Experimental design method of middle-phase microemulsion enhanced carbonated water recovery efficiency improving system

Abstract

The invention belongs to the field of oil reservoir experimental design, and particularly relates to an experimental design method of a system for improving recovery efficiency by using middle-phase microemulsion to enhance carbonated water, an experimental trial and error initial value with physical significance is obtained through estimation of an HLD equation and an empirical formula, and CO2 solubility in carbonated water is improved by a nonionic surfactant while CO2 solubility in carbonated water is improved by a non-ionic surfactant. The characteristic parameter Cc value of the nonionic surfactants in a mixed system composed of oil, water, CO2 and the two nonionic surfactants is controlled by adjusting the use amount of the two nonionic surfactants with different Cc values, the mixed system capable of forming the middle-phase microemulsion under the reservoir condition is preferably selected, and the middle-phase microemulsion can be formed under the reservoir condition according to the preferably selected mixed system. The enhanced carbonated water is prepared to carry out a displacement experiment on a saturated oil rock core, the enhanced carbonated water is optimized and evaluated by combining common carbonated water displacement experiment data comparison, and under the background that a trial-and-error experiment cannot be avoided, the trial-and-error method test turns of the technology are greatly reduced, and the experiment efficiency and economical efficiency are greatly improved.

Description

Technical Field

[0001] The invention belongs to the technical field of improving the recovery rate of low-permeability tight oil and gas reservoirs, and particularly relates to an experimental design method for a medium-phase microemulsion-enhanced carbonated water recovery system. Background Art

[0002] Carbonated water flooding is an enhanced water injection technique that dissolves CO2 in formation water and injects it into underground reservoirs for displacement. The enhanced recovery mechanism of carbonated water flooding is crude oil swelling and improved physical properties, such as reduced viscosity and oil-water interfacial tension. Current research indicates that the higher the CO2 dosage, the better the carbonated water flooding effect. However, the solubility of CO2 in formation water is generally low and unadjustable, which limits the effects of CO2-related mechanisms. The addition of surfactants can increase CO2 solubility in saline water. Middle-phase microemulsions also have significant potential for enhanced oil recovery. If the added surfactant can be utilized to optimize the oil-water-CO2 surfactant system, a two-phase, four-component system, to form a middle-phase microemulsion, further enhancing oil recovery will be a crucial technological foundation for unlocking the potential of mature reservoirs.

[0003] The invention patent "An Experimental Apparatus and Method for Nanofluid-Enhanced Carbonated Water Displacement in Heavy Oil Reservoirs" (CN115977585A) proposes introducing nanofluids into the carbonated water flooding process in heavy oil reservoirs by adding a small amount of nanoparticles and a dispersant to the carbonated water. Although this invention increases the solubility of CO2 in carbonated water, nanofluids are thermodynamically unstable and cannot form microemulsions. The invention patent "A Formation Pretreatment Method for Enhancing CO2 Geological Storage" (CN115788577A) proposes using nonionic surfactants to pretreat saline aquifers. Although this invention increases the solubility of CO2 in saline aquifers, achieving rapid dissolution and effectively increasing CO2 storage in saline aquifers, the nonionic surfactants do not form microemulsions underground, making their application in enhancing oil recovery relatively limited. Some scholars have found that CO2 has higher solubility in different surfactant solutions (Jianling Z, Buxing H, Yueju Z, et al. CO2 capture by hydrocarbon surfactant liquids. [J]. Chemical communications (Cambridge, England), 2011, 47 (3): 1033-5.), but did not enable the surfactant to form microemulsion in the reservoir to enhance oil recovery.

[0004] The HLD (Hydrophilic-Lipophilic Deviation) model has the ability to predict the phase state of the middle phase microemulsion. Based on the HLD theory, the formula of the middle phase microemulsion formed by the mixed system of oil, water and non-ionic surfactant can be calculated. However, when CO2 exists in the mixed system, the theoretical calculation will be difficult to perform. Figure 1 As shown, the equivalent alkane carbon number EACN of crude oil is substituted into the HLD equation to obtain the characteristic parameters of the non-ionic surfactant. It is further known that CO2 is dissolved in water, and CO2 will transfer into the oil phase, causing the EACN of crude oil to change. According to the HLD equation, the new characteristic parameters of the mixed system after the oil phase EACN changes are calculated. If the characteristic parameters of the non-ionic surfactant are significantly different from the previous ones, the new characteristic parameters are used for cyclic calculation. If the two are equal or similar, the previous characteristic parameters of the non-ionic surfactant can be used to directly calculate the mixed system formula. However, due to the cyclic reference of the above process parameters, they affect each other, and the existing theory cannot accurately calculate the EACN of crude oil after dissolving CO2. Figure 1 The cycle calculation process shown cannot be carried out, so the model calculation has no basis. Figure 2 The microemulsion formula was found through trial and error.

[0005] Previous research has largely focused on increasing the solubility of CO2 in injected water to enhance the effectiveness of carbonated water flooding. To further strengthen the carbonated water flooding effect, this application proposes using nonionic surfactants to increase the solubility of CO2 in carbonated water. Simultaneously, the nonionic surfactants spontaneously form a thermodynamically stable middle-phase microemulsion with live oil under formation conditions, further enhancing oil recovery. Furthermore, this method employs the HLD equation to estimate physically meaningful initial experimental trial-and-error values, significantly reducing the number of trial-and-error testing cycles and improving the efficiency and cost-effectiveness of designing carbonated water formulations for the middle-phase microemulsion. Summary of the Invention

[0006] The purpose of the present invention is to provide a design method and experimental device for a medium-phase microemulsion enhanced carbonated water recovery system, which has a reliable principle, is easy to operate, and reduces the amount of experimental trial and error. Figure 1 As shown, the formula of the medium-phase microemulsion mixed system that can be formed after dissolving CO2 can be calculated using the hydrophilic-lipophilic deviation HLD equation (hereinafter referred to as the "HLD equation"). However, the calculation process is complex, and existing theories cannot obtain the equivalent alkane carbon number EACN (hereinafter referred to as "EACN") of the oil phase after dissolving CO2, making the HLD equation calculation infeasible. However, the present invention estimates the initial value of the experimental trial and error with physical significance through the HLD equation and empirical formula. In the context of unavoidable trial and error experiments, the number of trial and error test rounds of this technology is greatly reduced. Under the reservoir temperature and pressure conditions, based on the HLD equation, while the non-ionic surfactant increases the solubility of CO2 in carbonated water, by adjusting the two different C cThe characteristic parameter C of the nonionic surfactant in the mixed system composed of oil, water, CO2 and two nonionic surfactants is controlled by the amount of nonionic surfactant with the value of c Value (hereinafter referred to as "C c value"), a mixed system that can form a middle-phase microemulsion under reservoir conditions was optimized. Based on the optimized mixed system, enhanced carbonated water was prepared and displacement experiments were carried out on oil-saturated cores. The enhanced carbonated water was evaluated by comparing the results with those of ordinary carbonated water displacement experiments.

[0007] In order to achieve the above technical objectives, the present invention adopts the following technical solutions.

[0008] An experimental design method for a medium-phase microemulsion-enhanced carbonated water enhanced oil recovery system comprises the following steps: Step S1: Determine the CO2 solubility in formation water. Determine the CO2 solubility in two mixed systems consisting of non-ionic surfactants and formation water in different proportions. The amount of CO2 injected in the experiment is the minimum CO2 solubility of the mixed system measured, recorded as a mol / L. Calibration of the minimum CO2 solubility can prevent the escape of dissolved CO2 in the mixed system during the experiment. Step S2: Determine the EACN1 of the CO2-free oil phase and substitute the EACN1 into the HLD equation to calculate the C when the mixed system forms the middle phase microemulsion. c1 value; Step S3: Calculate the maximum amount of CO2 dissolved in the oil phase based on the empirical formula for the amount of CO2 dissolved in crude oil. Experimentally measure the solubility of CO2 in formation water and calculate the distribution coefficient K1 according to the following formula. Combined with the total amount of CO2 dissolved in the experiment, the amount of CO2 dissolved in the oil phase of the mixed system is calculated using the distribution coefficient. The value of EACN1 reduced when CO2 dissolves in the oil phase is calculated based on the amount of CO2 dissolved in the oil phase, which is recorded as EACN2.

[0009] in: K1——CO2 distribution coefficient ——CO2 solubility in formation water, mol / L; ——CO2 solubility in crude oil, mol / L; Step S4: According to the HLD equation in step S2, substitute EACN2 to calculate the C required for the mixed system to form a middle phase microemulsion after the oil phase EACN changes when CO2 is dissolved. c2 value; Step S5: After cleaning the PVT cylinder, add a certain amount of NS1 solution and NS2 solution into the cylinder again. The characteristic parameter of the mixed system is C c2A certain proportion of oil phase is added to the PVT cylinder, the temperature of the PVT cylinder is set to the target layer temperature, and the hydraulic oil below the PVT cylinder pushes the piston in the PVT cylinder upward to make the pressure of the PVT cylinder equal to the formation pressure; then the piston in the PVT cylinder is controlled and CO2 is introduced into the PVT cylinder under constant pressure conditions to make the CO2 concentration in the mixed system a mol / L, ensuring that CO2 can be fully dissolved in the mixed system; Step S6: Control the PVT cylinder to stir the mixed system at a uniform speed, let it stand for a period of time, and determine whether a middle phase microemulsion appears after it stabilizes; if a lower phase microemulsion is formed in the PVT cylinder, continue to add NS2 solution to the PVT cylinder and continue to introduce CO2 to ensure that the CO2 concentration in the mixed system always remains at a mol / L; if an upper phase microemulsion is formed in the PVT cylinder, continue to add NS1 solution to the PVT cylinder and continue to introduce CO2 to ensure that the CO2 concentration in the mixed system always remains at a mol / L, until a middle phase microemulsion is formed in the PVT cylinder, and then record the formula of the mixed system in the PVT cylinder; finally, obtain the component ratio of NS1 solution and NS2 solution.

[0010] Step S7: Verify the experimental design conclusions based on the long core flooding experiment and compare the results.

[0011] Preferably, the specific steps of obtaining the minimum solubility of CO2 in the middle phase microemulsion surfactant mixed system in step 1 include: Step S1.1: Determine the target layer temperature and pressure, prepare a certain amount of reservoir crude oil (live oil) sample and formation water; select two non-ionic surfactants NS1 and NS2, prepare NS1 solution and NS2 solution of certain concentrations, and determine the characteristic parameters C of NS1 and NS2. c Value, where NS1's C c The value is less than NS2, and the target layer temperature should be lower than the cloud point of the nonionic surfactant, otherwise the nonionic surfactant will become ineffective; Step S1.2: Control the displacement pump 1 to mix different ratios of NS1 solution and NS2 solution in the PVT cylinder, wherein the ratios of NS1 solution and NS2 solution in the mixed system are set to 0:1, 2:8, 4:6, 6:4, 8:2, and 1:0; Step S1.3: Control displacement pumps 1 and 17 to pressurize the PVT cylinder to the target layer pressure, set the PVT cylinder to the target layer temperature, and then set displacement pump 17 to constant pressure mode; then control displacement pump 1 to pressurize the CO2 intermediate container to the target layer pressure, and then slowly inject an appropriate amount of CO2 into the PVT cylinder; Step S1.4: Turn on the magnetic stirring device of the PVT cylinder. After the mixed system in the PVT cylinder is equilibrated, observe whether it changes from a single phase to two phases. Record the maximum CO2 solubility when the mixed system is in a single phase. Measure the CO2 solubility of each mixed system in turn. Step S1.5: Calculate the C of each mixed system according to the following formula c According to the measurement results, draw different C c The value corresponds to the solubility curve of CO2, and the lowest point of the curve is the CO2 solubility of the middle phase microemulsion nonionic surfactant mixed system, which is recorded as a mol / L;

[0012] in: x——the proportion of the first nonionic surfactant NS1 in the mixed system; y——the proportion of the second nonionic surfactant NS2 in the mixed system; C ca ——Characteristic parameters of the first nonionic surfactant NS1; C cb ——Characteristic parameters of the second nonionic surfactant NS2.

[0013] Preferably, the nonionic surfactant in step S1 can be Tween 60, Tween 80, TX-45, TX-100, TX-114, or other single-agent nonionic surfactants that can solubilize CO2 or form a middle-phase microemulsion with crude oil, or a mixture of multiple single-agents, such as NPE9 (C 33 H 60 O 10 )、Span20(C 18 H 34 O6)、Brij-35(C 12 H 25 (OC2H4) 23 OH), PNS (C 33 H 60 O 10 ), MPEG-350 (C 25 H 53 NO 12 ).

[0014] Preferably, the HLD equation calculation formula in step S2 is as follows:

[0015] The Cc value can be calculated by changing the formula:

[0016] in: S——formation water mineralization, g / 100mL; b is a constant, which is 0.13 for sodium chloride and 0.1 for calcium chloride; K - surfactant characteristic parameter head, characterizing the hydrophilicity / lipophilicity of nonionic surfactants; EACN – equivalent alkane carbon number of the oil phase; ——The temperature coefficient of the optimal salinity is 0.06 K -1 ; ——the difference between the experimental temperature and the normal temperature, K; C c ——The characteristic parameter tail chain of nonionic surfactants characterizes the hydrophilicity / lipophilicity of nonionic surfactants; ——Characterizes the type and concentration of co-surfactant in the system. If no co-surfactant is used, the value of this function is zero; Preferably, the experimental method for determining the oil phase EACN in step S2 comprises the following steps: Step S2.1: Determine the minimum miscibility pressure (MMP) of the crude oil. The minimum miscibility pressure (MMP) is related to the average carbon number (Cn), and the average carbon number (Cn) is related to the equivalent alkane carbon number (EACN) as follows:

[0017]

[0018] in: ——minimum miscible pressure, MPa; — average carbon number; ——Equivalent alkane carbon number of the oil phase; ——Experience coefficient, the value is 1.

[0019] Step S2.2: The average carbon number Cn of crude oil and the equivalent alkane carbon number EACN can be calculated according to the above relationship; Preferably, the characteristic parameter Cc value of the nonionic surfactant in step S2 is used to characterize the hydrophobicity of the nonionic surfactant. The larger the Cc value of the nonionic surfactant, the more lipophilic it is, and the smaller the Cc value, the more hydrophilic it is. By adjusting the amount of two nonionic surfactants with different Cc values ​​to control the Cc value of the mixed system, a middle phase microemulsion can be formed. In the HLD equation, when the mixed system forms a middle phase microemulsion, HLD is equal to 0.

[0020] Preferably, the empirical formula in step S3 is as follows:

[0021]

[0022] in: T——temperature, K; P s ——CO2 saturation pressure, MPa; P b ——bubble point pressure of oil, MPa; MW - molar mass of oil, g / mol; Preferably, in step S6, the concentration gradients of the NS1 and NS2 solutions added to the PVT cylinder are both 0.01 mol / L.

[0023] Preferably, the specific steps of verifying the conclusion in step S7 are: Step S7.1: Add a fixed amount of NS1 solution and NS2 solution to the sample dispenser in sequence, then inject a fixed amount of CO2 into the mixed system, where the CO2 concentration is a mol / L, stir evenly, and transfer to an intermediate container for later use; Step S7.2: Select a long core for use, determine the parameters of the long core, and clean, dry, and vacuum the core; Step S7.3: After the core is loaded into a long core holder, it is quantitatively saturated with formation water. The pressure and temperature are raised to the formation pressure and temperature, respectively. After standing for 24 hours, the formation water in the long core is displaced with crude oil to establish irreducible water saturation. Step S7.4: Set the back pressure slightly lower than the formation pressure, displace the oil with ordinary carbonated water at a rate of 0.125 mL / min, record the produced oil volume, and calculate the crude oil recovery factor; Step S7.5: Repeat steps S7.2 to S7.4, setting the back pressure slightly lower than the formation pressure so that the enhanced carbonated water in the intermediate container is displaced at a rate of 0.125 mL / min. Record the produced oil volume and calculate the crude oil recovery factor.

[0024] The present invention has the following benefits: (1) In this study, two nonionic surfactants were added to the mixed system. The nonionic surfactants used can increase the solubility of CO2 and increase the amount of CO2 used when preparing carbonated water on the ground.

[0025] (2) The nonionic surfactant in the enhanced carbonated water can form a thermodynamically stable middle phase microemulsion underground through the design of this method. The middle phase microemulsion can further significantly improve the recovery rate compared with single carbonated water.

[0026] (3) The HLD equation is used to estimate the initial values ​​of the physically meaningful experimental trial and error, which greatly reduces the number of trial and error test rounds and improves the efficiency and economy of formula design. BRIEF DESCRIPTION OF THE DRAWINGS

[0027] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for describing the embodiments or the prior art.

[0028] Figure 1 This is the flow chart of theoretical calculation for mixed system; Figure 2 This is the experimental flow chart for optimizing the nonionic surfactant mixed system; Figure 3 The solubility curve of CO2 in the mixed system of nonionic surfactants with different proportions; Figure 4 This is the system diagram of the experimental device; Figure 4 In: 1, 16, 17 - displacement pump; 2 - intermediate container for nonionic surfactant 1; 3 - intermediate container for nonionic surfactant 2; 4 - intermediate container for formation water; 5 - intermediate container for CO2; 6 - intermediate container for formation crude oil; 20 - intermediate container for enhanced carbonated water; 33 - intermediate container for carbonated water; 7, 8, 9, 10, 11, 12, 15, 17, 18, 19, 21, 22, 28, 30, 31, 32, 34 - valves; 13, 35 - constant temperature oven; 14 - PVT cylinder; 29 - magnetic stirring device; 23 - long core holder; 24 - differential pressure gauge; 25 - back pressure regulator; 26 - back pressure gauge; 27 - beaker. DETAILED DESCRIPTION

[0029] To more clearly illustrate the present invention, the present invention is further described below with reference to preferred embodiments and accompanying drawings. For clarity and ease of understanding, the various parts in the accompanying drawings are not drawn to scale. Similar components in the accompanying drawings are represented by the same reference numerals. Those skilled in the art should understand that the detailed description below is illustrative and non-restrictive and should not be used to limit the scope of protection of the present invention.

[0030] In order to achieve the above technical objectives, the present invention adopts the following technical solutions.

[0031] The laboratory design method of the medium phase microemulsion enhanced carbonated water enhanced oil recovery system includes the following steps in sequence: Step S1: Determine the CO2 solubility in formation water. Determine the CO2 solubility in a mixed system (two nonionic surfactants and formation water) at different ratios of two nonionic surfactants. The amount of CO2 injected in the experiment is the minimum CO2 solubility of the mixed system measured, recorded as a mol / L, to prevent CO2 from escaping from the mixed system during the experiment. Step S2: Determine the EACN1 of the oil phase without dissolving CO2, substitute it into EACN1, and calculate the C when the mixed system forms the middle phase microemulsion according to HLD equations (1) and (2). c1The value is calculated as follows:

[0032]

[0033] in: S——formation water mineralization, g / 100mL; b is a constant, which is 0.13 for sodium chloride and 0.1 for calcium chloride; K - surfactant characteristic parameter head, characterizing the hydrophilicity / lipophilicity of nonionic surfactants; EACN – equivalent alkane carbon number of the oil phase; ——The temperature coefficient of the optimal salinity is 0.06 K -1 ; ——the difference between the experimental temperature and the normal temperature, K; C c ——The characteristic parameter tail chain of nonionic surfactants characterizes the hydrophilicity / lipophilicity of nonionic surfactants; ——Characterizes the type and concentration of co-surfactant in the system. If no co-surfactant is used, the value of this function is zero; Step S3: Calculate the maximum amount of CO2 dissolved in the oil phase according to the empirical formulas (3) and (4) of CO2 dissolved in crude oil, experimentally measure the solubility of CO2 in formation water, calculate the distribution coefficient K1 according to formula (5), and calculate the amount of CO2 dissolved in the oil phase of the mixed system by the distribution coefficient based on the total amount of CO2 dissolved in the experiment. Calculate the value of EACN1 after CO2 dissolves in the oil phase based on the amount of CO2 dissolved in the oil phase, which is recorded as EACN2;

[0034]

[0035] in: T——temperature, K; P s ——CO2 saturation pressure, MPa; P b ——bubble point pressure of oil, MPa; MW - molar mass of oil, g / mol;

[0036] in: K1——CO2 distribution coefficient ——CO2 solubility in formation water, mol / L; ——CO2 solubility in crude oil, mol / L; Step S4: According to the HLD equations (1) and (2) in step S2, substitute EACN2 to calculate the C required for the mixed system to form a middle phase microemulsion after the oil phase EACN changes when CO2 is dissolved. c2 value; Step S5: After cleaning the PVT cylinder, add a certain amount of NS1 solution and NS2 solution into the cylinder again. The characteristic parameter of the mixed system is C c2 A certain proportion of oil phase is added to the PVT cylinder, the temperature of the PVT cylinder is set to the target layer temperature, and the hydraulic oil below the PVT cylinder pushes the piston in the PVT cylinder upward to make the pressure of the PVT cylinder equal to the formation pressure; then the piston in the PVT cylinder is controlled and CO2 is introduced into the PVT cylinder under constant pressure conditions to make the CO2 concentration in the mixed system a mol / L, ensuring that CO2 can be fully dissolved in the mixed system; Step S6: Control the PVT cylinder to stir the mixed system at a uniform speed, let it stand for a period of time, and determine whether a middle phase microemulsion appears after it stabilizes; if a lower phase microemulsion is formed in the PVT cylinder, continue to add NS2 to the PVT cylinder at a concentration gradient of 0.01 mol / L, and continue to introduce CO2 to ensure that the CO2 concentration in the mixed system always remains at a mol / L; if an upper phase microemulsion is formed in the PVT cylinder, continue to add NS1 to the PVT cylinder at a concentration gradient of 0.01 mol / L, and continue to introduce CO2 to ensure that the CO2 concentration in the mixed system always remains at a mol / L, until a middle phase microemulsion is formed in the PVT cylinder, and then record the mixed system formula in the PVT cylinder; finally, obtain the ratio of NS1 and NS2 components.

[0037] Step S7: Verify the experimental design conclusions based on the long core flooding experiment and compare the results.

[0038] Preferably, the specific steps of obtaining the minimum solubility of CO2 in the middle phase microemulsion surfactant mixed system in step 1 include: Step S1.1: Determine the target layer temperature and pressure, prepare a certain amount of reservoir crude oil (live oil) sample and formation water; select two non-ionic surfactants NS1 and NS2, prepare NS1 solution and NS2 solution of certain concentrations, and determine the characteristic parameters C of NS1 and NS2. c value, where NS1's C c The value is less than NS2, and the target layer temperature should be lower than the cloud point of the nonionic surfactant, otherwise the nonionic surfactant will become ineffective; Step S1.2: Control the displacement pump 1 to mix different ratios of NS1 solution and NS2 solution in the PVT cylinder, wherein the ratios of NS1 solution and NS2 solution in the mixed system are set to 0:1, 2:8, 4:6, 6:4, 8:2, and 1:0; Step S1.3: Control displacement pumps 1 and 17 to pressurize the PVT cylinder to the target layer pressure, set the PVT cylinder to the target layer temperature, and then set displacement pump 17 to constant pressure mode; then control displacement pump 1 to pressurize the CO2 intermediate container to the target layer pressure, and then slowly inject an appropriate amount of CO2 into the PVT cylinder; Step S1.4: Turn on the magnetic stirring device of the PVT cylinder. After the mixed system in the PVT cylinder is equilibrated, observe whether it changes from a single phase to two phases. Record the maximum CO2 solubility when the mixed system is in a single phase. Measure the CO2 solubility of each mixed system in turn. Step S1.5: Calculate C for each mixed system according to formula (6) c According to the measurement results, draw different C c The value corresponds to the solubility curve of CO2, and the lowest point of the curve is the CO2 solubility of the middle phase microemulsion nonionic surfactant mixed system, which is recorded as a mol / L;

[0039] in: x——the proportion of the first nonionic surfactant NS1 in the mixed system; y——the proportion of the second nonionic surfactant NS2 in the mixed system; C ca ——Characteristic parameters of the first nonionic surfactant NS1; C cb ——Characteristic parameters of the second nonionic surfactant NS2.

[0040] Preferably, the nonionic surfactant in step S1 can be Tween 60, Tween 80, TX-45, TX-100, TX-114, or other single-agent nonionic surfactants that can solubilize CO2 or form a middle-phase microemulsion with crude oil, or a mixture of multiple single-agents, such as NPE9 (C 33 H 60 O 10 )、Span20(C 18 H 34 O6)、Brij-35(C 12 H 25 (OC2H4) 23 OH), PNS (C 33 H 60 O 10 ), MPEG-350 (C 25H 53 NO 12 ).

[0041] Preferably, the experimental method for determining the oil phase EACN in step S2 comprises the following steps: Step S2.1: Determine the minimum miscibility pressure (MMP) of the crude oil. The minimum miscibility pressure (MMP) is related to the average carbon number (Cn), and the average carbon number (Cn) is related to the equivalent alkane carbon number (EACN) as follows:

[0042]

[0043] in: ——minimum miscible pressure, MPa; — average carbon number; ——Equivalent alkane carbon number of the oil phase; ——Experience coefficient, the value is 1.

[0044] Step S2.2: Calculate the average carbon number of crude oil as Cn according to Formula 7, and calculate the equivalent alkane carbon number as EACN according to Formula 8; Preferably, the characteristic parameter Cc value of the nonionic surfactant in step S2 is used to characterize the hydrophobicity of the nonionic surfactant. The larger the Cc value of the nonionic surfactant, the more lipophilic it is, and the smaller the Cc value, the more hydrophilic it is. By adjusting the amount of two nonionic surfactants with different Cc values ​​to control the Cc value of the mixed system, a middle phase microemulsion can be formed. In the HLD equation, when the mixed system forms a middle phase microemulsion, HLD is equal to 0.

[0045] Preferably, the specific steps of verifying the conclusion in step S7 are: Step S7.1: Add a fixed amount of NS1 solution and NS2 solution to the sample dispenser in sequence, then inject a fixed amount of CO2 into the mixed system, where the CO2 concentration is a mol / L, stir evenly, and transfer to an intermediate container for later use; Step S7.2: Select a long core for use, determine the parameters of the long core, and clean, dry, and vacuum the core; Step S7.3: After the core is loaded into a long core holder, it is quantitatively saturated with formation water. The pressure and temperature are raised to the formation pressure and temperature, respectively. After standing for 24 hours, the formation water in the long core is displaced with crude oil to establish irreducible water saturation. Step S7.4: Set the back pressure slightly lower than the formation pressure, displace the oil with ordinary carbonated water at a rate of 0.125 mL / min, record the produced oil volume, and calculate the crude oil recovery factor; Step S7.5: Repeat steps S7.2 to S7.4, setting the back pressure slightly lower than the formation pressure so that the enhanced carbonated water in the intermediate container is displaced at a rate of 0.125 mL / min. Record the produced oil volume and calculate the crude oil recovery factor.

[0046] This example uses actual oil field parameters at a certain location as an example. The target formation pressure of the oil field water injection layer is 20 MPa, the formation temperature is 45°C, the formation water salinity is 8000 mg / L, and the core used in the displacement experiment has a diameter of 2.5 cm, a length of 50 cm, a permeability of 48 mD, and a porosity of 16%. The specific implementation method is as follows.

[0047] The experimental device includes a displacement pump (1, 16, 17), an NS1 intermediate container 2, an NS2 intermediate container 3, a formation water intermediate container 4, a CO2 intermediate container 5, a formation crude oil intermediate container 6, an enhanced carbonated water intermediate container (20), a carbonated water intermediate container (33), valves (7, 8, 9, 10, 11, 12, 15, 17, 18, 19, 21, 22, 28, 30, 31, 32, 34), a constant temperature oven (13, 35), a PVT cylinder (14), a magnetic stirring device (29), a long core holder (23), a differential pressure gauge (24), a back pressure regulator (25), a back pressure gauge (26), and a beaker (27).

[0048] (1) Nonionic surfactant selected NPE9 (C 33 H 60 O 10 ) and Span20 (C 18 H 34 O6), the characteristic parameters of the two nonionic surfactants were 1.651 and 3.54 respectively; (2) Prepare 0.05 mol / L NPE9 solution and 0.05 mol / L Span20 solution using formation water sample of target layer, and inject them into intermediate containers 2 and 3 respectively; (3) Open valves 12, 7, 19, and 28, turn on displacement pump 1, add a fixed amount of NPE9 solution to the PVT cylinder, turn off displacement pump 1, and close valve 7; open valve 8, turn on displacement pump 1, add a fixed amount of Span20 solution to the PVT cylinder, turn off displacement pump 1, and close the valves. The amount of nonionic surfactant added is shown in Table 1 for mixed system 1; (4) Set the PVT cylinder temperature to 45°C, open valve 15, control the displacement pump 17, pressurize the PVT cylinder to 20 MPa, and set the displacement pump to constant pressure mode; (5) Open valve 12, turn on displacement pump 1, pressurize the intermediate container from 5 to 20 MPa, open valves 10, 19, and 28, control displacement pump 1 to slowly inject 2 mL of CO2 into the PVT cylinder, and close the valve and displacement pump 1; (6) Turn on the magnetic stirring device 29 and stir the mixed system for 2 h. After it stabilizes, observe whether the mixed system is two-phase. If not, repeat steps (5) to (6); if yes, proceed to the next step. (7) Record the maximum amount of CO2 dissolved when the mixed system is in a single-phase state and calculate the CO2 solubility of mixed system 1; (8) Control pump 17, depressurize and clean the PVT cylinder, repeat steps (3) to (7), and measure the CO2 solubility of mixed systems 2 to 6 in Table 1 respectively. After the measurement, depressurize the intermediate container and close the displacement pump 1 and all valves; (9) The CO2 solubility in formation water was measured to be 1.29 mol / L. Based on the experimental results, the CO2 solubility curves of mixed systems 1 to 6 were drawn, and the lowest point of the curve was 2.4 mol / L.

[0049] (10) According to the invention patent “A method for preparing representative degassed crude oil with equivalent minimum miscibility pressure” (CN115078024A), the minimum miscibility pressure of crude oil was first measured using the SY / T 6573-2016 capillary method to be 7.3 MPa. The EACN of crude oil was calculated to be 13.58, and the corrected EACN was 12.13. (11) According to the relationship (Formulas 3 and 4), the CO2 saturation pressure is 9.12 MPa, the oil phase bubble point pressure is 8.07 MPa, the temperature is 318 K, and the crude oil molar mass is 231 g / mol. The calculated y is 1.0095, the oil phase CO2 solubility is 1.584 mol / L, the CO2 solubility in formation water is measured to be 1.29 mol / L, and the distribution coefficient K1 is calculated to be 0.814 according to Formula 5. Therefore, the oil phase CO2 solubility of the mixed system is 1.05 mol / L. (12) The EACN of the oil phase was estimated to decrease by 20%, and the EACN after the decrease was 9.704; (13) According to the HLD equation (Formula 2), b is 0.13, S is 0.8 g / 100 mL, K is 0.17, and C T 0.06K -1 , then the initial experimental value C of the mixed system is calculated c is 2.75, then the corresponding ratio of nonionic surfactant NPE9 and Span20 in the mixed system is 0.42:0.58; (14) Open valves 12, 7, 19, and 28, open displacement pump 1, and slowly add 4.2 mL of NPE9 solution to the cylinder. Close displacement pump 1 and valve 7. Open valve 8 and displacement pump 1, and slowly add 5.8 mL of Span20 solution to the cylinder. Close displacement pump 1 and valve 8. Open valve 11 and displacement pump 1, and add 10 mL of formation crude oil to the cylinder. Close displacement pump 1 and valves 12, 11, 19, and 28. (15) Open the displacement pump 17 and valve 15, and control the hydraulic oil in the lower part of the PVT cylinder to increase the pressure upward, so that the pressure in the PVT cylinder is increased to 20 MPa and then maintained at a constant pressure state. At the same time, control the constant temperature oven 13 to heat the PVT cylinder to 45°C; (16) Open displacement pump 1 and valve 12 to pressurize the intermediate container to 20 MPa; (17) Open valves 10, 19, and 28, control displacement pump 1, add 2.4 mol / L CO2 to the cylinder, turn off displacement pump 1, and close valves 10, 19, and 28; (18) Turn on the magnetic stirring device 29 and stir the mixed system at a constant speed for 2 h. After the system stabilizes, observe whether a middle phase microemulsion appears. (19) If the middle phase microemulsion does not form in the PVT cylinder: (a) When the lower phase microemulsion is formed, the displacement pump 1, valves 8, 12, 19, and 28 are opened, 1 mL of PNS solution is added to the cylinder, the displacement pump 1 and valve 8 are closed, valve 9 is opened, 1 mL of formation water is added to the cylinder, valve 9 is closed, valve 10 is opened, CO2 is continued to be added to the mixed system to keep the CO2 concentration in the mixed system unchanged, and steps (18) to (19) are repeated; (b) When the upper phase microemulsion is formed, the displacement pump 1, valves 7, 12, 19, and 28 are opened, 1 mL of TX-100 solution is added to the cylinder, the displacement pump 1 is closed, valve 7 is closed, valve 9 is opened, 1 mL of formation water is added to the cylinder, valve 9 is closed, valve 10 is opened, CO2 is continued to be added to the mixed system to keep the CO2 concentration in the mixed system unchanged, and steps (18) to (19) are repeated; (20) If a middle phase microemulsion is formed in the PVT cylinder, record the formula of the mixed system in the PVT cylinder; (21) Control displacement pumps 1 and 17, depressurize the intermediate container and PVT cylinder, and clean the PVT cylinder; (22) According to the mixed system recorded in step 20, open valves 12, 7, 18, 22, and 32, turn on displacement pump 1, add TX-100 to the intermediate container 20, close valve 7, open valve 8, add PNS to the intermediate container 20, close valve 8, open valve 9, add formation water to the intermediate container 20, close valve 9, open valve 10, add 2.4 mol / L CO2, and close the valves and displacement pump; (23) Open valves 12, 9, 18, 22, and 31, start displacement pump 1, add 100 mL of formation water to the intermediate container 33, close valve 9, open valve 10, add 1.29 mol / L CO2, and close the valves and displacement pump; (24) Turn on the displacement pump 16 and pressurize the intermediate containers 20 and 33 to 20 MPa for standby use; (25) After the core is cleaned, dried and vacuumed, the long core is placed in the long core holder 23; (26) Open valves 12, 9, 18, and 21, turn on displacement pump 1, saturate the core with 2 PV of formation water, and close valves and pump 1; (27) Open valve 34, displacement pump 16, and constant temperature oven 35 to raise the pressure and temperature of the long core holder to the formation pressure and temperature, respectively; (28) After standing for 24 hours, open valve 12 and displacement pump 1 to pressurize the intermediate container to the formation pressure, open valves 11, 18, and 21, and use crude oil to displace the formation water in the long core to establish irreducible water saturation; (29) Control the back pressure regulator 25 to set the back pressure slightly lower than the formation pressure, open valves 31 and 30, turn on the displacement pump 16, and allow carbonated water to displace at a rate of 0.125 mL / min. The amount of oil produced in the beaker 27 is 17.8 mL, and the crude oil recovery factor is calculated to be 48.77%. Close the valve and the displacement pump; (30) Repeat steps (25) to (28), control the back pressure regulator 25, set the back pressure to the formation pressure, open valves 32 and 30, turn on the displacement pump 16, and allow the enhanced carbonated water to displace at a rate of 0.125 mL / min. The amount of oil produced in the beaker 27 is 27.4 mL, and the crude oil recovery factor is calculated to be 75.07%. Close the valve and the displacement pump; The above description is only a preferred specific embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any technician familiar with the technical field, within the technical scope disclosed by the present invention, who makes equivalent replacements or changes based on the technical solution and inventive concept of the present invention, should be covered by the scope of protection of the present invention.

Claims

1. An experimental design method for a medium-phase microemulsion-enhanced carbonated water enhanced oil recovery system, comprising the following steps: Step S1: Determine the CO2 solubility in formation water. Determine the CO2 solubility in two mixed systems consisting of non-ionic surfactants and formation water in different proportions. The amount of CO2 injected in the experiment is the minimum CO2 solubility of the mixed system measured, recorded as amol / L. Calibration of the minimum CO2 solubility can prevent the escape of dissolved CO2 in the mixed system during the experiment. Step S2: Determine the equivalent alkane carbon number of the CO2-free oil phase, record it as EACN1, and substitute EACN1 into the hydrophilic-lipophilic deviation (HLD) equation to calculate the characteristic parameter C of the nonionic surfactant when the mixed system forms a middle phase microemulsion. c1 value; Step S3: Calculate the maximum amount of CO2 dissolved in the oil phase according to the empirical formula for the amount of CO2 dissolved in crude oil. Experimentally measure the solubility of CO2 in formation water and calculate the distribution coefficient K1 according to the following formula. Combined with the total amount of CO2 dissolved in the experiment, the amount of CO2 dissolved in the oil phase of the mixed system is calculated by the distribution coefficient. The value of EACN1 reduced when CO2 is dissolved in the oil phase is calculated based on the amount of CO2 dissolved in the oil phase, and recorded as the equivalent alkane carbon number EACN2; ， in: K1——CO2 distribution coefficient; ——CO2 solubility in formation water, mol / L; ——CO2 solubility in crude oil, mol / L; Step S4: Substitute EACN2 into the step S2 to calculate the C required for the mixed system to form a middle phase microemulsion after the oil phase EACN changes when CO2 is dissolved. c2 value; Step S5: After cleaning the PVT cylinder, add a certain amount of NS1 solution and NS2 solution into the cylinder again. The characteristic parameter of the mixed system is C c2 A certain proportion of oil phase is added to the PVT cylinder, the temperature of the PVT cylinder is set to the target layer temperature, and the hydraulic oil below the PVT cylinder pushes the piston in the PVT cylinder upward to make the pressure of the PVT cylinder equal to the formation pressure; then the piston in the PVT cylinder is controlled and CO2 is introduced into the PVT cylinder under constant pressure conditions to make the CO2 concentration in the mixed system a mol / L, ensuring that CO2 can be fully dissolved in the mixed system; Step S6: Control the PVT cylinder to stir the mixed system at a uniform speed, let it stand for a period of time, and determine whether a middle phase microemulsion appears after it stabilizes; if a lower phase microemulsion is formed in the PVT cylinder, continue to add NS2 solution to the PVT cylinder and continue to introduce CO2 to ensure that the CO2 concentration in the aqueous phase is always maintained at a mol / L; if an upper phase microemulsion is formed in the PVT cylinder, continue to add NS1 solution to the PVT cylinder and continue to introduce CO2 to ensure that the CO2 concentration in the mixed system is always maintained at a mol / L, until a middle phase microemulsion is formed in the PVT cylinder, and then record the mixed system formula in the PVT cylinder; finally, obtain the component ratio of NS1 solution and NS2 solution; Step S7: Verify the experimental design conclusions based on the long core flooding experiment and compare the results.

2. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 1, characterized in that: The specific steps of obtaining the minimum solubility of CO2 in the middle phase microemulsion surfactant mixed system in step S1 include: Step S1.1: Determine the target layer temperature and pressure, prepare a certain amount of reservoir crude oil (live oil) sample and formation water; select two non-ionic surfactants NS1 and NS2, prepare NS1 solution and NS2 solution of certain concentrations, and determine the characteristic parameters C of NS1 and NS2. c value, where NS1's C c The value is less than NS2, and the target layer temperature should be lower than the cloud point of the nonionic surfactant, otherwise the nonionic surfactant will become ineffective; Step S1.2: Control the displacement pump 1 to mix different ratios of NS1 solution and NS2 solution in the PVT cylinder, wherein the ratios of NS1 solution and NS2 solution in the mixed system are set to 0:1, 2:8, 4:6, 6:4, 8:2, and 1:0; Step S1.3: Control displacement pumps 1 and 17 to pressurize the PVT cylinder to the target layer pressure, set the PVT cylinder to the target layer temperature, and then set displacement pump 17 to constant pressure mode; then control displacement pump 1 to pressurize the CO2 intermediate container to the target layer pressure, and then slowly inject an appropriate amount of CO2 into the PVT cylinder; Step S1.4: Turn on the magnetic stirring device of the PVT cylinder. After the mixed system in the PVT cylinder is equilibrated, observe whether it changes from a single phase to two phases. Record the maximum CO2 solubility when the mixed system is in a single phase. Measure the CO2 solubility of each mixed system in turn. Step S1.5: Calculate the C of each mixed system according to the following formula c According to the measurement results, different C c The value corresponds to the solubility curve of CO2, and the lowest point of the curve is the CO2 solubility of the middle phase microemulsion nonionic surfactant mixed system, which is recorded as a mol / L; ， in: x——the proportion of the first nonionic surfactant NS1 in the mixed system; y——the proportion of the second nonionic surfactant NS2 in the mixed system; C ca ——Characteristic parameters of the first nonionic surfactant NS1; C cb ——Characteristic parameters of the second nonionic surfactant NS2.

3. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 2, characterized in that: The nonionic surfactant in step S1 can be Tween 60, Tween 80, TX-45, TX-100, TX-114, or other single-agent nonionic surfactants that can solubilize CO2 or form a middle-phase microemulsion with crude oil, or a mixture of multiple single-agents, such as NPE9 (C 33 H 60 O 10 )、Span20(C 18 H 34 O6)、Brij-35(C 12 H 25 (OC2H4) 23 OH), PNS (C 33 H 60 O 10 ), MPEG-350 (C 25 H 53 NO 12 ).

4. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 1, characterized in that: The HLD equation calculation formula in step S2 is as follows: ， Formula transformation to calculate Cc value: ， in: S——formation water mineralization, g / 100mL; b is a constant, which is 0.13 for sodium chloride and 0.1 for calcium chloride; K - surfactant characteristic parameter head, characterizing the hydrophilicity / lipophilicity of nonionic surfactants; EACN – equivalent alkane carbon number of the oil phase; ——The temperature coefficient of the optimal salinity is 0.06 K -1 ; ——the difference between the experimental temperature and the normal temperature, K; C c ——The characteristic parameter tail chain of nonionic surfactants characterizes the hydrophilicity / lipophilicity of nonionic surfactants; ——Characterizes the type and concentration of co-surfactant in the system. If no co-surfactant is used, the value of the function is zero.

5. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 4, characterized in that: The experimental method for determining the oil phase EACN in step S2 comprises the following steps: Step S2.1: Determine the minimum miscibility pressure (MMP) of the crude oil. The minimum miscibility pressure (MMP) is related to the average carbon number (Cn), and the average carbon number (Cn) is related to the equivalent alkane carbon number (EACN) as follows: ， ， in: ——minimum miscible pressure, MPa; — average carbon number; ——Equivalent alkane carbon number of the oil phase; ——Experience coefficient, the value is 1; Step S2.2: Calculate the average carbon number Cn of crude oil and the equivalent alkane carbon number EACN according to the above relationship.

6. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 5, characterized in that: The characteristic parameter Cc value of the nonionic surfactant in step S2 is used to characterize the hydrophobicity of the nonionic surfactant. The larger the Cc value of the nonionic surfactant, the more lipophilic it is, and the smaller the Cc value, the more hydrophilic it is. By adjusting the amount of two nonionic surfactants with different Cc values ​​to control the Cc value of the mixed system, a middle phase microemulsion can be formed. In the HLD equation, when the mixed system forms a middle phase microemulsion, HLD is equal to 0.

7. The experimental design method for the middle phase microemulsion enhanced carbonated water recovery system according to claim 1, characterized in that: The empirical formula in step S3 is as follows: ， ， in: T——temperature, K; P s ——CO2 saturation pressure, MPa; P b ——bubble point pressure of oil, MPa; MW – molar mass of the oil, g / mol.

8. The experimental design method for the medium-phase microemulsion enhanced carbonated water enhanced oil recovery system according to claim 1, characterized in that: In step S6, the concentration gradients of NS1 and NS2 solutions added to the PVT cylinder are both 0.01 mol / L.

9. The experimental design method for the medium-phase microemulsion enhanced carbonated water recovery system according to claim 1, characterized in that: Specific steps for verifying the conclusion in step S7: Step S7.1: Add a fixed amount of NS1 solution and NS2 solution to the sample dispenser in sequence, then inject a fixed amount of CO2 into the mixed system, where the CO2 concentration is a mol / L, stir evenly, and transfer to an intermediate container for later use; Step S7.2: Select a long core for use, determine the parameters of the long core, and clean, dry, and vacuum the core; Step S7.3: After the core is loaded into a long core holder, it is quantitatively saturated with formation water. The pressure and temperature are raised to the formation pressure and temperature, respectively. After standing for 24 hours, the formation water in the long core is displaced with crude oil to establish irreducible water saturation. Step S7.4: Set the back pressure slightly lower than the formation pressure, displace the oil with ordinary carbonated water at a rate of 0.125 mL / min, record the produced oil volume, and calculate the crude oil recovery factor; Step S7.5: Repeat steps S7.2 to S7.4, setting the back pressure slightly lower than the formation pressure so that the enhanced carbonated water in the intermediate container is displaced at a rate of 0.125 mL / min. Record the produced oil volume and calculate the crude oil recovery factor.

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