A method and system for simulating a pore-scale shale oil elastic development process

Abstract

This invention provides a simulation method and system for the elastic development process of shale oil at the pore scale. A two-dimensional model of the pore structure of a real shale core is extracted from scanning electron microscope images. Basic parameters and initial conditions are set using Comsol software. Fluid density, viscosity, and contact angle are calculated equivalently considering the stress sensitivity transformation of porosity and permeability. The pressure-suppression-production process is simulated sequentially. The fluid mobilization law and the contribution rate of seepage to oil production during the entire pressure-suppression-production process are analyzed. This method has significant advantages such as good repeatability, strong model representativeness, consideration of the influence of porosity and permeability changes, and high analytical accuracy, providing a reference for in-depth analysis of the mobilization law and seepage mechanism of shale oil elastic development.

Description

Technical Field

[0001] This invention relates to the field of unconventional oil and gas extraction technology, and in particular to a simulation method and system for the elastic development process of shale oil at the pore scale. Background Technology

[0002] Currently, shale oil is mainly developed using a volumetric fracturing followed by elastic development. Production practices in multiple shale oil and gas wells have shown that appropriate well shut-in can shorten the time to oil breakthrough, increase cumulative oil production, and reduce water cut and flowback rates. Preliminary analysis suggests that percolation in shale oil and gas reservoirs is one of the key mechanisms affecting production dynamics, and fully utilizing percolation is beneficial for improving single-well productivity. However, a thorough understanding of the impact of pore-scale percolation on shale oil utilization patterns and the dynamic laws governing shale oil fracturing-shut-production development is still lacking, along with intuitive characterization methods.

[0003] While field production dynamics, reservoir numerical simulations, and core experiments can explain macroscopic laws and phenomena, they struggle to reveal in-depth flow mechanisms. Studying the dynamic processes of elastic development at the pore scale is crucial for explaining core experiment phenomena, supporting the optimization of development technology policies, and improving shale oil production capacity. Commonly used methods for studying shale oil flow mechanisms at the pore scale include microfluidic experiments and microscopic flow simulations. Microfluidic experiments directly observe and record the pressure-stagnation-production dynamic processes within the pores using high-precision microscopy, providing intuitive and accurate results. Microscopic simulations offer high flexibility, are not limited by experimental conditions and equipment, and can fully investigate key parameters such as velocity, pressure, and saturation.

[0004] Shale oil reservoirs have complex pore structures and are highly stress-sensitive. Current microfluidic experiments and micro-flow simulation studies still have some shortcomings, specifically: (1) There is a lack of experimental and simulation methods for the entire process of elastic development of shale oil at the pore scale, including pressure-suppression-production. Most studies only focus on the seepage process in suppressed wells; (2) Microfluidic experiments are costly, and experimental equipment and conditions are limited, making data processing difficult; (3) Microfluidic experiments and simulation studies mainly use ideal pore structure conceptual models, which are difficult to represent the real complex pore structure of shale; (4) The analysis of stress sensitivity is insufficient, and the contribution of seepage to oil production is difficult to evaluate. Summary of the Invention

[0005] In view of the above problems, the present invention is proposed to provide a simulation method and system for the elastic development process of pore-scale shale oil to overcome or at least partially solve the above problems.

[0006] According to one aspect of the present invention, a simulation method for the elastic development process of shale oil at the pore scale is provided, the simulation method comprising:

[0007] Step S1: Perform scanning electron microscopy analysis on the shale sample to obtain a high-resolution pore structure image of the real core. Select representative locations from the pore structure image to extract and characterize the pore structure to obtain a natural pore structure map of the shale core.

[0008] Step S2: Import the natural pore structure diagram into Comsol software, and add main cracks and random secondary cracks to simulate artificial pressure cracks to complete the two-dimensional pore structure diagram of visualization simulation;

[0009] Step S3: Considering the macroscopic porosity stress sensitivity, calculate the equivalent fluid density based on the mass conservation principle to characterize the porosity stress sensitivity, and set the fluid equivalent density versus pressure curve;

[0010] Step S4: Considering the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity equivalently based on the principle of fluidity similarity to characterize the permeability stress sensitivity, and set the fluid equivalent viscosity as a function of pressure curve;

[0011] Step S5: Considering the stress sensitivity of macroscopic porosity, the contact angle is calculated based on the capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and the equivalent contact angle versus pressure curve is set.

[0012] Step S6: Set initial conditions and fluid properties, select the laminar flow-phase field model, and set the initial fluid distribution, initial pressure, fluid compressibility, wetting wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence;

[0013] Step S7: Simulate the fracturing process, close the outlet, inject fracturing fluid at high pressure at the inlet, and analyze the fluid distribution during the fracturing fluid injection process;

[0014] Step S8: Well shut-in process simulation. The well shut-in process is simulated by closing the inlet, and the seepage mechanism is analyzed by the change in fluid distribution.

[0015] Step S9: Simulate the oil production process, reduce the outlet pressure to simulate the elastic development process, and analyze the changes in fluid distribution, water cut of the produced fluid, and degree of recovery;

[0016] Step S10: Data processing, calculate fluid distribution, oil production rate, water cut and flowback rate parameters at different times based on pressure, density and surface integral;

[0017] Step S11: Compare the recovery rate under conditions where no seepage occurs, and calculate the contribution rate of seepage to oil production.

[0018] Optionally, in step S1, based on the high-resolution pore structure of the real shale core obtained by scanning electron microscopy, a two-dimensional natural pore structure model is established by extracting connected pores using CAD.

[0019] Optionally, in step S3, based on the evaluation results of the volume factor changes and porosity stress sensitivity of the oil and water phases, the density change is calculated according to the mass conservation equivalent to improve the shortcomings of conventional simulation that ignores porosity stress sensitivity.

[0020] Porosity stress-sensitive equivalent calculation:

[0021]

[0022] In the formula, ρ0 represents the true density of the oil / water phase under different pressures, in kg / m³. 3 ρ1—Equivalent density of oil / water phase under different pressures, kg / m³ 3 ;p i p t — Fluid pressure at initial time and time t, MPa; a, b — Coefficients obtained from the regression of the porosity stress-sensitive experimental curve of shale oil core, constant values.

[0023] Optionally, in step S4, based on the viscosity changes of the oil and water phases under different pressures and the evaluation results of permeability stress sensitivity, the viscosity change is calculated according to the similarity of flowability to improve the shortcomings of conventional simulation that ignores permeability stress sensitivity.

[0024] Permeability stress-sensitive equivalent calculation:

[0025]

[0026] In the formula, μ0 is the true viscosity of the oil / water phase under different pressures, in mPa·s; μ1 is the equivalent viscosity of the oil / water phase under different pressures, in mPa·s; p i p t — Fluid pressure at the initial moment and at any other moment, in MPa; c, d — Coefficients obtained from the regression of the stress-sensitive experimental curve of shale oil core permeability, constant values.

[0027] Optionally, step S5 involves calculating the contact angle based on the capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and setting a two-dimensional equivalent contact angle versus pressure curve.

[0028] Capillary force equivalent calculation:

[0029]

[0030] In the formula, θ0 is the actual contact angle under different pressures, °; θ1 is the equivalent contact angle under different pressures, °.

[0031] Optionally, step S6 takes into account the actual field development situation. In shale oil fracturing development, fracturing fluid injection, well shut-in, and oil production are all completed by a single well, and the model inlet and outlet are set to the same path.

[0032] Optionally, in step S6, the natural pore structure is completely filled with oil, and the artificially inflated crack is completely filled with water; the wetting walls of the pore structure are all hydrophilic, with a contact angle of less than 90°.

[0033] Optionally, in step S7, the inlet pressure is higher than the initial pressure to ensure fracturing fluid injection, and both constant pressure injection and variable pressure injection methods are selected.

[0034] Optionally, in step S9, the outlet pressure is lower than the initial pressure to ensure fluid extraction, while selecting constant pressure development and step-by-step pressure reduction development methods.

[0035] Optionally, step S10 calculates parameters such as fluid distribution, oil production rate, water cut, and flowback rate at different times based on pressure, fluid viscosity, and surface integral, and analyzes the oil production pattern and recovery degree.

[0036] Calculation of fracturing fluid injection volume:

[0037] V f =ρ w1i *V*S wi

[0038] In the formula, V f —Total fracturing fluid injection volume, m 2 ;ρ w1i —Equivalent density of fracturing fluid at the point of cessation of injection, kg / m³ 3 V — Total area of ​​the model, in meters 2 S wi —Saturation level of fracturing fluid when injection stops, %.

[0039] Moisture content calculation:

[0040]

[0041] In the formula, f w —Water content of the product liquid, %; ρ w1m ρ w1n —Equivalent density of fracturing fluid at times m and n, kg / m 3 S wm S wn —Fracturing fluid saturation at times m and n, %; ρ o1m ρ o1n —Equivalent density of shale oil at times m and n, kg / m³ 3 S om S on — Shale oil saturation at times m and n, %.

[0042] Calculation of return rate:

[0043]

[0044] In the formula, β is the return rate, %; ρ is the return rate. w1t —Equivalent density of fracturing fluid at time t, kg / m³ 3 S wt —Fracturing fluid saturation at time t, %.

[0045] Oil production rate calculation:

[0046]

[0047] In the formula, V o —Oil production rate, m 2 / ms;T n T m —Times m and n, in milliseconds (ms).

[0048] Extraction degree calculation:

[0049]

[0050] In the formula, R represents the degree of shale oil recovery, in percentages; ρ o1i —Equivalent density of shale oil at the point when fracturing injection stops, kg / m³ 3 S oi — Shale oil saturation at the point where fracturing injection stops, %; ρ o1t —Equivalent density of shale oil at time t, kg / m³ 3 S ot — Shale oil saturation at time t, %.

[0051] Optionally, in step S11, the recovery rate is simulated under the condition that the interfacial tension is 0 and no seepage occurs, and the seepage oil production contribution rate is calculated. Different rock facies have different porosity and permeability stress sensitivities, and the stress sensitivity data needs to be adjusted simultaneously to evaluate the seepage oil production contribution rate of different rock facies.

[0052] This invention also provides a simulation system for the elastic development process of shale oil at the pore scale, applying the above-described simulation method for the elastic development process of shale oil at the pore scale. The simulation system includes:

[0053] The natural pore structure map acquisition module is used to obtain high-resolution pore structure images of real cores by scanning electron microscopy analysis of shale samples. Representative locations are selected from the pore structure images to extract and characterize the pore structure, thus obtaining a natural pore structure map of the shale core.

[0054] The two-dimensional pore structure diagram visualization and simulation module is used to import the natural pore structure diagram into Comsol software, and add main cracks and random secondary cracks to simulate artificial pressure cracks, thus completing the visualization and simulation of the two-dimensional pore structure diagram.

[0055] The fluid equivalent density versus pressure curve setting module is used to consider the macroscopic porosity stress sensitivity, calculate the fluid density equivalently based on the mass conservation principle to characterize the porosity stress sensitivity, and set the fluid equivalent density versus pressure curve.

[0056] The fluid equivalent viscosity versus pressure curve setting module is used to consider the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity based on the flow similarity principle to characterize the permeability stress sensitivity, and set the fluid equivalent viscosity versus pressure curve.

[0057] The equivalent contact angle versus pressure curve setting module is used to consider the stress sensitivity of macroscopic porosity, calculate the contact angle based on capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and set the equivalent contact angle versus pressure curve.

[0058] The initial conditions and fluid properties setting module is used to set initial conditions and fluid properties. Select the laminar flow-phase field model and set the initial fluid distribution, initial pressure, fluid compressibility, wetting wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence.

[0059] The fracturing process simulation module is used to simulate the fracturing process, close the outlet, inject fracturing fluid at high pressure at the inlet, and analyze the fluid distribution during the fracturing fluid injection process;

[0060] The well shut-in process simulation module is used to simulate the well shut-in process. Closing the inlet simulates the well shut-in process, and the seepage mechanism is analyzed by the change in fluid distribution.

[0061] The oil production process simulation module is used to simulate the oil production process, reduce outlet pressure to simulate the elastic development process, and analyze changes in fluid distribution, water cut of produced fluid, and degree of recovery.

[0062] The data processing module is used for data processing, calculating parameters such as fluid distribution, oil production rate, water cut, and flowback rate at different times based on pressure, density, and surface integral.

[0063] The percolation oil production contribution rate calculation module is used to compare the recovery rate under conditions where no percolation occurs and calculate the percolation oil production contribution rate.

[0064] This invention provides a simulation method and system for the elastic development process of shale oil at the pore scale. It achieves simulation of the entire process of pressure-suppression-production, exhibiting good repeatability, comprehensive consideration of factors, and high flexibility. The simulation results are highly comparable to the actual production effects in shale oil reservoirs, providing a reliable basis for analyzing the mobilization law and percolation mechanism of the entire pressure-suppression-production process in shale oil reservoirs. It solves the problems of lacking experimental and simulation methods for the entire pressure-suppression-production process of shale oil elastic development at the pore scale; the high cost, limitations imposed by experimental equipment and conditions, and difficulty in data processing of microfluidic experiments; the difficulty in representing the real complex pore structure of shale using ideal pore structure conceptual models in microfluidic experiments and simulation studies; and the shortcomings of insufficient stress sensitivity analysis and difficulty in evaluating the contribution of percolation to oil production.

[0065] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, and to make the above and other objects, features and advantages of the present invention more apparent and understandable, specific embodiments of the present invention are described below. Attached Figure Description

[0066] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the following description of the embodiments will be briefly introduced. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0067] Figure 1 A flowchart illustrating a simulation method for the elastic development process of shale oil at the pore scale, provided as an embodiment of the present invention;

[0068] Figure 2 This is a scanning electron microscope image of the pore structure of a shale core in a specific embodiment of the present invention.

[0069] Figure 3 This is a two-dimensional pore structure model diagram of shale core in a specific embodiment of the present invention.

[0070] Figure 4 This is a fluid saturation field diagram of the fracturing fluid injection process in a specific embodiment of the present invention.

[0071] Figure 5 This is a fluid saturation field diagram of the well-sealing process in a specific embodiment of the present invention.

[0072] Figure 6 This is a fluid saturation field diagram of the oil extraction process in a specific embodiment of the present invention.

[0073] Figure 7 This is a simulation result diagram of moisture content change in a specific embodiment of the present invention.

[0074] Figure 8 This is a simulation result diagram of the change in the return rate in a specific embodiment of the present invention. Detailed Implementation

[0075] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0076] The terms "comprising" and "having," and any variations thereof, in the specification, embodiments, claims, and drawings of this invention are intended to cover non-exclusive inclusion, such as including a series of steps or units.

[0077] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments.

[0078] Example 1:

[0079] In one embodiment 1 of the present invention, Figure 1 This invention presents a flowchart of an improved simulation method for the entire process of pressure-suppression-production in shale oil elastic development at the pore scale. The method includes: extracting and establishing a two-dimensional model of the pore structure of a real shale core from scanning electron microscope images; setting basic parameters and initial conditions in Comsol software; calculating fluid density, viscosity, and contact angle considering the stress sensitivity transformation of porosity and permeability; simulating the pressure-suppression-production process sequentially; and analyzing the fluid mobility and seepage mechanism throughout the entire process. Specifically, it includes the following steps:

[0080] Step 1) From the high-resolution scanning electron microscope (SEM) pore structure image of the shale sample, a rectangular lamellar structure with a width of 700 μm and a height of 650 μm was selected. Using CAD software, a natural lamellar pore structure pattern of the shale core was extracted. The pore diameter mainly ranged from 0.1 to 10 μm. Figure 2 As shown;

[0081] Step 2) Import the extracted natural pore structure map into Comsol software. Simultaneously, add a rectangular simulated artificial pressure fracture (50 μm wide, 650 μm high) and random secondary fractures to the left of the natural pore structure to complete the visualized two-dimensional pore structure map, as shown below. Figure 3 As shown;

[0082] Step 3) Considering the macroscopic porosity stress sensitivity, the fluid density is equivalently calculated according to the mass conservation principle to characterize the porosity stress sensitivity, and a fluid equivalent density versus pressure curve is set.

[0083] Porosity stress-sensitive equivalent calculation:

[0084]

[0085] In the formula, ρ0 represents the true density of the oil / water phase under different pressures, in kg / m³. 3 ρ1—Equivalent density of oil / water phase under different pressures, kg / m³ 3 ;p i p t — Fluid pressure at initial time and time t, MPa; a, b — Coefficients obtained from the regression of the porosity stress-sensitive experimental curve of shale oil core, constant values.

[0086] Step 4) Considering the macroscopic permeability stress sensitivity, the microscopic fluid viscosity is equivalently calculated based on the principle of flow similarity to characterize the permeability stress sensitivity, and a curve of the fluid equivalent viscosity changing with pressure is set.

[0087] Permeability stress-sensitive equivalent calculation:

[0088]

[0089] In the formula, μ0 is the true viscosity of the oil / water phase under different pressures, in mPa·s; μ1 is the equivalent viscosity of the oil / water phase under different pressures, in mPa·s; p i p t — Fluid pressure at the initial moment and at any other moment, in MPa; c, d — Coefficients obtained from the regression of the stress-sensitive experimental curve of shale oil core permeability, constant values.

[0090] Step 5) Shale reservoirs are highly sensitive to porosity stress. In actual development, as the net overburden increases, the pores are compressed. Considering the influence of porosity stress sensitivity can improve the accuracy of the simulation. Based on the capillary force similarity equivalent calculation, the contact angle characterizes the influence of pressure change on pore structure and capillary force. A two-dimensional equivalent contact angle curve with pressure change is set.

[0091] Capillary force equivalent calculation:

[0092]

[0093] In the formula, θ0 is the actual contact angle under different pressures, π / 4, for hydrophilic wetting; θ1 is the equivalent contact angle under different pressures, °.

[0094] Step 6) Initially, the natural porous structure contains a saturated oil phase, and the artificially fractured structure contains a saturated water phase. Based on actual production conditions, the lower end of the artificially fractured structure is designated as the inlet during fracturing and as the outlet during oil production. Water is injected at the inlet end. The initial system pressure is a constant 50 MPa. The system uses the finest meshing.

[0095] Step 7) Simulate the fracturing process: Close the outlet, inject fracturing fluid at a high pressure of 80 MPa at the inlet, simulate for 20 ms with a time step of 1 ms. Figure 4 As shown;

[0096] Step 8) Simulate the well shut-in process: Close the inlet to simulate the well shut-in process. The simulation time is 300ms, and the time step is 1ms. Figure 5 As shown;

[0097] Step 9) Simulate the oil production process: Stepwise reduce the outlet pressure to 20 MPa to simulate the elastic development process. The simulation time is 120 ms, and the time step is 1 ms. Figure 6 As shown;

[0098] Step 10) Data processing: Calculate parameters such as fluid distribution, oil production rate, water cut, and flowback rate at different times based on pressure, density, and surface integral. Figure 7 , Figure 8 As shown.

[0099] Calculation of fracturing fluid injection volume:

[0100] V f =ρ w1i *V*S wi

[0101] In the formula, V f —Total fracturing fluid injection volume, m 2 ;ρ w1i —Equivalent density of fracturing fluid at the point of cessation of injection, kg / m³ 3 V — Total area of ​​the model, in meters 2 S wi —The saturation of the fracturing fluid at the point where injection stops (obtainable by direct integration), %.

[0102] Moisture content calculation:

[0103]

[0104] In the formula, f w —Water content of the product liquid, %; ρ w1m ρ w1n —Equivalent density of fracturing fluid at times m and n, kg / m 3 S wm S wn —Fracturing fluid saturation at times m and n (obtainable by direct integration), %; ρ o1m ρ o1n —Equivalent density of shale oil at times m and n, kg / m³ 3 S om S on— Shale oil saturation at times m and n (obtainable by direct integration), %.

[0105] Calculation of return rate:

[0106]

[0107] In the formula, β is the return rate, %; ρ is the return rate. w1t —Equivalent density of fracturing fluid at time t, kg / m³ 3 S wt —Fracturing fluid saturation at time t (obtainable by direct integration), %.

[0108] Oil production rate calculation:

[0109]

[0110] In the formula, V o —Oil production rate, m 2 / ms;T n T m —Times m and n, in milliseconds (ms).

[0111] Extraction degree calculation:

[0112]

[0113] In the formula, R represents the degree of shale oil recovery, in percentages; ρ o1i —Equivalent density of shale oil at the point when fracturing injection stops, kg / m³ 3 S oi — Shale oil saturation at the point where fracturing injection stops (obtainable by direct integration), %; ρ o1t —Equivalent density of shale oil at time t, kg / m³ 3 S ot — Shale oil saturation at time t (obtainable by direct integration), %.

[0114] Step 11) Compare the recovery rate under conditions where no percolation occurs. Under this model, the contribution rate of percolation to oil production is close to 30%.

[0115] Example 2:

[0116] Example 1 considered the effects of wettability and percolation, resulting in an elastic recovery rate of approximately 24% for shale oil, which is a combined effect of elastic properties and percolation. Based on this model, by adjusting the contact angle to 0 and disregarding the effect of percolation, a complete simulation of the compression-suppression-production process was performed, yielding an elastic recovery rate of approximately 16% for shale oil. Therefore, the calculated contribution rate of percolation to oil production in this lithology is close to 30%.

[0117] Considering the influence of different pore structures and stress sensitivity, by changing key parameters such as pore structure model, stress sensitivity parameters, and wettability strength, the oil production contribution rate under different conditions is obtained through the simulation calculation method of this invention.

[0118] Beneficial effects: (1) A method for simulating the entire process of shale oil pressure-suppression-production at the pore scale based on the laminar flow-phase field-compressible fluid model of Comsol software was established; (2) A real pore structure model was established based on the scanning electron microscope images of shale cores to improve simulation accuracy; (3) The influence of porosity and permeability stress sensitivity was considered equivalently through the principle of similarity; (4) The dynamic law and permeation mechanism of the entire process of pressure-suppression-production in the pore structure of shale oil were dynamically analyzed.

[0119] The above specific embodiments further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method of simulating a pore-scale shale oil elastic development process, characterized in that, The simulation method includes: Step S1: Perform scanning electron microscopy analysis on the shale sample to obtain a high-resolution pore structure image of the real core. Select representative locations from the pore structure image to extract and characterize the pore structure to obtain a natural pore structure map of the shale core. Step S2: Import the natural pore structure diagram into Comsol software, and add main cracks and random secondary cracks to simulate artificial pressure cracks to complete the two-dimensional pore structure diagram of visualization simulation; Step S3: Considering the macroscopic porosity stress sensitivity, calculate the equivalent fluid density based on the mass conservation principle to characterize the porosity stress sensitivity, and set the fluid equivalent density versus pressure curve; In step S3, based on the evaluation results of the volume factor changes and porosity stress sensitivity of the oil and water phases, the density change is calculated according to the mass conservation equivalent to improve the shortcomings of conventional simulation that ignores porosity stress sensitivity. Porosity stress-sensitive equivalent calculation: In the formula, —True density of oil / water phase under different pressures, kg / m³ 3 ; —Equivalent density of oil / water phase under different pressures, kg / m³ 3 ; , — Fluid pressure at initial time and time t, in MPa; , —Coefficients obtained from the regression of the porosity stress-sensitive experimental curve of shale oil core, and constant values; Step S4: Considering the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity equivalently based on the principle of fluidity similarity to characterize the permeability stress sensitivity, and set the fluid equivalent viscosity as a function of pressure curve; Step S5: Considering the stress sensitivity of macroscopic porosity, the contact angle is calculated based on the capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and the equivalent contact angle versus pressure curve is set. Step S5 is to calculate the contact angle based on the capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and set a two-dimensional equivalent contact angle curve with pressure change. Capillary force equivalent calculation: In the formula, —The actual contact angle under different pressures, in °; —Equivalent contact angle under different pressures, °; Step S6: Set initial conditions and fluid properties, select the laminar flow-phase field model, and set the initial fluid distribution, initial pressure, fluid compressibility, wetting wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence; Step S7: Simulate the fracturing process, close the outlet, inject fracturing fluid at high pressure at the inlet, and analyze the fluid distribution during the fracturing fluid injection process; Step S8: Well shut-in process simulation. The well shut-in process is simulated by closing the inlet, and the seepage mechanism is analyzed by the change in fluid distribution. Step S9: Simulate the oil production process, reduce the outlet pressure to simulate the elastic development process, and analyze the changes in fluid distribution, water cut of the produced fluid, and degree of recovery; Step S10: Data processing, calculate fluid distribution, oil production rate, water cut and flowback rate parameters at different times based on pressure, density and surface integral; Step S11: Compare the recovery rate under conditions where no seepage occurs, and calculate the contribution rate of seepage to oil production.

2. The method of claim 1, wherein, Step S1 involves using CAD to extract connected pores and establish a two-dimensional natural pore structure model based on the high-resolution pore structure of real shale cores obtained by scanning electron microscopy.

3. The method of claim 1, wherein, In step S4, based on the viscosity changes of the oil and water phases under different pressures and the evaluation results of permeability stress sensitivity, the viscosity change is calculated according to the similarity of flowability, which improves the shortcomings of conventional simulation that ignores permeability stress sensitivity. Permeability stress-sensitive equivalent calculation: In the formula, —The true viscosity of the oil / water phase under different pressures, in mPa·s; —Equivalent viscosity of oil / water phase under different pressures, mPa·s; , — Fluid pressure at the initial moment and at any other moment, in MPa; , —Coefficients obtained from the regression of the stress-sensitive experimental curve of shale oil core permeability, and fixed values.

4. The simulation method for the elastic development process of shale oil at the pore scale according to claim 1, characterized in that, Step S6 takes into account the actual field development situation. The fracturing fluid injection, well shut-in, and oil production of shale oil fracturing development are all completed by a single well, and the model inlet and outlet are set to the same path.

5. The method of claim 1, wherein, In step S6, the natural pore structure is completely filled with oil, and the artificially pressed cracks are completely filled with water; the wetting walls of the pore structure are all hydrophilic, with a contact angle of less than 90°.

6. The method of claim 1, wherein, In step S7, the inlet pressure is higher than the initial pressure to ensure fracturing fluid injection, and both constant pressure injection and variable pressure injection methods are selected.

7. The method of claim 1, wherein, In step S9, the outlet pressure is lower than the initial pressure to ensure fluid extraction, while selecting constant pressure development and step-by-step pressure reduction development methods.

8. The simulation method for the elastic development process of shale oil at the pore scale according to claim 1, characterized in that, Step S10 calculates parameters such as fluid distribution, oil production rate, water cut, and flowback rate at different times based on pressure, fluid viscosity, and surface integral, and analyzes the oil production pattern and recovery degree. Calculation of fracturing fluid injection volume: In the formula, —Total fracturing fluid injection volume, kg; —Equivalent density of fracturing fluid at the point of cessation of injection, kg / m³ 3 ; —Total volume of the model, m 3 ; —Saturation level of fracturing fluid when injection stops, % Moisture content calculation: In the formula, —Water content of the product liquid, % , —Equivalent density of fracturing fluid at times m and n, kg / m 3 ; , —Fracturing fluid saturation at times m and n, % , —Equivalent density of shale oil at times m and n, kg / m³ 3 ; , —Shale oil saturation at times m and n, % Calculation of return rate: In the formula, —Return rate, % —Equivalent density of fracturing fluid at time t, kg / m³ 3 ; —Fracturing fluid saturation at time t, % Oil production rate calculation: wherein - oil production rate, m 2 / ms; , - m, n time, ms; Extraction degree calculation: In the formula, — Shale oil recovery rate, % —Equivalent density of shale oil at the point when fracturing injection stops, kg / m³ 3 ; — Shale oil saturation at the point when fracturing injection stops, % —Equivalent density of shale oil at time t, kg / m³ 3 ; — Shale oil saturation at time t, %.

9. The simulation method for the elastic development process of shale oil at the pore scale according to claim 1, characterized in that, In step S11, the recovery rate is simulated under the condition that the interfacial tension is 0 and no seepage occurs, and the contribution rate of seepage oil production is calculated. Different rock facies have different porosity and permeability stress sensitivities, and the stress sensitivity data needs to be adjusted simultaneously to evaluate the contribution rate of seepage oil production of different rock facies.

10. A simulation system for the elastic development process of shale oil at the pore scale, employing the simulation method for the elastic development process of shale oil at the pore scale as described in any one of claims 1-9, characterized in that, The simulation system includes: The natural pore structure map acquisition module is used to obtain high-resolution pore structure images of real cores by scanning electron microscopy analysis of shale samples. Representative locations are selected from the pore structure images to extract and characterize the pore structure, thus obtaining a natural pore structure map of the shale core. The two-dimensional pore structure diagram visualization and simulation module is used to import the natural pore structure diagram into Comsol software, and add main cracks and random secondary cracks to simulate artificial pressure cracks, thus completing the visualization and simulation of the two-dimensional pore structure diagram. The fluid equivalent density versus pressure curve setting module is used to consider the macroscopic porosity stress sensitivity, calculate the fluid density equivalently based on the mass conservation principle to characterize the porosity stress sensitivity, and set the fluid equivalent density versus pressure curve. The fluid equivalent viscosity versus pressure curve setting module is used to consider the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity based on the flow similarity principle to characterize the permeability stress sensitivity, and set the fluid equivalent viscosity versus pressure curve. The equivalent contact angle versus pressure curve setting module is used to consider the stress sensitivity of macroscopic porosity, calculate the contact angle based on capillary force similarity to characterize the influence of pressure change on pore structure and capillary force, and set the equivalent contact angle versus pressure curve. The initial conditions and fluid properties setting module is used to set initial conditions and fluid properties. Select the laminar flow-phase field model and set the initial fluid distribution, initial pressure, fluid compressibility, wetting wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence. The fracturing process simulation module is used to simulate the fracturing process, close the outlet, inject fracturing fluid at high pressure at the inlet, and analyze the fluid distribution during the fracturing fluid injection process; The well shut-in process simulation module is used to simulate the well shut-in process. Closing the inlet simulates the well shut-in process, and the seepage mechanism is analyzed by the change in fluid distribution. The oil production process simulation module is used to simulate the oil production process, reduce outlet pressure to simulate the elastic development process, and analyze changes in fluid distribution, water cut of produced fluid, and degree of recovery. The data processing module is used for data processing, calculating parameters such as fluid distribution, oil production rate, water cut, and flowback rate at different times based on pressure, density, and surface integral. The percolation oil production contribution rate calculation module is used to compare the recovery rate under conditions where no percolation occurs and calculate the percolation oil production contribution rate.

Images