Method for improving shale oil recovery ratio based on cooperation of nano-particles and CO2

Abstract

The invention provides a method for improving shale oil recovery ratio based on nanoparticle synergetic CO2, which comprises the following steps: injecting a surface modified nanoparticle dispersion liquid into a shale reservoir, alternately injecting supercritical CO2 and a nanoparticle reinforcement phase, calculating a nanoparticle-CO2-crude oil three-phase synergetic factor in real time based on reservoir parameters, and calculating the recovery ratio of the shale oil based on the nanoparticle synergetic CO2-crude oil three-phase synergetic factor. Injection parameters are dynamically adjusted according to the three-phase synergistic factors, and the nano-particles are excited to directionally migrate through pulse pressure waves; according to the method, surface-modified nano-particle dispersion liquid and supercritical CO2 are cooperatively injected into the shale reservoir, and pulse pressure waves are matched to excite nano-particles to directionally migrate, so that the mixed-phase efficiency of CO2 and crude oil is improved, the flowability of the crude oil in nano-scale pore channels is improved, the reservoir transformation effect is enhanced, reservoir damage is reduced, and the reservoir recovery rate is increased. Therefore, the recovery rate of shale oil is effectively improved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil extraction, and in particular to a method for improving shale oil recovery based on nanoparticles and CO2. Background Art

[0002] Against the backdrop of continued growth in global energy demand, shale oil, as an important unconventional oil and gas resource, is attracting increasing attention for its development and utilization. In recent years, shale oil extraction technology has continued to develop. For example, horizontal well technology has enabled long-distance drilling in shale formations, effectively increasing the contact area with the reservoir. Volume fracturing technology can form complex fracture networks in shale reservoirs, improving the permeability of the reservoir and allowing shale oil to flow more smoothly to the wellbore. Carbon dioxide (CO2) flooding technology has also made significant progress. By injecting CO2 into the reservoir, it uses its properties of reducing crude oil viscosity, expanding crude oil volume, and miscible with crude oil to improve crude oil fluidity and recovery rate. At the same time, nanotechnology has gradually penetrated into the field of oil extraction, providing new ways to improve reservoir properties and increase recovery rate.

[0003] However, existing technologies still have many problems in shale oil extraction. First, shale reservoirs have a unique microstructure, with pore and throat sizes mostly at the nanometer level, narrow pores and poor connectivity, resulting in extremely low fluidity of crude oil in the reservoir, and conventional extraction methods are difficult to effectively drive crude oil to the wellbore. Second, during CO2 flooding, the miscibility of CO2 and crude oil is low, and CO2 is prone to cross-flow, which cannot evenly displace crude oil, resulting in a large amount of crude oil remaining in the reservoir, limiting the increase in recovery rate. Third, the fracture network formed solely by fracturing is prone to closing as the extraction time increases, affecting the fluid seepage capacity. In addition, traditional extraction methods often cause great damage to the reservoir. For example, the fluid used in the drilling and completion process may block the reservoir pores, further reducing the reservoir permeability.

[0004] Therefore, there is an urgent need in this field for a method to enhance shale oil recovery based on nanoparticles and CO2 to solve the above problems. Summary of the Invention

[0005] The present invention aims to provide a method for enhancing shale oil recovery based on nanoparticles in synergistic relationship with CO2. By synergistically injecting a surface-modified nanoparticle dispersion into a shale reservoir with supercritical CO2, and combining it with pulsed pressure waves to stimulate the directional migration of nanoparticles, the method aims to improve the miscibility of CO2 and crude oil, improve the fluidity of crude oil in nanoscale pores, enhance the reservoir transformation effect, and reduce reservoir damage, thereby effectively improving the recovery rate of shale oil and providing a new solution for the efficient development of shale oil.

[0006] The present invention provides a method for enhancing shale oil recovery based on nanoparticles and CO2, comprising the following steps:

[0007] Step 1: injecting the surface-modified nanoparticle dispersion into the shale reservoir;

[0008] Step 2: alternately injecting supercritical CO2 and nanoparticle reinforcement phase;

[0009] Step 3: Real-time calculation of the nanoparticle-CO2-crude oil three-phase synergy factor based on reservoir parameters;

[0010] Step 4: Dynamically adjust the injection parameters according to the three-phase synergy factor;

[0011] Step five: stimulate the directional migration of nanoparticles through pulse pressure waves.

[0012] Compared with the prior art, the present invention has the following advantages:

[0013] 1. This application constructs a computational model for the nanoparticle-CO2-crude oil three-phase synergy factor, comprehensively considering reservoir dynamic parameters such as interfacial tension, crude oil viscosity, and relative permeability, to achieve real-time optimization of injection parameters (nanoparticle concentration, CO2 injection rate, etc.). For example, if a drop in permeability is detected at a certain point in the reservoir, the system automatically reduces the nanoparticle injection concentration to prevent blockage while simultaneously increasing the CO2 injection pressure to enhance oil displacement.

[0014] 2. This application achieves directional migration and efficient blocking of nanoparticles in pores by setting pulse pressure waves with specific parameters and utilizing the resonance effect of pressure waves and nanoparticles.

[0015] 3. This application reduces the amount of a single material while improving the synergistic effect through a multi-technical association scheme of surface-modified nanoparticle dispersion, alternating supercritical CO2 injection, and pulse pressure wave regulation.

[0016] Other features and advantages of the present invention will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the written description and the accompanying drawings.

[0017] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0018] The accompanying drawings are used to provide further understanding of the present invention and constitute a part of the specification. They are used to explain the present invention together with the embodiments of the present invention and do not constitute a limitation of the present invention.

[0019] In the attached figure:

[0020] Figure 1 This is a flow chart of a method for improving shale oil recovery based on nanoparticles and CO2 provided by the present invention. DETAILED DESCRIPTION

[0021] The preferred embodiments of the present invention are described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are only used to illustrate and explain the present invention, and are not used to limit the present invention.

[0022] Example 1:

[0023] Please refer to Figure 1 The embodiment of the present invention provides a method for enhancing shale oil recovery based on nanoparticles and CO2, comprising the following steps:

[0024] Step 1: injecting the surface-modified nanoparticle dispersion into the shale reservoir;

[0025] Step 2: alternately injecting supercritical CO2 and nanoparticle reinforcement phase;

[0026] Step 3: Real-time calculation of the nanoparticle-CO2-crude oil three-phase synergy factor based on reservoir parameters;

[0027] Step 4: Dynamically adjust the injection parameters according to the three-phase synergy factor;

[0028] Step five: stimulate the directional migration of nanoparticles through pulse pressure waves.

[0029] In step 3, the three-phase synergy factor Λ is calculated by a synergy calculation model, and the synergy calculation model is:

[0030]

[0031] Here, α is a comprehensive correction factor, determined through dimensional analysis combined with reservoir parameter sensitivity testing. In the laboratory, flooding simulations were conducted on shale core samples from different geological conditions, varying various parameters such as porosity, permeability, and crude oil properties. The calculated values ​​of the synergy factor and the actual recovery enhancement effects were recorded. Through data fitting and analysis, appropriate values ​​of α were obtained for different situations. α is used to correct for the effects of factors such as the complexity of actual reservoir conditions, measurement errors, and incompletely considered physical and chemical interactions on the calculated synergy factor, ensuring that the calculated value of the synergy factor Λ more closely matches the synergistic effect experienced during actual flooding.

[0032] is the reduction in crude oil-rock interfacial tension after the action of nanoparticles, which is determined by the hanging drop method. In a laboratory environment, thin shale core slices and crude oil samples are prepared. The interfacial tension between the crude oil and the core surface is measured without the addition of nanoparticles. Then, the nanoparticle dispersion is mixed with the crude oil and the interfacial tension is measured again. The difference between the two measured values ​​is Used to reflect the degree to which nanoparticles improve the properties of the crude oil-rock interface. Reduced interfacial tension helps crude oil peel from the rock surface, improving its fluidity and recoverability. A larger value indicates a more significant effect of the nanoparticles in improving interfacial properties and a greater contribution to synergistic oil recovery.

[0033] β1 is the weight index of interfacial tension reduction on synergistic effect, and in is the reservoir porosity, measured by a helium porosimeter; k is the absolute permeability, determined by the steady-state method; β1 is calculated by substituting the measured porosity and permeability values ​​into the formula; β1 is used to reflect the influence of the reservoir pore structure characteristics on the synergistic effect of interfacial tension reduction; reservoirs with different porosity and permeability have different contributions to the synergistic effect of oil recovery, and β1 is adjusted by correlating it with porosity and permeability. The weight in the calculation of synergy factors makes the calculation more consistent with the actual conditions of different reservoirs;

[0034] Δμ o Δμ is the viscosity reduction of crude oil after the synergistic effect of CO2 and nanoparticles, measured using a rotational viscometer; under simulated reservoir temperature and pressure conditions, the viscosity of crude oil before CO2 and nanoparticle injection and the viscosity of crude oil in the mixed system after injection are measured respectively. The difference between the two is Δμ o ;Δμ o Used to characterize the synergistic effect of CO2 and nanoparticles on improving the fluidity of crude oil; reducing the viscosity of crude oil can reduce the flow resistance of crude oil in the pores, improve the seepage capacity of crude oil, and thus increase the recovery rate, Δμ o The larger it is, the better the synergistic viscosity reduction effect is and the greater the contribution to the synergistic factor is;

[0035] β2 is the weight index of the synergistic effect of crude oil viscosity reduction, and Among them, M w is the average molecular weight of crude oil, which is calculated by measuring the molecular weight of each component of crude oil through mass spectrometry analysis; M w，c is the critical molecular weight, a characteristic value determined by conducting oil displacement experiments on a large number of crude oil samples and analyzing the relationship between viscosity reduction and recovery rate improvement; according to the measured M w and the known M w，cCalculate β2; β2 is used to adjust the weight of the impact of reduced crude oil viscosity on the synergistic effect based on the molecular structure of the crude oil itself. Crude oils with different molecular weights have different degrees of effect of reduced viscosity on the synergistic effect of oil recovery. β2 takes the crude oil molecular weight into account, allowing the synergistic factor calculation to more accurately reflect the impact of crude oil properties on synergistic oil recovery.

[0036] ΔK r ΔK is the increase in oil phase relative permeability after mixed injection, obtained from core flooding experiments. Select representative shale cores, first measure the oil phase relative permeability in the initial state, then inject the nanoparticle and CO2 mixed system, and measure the oil phase relative permeability again after the flooding stabilizes. The difference between the two measured values ​​is ΔK. r ; Used to measure the degree of improvement in reservoir seepage characteristics after the injection of nanoparticles and CO2 mixture; the increase in relative permeability means that the flow ability of crude oil in the reservoir is enhanced and it can be displaced more effectively, ΔK r The larger it is, the more obvious the effect of the mixed injection system on enhancing oil recovery is;

[0037] β3 is the weight index of relative permeability change on synergy effect, and Where p is the current reservoir pressure, which is measured in real time by the downhole pressure sensor; p b is the crude oil bubble point pressure, which is determined by the crude oil high-pressure physical property experiment; p c is the pressure adjustment coefficient, which is determined by analyzing the oil displacement experimental data under different reservoir pressure conditions; β3 is calculated based on the pressure values ​​measured in real time and experimentally; it is used to reflect the influence of the reservoir pressure state on the relative permeability change acting on the synergistic effect; under different reservoir pressures, the relative permeability change contributes differently to the oil displacement synergistic effect, and β3 is related to the reservoir pressure to adjust ΔK r The weight in the calculation of the synergy factor makes the calculation results more consistent with the influence of pressure factors in the actual oil recovery process;

[0038] τ is the reservoir tortuosity, obtained through CT scanning and digital core analysis. High-resolution CT scanning of shale cores obtains a three-dimensional image of the core's internal pore structure. Digital image processing technology is used to construct a digital core model. The relationship between the fluid flow path and the straight-line distance in the model is calculated to obtain the tortuosity τ. This describes the complexity of the fluid flow path in the reservoir pores. The greater the tortuosity, the greater the fluid flow resistance, the more difficult the migration and diffusion of nanoparticles and CO2 in the reservoir, which has a negative impact on the synergistic oil recovery effect and is calculated as an obstacle in the synergy factor formula.

[0039] L is the characteristic distance from the injection well to the production well, determined based on the reservoir development well pattern layout and obtained through geological mapping and well location design data. It is used to reflect the migration distance of the fluid from the injection well to the production well. The longer the distance, the greater the energy loss during the fluid flow in the reservoir. The synergistic effect of nanoparticles and CO2 may be attenuated with distance. In the formula, this factor, together with factors such as tortuosity, affects the fluid migration efficiency, thereby affecting the size of the synergy factor.

[0040] D eff is the effective diffusion coefficient of nanoparticles in porous media, and Among them D n is the diffusion coefficient of nanoparticles in pure fluid, determined by dynamic light scattering experiments; k is the absolute permeability, is the reservoir porosity and τ is the reservoir tortuosity, both of which are obtained through the corresponding measurement methods mentioned above; they are used to reflect the diffusion ability of nanoparticles in the porous medium of the reservoir; the larger the effective diffusion coefficient, the easier it is for the nanoparticles to diffuse and distribute in the reservoir, and the more fully they interact with crude oil and rock, thereby enhancing the synergistic oil recovery effect. In the formula, it is used as a factor to promote the effect of nanoparticles.

[0041] σ p is the stress amplitude of the pulse pressure wave, which is set by the pressure wave generator and determined through parameter adjustment of the device and real-time monitoring by the measurement system. It determines the magnitude of the force exerted by the pulse pressure wave on the nanoparticles and the fluid. The larger the stress amplitude, the stronger the ability of the pulse pressure wave to stimulate the directional migration of nanoparticles, which helps the nanoparticles reach crude oil-rich areas more effectively and enhances the synergistic oil recovery effect. In the formula, it jointly influences the migration and synergistic effect of nanoparticles with factors such as the pulse pressure wave frequency.

[0042] f p The pulse pressure wave frequency is optimized and determined based on the reservoir response characteristics. The optimal pulse pressure wave frequency is determined by conducting oil displacement experiments in the laboratory or on-site under the action of pulse pressure waves of different frequencies, analyzing the migration effect of nanoparticles and changes in recovery rate. This is used to influence the directional migration effect of nanoparticles and the degree of fluid disturbance. The appropriate pulse pressure wave frequency can enable more effective directional migration of nanoparticles in the reservoir, while also properly disturbing the fluid, promoting the flow and displacement of crude oil. Together with the stress amplitude, the contribution of the pulse pressure wave to the synergy factor is quantified in the formula.

[0043] S orResidual oil saturation is measured through core experiments. After flooding, the cores are processed in the laboratory, and the remaining crude oil content in the cores is measured using methods such as centrifugation and extraction. The residual oil saturation is calculated. It reflects the proportion of crude oil in the reservoir that is difficult to displace by conventional methods. The lower the residual oil saturation, the better the flooding effect. In the formula, it serves as part of the denominator and is associated with the pulse pressure wave parameter, reflecting the impact of the pulse pressure wave's effect on reducing residual oil saturation and improving oil recovery on the synergy factor.

[0044] In one embodiment, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the nanoparticle injection concentration through the first adjustment model. The first adjustment model is:

[0045]

[0046] in, The current nanoparticle injection concentration is obtained in real time through the flow control system and concentration monitor of the injection equipment;

[0047] Λ ref It is a preset reference synergy factor, determined through numerical simulation and laboratory flooding experiments based on the target reservoir geological conditions (porosity, permeability, etc.) and crude oil properties;

[0048] γ1 is the sensitivity adjustment parameter and is dynamically related to the injection pressure, that is, ΔP is the difference between the current injection pressure and the initial pressure, which is obtained by real-time monitoring of the pressure sensor. s is the pressure sensitivity threshold, which is determined through fracturing experiments to ensure the stability of concentration adjustment during pressure fluctuations.

[0049] Specifically, the first adjustment model is based on the current nanoparticle injection concentration Based on the actual value of the synergy factor Λ and the reference value Λ ref The deviation of Λ>Λ is used to dynamically adjust the injection concentration. ref When Λ<Λ ref When the concentration is too high, the concentration is reduced to avoid particle accumulation and blockage. This embodiment breaks through the traditional fixed concentration injection mode and realizes adaptive adjustment of concentration according to synergistic effect, avoiding the problem of increased seepage resistance due to excessively high concentration or insufficient synergy due to too low concentration.

[0050] In one embodiment, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the CO2 injection rate through the second adjustment model. The second adjustment model is:

[0051]

[0052] in, is the current CO2 injection rate, recorded in real time by the flow meter;

[0053] S w The current water saturation is monitored in real time through resistivity logging technology;

[0054] S w，max is the maximum water saturation, determined by core experiments;

[0055] γ2 is the rate adjustment index, which is calculated by the reservoir seepage characteristic parameters, that is, is porosity, k is permeability, obtained through well logging data, μ m is the viscosity of the mixed fluid, measured by an online viscometer;

[0056] Specifically, the CO2 injection rate is adjusted by combining the dual constraints of the synergy factor ratio and the water saturation state; Reflecting the rate regulation driven by synergistic effects, Avoid ineffective injection in the high water content stage; this embodiment establishes a multi-dimensional control model of synergistic effect-permeability-water content state, which can reduce the ineffective gas injection volume compared with a single empirical formula.

[0057] In one embodiment, in step 4, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the pulse pressure wave stress amplitude through the third adjustment model. The third adjustment model is:

[0058]

[0059] in, is the current pulse pressure wave stress amplitude, which is the real-time output of the pressure wave generating device;

[0060] γ3 is the stress adjustment coefficient and is related to the rock elastic modulus, that is, E f is the elastic modulus of reservoir rock, obtained in real time through ultrasonic logging, E f，c is the critical elastic modulus, determined by rock fracture experiments.

[0061] Specifically, the third adjustment model is similar to the concentration adjustment structure, but incorporates rock mechanical property constraints through γ3. When the synergistic effect is insufficient, the stress amplitude is increased according to a nonlinear law to enhance nanoparticle migration, but is constrained by the rock elastic modulus to avoid reservoir damage. This embodiment achieves intelligent control of pressure wave intensity, improving nanoparticle migration efficiency while reducing the risk of reservoir rupture.

[0062] In one embodiment, in step 4, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the pulse pressure wave frequency through the fourth adjustment model The fourth adjustment model is:

[0063]

[0064] in, is the current pulse pressure wave frequency, that is, the current operating frequency of the pressure wave generator;

[0065] ΔT is the reservoir temperature change value, which is obtained by real-time monitoring of the distributed optical fiber temperature measurement system;

[0066] T r is the reference temperature change value, determined through thermal simulation experiments;

[0067] γ4 is the frequency adjustment coefficient and is determined by the thermal-fluid coupling parameter, that is, ρ m is the density of the mixed fluid, c p,m is the specific heat capacity of the mixed fluid, determined by PVT experiment, k h is the reservoir thermal conductivity, obtained from heat conduction experiments;

[0068] Specifically, this embodiment is used to construct a synergistic effect-temperature response dual-factor regulation model. Adjust the frequency based on the synergistic effect, Compensating for the effects of temperature changes on the Brownian motion of nanoparticles and fluid viscosity. This embodiment solves the problem that traditional fixed-frequency operations cannot adapt to reservoir temperature fluctuations and improves the efficiency of nanoparticle directional migration.

[0069] In one embodiment, in the surface-modified nanoparticle dispersion of step 1, the nanoparticles are one or more of silica nanoparticles, alumina nanoparticles or carbon nanotubes, and the surface modification is performed using one or more of a silane coupling agent and a titanate coupling agent.

[0070] It should be noted that silica nanoparticles have excellent chemical stability and biocompatibility, and their surfaces are rich in silanol groups, making them easy to chemically modify. In shale oil extraction, silica nanoparticles can effectively reduce the interfacial tension between crude oil and rock, changing the rock's wettability from oleophilic to hydrophilic, thereby facilitating the detachment of crude oil from the rock surface and improving its fluidity and recoverability.

[0071] Alumina nanoparticles have high hardness, excellent mechanical properties, and multiple active sites on their surface. In shale reservoirs, alumina nanoparticles can fill tiny pores and cracks, improving the reservoir's seepage channels. At the same time, their surface active sites can interact with certain components in crude oil, promoting viscosity reduction and dispersion, thereby increasing crude oil recovery.

[0072] Carbon nanotubes (CNTs) possess a unique one-dimensional nanostructure, excellent mechanical properties, and good electrical conductivity. During synergistic oil recovery, CNTs form a conductive network within the pores, affecting the charge distribution of crude oil molecules and reducing oil viscosity. Their large surface area also helps adsorb crude oil molecules and reduce interfacial tension. Furthermore, under the action of pulsed pressure waves, the high aspect ratio of CNTs facilitates directional migration, leading to more efficient oil recovery.

[0073] Combining one or more of the above nanoparticles can leverage the advantages of each. For example, silica nanoparticles improve wettability, carbon nanotubes enhance conductivity and directional migration, and alumina nanoparticles optimize seepage channels, achieving a synergistic effect on shale oil recovery.

[0074] The molecular structure of silane coupling agents contains two groups of different properties. One end can chemically react with the hydroxyl groups on the surface of nanoparticles to form a stable chemical bond, thereby modifying the nanoparticle surface. The other end has a lipophilic or other functional group that can interact with crude oil molecules or rock surfaces. After modification with silane coupling agents, the dispersion of nanoparticles in crude oil is significantly improved, reducing agglomeration and enabling them to be more evenly distributed in the reservoir pores, fully exerting their effects of reducing interfacial tension and improving wettability.

[0075] Titanate coupling agents also have a unique molecular structure that allows them to chemically bond with the surface of nanoparticles. They can enhance the affinity between nanoparticles and crude oil and rock, altering the charge and surface energy of the nanoparticles, making them more easily adsorbed on the rock surface, forming a stable adsorption layer. This effectively alters rock wettability and facilitates the migration and dispersion of nanoparticles within pores, improving synergistic oil recovery efficiency.

[0076] The primary purpose of surface modification is to alter the surface properties of nanoparticles, enabling them to better adapt to shale oil reservoir environments and enhance their interaction with crude oil and rock. The modified nanoparticles not only maintain excellent dispersion stability in the dispersion, preventing agglomeration and precipitation, but also, after injection into the reservoir, through physical and chemical interactions with crude oil and rock, achieve multiple benefits, including reducing interfacial tension, improving rock wettability, and promoting crude oil viscosity reduction, thereby increasing shale oil recovery.

[0077] In one embodiment, during the alternate injection of supercritical CO2 and nanoparticles into the enhanced phase in step 2, the injection pressure of supercritical CO2 is 10-30 MPa and the injection rate is 5-20 m / s. 3 / d; the injection pressure of the nanoparticle reinforcement phase is 8-28MPa, and the injection rate is 3-15m 3 / d.

[0078] It should be noted that the critical pressure of CO2 injection is 7.38MPa. When the pressure is ≥10MPa, it can ensure that it maintains a supercritical state in the reservoir. Supercritical CO2 has both the low viscosity of gas and the high diffusivity of liquid. It can efficiently penetrate the micropores of shale, dissolve the light components in crude oil, reduce the viscosity of crude oil, and expand the volume of crude oil to improve its fluidity. Shale reservoirs have extremely low permeability. When the pressure is ≥15MPa, it can induce the expansion of microcracks and form CO2-fracture network seepage channels; however, pressure exceeding 30MPa may cause over-fracture of the reservoir, triggering fluid channeling and reducing oil recovery efficiency.

[0079] For CO2 injection rate, the rate is too low (<5m 3 / d), CO2 migrates slowly in the reservoir, and the mass transfer process with crude oil (such as dissolution and miscibility) is insufficient, making it difficult to form a continuous displacement front; when the rate is too high (>20m 3 / d) will lead to CO2 fingering (i.e., rapid fluid breakthrough along high-permeability channels), increasing the amount of residual oil flowing around. Furthermore, as the rate increases, compressor energy consumption increases exponentially, while the recovery rate increases more slowly.

[0080] The injection pressure of the nanoparticle reinforcement phase is slightly lower than that of CO2, creating a "pressure differential drive" mechanism. This means that CO2 enters micropores first under high pressure, and the nanoparticles, along with the subsequently injected reinforcement phase, migrate toward the CO2 front under the pressure differential, filling the remaining oil zone after CO2 displacement. When the pressure is too low (<8 MPa), the nanoparticle dispersion has high flow resistance in low-permeability reservoirs, prone to agglomeration and pore throat clogging. When the pressure is too high (>28 MPa), the surface modification layer of the nanoparticles may be damaged, causing them to lose their ability to reduce interfacial tension.

[0081] For the injection rate of the nanoparticle reinforcement phase, the directional migration of nanoparticles is stimulated by pulse pressure waves (frequency 0.5-2 Hz), and the rate setting needs to be coupled with the pulse frequency: rate 3-5m 3 / d, the pulse wave can form periodic pressure oscillations, causing the nanoparticles to produce vibration-slip motion in the pores, and the migration distance is increased by 2-3 times compared with static injection; the rate exceeds 15m 3When the pulse wave is injected at a rate of 100 / d, fluid inertia dominates, weakening the oscillation effect of the pulse wave and reducing the efficiency of the nanoparticles' directional migration. The periodic alternation of supercritical CO2 and nanoparticles creates a dissolution-blocking-redissolution cycle in the reservoir. This involves the CO2 first dissolving the crude oil, followed by the nanoparticles blocking the high-permeability channels, forcing subsequent CO2 into the low-permeability zones. This results in a higher recovery rate than a single injection alone.

[0082] In one embodiment, when the directional migration of nanoparticles is stimulated by pulse pressure waves in step five, the stress amplitude of the pulse pressure waves is 1-5 MPa, the frequency is 0.1-1 Hz, the pulse duration is 5-30 s, and the interval time is 30-120 min.

[0083] It should be noted that the design of these parameters uses stress amplitude to provide the driving force, frequency to match the nanoparticle vibration characteristics, duration to control migration distance, and interval time to ensure deposition efficiency, forming a controlled excitation-migration-deposition process. The pulsed pressure wave alters the reservoir stress state, inducing dynamic adsorption and desorption of the nanoparticle surface modifier from the rock surface, enhancing interfacial activity.

[0084] In one embodiment, before injecting the surface-modified nanoparticle dispersion into the shale reservoir, the shale reservoir is pretreated. The pretreatment includes flushing the reservoir with high-pressure water to remove impurities and blockages in the reservoir pores.

[0085] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, rather than to limit it. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein. However, these modifications or replacements do not deviate the essence of the corresponding technical solutions from the spirit and scope of the technical solutions of the various embodiments of the present invention.

Claims

1. A method for enhancing shale oil recovery based on nanoparticles and CO2, characterized in that: The following steps are involved: Step 1: injecting the surface-modified nanoparticle dispersion into the shale reservoir; Step 2: alternately injecting supercritical CO2 and nanoparticle reinforcement phase; Step 3: Real-time calculation of the nanoparticle-CO2-crude oil three-phase synergy factor based on reservoir parameters; Step 4: Dynamically adjust the injection parameters according to the three-phase synergy factor; Step five: stimulate the directional migration of nanoparticles through pulse pressure waves.

2. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In step 3, the three-phase synergy factor Λ is calculated by a synergy calculation model, and the synergy calculation model is: Among them, α is the comprehensive correction coefficient, is the reduction value of the crude oil-rock interfacial tension after the action of nanoparticles, β1 is the weight index of the interfacial tension reduction on the synergistic effect, Δμ o is the reduction value of crude oil viscosity after the synergistic effect of CO2 and nanoparticles, β2 is the weight index of crude oil viscosity reduction on the synergistic effect, ΔK r is the increase in relative permeability of the oil phase after mixed injection, β3 is the weight index of relative permeability change on synergistic effect, τ is the reservoir tortuosity, L is the characteristic distance from the injection well to the production well, D eff is the effective diffusion coefficient of nanoparticles in porous media, σ p is the stress amplitude of the pulse pressure wave, f p is the pulse pressure wave frequency, S or is the residual oil saturation.

3. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In step 4, the injection parameters are dynamically adjusted according to the three-phase synergistic factor, specifically including adjusting the nanoparticle injection concentration through the first adjustment model The first adjustment model is: in, is the current nanoparticle injection concentration, Λ ref is the preset reference synergy factor, γ1 is the sensitivity adjustment parameter, and ΔP is the difference between the current injection pressure and the initial pressure, P s is the pressure sensitivity threshold.

4. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In step 4, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the CO2 injection rate through the second adjustment model The second adjustment model is: in, is the current CO2 injection rate, S w is the current water saturation, S w，max is the maximum water saturation, γ2 is the rate adjustment index, and is porosity, k is permeability, μ m is the viscosity of the mixed fluid.

5. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In step 4, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the pulse pressure wave stress amplitude through the third adjustment model The third adjustment model is: in, is the current pulse pressure wave stress amplitude, γ3 is the stress adjustment coefficient, and E f is the elastic modulus of reservoir rock, E f，c is the critical elastic modulus.

6. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In step 4, the injection parameters are dynamically adjusted according to the three-phase synergy factor, specifically including adjusting the pulse pressure wave frequency through the fourth adjustment model The fourth adjustment model is: in, is the current pulse pressure wave frequency, ΔT is the reservoir temperature change value, T r is the reference temperature change value, γ4 is the frequency adjustment coefficient, and ρ m is the density of the mixed fluid, c p，m is the specific heat capacity of the mixed fluid, k h is the reservoir thermal conductivity.

7. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In the surface-modified nanoparticle dispersion of step 1, the nanoparticles are one or more of silicon dioxide nanoparticles, aluminum oxide nanoparticles or carbon nanotubes, and the surface modification is performed using one or more of a silane coupling agent and a titanate coupling agent.

8. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: In the process of alternately injecting supercritical CO2 and nanoparticles in step 2, the injection pressure of supercritical CO2 is 10-30 MPa and the injection rate is 5-20 m 3 / d; the injection pressure of the nanoparticle reinforcement phase is 8-28MPa, and the injection rate is 3-15m 3 / d.

9. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: When the directional migration of nanoparticles is stimulated by pulse pressure waves in step five, the stress amplitude of the pulse pressure waves is 1-5 MPa, the frequency is 0.1-1 Hz, the pulse duration is 5-30 s, and the interval time is 30-120 min.

10. The method for enhancing shale oil recovery based on nanoparticles and CO2 according to claim 1, characterized in that: Before injecting the surface-modified nanoparticle dispersion into the shale reservoir, the method also includes a step of pre-treating the shale reservoir. The pre-treatment includes flushing the reservoir with high-pressure clean water to remove impurities and blockages in the reservoir pores.

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