Simulation method and system for pore-scale shale oil elastic development process

Abstract

The invention provides a simulation method and system for a pore-scale shale oil elastic development process. The method comprises the following steps: extracting and establishing a two-dimensional real shale core pore structure model according to a scanning electron microscope picture; setting basic parameters and initial conditions based on Comsol software; calculating fluid density, viscosity and contact angle equivalently by considering stress sensitivity similar conversion of porosity and permeability; sequentially simulating a pressing-closing-mining process; and analyzing the fluid utilization rule and the imbibition oil production contribution rate in the whole process of pressing, closing and production. The method has the obvious advantages of good repeatability, strong model representativeness, consideration of the influence of porosity and permeability change, high analysis precision and the like, and provides reference for deep analysis of shale oil elastic development and utilization rules and imbibition action mechanisms.

Description

Technical Field

[0001] The present invention relates to the technical field of unconventional oil and gas exploitation, and in particular to a simulation method and system for a pore-scale shale oil elastic development process. Background Art

[0002] At present, shale oil is mainly developed by elastic development after volume fracturing. The production practice of many shale oil and gas wells has found that appropriate well blocking can shorten the time to oil, increase cumulative oil production, and reduce water content and flowback rate. Preliminary analysis shows that the imbibition effect of shale oil and gas reservoirs is one of the key mechanisms affecting production dynamics, and making full use of the imbibition effect is conducive to improving the production capacity of a single well. However, there is no in-depth understanding of the impact of pore-scale imbibition on the law of shale oil production and the dynamic law of shale oil pressure-blocking-production development, and there is a lack of intuitive characterization methods.

[0003] Mine production dynamics, reservoir numerical simulation, and core experimental research can explain macroscopic laws and phenomena, but it is difficult to deeply reveal the flow mechanism. Studying the dynamic process of pore-scale elastic development is the key to explaining core experimental phenomena, supporting the optimization of development technology policies, and improving shale oil production capacity. Commonly used pore-scale shale oil flow mechanism research mainly includes two methods: microfluidic experiments and microscopic flow simulation. Microfluidic experiments use high-precision microscope mechanisms to directly observe and record the dynamic process of pressure-suffocation-production in pores, and the experimental results are intuitive and accurate. Microscopic simulation research is highly flexible and is not limited by experimental conditions and equipment. It can fully study key parameters such as velocity, pressure, and saturation.

[0004] Shale oil reservoirs have complex pore structures and are highly stress sensitive. The currently used microfluidic experiments and microscopic flow simulation studies still have some shortcomings, specifically: (1) There is a lack of experimental and simulation methods for the entire process of shale oil elastic development, compression-suffocation-production at the pore scale, and most studies only focus on the well-suffocation and imbibition process; (2) Microfluidic experiments are expensive, and the experimental equipment and conditions are greatly restricted, 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 stress sensitivity analysis is insufficient, and it is difficult to evaluate the contribution of imbibition to oil production. 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 shale oil at the pore scale that overcomes the above problems or at least partially solves the above problems.

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

[0007] Step S1: Perform scanning electron microscope analysis on the shale sample to obtain a high-resolution pore structure photo of the real core, select representative positions from the pore structure photo, extract and depict the pore structure to obtain a natural pore structure plate of the shale core;

[0008] Step S2: importing the natural pore structure map into Comsol software, adding primary fractures and random secondary fractures to simulate artificial fractures, and completing a two-dimensional pore structure map of visual simulation;

[0009] Step S3: Considering the macro porosity stress sensitivity, the fluid density is equivalently calculated according to the mass conservation principle to characterize the porosity stress sensitivity, and a curve of fluid equivalent density changing with pressure is set;

[0010] Step S4: Considering the macroscopic permeability stress sensitivity, the microscopic fluid viscosity is equivalently calculated according to the fluidity similarity principle to characterize the permeability stress sensitivity, and a fluid equivalent viscosity versus pressure change curve is set;

[0011] Step S5: Considering the stress sensitivity of macro 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 an 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 initial fluid distribution, initial pressure, fluid compressibility, wetted wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence;

[0013] Step S7: simulating the fracturing process, closing the outlet, injecting fracturing fluid at the inlet under high pressure, and analyzing the fluid distribution during the fracturing fluid injection process;

[0014] Step S8: simulating the well shut-in process, closing the inlet to simulate the well shut-in process, and analyzing the imbibition mechanism through the change of fluid distribution;

[0015] Step S9: Simulating the oil production process, reducing the outlet pressure to simulate the elastic development process, analyzing the fluid distribution changes, the water content of the produced fluid, and the degree of recovery;

[0016] Step S10: data processing, calculating fluid distribution, oil production rate, water content and flowback rate parameters at different times according to pressure, density and surface integral;

[0017] Step S11: Compare the recovery degree without imbibition and calculate the imbibition oil production contribution rate.

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

[0019] Optionally, in step S3, based on the volume coefficient change of the oil phase and the water phase and the porosity stress sensitivity evaluation results, the density change is equivalently calculated according to the mass conservation law to improve the deficiency of conventional simulation ignoring porosity stress sensitivity;

[0020] Equivalent calculation of porosity stress sensitivity:

[0021]

[0022] Where, ρ0——real density of oil phase / water phase under different pressures, Kg / m 3 ; ρ1——Equivalent density of oil phase / water phase under different pressures, Kg / m 3 ;p i 、p t ——Fluid pressure at the initial moment and time t, MPa; a, b——Coefficients obtained by regression of shale oil core porosity stress sensitivity experimental curve, constant value.

[0023] Optionally, in step S4, based on the viscosity change of the oil phase and the water phase under different pressures and the permeability stress sensitivity evaluation results, the viscosity change is equivalently calculated according to the mobility similarity to improve the deficiency of conventional simulation ignoring the permeability stress sensitivity;

[0024] Equivalent calculation of permeability stress sensitivity:

[0025]

[0026] Where, μ0 is the real viscosity of the oil phase / water phase at different pressures, mPa·s; μ1 is the equivalent viscosity of the oil phase / water phase at different pressures, mPa·s; p i 、p t ——Fluid pressure at the initial moment and any moment, MPa; c, d——Coefficients obtained by regression of shale oil core permeability stress sensitivity experimental curve, constant value.

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

[0028] Equivalent calculation of capillary force:

[0029]

[0030] Wherein, θ0 is the real 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, and the fracturing fluid injection, well blocking, and oil production of shale oil fracturing development are all completed by one 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 artificial fractures are completely filled with water; the wetting walls of the pore structure are all hydrophilic, and the contact angle is less than 90°.

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

[0034] Optionally, the outlet pressure in step S9 is lower than the initial pressure to ensure fluid production, and constant pressure development and step-by-step pressure reduction development are selected at the same time.

[0035] Optionally, the step S10 calculates parameters such as fluid distribution, oil production rate, water content and flowback rate at different times according to pressure, fluid viscosity and surface integral, and analyzes oil production rules and recovery degree;

[0036] Calculation of fracturing fluid injection volume:

[0037] V f =ρ w1i *V*S wi

[0038] Where V f ——Total injection volume of fracturing fluid, m 2 ρ w1i ——Equivalent density of fracturing fluid when injection is stopped, Kg / m 3 ; V——total area of ​​the model, m 2 ; S wi ——Saturation when fracturing fluid injection stops, %.

[0039] Moisture content calculation:

[0040]

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

[0042] Calculation of flowback rate:

[0043]

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

[0045] Oil production rate calculation:

[0046]

[0047] Where V o ——Oil production rate, m 2 / ms;T n 、T m ——m, n time, ms.

[0048] Calculation of extraction degree:

[0049]

[0050] Where, R is the degree of shale oil recovery, %; ρ o1i ——Equivalent density of shale oil when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops, %; ρ o1t ——Equivalent density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t, %.

[0051] Optionally, in step S11, the degree of recovery under the condition that the interfacial tension is 0 and no imbibition occurs is simulated to calculate the imbibition contribution to oil production; the porosity and permeability stress sensitivities of different lithofacies are different, and the evaluation of the imbibition contribution to oil production of different lithofacies requires simultaneous adjustment of stress sensitivity data.

[0052] The present invention also provides a simulation system for the elastic development process of shale oil at a pore scale, and the simulation method for the elastic development process of shale oil at a pore scale described above is applied. The simulation system comprises:

[0053] The module for acquiring the natural pore structure plate is used to perform scanning electron microscope analysis on shale samples to obtain high-resolution pore structure photos of real cores, select representative positions from the pore structure photos, extract and depict the pore structure, and obtain the natural pore structure plate of the shale core;

[0054] A two-dimensional pore structure diagram visualization simulation module is used to import the natural pore structure diagram into Comsol software, and simultaneously add primary fractures and random secondary fractures to simulate artificial fractures, so as to complete a two-dimensional pore structure diagram of visualization simulation;

[0055] The module for setting the curve of fluid equivalent density versus pressure is used to consider the macro porosity stress sensitivity, calculate the fluid density equivalently according to the mass conservation principle to characterize the porosity stress sensitivity, and set the curve of fluid equivalent density versus pressure;

[0056] The module for setting the curve of fluid equivalent viscosity changing with pressure is used to consider the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity according to the principle of fluid similarity to characterize the permeability stress sensitivity, and set the curve of fluid equivalent viscosity changing with pressure;

[0057] The module for setting the curve of equivalent contact angle variation with pressure is used to consider the stress sensitivity of macro porosity, calculate the contact angle based on the similarity and equivalent calculation of capillary force to characterize the influence of pressure change on pore structure and capillary force, and set the curve of equivalent contact angle variation with pressure;

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

[0059] Fracturing process simulation module, used for fracturing process simulation, closing the outlet, injecting fracturing fluid at high pressure at the inlet, and analyzing 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, close the inlet to simulate the well shut-in process, and analyze the imbibition mechanism through the change of fluid distribution;

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

[0062] Data processing module, used for data processing, calculating fluid distribution, oil production rate, water content and flowback rate parameters at different times based on pressure, density and surface integral;

[0063] The imbibition oil production contribution rate calculation module is used to compare the recovery degree without imbibition and calculate the imbibition oil production contribution rate.

[0064] The present invention provides a simulation method and system for the elastic development process of shale oil at a pore scale, which realizes the simulation of the whole process of pressure-suffocation-production, has good repeatability, comprehensive consideration of factors, strong flexibility, and strong comparison between the simulation results and the on-site production effect of shale oil reservoirs, providing a reliable basis for the analysis of the utilization law and the mechanism of imbibition in the whole process of pressure-suffocation-production of shale oil reservoirs. It solves the problems of lack of experimental and simulation methods for the whole process of pressure-suffocation-production of elastic development of shale oil at a pore scale; the problems of high cost of microfluidic experiments, great restrictions on experimental equipment and conditions, and great difficulty in data processing; the problem that the ideal pore structure conceptual model used in microfluidic experiments and simulation studies is difficult to represent the real complex pore structure of shale; the insufficiency of stress sensitivity analysis and the difficulty in evaluating the contribution of imbibition to oil production.

[0065] The above description is only an overview of the technical solution of the present invention. In order to more clearly understand the technical means of the present invention, it can be implemented according to the contents of the specification. In order to make the above and other purposes, features and advantages of the present invention more obvious and easy to understand, the specific implementation methods of the present invention are listed below. BRIEF DESCRIPTION OF THE DRAWINGS

[0066] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings required for use in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other accompanying drawings can be obtained based on these accompanying drawings without paying creative work.

[0067] Figure 1 A flow chart of a method for simulating a pore-scale shale oil elastic development process provided by an embodiment of the present invention;

[0068] Figure 2 It 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 It is a two-dimensional pore structure model diagram of a shale core in a specific embodiment of the present invention.

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

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

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

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

[0074] Figure 8 It is a simulation result diagram of the change of the backflow rate in a specific embodiment of the present invention. DETAILED DESCRIPTION

[0075] The exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0076] The terms "comprises" and "having" and any variations thereof in the description embodiments, claims and drawings of the present invention are intended to cover non-exclusive inclusions, for example, including a series of steps or units.

[0077] The technical solution of the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments.

[0078] Embodiment 1:

[0079] In one embodiment 1 of the present invention, Figure 1 This is a flow chart of the simulation method of the whole process of pressure-suffocation-extraction of an improved pore-scale shale oil elastic development of the present invention, including: establishing a two-dimensional real shale core pore structure model based on scanning electron microscope image extraction, setting basic parameters and initial conditions in Comsol software, considering the stress sensitivity of porosity and permeability to convert and equivalently calculate fluid density, viscosity and contact angle, simulating the pressure-suffocation-extraction process in turn, and analyzing the fluid utilization law and imbibition mechanism of the whole process of pressure-suffocation-extraction. Specifically, it includes the following steps:

[0080] Step 1) A rectangular laminar structure with a width of 700 μm and a height of 650 μm is selected from the high-resolution pore structure photograph of the shale sample taken by scanning electron microscopy, and the natural laminar pore structure plate of the shale core is extracted using CAD software. The pore diameter mainly ranges from 0.1 to 10 μm, such as Figure 2 As shown;

[0081] Step 2) Import the extracted natural pore structure plate into Comsol software, and add a rectangular simulated artificial fracture with a width of 50 μm and a height of 650 μm and a random secondary fracture on the left side of the natural pore structure to complete the two-dimensional pore structure plate of visual simulation, as shown in Figure 2. Figure 3 As shown;

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

[0083] Equivalent calculation of porosity stress sensitivity:

[0084]

[0085] Where, ρ0——real density of oil phase / water phase under different pressures, Kg / m 3 ; ρ1——Equivalent density of oil phase / water phase under different pressures, Kg / m 3 ;p i 、p t ——Fluid pressure at the initial moment and time t, MPa; a, b——Coefficients obtained by regression of shale oil core porosity stress sensitivity experimental curve, constant value.

[0086] Step 4) Considering the macroscopic permeability stress sensitivity, the microscopic fluid viscosity is equivalently calculated according to the fluidity similarity principle to characterize the permeability stress sensitivity, and the fluid equivalent viscosity versus pressure change curve is set;

[0087] Equivalent calculation of permeability stress sensitivity:

[0088]

[0089] Where, μ0 is the real viscosity of the oil phase / water phase at different pressures, mPa·s; μ1 is the equivalent viscosity of the oil phase / water phase at different pressures, mPa·s; p i 、p t ——Fluid pressure at the initial moment and any moment, MPa; c, d——Coefficients obtained by regression of shale oil core permeability stress sensitivity experimental curve, constant value.

[0090] Step 5) Shale reservoirs are highly sensitive to porosity stress. In the actual development process, as the net overburden pressure increases, the pores are compressed. Considering the influence of porosity stress sensitivity can improve the accuracy of simulation. The contact angle is calculated based on the capillary force similarity to characterize the influence of pressure changes on pore structure and capillary force, and a two-dimensional equivalent contact angle versus pressure curve is set.

[0091] Equivalent calculation of capillary force:

[0092]

[0093] Where, θ0 is the real contact angle under different pressures, π / 4, hydrophilic wetting; θ1 is the equivalent contact angle under different pressures, °.

[0094] Step 6) At the initial moment, the natural pore structure is saturated with oil phase, and the artificial fracture is saturated with water phase; in combination with actual production, the lower end of the artificial fracture is set as the inlet during the fracturing process and the outlet during the oil production process, and water is injected at the inlet end; the initial pressure of the system is a constant pressure of 50MPa; the grid is divided into extremely fine grids;

[0095] Step 7) Fracturing process simulation, close the outlet, inject fracturing fluid at the inlet at a high pressure of 80 MPa, simulate for 20 ms, and 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, the time step is 1ms, as shown in Figure 5 As shown;

[0097] Step 9) Simulate the oil production process, step down the outlet pressure to 20 MPa to simulate the elastic development process, the simulation time is 120 ms, the time step is 1 ms, as shown in Figure 6 As shown;

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

[0099] Calculation of fracturing fluid injection volume:

[0100] V f =ρ w1i *V*S wi

[0101] Where V f ——Total injection volume of fracturing fluid, m 2 ρ w1i ——Equivalent density of fracturing fluid when injection is stopped, Kg / m 3 ; V——total area of ​​the model, m 2 ; S wi ——Saturation when fracturing fluid injection stops (obtained by direct integration), %.

[0102] Moisture content calculation:

[0103]

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

[0105] Calculation of flowback rate:

[0106]

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

[0108] Oil production rate calculation:

[0109]

[0110] Where V o ——Oil production rate, m 2 / ms;T n 、T m ——m, n time, ms.

[0111] Calculation of extraction degree:

[0112]

[0113] Where, R is the degree of shale oil recovery, %; ρ o1i ——Equivalent density of shale oil when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops (obtained by direct integration), %; ρ o1t ——Equivalent density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t (obtained by direct integration), %.

[0114] Step 11) comparing the recovery degree without imbibition, under the model conditions, the imbibition oil production contribution rate is close to 30%.

[0115] Embodiment 2:

[0116] Example 1 takes into account the effects of wettability and imbibition, and the recovery rate of shale oil elastic development is about 24%, which is the combined effect of elastic energy and imbibition. Based on this model, the contact angle is adjusted to 0, the influence of imbibition is not considered, and the whole process of pressure-suffocation-extraction is fully simulated, and the recovery rate of shale oil elastic development is about 16%. Therefore, the contribution rate of imbibition oil production in this lithofacies is calculated to be close to 30%.

[0117] Taking into account the influence of different pore structures and stress sensitivity, key parameters such as the pore structure model, stress sensitivity parameters, wettability, etc. are changed, and the imbibition oil production contribution rate under different conditions is obtained through the simulation calculation method of the present invention.

[0118] Beneficial effects: (1) A method for simulating the entire process of shale oil pressure-suffocation-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 scanning electron microscope photos of shale cores to improve simulation accuracy; (3) The influence of porosity and permeability stress sensitivity was equivalently considered through the similarity principle; (4) The production law and imbibition mechanism of the entire process of pressure-suffocation-production in the pore structure of shale oil were dynamically analyzed.

[0119] The above specific implementation methods further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above are only specific implementation methods 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 in the scope of protection of the present invention.

Claims

1. A method for simulating the elastic development process of shale oil at a pore scale, characterized in that: The simulation method comprises: Step S1: Perform scanning electron microscope analysis on the shale sample to obtain a high-resolution pore structure photo of the real core, select representative positions from the pore structure photo, extract and depict the pore structure to obtain a natural pore structure plate of the shale core; Step S2: importing the natural pore structure map into Comsol software, adding primary fractures and random secondary fractures to simulate artificial fractures, and completing a two-dimensional pore structure map of visual simulation; Step S3: Considering the macro porosity stress sensitivity, the fluid density is equivalently calculated according to the mass conservation principle to characterize the porosity stress sensitivity, and a curve of fluid equivalent density changing with pressure is set; Step S4: Considering the macroscopic permeability stress sensitivity, the microscopic fluid viscosity is equivalently calculated according to the fluidity similarity principle to characterize the permeability stress sensitivity, and a fluid equivalent viscosity versus pressure change curve is set; Step S5: Considering the stress sensitivity of macro 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 an equivalent contact angle versus pressure curve is set; Step S6: Set initial conditions and fluid properties, select the laminar flow-phase field model, and set initial fluid distribution, initial pressure, fluid compressibility, wetted wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence; Step S7: simulating the fracturing process, closing the outlet, injecting fracturing fluid at the inlet under high pressure, and analyzing the fluid distribution during the fracturing fluid injection process; Step S8: simulating the well shut-in process, closing the inlet to simulate the well shut-in process, and analyzing the imbibition mechanism through the change of fluid distribution; Step S9: Simulating the oil production process, reducing the outlet pressure to simulate the elastic development process, analyzing the fluid distribution changes, the water content of the produced fluid, and the degree of recovery; Step S10: data processing, calculating fluid distribution, oil production rate, water content and flowback rate parameters at different times according to pressure, density and surface integral; Step S11: Compare the recovery degree without imbibition and calculate the imbibition oil production contribution rate.

2. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: In step S1, based on the high-resolution pore structure of the real shale core obtained by scanning electron microscopy, CAD is used to extract the connected pores to establish a two-dimensional natural pore structure model.

3. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: In step S3, based on the volume coefficient change of the oil phase and the water phase and the porosity stress sensitivity evaluation results, the density change is equivalently calculated according to the mass conservation law to improve the deficiency of conventional simulation that ignores porosity stress sensitivity; Equivalent calculation of porosity stress sensitivity: Where, ρ0——real density of oil phase / water phase under different pressures, Kg / m 3 ; ρ1——Equivalent density of oil phase / water phase under different pressures, Kg / m 3 ;p i 、p t ——Fluid pressure at the initial moment and time t, MPa; a, b——Coefficients obtained by regression of shale oil core porosity stress sensitivity experimental curve, constant value.

4. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: In step S4, based on the viscosity change of the oil phase and the water phase under different pressures and the permeability stress sensitivity evaluation results, the viscosity change is equivalently calculated according to the mobility similarity to improve the deficiency of conventional simulation ignoring the permeability stress sensitivity; Equivalent calculation of permeability stress sensitivity: Where, μ0 is the real viscosity of the oil phase / water phase at different pressures, mPa·s; μ1 is the equivalent viscosity of the oil phase / water phase at different pressures, mPa·s; p i 、p t ——Fluid pressure at the initial moment and any moment, MPa; c, d——Coefficients obtained by regression of shale oil core permeability stress sensitivity experimental curve, constant value.

5. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: The step S5 calculates the contact angle based on the capillary force similarity to characterize the influence of pressure change on the pore structure and capillary force, and sets a two-dimensional equivalent contact angle versus pressure curve; Equivalent calculation of capillary force: Wherein, θ0 is the real contact angle under different pressures, °; θ1 is the equivalent contact angle under different pressures, °.

6. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: The step S6 takes into account the actual field development. The fracturing fluid injection, well blocking and oil production of shale oil fracturing development are all completed by one well, and the model inlet and outlet are set to the same path.

7. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: In step S6, the natural pore structure is completely filled with oil, and the artificial fractures are completely filled with water; the wetted walls of the pore structure are all hydrophilic, and the contact angle is less than 90°.

8. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: The inlet pressure in step S7 is higher than the initial pressure to ensure the injection of fracturing fluid, and both constant pressure injection and variable pressure injection are selected.

9. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: The outlet pressure in step S9 is lower than the initial pressure to ensure fluid production, while constant pressure development and step-by-step pressure reduction development are selected.

10. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: The step S10 calculates parameters such as fluid distribution, oil production rate, water content and flowback rate at different times according to pressure, fluid viscosity and surface integral, and analyzes oil production rules and recovery degree; Calculation of fracturing fluid injection volume: V f =ρ w1i *V*S wi Where V f ——Total injection volume of fracturing fluid, m 2 ; ρ w1i ——Equivalent density of fracturing fluid when injection is stopped, Kg / m 3 ; V——total area of ​​the model, m 2 ; S wi ——Saturation when fracturing fluid injection stops, %. Moisture content calculation: In the formula, f w ——Water content of output fluid, %; ρ w1m , w1n ——Equivalent density of fracturing fluid at time m and n, Kg / m 3 ; S wm , S wn ——Fracturing fluid saturation at time m and n, %; ρ o1m , o1n ——Equivalent density of shale oil at time m and n, Kg / m 3 ; S om , S on ——Shale oil saturation at time m and n, %. Calculation of flowback rate: In the formula, β is the flowback rate, %; ρ w1t ——Equivalent density of fracturing fluid at time t, Kg / m 3 ; S wt ——Fracturing fluid saturation at time t, %. Oil production rate calculation: Where V o ——Oil production rate, m 2 / ms;T n , T m ——m, n time, ms. Calculation of extraction degree: Where, R is the degree of shale oil recovery, %; ρ o1i ——Equivalent density of shale oil when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops, %; ρ o1t ——Equivalent density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t, %.

11. The method for simulating the elastic development process of shale oil at a pore scale according to claim 1, characterized in that: In the step S11, the degree of recovery under the condition that the interfacial tension is 0 and no imbibition occurs is simulated, and the imbibition contribution rate to oil production is calculated; the porosity and permeability stress sensitivities of different lithofacies are different, and the evaluation of the imbibition contribution rate to oil production of different lithofacies requires the simultaneous adjustment of stress sensitivity data.

12. A simulation system for pore-scale shale oil elastic development process, using a simulation method for pore-scale shale oil elastic development process as described in any one of claims 1 to 11, characterized in that: The simulation system comprises: The module for acquiring the natural pore structure plate is used to perform scanning electron microscope analysis on shale samples to obtain high-resolution pore structure photos of real cores, select representative positions from the pore structure photos, extract and depict the pore structure, and obtain the natural pore structure plate of the shale core; A two-dimensional pore structure diagram visualization simulation module is used to import the natural pore structure diagram into Comsol software, and simultaneously add primary fractures and random secondary fractures to simulate artificial fractures, so as to complete a two-dimensional pore structure diagram of visualization simulation; The module for setting the curve of fluid equivalent density versus pressure is used to consider the macro porosity stress sensitivity, calculate the fluid density equivalently according to the mass conservation principle to characterize the porosity stress sensitivity, and set the curve of fluid equivalent density versus pressure; The module for setting the curve of fluid equivalent viscosity changing with pressure is used to consider the macroscopic permeability stress sensitivity, calculate the microscopic fluid viscosity according to the principle of fluid similarity to characterize the permeability stress sensitivity, and set the curve of fluid equivalent viscosity changing with pressure; The module for setting the curve of equivalent contact angle variation with pressure is used to consider the stress sensitivity of macro porosity, calculate the contact angle based on the similarity and equivalent calculation of capillary force to characterize the influence of pressure change on pore structure and capillary force, and set the curve of equivalent contact angle variation with pressure; The initial condition and fluid property setting module is used to set the initial conditions and fluid properties, select the laminar flow-phase field model, and set the initial fluid distribution, initial pressure, fluid compressibility, wetted wall, interfacial tension, boundary conditions, mesh generation, and time step parameters in sequence; Fracturing process simulation module, used for fracturing process simulation, closing the outlet, injecting fracturing fluid at high pressure at the inlet, and analyzing 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, close the inlet to simulate the well shut-in process, and analyze the imbibition mechanism through the change of fluid distribution; The oil production process simulation module is used to simulate the oil production process, reduce the outlet pressure to simulate the elastic development process, and analyze the changes in fluid distribution, water content of the produced fluid, and the degree of recovery; Data processing module, used for data processing, calculating fluid distribution, oil production rate, water content and flowback rate parameters at different times based on pressure, density and surface integral; The imbibition oil production contribution rate calculation module is used to compare the recovery degree without imbibition and calculate the imbibition oil production contribution rate.

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