Surfactant system optimization method and in-situ emulsification assisted CO2 oil displacement method

Abstract

The invention discloses a surfactant system optimization method and an in-situ emulsification assisted CO2 oil displacement method. The surfactant system optimization method comprises the following steps: aiming at each to-be-selected surfactant system, preparing a surfactant system aqueous solution by using target oilfield injection water, and measuring the oil-water interfacial tension of the aqueous solution under an oil reservoir condition when CO2 reaches a dissolution equilibrium state; measuring the water phase precipitation rate of the surfactant system emulsion under the condition that CO2 reaches the dissolution equilibrium state under the oil reservoir condition; the unsaturated oil and saturated oil double-tube parallel core is used for carrying out seepage law testing and oil displacement testing on the surfactant system water solution, and first seepage resistance change data in the seepage law testing process and second seepage resistance change data in the oil displacement testing process are obtained; and according to the oil-water interfacial tension, the water phase precipitation rate, the first seepage resistance change data and the second seepage resistance change data, a surfactant system with the optimal displacement effect is screened. The method can be used for developing an in-situ emulsification surfactant system with a controllable CO2 profile control and flooding limit.

Description

Technical Field

[0001] The present invention relates to the technical field of oilfield chemistry and oilfield development, in particular to a surfactant system optimization method and an in-situ emulsification-assisted CO 2 Oil recovery method. Background Art

[0002] Affected by CO 2 Low density and low viscosity, poor reservoir properties and strong heterogeneity of low permeability oil reservoirs in my country, as well as the influence of cross-flow channels such as natural or artificial fractures, make CO 2 Viscous fingering, gravity overlay and gas channeling greatly reduce the CO 2 The effect on the utilization of crude oil (Yuan Shiyi et al. Petroleum Exploration and Development, 2022, 49(04): 828-834.). Even if some domestic oil fields can achieve CO 2 Miscible flooding conditions, due to the CO 2 Relative crude oil surplus or low well pressure, there is a probability that immiscible CO2 may exist in the oil layer around the injection and production wells. 2 Therefore, efficient mobility control technology is an important way to improve the CO 2 The key to oil recovery rate.

[0003] Low permeability reservoir CO 2 One of the fundamental reasons for the difficulty in fluidity control engineering is to control CO 2 The means of fluidity are limited. Existing fluidity control technologies mostly rely on gas-water alternation, foam, ASP alternating gas injection, etc. to control CO 2 For water-gas alternation technology (WAG), its mechanism is to reduce the gas saturation by injecting water, thereby achieving the purpose of reducing the mobility ratio, stabilizing the displacement front, thereby inhibiting viscous fingering, and expanding CO 2 Liao Xinwei (Journal of Shaanxi University of Science and Technology (Natural Science), 2016, 34(06):120-124.), Gao Yuncong (Petroleum Exploration and Development, 2014, 41(01):79-85.) and other researchers have conducted a series of studies on this technology. This technology is currently widely used in mines and is relatively mature. However, this technology can prevent CO 2 The gas blowby capacity is limited and the oil washing efficiency cannot be improved.

[0004] Regarding foam plugging technology, Boud et al. (Gas drive oil recovery process: US, US2866507[P]. 1958.) first applied for a patent in 1958 for using foam to improve the effect of gas drive development. Foam plugging technology mainly relies on the deformation of the bubble interface to produce the Jamin effect on the liquid flow, and the Jamin effect can be superimposed. When the foam enters the formation, it preferentially enters the high permeability area. The Jamin effect gradually increases the flow resistance, thereby delaying gas channeling, effectively improving the sweep coefficient, and replenishing the formation energy. In addition, the foam system generally has the ability to reduce interfacial tension, which can increase the oil washing efficiency and thus improve the crude oil recovery rate. As an extension of the water-gas alternation technology, the theoretical research on foam plugging technology has been relatively mature, and it has been applied in the field with remarkable results. However, due to CO 2 Compared with air / water, nitrogen / water and other interfaces, it is more difficult to adsorb active substances on the CO / water interface. 2 Compared with air, nitrogen and other systems, foam is less stable. In addition, it is difficult for the foam system to reduce both the gas-liquid surface tension and the oil-water interfacial tension. 2 / Water has the disadvantages of being difficult to select surfactants on the surface, short action time, short action distance, and difficult to balance expanding the impact and improving the oil washing effect.

[0005] Regarding ASP alternating gas injection (ASPAG) technology, Kumar S (Journal of Petroleum Science and Engineering, 2017, 157: 696-715.) reviewed the ternary composite system alternating gas injection (ASPAG) to further improve the recovery rate by reducing interfacial tension, changing contact angle, increasing water phase viscosity, adjusting phase behavior and generating foam. The injection system in ASPAG includes various combinations of alkali, surfactant and polymer. Researchers usually emphasize that the system has ultra-low interfacial tension to improve oil washing efficiency, increases water phase viscosity through polymer and generates foam through surfactant to expand the swept volume, and weakens the water lock effect by changing the contact angle. However, the study of emulsions in this technology usually focuses on the effect of oil-water droplets on foam stability, without considering the emulsion blocking pore throats and thus controlling CO 2 The role of fluidity is less considered in terms of polymer resistance to acid and high temperature as well as low permeability and injectability.

[0006] It can be seen that CO 2 Controlling CO during oil recovery 2 There have been a lot of studies on technologies to improve oil recovery, but they are limited by CO 2 The existing mobility control system and technology are limited by the characteristics of the CO / water interface, the temperature and acid environment, and the injection pore size. 2Long-term and continuous deep profile control is difficult. Summary of the invention

[0007] In order to at least partially solve the above technical problems existing in the prior art, the inventors have made the present invention, and provide a surfactant system optimization method and an in-situ emulsification assisted CO 2 Oil recovery method, capable of developing CO 2 In-situ emulsifying surfactant system with controllable displacement limit.

[0008] In a first aspect, an embodiment of the present invention provides a surfactant system optimization method, comprising:

[0009] For each surfactant system to be selected, an aqueous surfactant solution was prepared using injection water from the target oil field, and the aqueous solution was measured under reservoir conditions in CO 2 Oil-water interfacial tension at solubility equilibrium; measuring CO under reservoir conditions 2 The water phase precipitation rate of the surfactant system emulsion that reaches the dissolution equilibrium state; using unsaturated oil and saturated oil dual-tube parallel cores to conduct seepage law test and oil displacement test on the surfactant system aqueous solution, and obtain the first seepage resistance change data during the unsaturated oil seepage law test and the second seepage resistance change data during the saturated oil oil displacement test;

[0010] According to the oil-water interfacial tension, water phase precipitation rate, the first seepage resistance change data and the second seepage resistance change data, the surfactant system with the best displacement effect is screened.

[0011] In a second aspect, an embodiment of the present invention provides an in-situ emulsification-assisted CO 2 Oil recovery methods, including:

[0012] The surfactant system selected by the above method was used to carry out in-situ emulsification-assisted CO 2 Oil recovery.

[0013] The beneficial effects of the above technical solution provided by the embodiment of the present invention include at least:

[0014] (1) The surfactant system optimization method provided in the embodiment of the present invention obtains the oil-water interfacial tension, water phase precipitation rate, first seepage resistance change data and second seepage resistance change data of each candidate surfactant system through a series of experiments, thereby screening out the surfactant system with the best displacement effect. 2 In-situ emulsifying surfactant system with controllable displacement limit.

[0015] (2) Compared with the existing water-gas alternation technology, the in-situ emulsification-assisted CO 2The oil displacement method can use the surfactant-containing water plug to emulsify the oil and water in situ to plug the pore throat and expand the CO 2 The sweep coefficient capability is significantly stronger than that of water-gas alternation technology.

[0016] (3) Compared with the existing foam plugging technology, the in-situ emulsification-assisted CO 2 The oil displacement method can not only significantly reduce the interfacial tension and improve the oil washing efficiency, but also avoid the CO 2 The problem of the difficulty in stabilizing the characteristics of the oil / water interface is that the oil / water interface always exists during the oil displacement process and the two phases are very different. It is easy to generate an oil-water emulsion with controllable interfacial film strength and stability in the pores, and hinder the CO 2 , water, and oil flow, and has the characteristics of less reservoir damage, higher injectivity, and stronger acid and temperature resistance, achieving CO 2 Long-term and continuous deep profile control is suitable for the mobility control needs of miscible and immiscible oil recovery, effectively solving the CO 2 The problem of limited mobility control methods has a very broad scope of application and prospects, promoting the CO 2 Storage and green, economical and efficient development.

[0017] (4) Compared with the existing ASP alternating gas injection technology, the in-situ emulsification assisted CO 2 The oil displacement method takes into account the advantages of ASP alternating gas injection and innovatively proposes a technical method of in-situ oil-water emulsification to plug CO2. The surfactant used has the characteristics of high injectability and strong acid and temperature resistance. In-situ emulsification can deeply adjust the profile with less damage to the reservoir, which is in sharp contrast to the ASP alternating gas injection technology that does not consider the plugging performance of the emulsion.

[0018] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the written description, claims, and drawings.

[0019] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0020] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0021] Figure 1 This is a flow chart of the method for optimizing the surfactant system in Example 1 of the present invention;

[0022] Figure 2 This is the interfacial tension diagram of three betaines in Example 2 of the present invention;

[0023] Figure 3 The stability diagram of three betaine emulsions expressed by the water phase precipitation rate in Example 2 of the present invention;

[0024] Figure 4 The surfactant system of the oil-containing / oil-free condition in Example 2 of the present invention is assisted by CO 2 Drive flow diagram; Figure 5 This is a diagram of injection-production pressure difference (seepage resistance) of surfactant systems with different strengths in Example 2 of the present invention;

[0025] Figure 6 The surfactant system of different strengths in Example 2 of the present invention -CO 2 Recovery factor diagram of dual-tube parallel chemical flooding. DETAILED DESCRIPTION

[0026] The exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0027] It should be understood that the terms described in the present invention are only for describing special embodiments and are not intended to limit the present invention. In addition, for the numerical range in the present invention, it should be understood that each intermediate value between the upper and lower limits of the scope is also specifically disclosed. Each smaller range between the intermediate value in any stated value or stated range and any other stated value or intermediate value in the described range is also included in the present invention. The upper and lower limits of these smaller ranges can be independently included or excluded in the scope.

[0028] Unless otherwise indicated, all technical and scientific terms used herein have the same meanings as commonly understood by those skilled in the art to which the invention belongs. Although the present invention describes only preferred methods and materials, any methods and materials similar or equivalent to those described herein may also be used in the implementation or testing of the present invention. All documents mentioned in this specification are incorporated by reference to disclose and describe the methods and / or materials related to the documents. In the event of a conflict with any incorporated document, the content of this specification shall prevail.

[0029] In the description of the present invention, it should be noted that the terms "include", "including", "have", "contain" and the like are open terms, meaning including but not limited to.

[0030] Embodiment 1

[0031] Embodiment 1 of the present invention provides a surfactant system optimization method, referring to Figure 1 As shown, the following steps are included:

[0032] Step S11: For each surfactant system to be selected, a surfactant system aqueous solution is prepared using injection water from the target oil field, and the aqueous solution is measured under reservoir conditions in CO 2 Oil-water interfacial tension at solubility equilibrium; measuring CO under reservoir conditions 2 The water phase precipitation rate of the surfactant system emulsion that reaches the dissolution equilibrium state; use unsaturated oil and saturated oil dual-tube parallel cores to conduct seepage law test and oil displacement test on the surfactant system aqueous solution, and obtain the first seepage resistance change data during the unsaturated oil seepage law test and the second seepage resistance change data during the saturated oil oil displacement test.

[0033] The surfactant system is any one of zwitterionic, anionic and nonionic, nonionic and anionic surfactants, or a surfactant system composed of at least two of them. When the surfactant system includes two or more single surfactants, different configuration ratios of the single surfactants form different surfactant systems.

[0034] (1) Oil-water interfacial tension measurement.

[0035] The target oilfield injection water was used to prepare a surfactant system aqueous solution with a mass concentration of 0.1% to 0.4%. The aqueous solution was measured under reservoir conditions in CO 2 The oil-water interfacial tension when the solution equilibrium is reached.

[0036] The surfactant system with the ultra-low interfacial tension is preferred, but the one with the lowest oil-water interfacial tension is not necessarily preferred.

[0037] (2) Emulsion stability test.

[0038] The experimental water was the injection water of the target oil field, and the experimental oil was the simulated oil prepared according to the dehydrated crude oil of the target oil field. The volume ratio of the injected water and the simulated oil was set to 1:1. The CO was measured under reservoir conditions by the bottle test method. 2 The water phase precipitation rate of the surfactant system emulsion that reaches the dissolution equilibrium state is used to characterize the stability of the emulsion.

[0039] Optionally, an oil-water interface dilation rheology test can be performed to measure the CO2 content of the surfactant system aqueous solution under reservoir conditions. 2 The dilation rheological test of the oil-water interface under the dissolution equilibrium state is carried out to obtain the interfacial film strength; the surfactant system whose interfacial film strength meets the set conditions is screened.

[0040] The greater the strength of the interfacial film, the better the plugging performance; the lower the water phase precipitation rate, the higher the stability and the stronger the plugging performance. Through the oil-water interface expansion rheology test and emulsion stability test, the plugging ability of the surfactant system was preliminarily determined.

[0041] (3) Seepage resistance change data test.

[0042] Simulating the target reservoir conditions, the seepage law test and oil displacement test of the surfactant system were carried out using unsaturated oil and saturated oil dual-tube parallel cores. The injection stage included water flooding, CO 2 flooding, gas-water alternating flooding, surfactant system aqueous solution gas-liquid alternating flooding and subsequent CO 2 The surfactant system was further analyzed by analyzing the system diversion rate, seepage resistance, gas-liquid ratio at the production end and recovery factor.

[0043] In the above-mentioned seepage and oil displacement process, the injection rate, injection timing, back pressure and slug size are not strictly limited and can be determined according to actual conditions.

[0044] The above-mentioned in-situ emulsifying surfactant system is suitable for oil reservoirs under various working conditions, especially suitable for oil reservoirs under the following working conditions: average permeability below 100mD; reservoir temperature 45℃-120℃; reservoir crude oil viscosity at 90℃ is 1mPa.s-1000mPa.s.

[0045] Step S12: Screening the surfactant system with the best displacement effect according to the oil-water interfacial tension, the water phase separation rate, the first seepage resistance change data and the second seepage resistance change data.

[0046] Screen the surfactant system that meets the following conditions as the surfactant system with the best displacement effect:

[0047] (1) The oil-water interfacial tension is lower than the set interfacial tension threshold.

[0048] (2) The water phase precipitation rate is lower than the set precipitation rate threshold.

[0049] (3) The difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage in the first seepage resistance change data is less than the set first seepage resistance difference threshold, and the difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage in the second seepage resistance change data is greater than the set second seepage resistance difference threshold.

[0050] That is, in the first seepage resistance change data, the seepage resistance in the gas-liquid alternating drive stage is close to that in the gas-water alternating drive stage, and in the second seepage resistance change data, the seepage resistance in the gas-liquid alternating drive stage is clearly higher than that in the gas-water alternating drive stage.

[0051] (4) In the second seepage resistance change data, the seepage resistance in the gas-liquid alternating drive stage is higher than the set seepage resistance threshold.

[0052] According to the first seepage resistance change data obtained during the oil displacement test, the system flooding intensity is ranked according to the seepage resistance in the gas-liquid alternating flooding stage. If the seepage resistance in the gas-liquid alternating flooding stage is higher, the system CO 2 The stronger the regulation and drive capability, the better the performance, and vice versa.

[0053] The surfactant system optimization method provided in the first embodiment of the present invention obtains the oil-water interfacial tension, water phase precipitation rate, first seepage resistance change data and second seepage resistance change data of each candidate surfactant system through a series of experiments, thereby screening out the surfactant system with the best displacement effect. 2 In-situ emulsifying surfactant system with controllable displacement limit.

[0054] In some embodiments, the surfactant system may also be subjected to CO 2 Surfactant system flooding -CO 2 Microscopic visualization of oil displacement experiment, obtained surfactant system to block CO 2 microscopic process.

[0055] Embodiment 2

[0056] Embodiment 2 of the present invention provides a specific application of a surfactant system optimization method, including:

[0057] 1. The experimental water is the on-site injection water of a certain test area, and three surfactants, long-chain hydroxypropyl betaine type 1, betaine type 2, and betaine type 3, are prepared with a mass concentration of 0.3wt%.

[0058] 2. Measurement of CO under reservoir conditions 2 The oil-water interfacial tension when the dissolution equilibrium is reached, the experimental temperature is 70℃, and the experimental oil is a simulated oil prepared by dehydrating crude oil in a certain test area. The results are as follows Figure 2 As shown, the two surfactants, betaine type 1 and betaine type 3, can achieve ultra-low interfacial tension, and are expected to be able to effectively emulsify in situ and have high oil washing efficiency.

[0059] 3. The in-situ emulsified surfactant systems of betaine type 1, betaine type 2 and betaine type 3 were subjected to CO 2 The stability test of the emulsion by the bottle test method under reservoir conditions when the solubility equilibrium is reached is carried out. The experimental temperature is 70℃, the experimental water is the water injected on site in a certain test area, and the experimental oil is the simulated oil prepared by dehydrated crude oil in a certain test area. The oil-water ratio is 1:1 (V / V). The emulsion is generated by shaking at a constant frequency for 100 times. The results are shown in the figure. Figure 3As shown, according to the ranking of emulsion stability, betaine type 3, betaine type 1, and betaine type 2 are identified as strong emulsification, medium emulsification, and weak emulsification, respectively, and the expected emulsion plugging ability ranking is betaine type 3 > betaine type 1 > betaine type 2.

[0060] 4. Simulate the target reservoir conditions, use unsaturated oil and saturated oil double-tube parallel cores to test the seepage law and oil displacement of a series of in-situ emulsified surfactant systems, the core gas permeability: high permeability 150mD, low permeability 7mD, experimental temperature 70℃, experimental water is the field injection water of a certain test area, the core outlet back pressure is 10MPa, the injection system is 0.3wt% betaine 3 strong emulsification system, the injection method is water drive to 98% water content + CO 2 Drive until gas-liquid ratio>2000+0.1PV gas-liquid alternation 4 times+subsequent CO 2 Drive until the gas-liquid ratio is >2000, the results are as follows Figure 4 The comparison of the diversion rate of the core experiment with and without oil shows that the in-situ emulsification system cannot block the high permeability under the condition of no oil, but under the condition of oil, the in-situ emulsification system contacts with crude oil to achieve emulsification, which can effectively block the high permeability and increase the low permeability flow.

[0061] 5. Simulate the target reservoir conditions, use saturated oil double-tube parallel cores to conduct oil displacement tests on in-situ emulsified surfactant systems of different strengths. The core gas permeability is: high permeability 150mD, low permeability 7mD, experimental temperature 70℃, experimental water is the on-site injection water of a certain test area, the core outlet back pressure is 10MPa, the injection system is 0.3wt% betaine 3 type strong emulsification system, betaine 1 type medium emulsification system, betaine 2 type system, and the injection method is water flooding to 98% water content + CO 2 Drive until gas-liquid ratio>2000+0.1PV gas-liquid alternation 4 times+subsequent CO 2 Drive until the gas-liquid ratio is >2000. The pressure difference during core flooding of different emulsification strength systems is as follows Figure 5 As shown in the figure, the injection pressure of the three emulsified systems, weak, medium and strong, is higher than that of the single CO 2 The flooding was increased by 1.2, 14.8 and 26.2 times respectively, indicating that in-situ emulsification flooding systems with different intensities have the ability to regulate different gas channeling advantage channels.

[0062] 6. The results of oil recovery enhancement test using in-situ emulsified surfactant systems with different strengths are as follows Figure 6 As shown, the results show that excessive emulsification leads to low osmotic CO 2 The high pressure makes it difficult to inject (low permeability recovery rate is 5.83%), and the too weak pressure gradient does not lead to sufficient pressure gradient for CO 2 Entering the low permeability (low permeability recovery rate 1.90%), the appropriate emulsification strength system can increase the low permeability section recovery rate by 59%. In summary, this clearly proves that in-situ emulsification assisted CO2 Successful application of oil recovery system and technology in improving oil recovery.

[0063] Based on the inventive concept of the present invention, the embodiment of the present invention also provides an in-situ emulsification-assisted CO 2 Oil recovery methods, including:

[0064] The surfactant system selected by the above method was used to carry out in-situ emulsification-assisted CO 2 Oil recovery.

[0065] Compared with the existing water-gas alternation technology, the in-situ emulsification-assisted CO 2 The oil displacement method can use the surfactant-containing water plug to emulsify the oil and water in situ to plug the pore throat and expand the CO 2 The sweep coefficient capability is significantly stronger than that of water-gas alternation technology.

[0066] Compared with the existing foam plugging technology, the in-situ emulsification assisted CO 2 The oil displacement method can not only significantly reduce the interfacial tension and improve the oil washing efficiency, but also avoid the CO 2 The problem of the difficulty in stabilizing the characteristics of the oil / water interface is that the oil / water interface always exists during the oil displacement process and the two phases are very different. It is easy to generate an oil-water emulsion with controllable interfacial film strength and stability in the pores, and hinder the CO 2 , water, and oil flow, and has the characteristics of less reservoir damage, higher injectivity, and stronger acid and temperature resistance, achieving CO 2 Long-term and continuous deep profile control is suitable for the mobility control needs of miscible and immiscible oil recovery, effectively solving the CO 2 The problem of limited mobility control methods has a very broad scope of application and prospects, promoting the CO 2 Storage and green, economical and efficient development.

[0067] Compared with the existing ASP alternating gas injection technology, the in-situ emulsification assisted CO 2 The oil displacement method takes into account the advantages of ASP alternating gas injection and innovatively proposes oil-water in-situ emulsification to plug CO 2 The surfactant used in this technical method has the characteristics of high injectability, strong acid and temperature resistance, and in-situ emulsification can deeply adjust the profile with less reservoir damage, which is in sharp contrast to the ASP alternating gas injection technology that does not consider the plugging performance of the emulsion.

[0068] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process can be rearranged without departing from the scope of protection of the present disclosure. The attached method claims present the elements of the various steps in an exemplary order and are not intended to be limited to the specific order or hierarchy described.

[0069] In the above detailed description, various features are grouped together in a single embodiment to simplify the disclosure. This method of disclosure should not be interpreted as reflecting an intention that the embodiments of the claimed subject matter require more features than are clearly stated in each claim. On the contrary, as reflected in the appended claims, the invention is in a state of having less than all the features of the disclosed individual embodiments. Therefore, the appended claims are hereby expressly incorporated into the detailed description, with each claim standing on its own as a separate preferred embodiment of the invention.

[0070] The above description includes examples of one or more embodiments. Of course, it is impossible to describe all possible combinations of components or methods for the purpose of describing the above embodiments, but it should be recognized by those skilled in the art that the various embodiments may be further combined and arranged. Therefore, the embodiments described herein are intended to cover all such changes, modifications and variations that fall within the scope of protection of the appended claims. In addition, with respect to the term "comprising" used in the specification or claims, the word is covered in a manner similar to the term "including", just as "including," is explained as a transitional word in the claims. In addition, any term "or" used in the specification of the claims is intended to mean "non-exclusive or".

Claims

1. A surfactant system optimization method, characterized in that: include: For each surfactant system to be selected, the target oilfield injection water is used to prepare the surfactant system aqueous solution, and the oil-water interfacial tension of the aqueous solution is measured under reservoir conditions when CO2 reaches a dissolution equilibrium state; the water phase precipitation rate of the surfactant system emulsion is measured under reservoir conditions when CO2 reaches a dissolution equilibrium state; the seepage law test and oil displacement test of the surfactant system aqueous solution are carried out using unsaturated oil and saturated oil double-tube parallel cores to obtain the first seepage resistance change data during the unsaturated oil seepage law test and the second seepage resistance change data during the saturated oil oil displacement test; According to the oil-water interfacial tension, water phase precipitation rate, the first seepage resistance change data and the second seepage resistance change data, the surfactant system with the best displacement effect is screened.

2. The method according to claim 1, characterized in that The use of unsaturated oil and saturated oil dual-tube parallel cores to conduct seepage law testing and oil displacement testing on the surfactant system aqueous solution specifically includes: The seepage law and oil displacement test of the surfactant system aqueous solution were carried out using dual-tube parallel cores of unsaturated oil and saturated oil. The injection stages included water drive, CO2 drive, gas-water alternating drive, gas-liquid alternating drive of the surfactant system aqueous solution and subsequent CO2 drive.

3. The method according to claim 1, characterized in that The screening of the surfactant system with the best displacement effect specifically includes screening the surfactant system that meets the following conditions: The oil-water interfacial tension is lower than the set interfacial tension threshold; The water phase precipitation rate is lower than the set precipitation rate threshold; The difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage in the first seepage resistance change data is less than the set first seepage resistance difference threshold, and the difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage in the second seepage resistance change data is greater than the set second seepage resistance difference threshold; The seepage resistance in the gas-liquid alternating drive stage in the second seepage resistance change data is higher than the set seepage resistance threshold.

4. The method according to claim 1, characterized in that The method of using the target oilfield injection water to prepare the surfactant system aqueous solution specifically includes: The target oilfield injection water is used to prepare a surfactant system aqueous solution with a mass concentration of 0.1% to 0.4%.

5. The method according to claim 1, characterized in that The method of measuring the water phase precipitation rate of the surfactant system emulsion when CO2 reaches a dissolution equilibrium state under reservoir conditions specifically includes: The experimental water is the injection water, and the experimental oil is a simulated oil prepared according to the dehydrated crude oil of the target oil field. The water phase precipitation rate of the surfactant system emulsion when CO2 reaches a dissolution equilibrium state is measured under reservoir conditions through a bottle test method.

6. The method according to claim 5, characterized in that The bottle test method also includes: The volume ratio of injected water and simulated oil was set to 1:

1.

7. The method according to claim 1, characterized in that Also includes: The surfactant system aqueous solution was subjected to an oil-water interface dilation rheological test under reservoir conditions when CO2 reached a dissolution equilibrium state to obtain the interfacial film strength. Screen the surfactant system whose interfacial film strength meets the set conditions.

8. The method according to claim 1, characterized in that Also includes: A visualized oil displacement experiment of CO2 flooding surfactant system-CO2 flooding was carried out on the surfactant system under reservoir conditions to obtain the process of CO2 blocking by the surfactant system.

9. The method according to any one of claims 1 to 8, characterized in that: The surfactant system is any one of zwitterionic, anionic and nonionic, nonionic and anionic surfactants, or a surfactant system consisting of at least two of them.

10. The method according to any one of claims 1 to 8, characterized in that: The reservoir conditions are: Reservoir temperature 45℃~20℃; The viscosity of the reservoir crude oil at 90°C is 1 mPa.s to 1000 mPa.s.

11. An in-situ emulsification-assisted CO2 flooding method, characterized in that: include: The surfactant system selected by the method described in any one of claims 1 to 9 is used for in-situ emulsification-assisted CO2 flooding.

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