A method for optimizing a surfactant system and an in-situ emulsification-assisted CO2 oil displacement method

Abstract

This invention discloses a method for optimizing surfactant systems and an in-situ emulsification-assisted CO2 flooding method. The surfactant system optimization method includes: for each candidate surfactant system, preparing an aqueous solution using injection water from the target oilfield; measuring the oil-water interfacial tension of the aqueous solution under reservoir conditions when CO2 reaches dissolution equilibrium; measuring the aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions when CO2 reaches dissolution equilibrium; conducting seepage law tests and oil displacement tests on the surfactant system aqueous solution using parallel core samples from unsaturated and saturated oil pipes, obtaining data on the first seepage resistance change during the seepage law test and the second seepage resistance change during the oil displacement test; and selecting the surfactant system with the optimal displacement effect based on the oil-water interfacial tension, aqueous phase precipitation rate, and the first and second seepage resistance changes. This method enables the development of an in-situ emulsified surfactant system with controllable CO2 displacement limits.

Description

Technical Field

[0001] This invention relates to the fields of oilfield chemistry and oilfield development technology, and in particular to a method for optimizing a surfactant system and an in-situ emulsification-assisted CO2 flooding method. Background Technology

[0002] Due to the low density and viscosity of CO2, the poor physical properties and strong heterogeneity of low-permeability oil reservoirs in my country, as well as the influence of natural or artificial fractures and other channeling pathways, CO2 is highly susceptible to viscous fingering, gravity overlap, and gas channeling, which greatly reduces the effectiveness of CO2 in mobilizing crude oil (Yuan Shiyi et al. Petroleum Exploration and Development, 2022, 49(04):828-834). Even if some domestic oilfields can achieve CO2 miscible flooding conditions, due to the relative excess of CO2 around injection wells or the low pressure of production wells, there is a probability that immiscible CO2 may exist in the oil layers around injection and production wells, leading to fingering or gas channeling. Therefore, efficient mobility control technology is the key to improving the recovery rate of CO2-driven oil in low-permeability oil reservoirs in my country.

[0003] One of the fundamental reasons for the difficulties in CO2 mobility control engineering in low-permeability reservoirs is the limited means of controlling CO2 mobility. Existing mobility control technologies mostly rely on gas-water alternation, foam, and ASP alternating gas injection to regulate CO2 mobility. For water-gas alternation technology (WAG), its mechanism is to reduce the saturation of gas by injecting water, thereby reducing the mobility ratio, stabilizing the displacement front end, inhibiting viscous fingering, and increasing the sweep efficiency of CO2. Researchers such as Liao Xinwei (Journal of Shaanxi University of Science and Technology (Natural Science), 2016, 34(06): 120-124.) and Gao Yuncong (Petroleum Exploration and Development, 2014, 41(01): 79-85.) have conducted a series of studies on this technology, and it is currently widely used in the field and is relatively mature. However, this technology has limited ability to prevent CO2 gas channeling and cannot improve oil washing efficiency.

[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 Jamin effect generated by the deformation of the bubble interface on the fluid flow, and the Jamin effect can be superimposed. When foam enters the formation, it preferentially enters high-permeability areas, and the Jamin effect gradually increases the flow resistance, thereby delaying gas channeling and effectively improving the sweep efficiency and replenishing formation energy. In addition, foam systems generally also have the ability to reduce interfacial tension, which can increase oil washing efficiency and thus improve oil recovery. As an extension of water-gas alternation technology, the theoretical research on foam plugging technology is relatively mature, and it has been applied in the field with significant results. However, CO2 foam is less stable than air / water or nitrogen / water interfaces because it is more difficult to adsorb active substances at the CO2 / water interface. In addition, foam systems cannot simultaneously reduce gas-liquid surface tension and oil-water interfacial tension. It has disadvantages such as difficulty in selecting active substances at the CO2 / water interface, short action time, short action distance, and difficulty in balancing expanding the scope and improving the oil washing effect.

[0005] Regarding ASP (Alternating Gas Injection) technology, Kumar S (Journal of Petroleum Science and Engineering, 2017, 157: 696-715.) reviewed how ternary composite ASPAG systems further enhance oil recovery by reducing interfacial tension, altering contact angles, increasing aqueous phase viscosity, regulating phase behavior, and generating foam. The injection system in ASPAG includes various combinations of alkali, surfactants, and polymers. Researchers typically emphasize the system's ultra-low interfacial tension to improve washout efficiency, the use of polymers to increase aqueous phase viscosity, and surfactants to generate foam to expand swept volume, while altering the contact angle reduces water-locking effects. However, research on emulsions in this technology usually focuses on the impact of oil-water droplets on foam stability, neglecting the role of emulsions in blocking pore throats and controlling CO2 mobility, and giving less consideration to the polymer's acid and high-temperature resistance and low-permeability injection properties.

[0006] It is evident that a great deal of research has been conducted on techniques for controlling CO2 mobility and enhancing oil recovery during CO2 flooding. However, due to limitations imposed by the characteristics of the CO2 / water interface, the acidic environment, and the size of the injection orifice throat, existing mobility control systems and technologies face difficulties in achieving long-term, continuous deep profile control of CO2. Summary of the Invention

[0007] In order to at least partially solve the above-mentioned technical problems existing in the prior art, the inventors made this invention, which provides a method for optimizing a surfactant system and an in-situ emulsification-assisted CO2 oil displacement method through specific embodiments, and can develop an in-situ emulsified surfactant system with controllable CO2 displacement limits.

[0008] In a first aspect, embodiments of the present invention provide a preferred method for a surfactant system, comprising:

[0009] For each candidate surfactant system, an aqueous solution of the surfactant system was prepared using injection water from the target oilfield. The oil-water interfacial tension of the aqueous solution was measured under reservoir conditions when CO2 reached dissolution equilibrium. The aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions when CO2 reached dissolution equilibrium was measured. The seepage law test and oil displacement test of the surfactant system aqueous solution were conducted using unsaturated oil and saturated oil dual-tube parallel cores. The data on the change of the first seepage resistance during the seepage law test of unsaturated oil and the data on the change of the second seepage resistance during the oil displacement test of saturated oil were obtained.

[0010] Based on the data of oil-water interfacial tension, aqueous phase precipitation rate, changes in the first seepage resistance and the second seepage resistance, the surfactant system with the best displacement effect was screened.

[0011] Secondly, embodiments of the present invention provide an in-situ emulsification-assisted CO2 oil displacement method, comprising:

[0012] The surfactant system selected by the above method was used for in-situ emulsification-assisted CO2 flooding.

[0013] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0014] (1) The surfactant system optimization method provided in this embodiment of the invention obtains the oil-water interfacial tension, aqueous phase precipitation rate, first seepage resistance change data, and second seepage resistance change data for each candidate surfactant system through a series of experiments, thereby screening out the surfactant system with the best displacement effect. It can develop an in-situ emulsified surfactant system with controllable CO2 displacement limit according to the specific needs of the field.

[0015] (2) Compared with existing water-gas alternation technology, the in-situ emulsification-assisted CO2 oil displacement method provided in this embodiment of the invention can use a water slug containing surfactant to emulsify oil and water in situ to seal the throat, and its ability to expand the sweep efficiency of CO2 is significantly stronger than that of water-gas alternation technology.

[0016] (3) Compared with existing foam plugging technology, the in-situ emulsification-assisted CO2 flooding method provided in this embodiment of the invention can not only significantly reduce interfacial tension and improve oil washing efficiency, but also avoid the problem of unstable CO2 / water interface characteristics in foam systems. It utilizes the characteristics of oil-water interface always existing and large differences between the two phases during the flooding process, and can easily generate an oil-water emulsion with controllable interfacial film strength and stability in the pores. It also hinders the flow of CO2, water and oil through the Jamin effect. At the same time, it has the characteristics of less reservoir damage, higher injectionability and stronger acid and temperature resistance, and can realize long-term and continuous deep profile control of CO2. It is suitable for the needs of miscible and immiscible flooding mobility control, effectively solves the problem of limited CO2 mobility control methods, and has a very broad scope of application and prospects, promoting CO2 storage in low-permeability reservoirs and green, economical and efficient development.

[0017] (4) Compared with the existing ASP alternating gas injection technology, the in-situ emulsification-assisted CO2 oil displacement method provided in this embodiment of the invention takes into account the advantages of ASP alternating gas injection and innovatively proposes an in-situ oil-water emulsification method to block CO2. The surfactant used has the characteristics of high injectability and strong acid and temperature resistance. In-situ emulsification can perform deep profile control and cause less damage to the reservoir. This is in stark contrast to the ASP alternating gas injection technology, which does not consider the emulsion blocking performance.

[0018] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0019] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0020] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0021] Figure 1 This is a flowchart of the preferred method for the surfactant system in Embodiment 1 of the present invention;

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

[0023] Figure 3 This is a stability graph of three betaine emulsions in Example 2 of the present invention, expressed as aqueous phase precipitation rate;

[0024] Figure 4This is a flow rate diagram of the CO2-assisted displacement system under oil-containing / oil-free conditions in Example 2 of the present invention. Figure 5 This is a diagram showing the injection-production pressure difference (seepage resistance) of surfactant systems with different strengths in Embodiment 2 of the present invention;

[0025] Figure 6 This is a graph showing the recovery rate of the CO2 dual-tube parallel chemical flooding system with different strength surfactant systems in Example 2 of the present invention. Detailed Implementation

[0026] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0027] It should be understood that the terminology used in this invention is merely for describing particular embodiments and is not intended to limit the invention. Furthermore, with respect to numerical ranges in this invention, it should be understood that each intermediate value between the upper and lower limits of the range is also specifically disclosed. Every smaller range between any stated value or intermediate value within a stated range, and any other stated value or intermediate value within said range, is also included in this invention. The upper and lower limits of these smaller ranges may be independently included or excluded from the range.

[0028] Unless otherwise stated, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains. While only preferred methods and materials have been described herein, any methods and materials similar or equivalent to those described herein may be used in the implementation or testing of this invention. All references to this specification are incorporated by way of citation to disclose and describe methods and / or materials associated with those references. In the event of any conflict with any incorporated reference, the content of this specification shall prevail.

[0029] In the description of this invention, it should be noted that the terms "comprising", "including", "having", "containing", etc., are all open-ended terms, meaning that they include but are not limited to.

[0030] Example 1

[0031] Embodiment 1 of the present invention provides a preferred method for a surfactant system, referring to... Figure 1 As shown, it includes the following steps:

[0032] Step S11: For each candidate surfactant system, prepare an aqueous solution of the surfactant system using injection water from the target oilfield. Measure the oil-water interfacial tension of the aqueous solution under reservoir conditions when CO2 reaches dissolution equilibrium. Measure the aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions when CO2 reaches dissolution equilibrium. Use parallel core samples from unsaturated and saturated oil pipes to conduct seepage law tests and oil displacement tests on the surfactant system aqueous solution, obtaining 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] A surfactant system is any one of zwitterionic, anionic / nonionic, nonionic, and anionic surfactants, or a surfactant system composed of at least two of them. When a surfactant system contains two or more single surfactants, different formulation ratios of the single surfactants constitute different surfactant systems.

[0034] (1) Measurement of oil-water interfacial tension.

[0035] An aqueous solution of surfactant with a mass concentration of 0.1% to 0.4% was prepared using injection water from the target oilfield. The interfacial tension of the aqueous solution under reservoir conditions was measured when CO2 reached dissolution equilibrium.

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

[0037] (2) Emulsion stability test.

[0038] The water used in the experiment was the injection water from the target oilfield, and the oil used in the experiment was a simulated oil formulated based on the dehydrated crude oil from the target oilfield. The volume ratio of the injection water to the simulated oil was set to 1:1. The aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions was measured by the bottle test method to characterize the stability of the emulsion.

[0039] Optionally, an oil-water interface expansion rheological test can also be performed. The surfactant system aqueous solution is subjected to an oil-water interface expansion rheological test under reservoir conditions when CO2 reaches dissolution equilibrium to obtain the interfacial film strength; surfactant systems with interfacial film strength that meet the set conditions are then screened.

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

[0041] (3) Test data on seepage resistance variation.

[0042] Simulating target reservoir conditions, the surfactant system was tested for seepage patterns and oil displacement using unsaturated and saturated oil cores in parallel. The injection phase included water flooding, CO2 flooding, gas-water alternating flooding, gas-liquid alternating flooding of the surfactant system aqueous solution, and subsequent CO2 flooding. The surfactant system was further analyzed by analyzing the system diversion rate, seepage resistance, gas-liquid ratio at the production end, and recovery rate.

[0043] In the above-mentioned seepage and oil displacement process, there are no strict limitations on the injection rate, injection timing, back pressure, and slug size, which can be determined according to the actual situation.

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

[0045] Step S12: Based on the oil-water interfacial tension, water phase precipitation rate, changes in the first seepage resistance and the second seepage resistance, screen the surfactant system with the best displacement effect.

[0046] The surfactant system that meets the following criteria is selected 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 aqueous phase precipitation rate is lower than the set precipitation rate threshold.

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

[0050] That is, in the first data on seepage resistance changes, the seepage resistance in the gas-liquid alternating drive stage is close to that in the gas-water alternating drive stage, while in the second data on seepage resistance changes, 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] Based on the change data of the first seepage resistance obtained during the oil displacement test, the system's regulation and displacement strength is ranked according to the seepage resistance in the gas-liquid alternating drive stage. If the seepage resistance in the gas-liquid alternating drive stage is higher, the CO2 regulation and displacement capability of the system is stronger, and vice versa.

[0053] The surfactant system optimization method provided in Embodiment 1 of this invention obtains data on the oil-water interfacial tension, aqueous phase precipitation rate, changes in the first seepage resistance, and changes in the second seepage resistance for each candidate surfactant system through a series of experiments, thereby screening out the surfactant system with the optimal displacement effect. This method enables the development of in-situ emulsified surfactant systems with controllable CO2 displacement limits based on specific on-site requirements for displacement capabilities.

[0054] In some embodiments, the method may further include conducting a microscopic visualization experiment on the surfactant system under reservoir conditions to obtain the microscopic process of the surfactant system blocking CO2.

[0055] Example 2

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

[0057] 1. The experimental water was water injected on-site in a certain test area. Three surfactants, namely long-chain hydroxypropyl betaine type 1, betaine type 2 and betaine type 3, were prepared with a mass concentration of 0.3wt%.

[0058] 2. The oil-water interfacial tension was measured under reservoir conditions when CO2 reached dissolution equilibrium. The experimental temperature was 70℃, and the oil used was a simulated oil prepared from dehydrated crude oil from a certain test area. The results are as follows: Figure 2 As shown, betaine type 1 and betaine type 3 surfactants can achieve ultra-low interfacial tension, and are expected to effectively emulsify in situ and have high oil washing efficiency.

[0059] 3. The stability of in-situ emulsified surfactant systems of betaine type 1, betaine type 2, and betaine type 3 was tested under reservoir conditions with CO2 reaching dissolution equilibrium using a bottle test method. The experimental temperature was 70℃. The experimental water was water injected from a test area, and the experimental oil was a simulated oil prepared from dehydrated crude oil from the same test area, with an oil-water ratio of 1:1 (V / V). Emulsions were generated by shaking at a constant frequency 100 times. The results are as follows: Figure 3 As shown, based on the stability ranking of emulsions, betaine type 3, betaine type 1, and betaine type 2 are respectively classified as strong emulsifiers, medium emulsifiers, and weak emulsifiers. The expected emulsion blocking ability ranking is betaine type 3 > betaine type 1 > betaine type 2.

[0060] 4. Simulating target reservoir conditions, parallel core samples from both unsaturated and saturated oil pipes were used to conduct seepage law tests and oil displacement tests on a series of in-situ emulsified surfactant systems. Core gas permeability was: 150 mD for high permeability and 7 mD for low permeability. The experimental temperature was 70℃, and the water used was injected from a test area. The core outlet back pressure was 10 MPa. The injection system was a 0.3 wt% betaine 3 strong emulsified system. The injection method was water flooding until the water cut reached 98% + CO2 flooding until the gas-liquid ratio > 2000 + 0.1 PV gas-liquid alternation four times + subsequent CO2 flooding until the gas-liquid ratio > 2000. The results are as follows: Figure 4 As shown, the comparison of core sample diversion rates with and without oil indicates that the in-situ emulsification system cannot block high permeability under oil-free conditions, while under oil-containing conditions, the in-situ emulsification system achieves emulsification upon contact with crude oil, which can effectively block high permeability and increase low permeability flow.

[0061] 5. Simulating target reservoir conditions, oil displacement tests were conducted on in-situ emulsified surfactant systems of different strengths using saturated oil dual-tube parallel core samples. Core gas permeability was: 150 mD for high permeability and 7 mD for low permeability. The experimental temperature was 70℃, and the experimental water was the field-injected water from a test area. The core outlet back pressure was 10 MPa. The injection systems were 0.3 wt% betaine type 3 strong emulsification system, betaine type 1 medium emulsification system, and betaine type 2 system. The injection method was water flooding to 98% water cut + CO2 flooding to gas-liquid ratio > 2000 + 0.1 PV gas-liquid alternation 4 times + subsequent CO2 flooding to gas-liquid ratio > 2000. The pressure difference during the oil displacement process of core samples with different emulsification strengths is as follows: Figure 5 As shown, the injection pressure of the weak, medium and strong emulsification systems was increased by 1.2, 14.8 and 26.2 times respectively compared with the single CO2 drive, indicating that the in-situ emulsification and drive systems of different intensities have the ability to regulate different gas channeling advantages.

[0062] 6. Results of enhanced oil recovery tests using in-situ emulsified surfactant systems of different strengths, as shown below. Figure 6 As shown, the results indicate that excessive emulsification leads to high CO2 pressure in low-permeability reservoirs, making injection difficult (low-permeability recovery rate 5.83%), while insufficient emulsification results in a lack of sufficient pressure gradient for CO2 to enter the low-permeability zone (low-permeability recovery rate 1.90%). A system with appropriate emulsification strength can increase the recovery rate of low-permeability sections by 59%. In summary, this clearly demonstrates the successful application of in-situ emulsification-assisted CO2 flooding systems and technologies in improving oil recovery in low-permeability reservoirs.

[0063] Based on the inventive concept of this invention, embodiments of this invention also provide an in-situ emulsification-assisted CO2 oil displacement method, comprising:

[0064] The surfactant system selected by the above method was used for in-situ emulsification-assisted CO2 flooding.

[0065] Compared with existing water-gas alternation technology, the in-situ emulsification-assisted CO2 oil displacement method provided in this embodiment of the invention can use a surfactant-containing water slug to emulsify oil and water in situ to seal the pore throat, and its ability to expand the sweep efficiency of CO2 is significantly stronger than that of water-gas alternation technology.

[0066] Compared with existing foam plugging technologies, the in-situ emulsification-assisted CO2 flooding method provided in this invention not only significantly reduces interfacial tension and improves oil washing efficiency, but also avoids the problem of unstable CO2 / water interface characteristics in foam systems. Utilizing the characteristics of the oil-water interface, which is always present during the flooding process and has significant phase differences, it easily generates an oil-water emulsion with controllable interfacial film strength and stability within the pores. Through the Jamin effect, it hinders the flow of CO2, water, and oil, while also exhibiting characteristics of minimal reservoir damage, high injectability, and strong acid and temperature resistance. This enables long-term, continuous deep profile control of CO2, suitable for the needs of miscible and immiscible flooding mobility regulation, effectively solving the problem of limited CO2 mobility control methods. Its application scope and prospects are very broad, promoting CO2 storage in low-permeability reservoirs and green, economical, and efficient development.

[0067] Compared with the existing ASP alternating gas injection technology, the in-situ emulsification-assisted CO2 flooding method provided in this invention takes into account the advantages of ASP alternating gas injection and innovatively proposes an in-situ oil-water emulsification method to block CO2. The surfactant used has the characteristics of high injectability and strong acid and temperature resistance. In-situ emulsification can perform deep profile control with less reservoir damage, which is in stark contrast to the ASP alternating gas injection technology, which does not consider the emulsion blocking performance.

[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 may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the scope to the specific order or hierarchy described.

[0069] In the detailed description above, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features in a single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, with each claim representing a separate preferred embodiment of the invention.

[0070] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," as interpreted when used as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

Claims

1. A method for optimizing a surfactant system, characterized in that, include: For each candidate surfactant system, an aqueous solution of the surfactant system was prepared using injection water from the target oilfield. The oil-water interfacial tension of the aqueous solution was measured under reservoir conditions when CO2 reached dissolution equilibrium. The aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions when CO2 reached dissolution equilibrium was measured. The seepage law test and oil displacement test of the surfactant system aqueous solution were conducted using unsaturated oil and saturated oil dual-tube parallel cores. The data on the change of the first seepage resistance during the seepage law test of unsaturated oil and the data on the change of the second seepage resistance during the oil displacement test of saturated oil were obtained. Based on the data of oil-water interfacial tension, aqueous phase precipitation rate, changes in the first seepage resistance, and changes in the second seepage resistance, the surfactant system that meets the following conditions is selected as the surfactant system with the best displacement effect: The oil-water interfacial tension is lower than the set interfacial tension threshold. The aqueous phase precipitation rate is lower than the set precipitation rate threshold; In the first seepage resistance change data, the difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage is less than the set first seepage resistance difference threshold, and in the second seepage resistance change data, the difference between the seepage resistance in the gas-liquid alternating drive stage and the seepage resistance in the gas-water alternating drive stage is greater than the set second seepage resistance difference threshold. In the second data on seepage resistance changes, the seepage resistance during the gas-liquid alternating drive stage is higher than the set seepage resistance threshold.

2. The method as described in claim 1, characterized in that, The method of using parallel core samples from both unsaturated and saturated oil pipes to test the seepage behavior and oil displacement of the surfactant system aqueous solution specifically includes: The seepage pattern and oil displacement tests of the surfactant system aqueous solution were conducted using unsaturated oil and saturated oil dual-tube parallel cores. The injection stages included water flooding, CO2 flooding, gas-water alternating flooding, gas-liquid alternating flooding of the surfactant system aqueous solution, and subsequent CO2 flooding.

3. The method as described in claim 1, characterized in that, The preparation of the surfactant system aqueous solution using injection water from the target oilfield specifically includes: Prepare an aqueous solution of surfactant system with a mass concentration of 0.1% to 0.4% using injection water from the target oilfield.

4. The method as described in claim 1, characterized in that, The measurement of the aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions, where CO2 has reached dissolution equilibrium, specifically includes: The water used in the experiment was the injected water, and the oil used in the experiment was a simulated oil formulated based on the dehydrated crude oil from the target oilfield. The aqueous phase precipitation rate of the surfactant system emulsion under reservoir conditions with CO2 reaching dissolution equilibrium was measured by the bottle test method.

5. The method as described in claim 4, characterized in that, The bottle test method also includes: The volume ratio of injected water to simulated oil is set to 1:

1.

6. The method as described in claim 1, characterized in that, Also includes: The interfacial film strength was obtained by conducting an oil-water interface expansion rheological test on the surfactant system aqueous solution under reservoir conditions where CO2 reached dissolution equilibrium. Surfactant systems that meet the set conditions for interfacial film strength are selected.

7. The method as described in claim 1, characterized in that, Also includes: A visualized oil displacement experiment was conducted on the surfactant system under reservoir conditions to observe the CO2 flooding process of the surfactant system blocking CO2.

8. The method according to any one of claims 1 to 7, characterized in that, The surfactant system is any one of zwitterionic, anionic / nonionic, nonionic, and anionic surfactants, or a surfactant system composed of at least two of them.

9. The method according to any one of claims 1 to 7, characterized in that, The reservoir conditions are as follows: Reservoir temperature: 45℃~20℃; The viscosity of crude oil in the reservoir at 90℃ is 1 mPa·s to 1000 mPa·s.

10. An in-situ emulsification-assisted CO2 oil displacement 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 oil displacement.

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