mixing it with the activated nanoparticles and a solvent, stirring at room temperature at a speed of 500 r / min for 2 hours, adding the other acid-treated silane coupling agent, adjusting the pH to 10, stirring at 60-90° C. for 22 hours, and vacuum drying to obtain modified nanoparticles, wherein the ratio of nanoparticles: solvent: silane coupling agent is 1:8-10:2-6 in parts by weight; Step S2: dispersing the obtained modified nanoparticles into liquid paraffin at 70° C., adding distilled water and stirring at a speed of 2500 r / min-3500 r / min for 1 hour, cooling and solidifying the solution, drying the solidified paraffin solution, and adding it to a 0.7%-1% perfluorooctanoic acid ethanol solution to react for 48 hours. After completion, dissolving the paraffin with chloroform, collecting the nanoparticles by centrifugation and vacuum drying to obtain amphiphilic Janus nanoparticles, wherein the ratio of modified nanoparticles: paraffin: distilled water: perfluorooctanoic acid is 1:4-6:25-35:0.3-0.5 in parts by weight; The silane coupling agent is silane coupling agent KH-550; The oil-soluble nonionic surfactant is one of lauramidopropyl betaine LAB-35, alkyl polyglycoside APG-1214, alkyl polyglycoside APG-0810, and alkyl polyglycoside APG-0814; the water-soluble anionic surfactant is one of fatty alcohol polyoxyethylene ether sodium sulfate AES and fatty alcohol polyoxyethylene ether carboxylic acid AEC9H; The oil-soluble emulsifier is one of glyceryl monostearate and Triton X-15, and the water-soluble emulsifier is one of sodium oleate, polyethylene glycol PEG-600 and Tween 80.

2. The oil-based emulsified system for selective water plugging according to claim 1, characterized in that: The nanoparticles in step S1 are one of SiO2 nanoparticles, Al2O3 nanoparticles, Ni2O3 nanoparticles, and TiO2 nanoparticles.

3. The oil-based emulsified system for selective water plugging according to claim 1, characterized in that: The solvent in step S1 is one of dimethyl sulfoxide, n-butanol, and n-hexane.

4. The oil-based emulsified system for selective water plugging according to claim 1, characterized in that: The oil phase component is one of naphtha, kerosene, industrial grade 5# white oil, and low-viscosity crude oil, wherein the viscosity of the low-viscosity crude oil ranges from 10 mPa·s to 50 mPa·s.

5. The method for preparing an oil-based emulsified system for selective water plugging according to claim 1, characterized in that: The following steps are involved: Take the oil phase component and add the amphiphilic Janus nanoparticles in the amount shown in the formula ratio at 50°C, stir at a speed of 2000r / min-3000r / min until uniform, then add the oil-soluble nonionic surfactant, water-soluble anionic surfactant, oil-soluble emulsifier, and water-soluble emulsifier respectively according to the formula ratio, maintain the speed and constant temperature and stir for 4 hours to obtain the oil-based emulsification system.

6. An application method of an oil-based emulsified system for selective water plugging, characterized in that: The selective water plugging oil-based emulsified system prepared by the method of claim 5 is injected into the water production channel at a fixed point for water plugging in oil fields with production profile test data, and is injected directly from the oil pipe for water plugging in oil fields without production profile test data.

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