A composite system for residual oil reactivation after carbon dioxide flooding, a preparation method and application thereof

Abstract

This invention discloses a composite system for restarting residual oil after CO2 flooding, its preparation method, and its application. The composite system comprises an oil-soluble surfactant and an emulsifier; the oil-soluble surfactant contains aromatic ring structural units, alkyl long-chain structural units, and polar group structural units, and is preferably prepared by free radical polymerization of styrene, octadecyl methacrylate, and maleic anhydride; the emulsifier is preferably sodium dodecylbenzenesulfonate. The composite system of this invention can rapidly reduce the viscosity and oil-water interfacial tension of heavy components in residual oil after CO2 flooding. Injecting the composite system of this invention into the CO2-flooded formation, followed by subsequent CO2 injection to form a gas-liquid flooding system, can effectively expand the sweep range and improve oil washing efficiency. Core displacement experiments show that it can increase the recovery rate by more than 16%. This invention solves the problems of high viscosity, difficult start-up, and poor injectability of heavy components in residual oil after CO2 flooding, and has good prospects for oilfield application.

Description

Technical Field

[0001] This invention relates to the fields of oil and gas field development engineering and oilfield chemistry, and in particular to an oil-soluble polymeric surfactant composite system for efficient restarting of residual oil after carbon dioxide flooding, its preparation method, and its application in oil displacement in low-permeability reservoirs. Background Technology

[0002] Carbon dioxide (CO2) enhanced oil recovery (EOR) technology has become one of the important means to improve the recovery rate of crude oil in low-permeability reservoirs. This technology injects CO2 into the formation, utilizing CO2's low surface tension and high solubility to improve the physicochemical properties of the reservoir and displace crude oil. Simultaneously, CO2 EOR technology enables the geological sequestration and utilization of industrially emitted CO2, aligning with the carbon capture, utilization, and storage (CCUS) development strategy and yielding significant economic and environmental benefits.

[0003] However, CO2 flooding can have adverse effects on reservoirs. CO2 has a strong extraction effect, preferentially extracting light components (such as saturated hydrocarbons) from crude oil during displacement and carrying them away through vaporization. As the CO2 displacement time increases, the content of light components in the remaining oil gradually decreases, while the proportion of heavy components such as aromatics, gums, and asphaltenes increases significantly. Studies have shown that after CO2 displacement, the polarity of the remaining oil increases, its viscosity rises, and its fluidity decreases significantly, leading to a significant increase in the difficulty of subsequent extraction. In addition, the cross-linking and association between heavy components further exacerbates formation damage and reduces the ultimate recovery rate.

[0004] To address the aforementioned issues, existing technologies have proposed injecting surfactant solutions into CO2-flooded formations to reduce oil-water interfacial tension and improve the fluidity of remaining oil through emulsification, thereby increasing the recovery rate of remaining oil. This method is simple and low-cost, but it still has the following shortcomings: (1) the emulsification effect is slow, making it difficult to quickly start up the remaining oil; (2) the emulsion formed has poor stability and is prone to demulsification under complex formation conditions; (3) the viscosity-reducing effect is limited for remaining oil with a high proportion of heavy components.

[0005] In recent years, oil-soluble polymeric surfactants have attracted attention due to their ability to directly act on heavy components of crude oil, dismantle aggregated structures, and reduce cohesion. These materials can rapidly reduce residual oil viscosity and improve start-up efficiency. However, existing oil-soluble polymeric surfactants generally suffer from poor water solubility, difficulties in field injection, and high costs, which limit their large-scale application in the field.

[0006] Therefore, how to combine the advantages of emulsification and oil-soluble polymer surfactant technology to construct a composite system that can quickly and efficiently restart residual oil after CO2 flooding and has good injectability and stability is a technical problem that urgently needs to be solved in this field. Summary of the Invention

[0007] This invention addresses the problems of high heavy component content, high viscosity, and difficulty in starting up residual oil after CO2 flooding, as well as the slow action of existing surfactants and poor injectability of oil-soluble polymeric agents. It provides a composite system that can rapidly reduce viscosity, lower oil-water interfacial tension, and is easy to inject to form a gas-liquid flooding mixture with subsequent CO2, so as to achieve efficient restart of residual oil after CO2 flooding and a significant improvement in recovery rate.

[0008] The present invention first provides an oil-soluble polymeric surfactant comprising aromatic ring structural units, alkyl long-chain structural units and polar group structural units, and is prepared by free radical polymerization reaction; The aromatic ring structural unit is a styrene monomer; The alkyl long-chain structural unit is an alkyl ester monomer of (meth)acrylate; The polar group unit is an olefinic unsaturated carboxylic acid or its anhydride monomer.

[0009] Preferably, the styrene monomer is styrene and / or methylstyrene; Preferably, the alkyl methacrylate monomer is octadecyl methacrylate; Preferably, the olefinic unsaturated carboxylic acid or its anhydride monomer is maleic anhydride.

[0010] The present invention also provides a method for preparing the oil-soluble surfactant, comprising the following steps: Styrene monomers, (meth)acrylate alkyl ester monomers, and olefinic unsaturated carboxylic acids or their anhydrides are mixed in an organic solvent, heated to 50-85°C and stirred under inert gas protection; After the monomer dissolves, add the initiator dropwise and continue the reaction for 6-12 hours. After the reaction is complete, the reaction solution is poured into an alcohol solvent to precipitate a solid. After washing and drying, the oil-soluble polymeric agent is obtained. The initiator is azobisisobutyronitrile (AIBN); the organic solvent is toluene; and the alcohol solvent is ethanol.

[0011] Based on the oil-soluble surfactant, the present invention also provides a composite system for restarting residual oil after carbon dioxide flooding, comprising: The oil-soluble surfactant and emulsifier; In the composite system, the mass concentration of the oil-soluble surfactant is 0.01%-0.1%; and the mass concentration of the emulsifier is 0.1%-0.5%.

[0012] The mass ratio of the oil-soluble surfactant to the emulsifier is 1:1 to 1:10.

[0013] Preferably, the emulsifier is selected from anionic surfactants, nonionic surfactants, or combinations thereof; preferably, the emulsifier is anionic surfactant, more preferably sodium dodecylbenzenesulfonate.

[0014] Based on the aforementioned composite system, the present invention further provides a method for improving oil recovery in reservoirs after carbon dioxide flooding, comprising the following steps: The composite system is injected into the reservoir formation where carbon dioxide flooding has been completed; then, carbon dioxide is injected into the formation to form a mixed gas-liquid flooding. The composite system emulsifies the remaining oil into small droplets by reducing the viscosity of the heavy components in the remaining oil after carbon dioxide flooding and / or reducing the oil-water interfacial tension.

[0015] The "residual heavy oil fraction" mentioned in this invention refers to the relatively enriched heavier hydrocarbon fractions in the crude oil remaining in the reservoir pores after CO2 displacement, due to the extraction effect of CO2.

[0016] Specifically, during the CO2 displacement process, CO2 preferentially extracts light components (such as C7-C10 saturated hydrocarbons) from crude oil and carries them out of the formation via vaporization. As the CO2 displacement time increases, the content of saturated hydrocarbons in the remaining oil decreases significantly, while the proportion of heavy components such as aromatics, resins, and asphaltenes increases relatively. Four-component analysis shows that the aromatic hydrocarbon content in the remaining oil after CO2 displacement can increase from around 15% to over 19%, and the contents of resins and asphaltenes also increase. Gas chromatography analysis of total hydrocarbons shows a significant increase in the mass percentage of C11 and above heavy components.

[0017] The aforementioned changes in composition lead to significant alterations in the physicochemical properties of the residual oil: increased polarity, higher viscosity, and decreased fluidity. Furthermore, the heavy components readily cross-link and associate, forming large aggregates or layered structures, further increasing the difficulty of restarting. The "heavy residual oil components" described in this invention refer to this highly polar, high-viscosity crude oil fraction enriched after CO2 extraction.

[0018] This invention also provides the application of the above-mentioned composite system or the above-mentioned oil-soluble surfactant in the preparation of an oil displacement agent for enhancing oil recovery in carbon dioxide flooded reservoirs. Preferably, the oil displacement agent is used to reduce the viscosity of heavy components in the residual oil after carbon dioxide flooding, reduce the oil-water interfacial tension, and / or expand the displacement sweep range.

[0019] The method for improving oil recovery after carbon dioxide flooding provided by this invention comprises the following two core principles: I. The chemical action principle of the composite system on residual oil components Rapid viscosity reduction principle: The oil-soluble surface-modifying agent (OSPS) synthesized in this invention simultaneously contains aromatic ring structures, long-chain alkyl groups, and polar groups (carboxyl groups). The aromatic rings can insert into the layered structure of aromatic hydrocarbons in the heavy components of residual oil through π-π conjugation; the polar groups can form hydrogen bonds with the gums and asphaltenes in the heavy components. This dual action effectively breaks down the physical cross-linking and association structures between heavy components, dispersing large aggregates into randomly stacked small molecule aggregates, reducing the cohesive force of crude oil, and thus rapidly reducing the apparent viscosity of residual oil.

[0020] The principle behind reducing interfacial tension is that OSPS, when combined with an emulsifier (preferably SDBS), can be directionally adsorbed at the oil-water interface. The oil-soluble portion of OSPS (aromatic rings, long-chain alkyl groups) inserts into the oil phase, while the hydrophilic groups of the emulsifier extend into the aqueous phase, forming a dense interfacial film that significantly reduces the oil-water interfacial tension (down to 0.003 mN / m). This low interfacial tension allows the remaining oil to be easily sheared and emulsified into small oil droplets, which are then dispersed in the aqueous phase.

[0021] Synergistic effect principle: OSPS improves the emulsifability of residual oil components, while the emulsifier improves the dispersibility of OSPS in the aqueous phase. The synergistic effect of the two not only solves the problems of poor water solubility and difficult injection when OSPS is used alone (Comparative Example 2), but also significantly improves the viscosity reduction rate and oil washing efficiency.

[0022] II. The principle of synergistic displacement with subsequent CO2 injection Formation of mixed-gas-liquid drive: After injecting the composite system, CO2 gas is continued to be injected into the formation. The CO2 gas and the composite system solution form a mixed-gas-liquid two-phase coexistence state in the porous medium of the formation.

[0023] Expanding the reach: CO2 bubbles preferentially enter large channels with high flow resistance. Due to the Jamin effect (the additional resistance generated when bubbles pass through the throat), blockage occurs, forcing subsequent complex solutions to divert into previously unused small and medium-sized channels. This process can occur cumulatively, effectively adjusting the water absorption profile and expanding the reach of liquid-phase displacement.

[0024] Improved oil washing efficiency: The composite system pre-emulsifies the remaining oil in small and medium-sized channels into small oil droplets, reducing the flow resistance of the oil-containing channels. During post-CO2 flooding, the gas phase drives the liquid phase forward, and the liquid phase carries the emulsified small oil droplets out of the channels. At the same time, CO2 can further dissolve in the remaining oil in the gas-liquid flooding, reducing the viscosity of the oil phase and enhancing its fluidity.

[0025] Synergistic effect: Core NMR experiments show that using the "composite system + post-CO2 flooding" method of this invention significantly reduces the area of ​​residual oil peaks in small and medium pores (a further reduction of 24.3% in small pores and 35.15% in medium pores), and the permeability recovery rate increases from 73.74% in SDBS flooding alone to 87.65%, ultimately increasing the recovery rate by more than 16%. Neither CO2 gas flooding nor surfactant flooding alone can achieve such a significant effect on the activation of small and medium pores (see Comparative Example 1).

[0026] In summary, the method of the present invention achieves efficient restart of the remaining oil after CO2 flooding, especially the remaining oil of heavy components in small and medium pores, by combining the chemical viscosity reduction and interfacial tension reduction of the composite system with the physical regulation and sweep expansion effect of subsequent CO2 injection, thereby significantly improving the final recovery rate of the reservoir.

[0027] Compared with the prior art, the present invention has the following beneficial effects: Significant and rapid viscosity reduction effect: The oil-soluble surfactant (OSPS) synthesized in this invention contains aromatic rings, long-chain alkyl groups, and polar groups, enabling it to rapidly insert into the layered stacking structure of residual heavy oil components after CO2 flooding, disintegrating aggregates and reducing crude oil cohesion. Experiments show that when OSPS is combined with SDBS (mass concentrations of 0.05% and 0.35%, respectively), the viscosity reduction rate for residual heavy oil components can reach 83.2%, and the action rate is significantly faster than that of surfactants used alone.

[0028] Significantly reduced oil-water interfacial tension: The composite system of this invention can rapidly accumulate at the oil-water interface, significantly reducing interfacial tension. The compound system can achieve ultra-low interfacial tension under simulated formation water conditions and has good salt resistance, which is beneficial for the emulsification and stripping of residual oil.

[0029] Synergistic effect of gas-liquid flooding: The composite system of this invention forms a gas-liquid flooding system with the subsequently injected CO2. The gas phase preferentially enters the large channels to generate the Jamin effect, blocking the dominant channels and forcing the liquid phase to turn to the medium and small channels. At the same time, the addition of OSPS reduces the flow resistance of the oil-containing channels and greatly expands the displacement sweep range.

[0030] Significantly improved oil recovery: Microscopic displacement experiments and core nuclear magnetic resonance experiments show that the composite system of this invention can effectively utilize various types of residual oil in small and medium pores, including columnar, clustered, blind-end, and film-like structures. In low-permeability core displacement experiments, the recovery rate of pre-CO2 flooding was 53.36%. After injecting the composite system of this invention and performing post-CO2 flooding, the final recovery rate reached 70.83%, an increase of over 16%, and the permeability recovery rate increased from 73.74% to 87.65%.

[0031] Good injectability and controllable cost: This invention improves the water dispersibility of oil-soluble surfactants by compounding them with emulsifiers, solving the problem of difficult injection when used alone. In addition, the raw materials are readily available and the preparation process is simple, which has good prospects for field application. Attached Figure Description

[0032] Figure 1 This is a schematic diagram illustrating the construction of the CO2-driven residual oil restart system of the present invention.

[0033] Figure 2 This is a comparison of the total hydrocarbon components of crude oil before and after CO2 flooding in an embodiment of the present invention.

[0034] Figure 3 Figure 1 shows the molecular simulation results of the present invention. Figure 2(a) shows the radial distribution function of different groups and oil phase, and Figure 3(b) shows the schematic diagram of the simulation system of residual oil molecules after CO2 flooding ("oil box").

[0035] Figure 4 The following are isosurface plots for IGMH analysis in this invention: (a) is the isosurface distribution of the interaction between OSPS containing aromatic ring structures and the remaining oil components, and (b) is the isosurface distribution of the interaction between molecules without aromatic hydrocarbon structures and the remaining oil components.

[0036] Figure 5 The figure shows the effect of OSPS and two surfactants with different addition amounts on the viscosity of the oil phase at different mixing times in the embodiments of the present invention.

[0037] Figure 6 Figure 1 shows the interfacial tension test results in an embodiment of the present invention. Figure 2 shows the change of the interfacial tension of the remaining oil over time before and after the OSPS and SDBS compounding process. Figure 3 shows the change of the interfacial tension of the remaining oil after the OSPS and SDBS / TX-100 compounding process. + With Ca 2+ The effect of the system on interfacial tension is shown in the diagram.

[0038] Figure 7 The diagrams shown are microscopic displacement process diagrams in the embodiments of the present invention, wherein (a)-(c) are saturated oil, pre-water flooding, and system flooding stages using a 0.35wt% SDBS system solution; and (d)-(f) are saturated oil, pre-water flooding, and system flooding stages using a 0.35wt% SDBS + 0.05wt% OSPS system solution.

[0039] Figure 8 The diagrams show the microscopic displacement process of each stage of CO2 gas drive in the embodiments of the present invention, wherein (a) is the pre-gas drive stage, (b) is the drive stage using the 0.35wt% SDBS+0.05wt% OSPS system, and (c) is the post-gas drive stage. Detailed Implementation

[0040] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention will be described in detail below with reference to the accompanying drawings. The drawings are for illustrative purposes only and should not be construed as limiting the invention.

[0041] This invention relates to a composite system for efficient restarting of residual oil after CO2 flooding and its application. The composite system comprises an oil-soluble surfactant and an emulsifier; the oil-soluble surfactant contains aromatic ring structural units, alkyl long-chain structural units, and polar group structural units, and is preferably prepared by free radical polymerization of styrene, octadecyl methacrylate, and maleic anhydride; the emulsifier is preferably sodium dodecylbenzenesulfonate (SDBS). This invention also provides a method for preparing the composite system and its application in improving oil recovery after CO2 flooding. This composite system can rapidly reduce the viscosity of heavy components in residual oil after CO2 flooding (viscosity reduction rate up to 83.2%) and the oil-water interfacial tension (up to 0.003 mN / m), forming a gas-liquid flooding mixture with subsequently injected CO2, effectively expanding the sweep range and improving oil washing efficiency. Core displacement experiments show that it can improve oil recovery by more than 16%, demonstrating good prospects for field application.

[0042] Example 1: Preparation of oil-soluble surfactant (OSPS) This embodiment provides an oil-soluble surfactant (OSPS) for restarting residual oil after CO2 flooding, which is prepared by free radical polymerization.

[0043] like Figure 1 As shown, the CO2-driven residual oil restart system constructed in this invention comprises a compound of oil-soluble surfactants and emulsifiers. The specific preparation is as follows: 250 mL of toluene was added to a 500 mL three-necked flask, followed by the addition of octadecyl methacrylate (20 g, 0.059 mol), styrene (10 g, 0.096 mol), and maleic anhydride (5 g, 0.051 mol), with a molar ratio of approximately 1:1.6:0.9. The entire experiment was conducted under nitrogen protection. The mixture was heated to 60 °C in a constant-temperature water bath and stirred at a constant speed of 300 rpm. After the monomers were completely dissolved, the initiator azobisisobutyl cyanide (AIBN, 0.3 g, dissolved in 5 mL of toluene) was slowly added dropwise over approximately 30 minutes using a constant-pressure dropping funnel. The reaction was continued at 60 °C for 5.5 hours. After the reaction was complete, a small amount of solid was observed precipitating at the bottom of the flask. The reaction solution was slowly poured into 500 mL of anhydrous ethanol and stirred, resulting in the precipitation of a white solid, which was then filtered. The filter cake was washed three times with ethanol to remove unreacted monomers. The filter cake was placed in a vacuum drying oven and dried at 40°C for 12 hours to obtain a white granular solid, which is the oil-soluble surfactant (OSPS), with a yield of about 78%.

[0044] Example 2: Preparation of the composite system Weigh 0.1g of OSPS prepared in Example 1 and 0.7g of sodium dodecylbenzenesulfonate (SDBS), add them to 200g of deionized water, and stir at 200r / min for 15 minutes at 25°C to obtain a homogeneous and stable composite solution.

[0045] Example 3: Component Analysis of Residual Oil After CO2 Flooding Crude oil samples provided by Changqing Oilfield were used to simulate CO2 flooding in a high-pressure reactor. Experimental conditions: temperature 85℃, pressure 10MPa, CO2 displacement times 48h and 72h, respectively. The oil samples before and after displacement were analyzed using a four-component method (saturated hydrocarbons, aromatic hydrocarbons, resins, and asphaltenes), and the results are shown in Table 1.

[0046] Table 1. Results of the four-component method test

[0047] Table 1 shows that after 72 hours of CO2 displacement, the saturated hydrocarbon content decreased from 72.41% to 65.85%, the aromatic hydrocarbon content increased from 15.08% to 18.79%, the resin content increased from 8.47% to 10.56%, and the asphaltene content increased from 4.04% to 4.80%. Simultaneously, gas chromatography was used to analyze the oil samples before and after displacement, and the results are as follows: Figure 2 As shown. By Figure 2 It can be seen that the hydrocarbon composition of crude oil before CO2 flooding has the highest mass percentage at C7 (10.53%); after CO2 flooding (48h and 72h), the hydrocarbon composition of crude oil has the highest mass percentage at C8 (8.52% and 8.07%, respectively), and the mass percentage of heavy components above C11 increases significantly. These results indicate that CO2 extraction leads to an increase in the remaining heavy components and enhanced polarity.

[0048] Example 4: Molecular Simulation and Structure Screening The "oil box" (e.g., oil box) of residual oil after CO2 flooding was constructed using the molecular simulation software Gromacs. Figure 3 (As shown in Figure b), the simulation was constructed according to the component proportions in Table 1 for 72h. The interaction between different functional groups and the oil phase was studied using the radial distribution function (RDF), and the results are as follows. Figure 3 As shown in Figure a. From Figure 3 As shown in Figure a, OSPS (containing styrene units) with aromatic structures have significantly higher RDF values ​​for the remaining oil components at 0.5 Å-1.5 Å than materials containing six-membered ring (vinylcyclohexane) structures, indicating that aromatic ring structures are more conducive to insertion into the layered stacking structure of the remaining oil.

[0049] Further IGMH analysis was performed using Multiwfn software, and interaction isosurface maps were plotted (e.g.) Figure 4 (As shown). By Figure 4 As shown in Figure a, the OSPS containing the benzene ring structure exhibits numerous isosurfaces of interaction with the remaining oil components, primarily distributed near the aromatic ring structure and carboxyl groups; while Figure 4 The molecules without aromatic hydrocarbon structures shown in Figure b exhibit fewer and weaker interactions. This indicates that the aromatic rings and polar groups of OSPS work synergistically to effectively dismantle aggregates of recombinant components.

[0050] Example 5: Performance Testing of the Composite System 1. Viscosity Reduction Performance Test Take 100g of the residual oil after the simulated CO2 flooding (72h sample) and place it in a constant temperature water bath at 85℃ for 30 minutes. Add different proportions of composite system solutions and mix at 100r / min for a certain time. Then, use a Brookfield viscometer at 85℃ and a shear rate of 10 s⁻¹. -1 The viscosity was measured, and the apparent viscosity reduction rate was calculated. The results are as follows: Figure 5 As shown.

[0051] With OSPS fixed at 0.05 wt%, the amount of SDBS was varied. Figure 5 It can be seen that when TX-100 is used alone (TX-100 only), the viscosity reduction initially increases and then stabilizes with increasing surfactant dosage, but the viscosity difference between 3 min and 15 min of mixing is relatively large (wide peak area), indicating a slow viscosity reduction rate. When combined with OSPS (TX-100 mix), the viscosity reduction rate increases and the peak area decreases at the same dosage, indicating that OSPS accelerates the viscosity reduction rate. Comparing the SDBS and TX-100 mixed systems (SDBS mix, TX-100 mix), when the SDBS dosage is 0.7 g (i.e., 0.35 wt%), the viscosity reduction rate reaches 83.2%; the viscosity reduction rate of TX-100 at the same dosage is 75.2%. Therefore, SDBS is preferred as the emulsifier, and a mass concentration of 0.35 wt% is preferred.

[0052] 2. Interface tension test The dynamic interfacial tension between different systems and simulated residual oil was measured using a rotating drop interfacial tensiometer at 85℃ and a rotation speed of 5000 r / min. The results are as follows: Figure 6 As shown.

[0053] Figure 6Figure a shows that the interfacial tension between the 0.35 wt% SDBS solution alone and the remaining oil stabilized at approximately 0.05 mN / m after 120 min; while the interfacial tension of the 0.35 wt% SDBS + 0.05 wt% OSPS mixture decreased to 0.008 mN / m within 30 min, eventually stabilizing at 0.003 mN / m. This indicates that the addition of OSPS significantly accelerated the decrease in interfacial tension and achieved a lower steady-state value.

[0054] Figure 6 Figure b shows that when NaCl and CaCl2 are added to the compound system, the interfacial tension decreases slightly when the NaCl concentration is 0.5%-1.0%; the interfacial tension drops to its lowest point (approximately 0.002 mN / m) when the CaCl2 concentration is 0.1%-0.2%. This indicates that the compound system has good salt tolerance.

[0055] Example 6: Microscopic Displacement Experiment A glass-etched microscopic model (pore size 10-100 μm) was used to simulate a formation temperature of 85℃ and a back pressure of 10 MPa. Experimental steps: (1) Saturate simulated residual oil (oil sample after CO2 flooding for 72 h); (2) Pre-flooding with water until no oil was produced; (3) Inject 0.5 PV composite system solution, followed by post-flooding with water until no oil was produced. Comparison system: System 1 was 0.35 wt% SDBS solution; System 2 was 0.35 wt% SDBS + 0.05 wt% OSPS compound system (stained with Rhodamine B).

[0056] The results are as follows Figure 7 As shown. Figure 7 The middle AC diagram shows a single SDBS flood: after the pre-water flood, the remaining oil exists in the form of continuous clusters, columnar, blind ends, and films. Figure 7 Figure a in the middle Figure 7 (Figure b); After the system was flooded, a large amount of residual oil remained unused. Figure 7 (Figure C in the middle) Figure 7 Figures d and f show the composite system flooding: after saturation oil ( Figure 7 (middle DTU), front-mounted water drive ( Figure 7 (Figure e), system driven by ( Figure 7 (Figure f) Most of the crude oil was extracted, leaving only a small amount of dripping and film-like residual oil, and the utilization efficiency of residual oil in small pore throats was significantly improved.

[0057] Further microscopic experiments were conducted on the alternating gas drive system of the CO2-composite system, divided into three stages: pre-gas drive, system drive, and post-gas drive. The results are as follows: Figure 8 As shown. Front-mounted air drive ( Figure 8 (Figure a) The remaining oil exists in columnar, film-like, and clustered forms, with the gas phase flowing along the dominant channels. After injection into the compound system ( Figure 8(Figure b) The displacement front exhibits a gas-water mixed displacement phenomenon, with the remaining oil emulsified into small oil droplets, expanding the affected area. After post-gas drive ( Figure 8 (See Figure C in the middle) The lateral impact expanded further, and the remaining oil on both sides was effectively utilized.

[0058] Example 7: Core Nuclear Magnetic Resonance Experiment Low-permeability cores (permeability approximately 2.0 mD) were taken, vacuum dried, and then saturated with deuterium water and simulated residual oil. The following procedures were performed at 85℃ and 10 MPa back pressure: (1) pre-flushing with CO2 until no oil was produced; (2) injection of a 0.5 PV composite solution (0.35 wt% SDBS for core 1, and 0.35 wt% SDBS + 0.05 wt% OSPS for core 2), followed by post-flushing with CO2 until no oil was produced. After each displacement, nuclear magnetic resonance T2 spectroscopy was performed to calculate the peak area changes in each pore region (small pore S, medium pore M, and large pore L). The results are shown in Table 2.

[0059] Table 2. Changes in peak area and permeability at different stages of core NMR.

[0060] Table 2 shows that for core 1 (SDBS only): after pre-gas drive, the peak area of ​​macropores decreased by 97%, micropores by 26.5%, and mesopores by 40.1%; after SDBS drive, micropores decreased by another 18.2%, and mesopores by another 6.1%; the final permeability recovery rate was 73.74%. For core 2 (composite system): after pre-gas drive, the peak area of ​​macropores decreased by 98.4%, micropores by 30.8%, and mesopores by 29.2%; after system drive + post-gas drive, micropores decreased by another 24.3%, and mesopores by another 35.15%; the final permeability recovery rate was 87.65%. This indicates that the composite system has a better ability to mobilize residual oil in small and medium pores.

[0061] Comparative Example 1: Oil displacement effect of SDBS alone Using the same core samples and experimental conditions as in Example 8, only the composite system was replaced with a 0.35 wt% SDBS solution. The pre-CO2 flooding recovery rate was 51.2%, and the final recovery rate after SDBS flooding was 63.5%, an increase in recovery rate of 12.3%, lower than the 16.37% in Example 8.

[0062] Comparative Example 2: Injection Testing Using OSPS Alone An attempt was made to directly disperse the OSPS prepared in Example 1 in deionized water at a concentration of 0.05 wt%. It was found that the OSPS floated on the water surface and was difficult to disperse evenly. After stirring and standing, it separated into layers and could not form a stable solution, indicating that OSPS alone has poor water solubility and is difficult to inject into the mine.

[0063] Comparative Example 3: OSPS Performance Comparison with Different Monomer Ratios Following the method of Example 1, the monomer ratios were varied: the molar ratios of octadecyl methacrylate:styrene:maleic anhydride were 1:0.5:0.5 (Comparative Example 3A), 1:2:1 (Comparative Example 3B), and 1:1.6:0 (Comparative Example 3C, without maleic anhydride). A compound system (OSPS 0.05wt% + SDBS 0.35wt%) was prepared according to Example 2, and the viscosity reduction rate was tested (mixed for 15 min). Results: The viscosity reduction rate of Comparative Example 3A was 68.5%, that of Comparative Example 3B was 72.1%, and that of Comparative Example 3C was 45.6%. All were lower than the 83.2% of Example 2. This indicates that the introduction of styrene and maleic anhydride is crucial for improving the viscosity reduction effect.

[0064] Comparative Example 4: Performance Comparison of Different OSPS to Emulsifier Mass Ratios With OSPS fixed at 0.05 wt%, SDBS was used at concentrations of 0.05 wt%, 0.2 wt%, 0.35 wt%, 0.5 wt%, and 0.7 wt%, corresponding to mass ratios of 1:1, 1:4, 1:7, 1:10, and 1:14. The viscosity reduction rate (mixing for 15 min) and interfacial tension (stable value) were tested. Results: At 1:1, the viscosity reduction rate was 45.2%, and the interfacial tension was 0.015 mN / m; at 1:4, the viscosity reduction rate was 68.3%, and the interfacial tension was 0.008 mN / m; at 1:7, the viscosity reduction rate was 83.2%, and the interfacial tension was 0.003 mN / m; at 1:10, the viscosity reduction rate was 82.5%, and the interfacial tension was 0.004 mN / m; and at 1:14, the viscosity reduction rate was 79.1%, and the interfacial tension was 0.007 mN / m. Considering the viscosity reduction effect, interfacial tension, and economy, a mass ratio of 1:7 was selected as the optimal ratio.

[0065] Example 9: Field Application Method (1) In reservoirs where CO2 flooding has been completed (formation temperature 85℃, formation pressure 10MPa), water is injected through wells at a rate of 0.5-1.0 m. 3 Inject 0.3-0.5 PV of the composite system (0.35 wt% SDBS + 0.05 wt% OSPS) at an injection rate of / min. (2) The well is shut in for 2-5 days to allow the composite system to fully interact with the remaining oil; (3) Then at 1.0-2.0 m 3 CO2 gas is injected at a rate of 0.5-1.0 PV per minute to form a mixed-gas liquid drive (see [reference]). Figure 8 (The micro-displacement process shown). (4) Continue with conventional water drive or CO2 injection until the economic limit is reached.

[0066] Effect verification: Simulation results using this method show that, compared with simple CO2 flooding followed by water flooding, the final recovery rate can be increased by more than 15%, and the injection pressure is stable, with no blockage or injection difficulties.

[0067] In summary, this invention addresses the technical challenges of high heavy component content, high viscosity, and difficult start-up in CO2 flooded residual oil by providing a composite system for efficient restarting of CO2 flooded residual oil and its application. This invention has the following core technical features: Targeted molecular design: Based on the increased aromatic hydrocarbon and gum content and enhanced polarity of residual oil after CO2 flooding, an oil-soluble surfactant (OSPS) containing an aromatic ring (styrene), a long-chain alkyl group (octadecyl methacrylate), and a polar group (maleic anhydride) was designed and synthesized. This structure can rapidly insert into the layered stacking structure of heavy components in the residual oil through π-π conjugation and hydrogen bonding, disintegrating aggregates and reducing the cohesiveness of the crude oil.

[0068] Synergistic compound system: OSPS and anionic surfactant SDBS are compounded at an optimal mass ratio of 1:7, effectively solving the problems of poor water solubility and difficult injection when OSPS is used alone. This compound system has the combined properties of rapid viscosity reduction (viscosity reduction rate of up to 83.2%), ultra-low interfacial tension (0.003 mN / m) and good salt resistance.

[0069] Synergistic effect of gas-liquid flooding: The composite system of this invention forms a gas-liquid flooding system with the subsequently injected CO2. The gas phase preferentially enters the large channels, generating the Jamin effect, which forces the liquid phase to redirect to the medium and small channels. At the same time, OSPS reduces the flow resistance in the oil-bearing channels, significantly expanding the affected area. Microscopic displacement experiments visually demonstrate this process. Figure 7 , Figure 8 ).

[0070] Significantly improved oil recovery: Core displacement experiments show that after applying the composite system of the present invention and performing post-CO2 flooding, the final recovery rate of low-permeability cores can reach 70.83%, which is more than 16.37% higher than that of pre-CO2 flooding; Core nuclear magnetic resonance experiments (Table 2) confirm that the system can effectively utilize the remaining oil in small and medium pores, and the permeability recovery rate increases from 73.74% to 87.65%.

[0071] In summary, the composite system and its application method provided by this invention offer a practical and effective technical solution for restarting residual oil in CO2-enhanced reservoirs and further improving recovery rates, with promising industrial application prospects and economic benefits.

Claims

1. An oil-soluble surfactant comprising aromatic ring structural units, alkyl long-chain structural units, and polar group structural units, and prepared by free radical polymerization; The aromatic ring structural unit is a styrene monomer; The alkyl long-chain structural unit is an alkyl ester monomer of (meth)acrylate; The polar group unit is an olefinic unsaturated carboxylic acid or its anhydride monomer.

2. The oil-soluble polymeric surfactant according to claim 1, characterized in that: The styrene monomer is styrene and / or methylstyrene; The alkyl methacrylate monomer is octadecyl methacrylate; The olefinic unsaturated carboxylic acid or its anhydride monomer is maleic anhydride.

3. A method for preparing the oil-soluble surfactant according to claim 1 or 2, comprising the following steps: Styrene monomers, (meth)acrylate alkyl ester monomers, and olefinic unsaturated carboxylic acids or their anhydrides are mixed in an organic solvent, heated to 50-70°C and stirred under inert gas protection; After the monomer dissolves, add the initiator dropwise and continue the reaction for 5-6 hours. After the reaction is complete, the reaction solution is poured into an alcohol solvent to precipitate a solid. After washing and drying, the oil-soluble polystyrene is obtained.

4. The method of claim 3, wherein: The initiator is azobisisobutyronitrile; the organic solvent is toluene; and the alcohol solvent is ethanol.

5. A composite system for restarting residual oil after carbon dioxide flooding, comprising: The oil-soluble surfactant according to claim 1 or 2; And emulsifiers; In the composite system, the mass concentration of the oil-soluble surfactant is 0.01%-0.1%; and the mass concentration of the emulsifier is 0.1%-0.5%.

6. The composite system of claim 5, wherein: The emulsifier is selected from anionic surfactants, nonionic surfactants, or combinations thereof; preferably, the emulsifier is anionic surfactant, more preferably sodium dodecylbenzenesulfonate.

7. A method for improving oil recovery in reservoirs after carbon dioxide flooding, comprising the following steps: The composite system described in claim 5 or 6 is injected into the reservoir formation that has undergone carbon dioxide flooding; then, carbon dioxide is injected into the formation to form a mixed gas-liquid flooding.

8. The method of claim 7, wherein: The composite system emulsifies the remaining oil into small droplets by reducing the viscosity of the heavy components in the remaining oil after carbon dioxide flooding and / or reducing the oil-water interfacial tension.

9. The application of the oil-soluble surfactant of claim 1 or 2 and the composite system of claim 5 or 6 in the preparation of an oil displacement agent for enhancing oil recovery in carbon dioxide flooded reservoirs.

10. Use according to claim 9, characterized in that: The oil displacement agent is used to reduce the viscosity of heavy components in the remaining oil after carbon dioxide flooding, reduce the oil-water interfacial tension, and / or expand the displacement sweep range.

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