Method and system for researching influence of pore scale wettability on shale oil imbibition

Abstract

The invention provides a method and system for researching the influence of pore scale wettability on shale oil imbibition. A method for simulating the pore scale high-pressure imbibition effect based on a Comsol software laminar flow-phase field-compressible fluid model is established; establishing a real core pore structure model based on a shale core scanning electron microscope picture; according to pore type identification, effective characterization of complex wettability is realized by changing contact angles of different pores; the accurate evaluation of the influence of oleophylic, hydrophilic, mixed wetting and other conditions on the imbibition effect is realized.

Description

Technical Field

[0001] The present invention relates to the technical field of unconventional oil and gas production, and in particular to a method and system for studying the effect of pore-scale wettability on shale oil imbibition. Background Art

[0002] Usually, low permeability reservoirs are developed by rapid flowback after fracturing to reduce the damage of fracturing fluid. However, the production practice of multiple shale oil and gas wells in multiple basins in China has proved that imbibition promotes the entry of fracturing fluid into the formation to replace shale oil and gas, thereby reducing the elastic development water content and flowback rate, and increasing the cumulative oil production and recovery. Studies have shown that hydrophilic wetting is the basis for imbibition. Shale reservoirs have developed micro-nano pores, inorganic pores and organic pores coexist, and wettability is complex. The impact of wettability on imbibition is not in-depth, and there is a lack of technical methods to effectively evaluate the impact of wettability.

[0003] Core-scale imbibition experiments are the main way to study the mechanism of imbibition and evaluate the impact of imbibition. Shale oil reservoirs develop inorganic pores and organic pores. The wettability of inorganic pores is hydrophilic, while the wettability of organic pores is oil-wet. Due to the different pore structures of shales and the large differences in wettability of different pores, the core imbibition experiment has poor comparative evaluation of the impact of wettability on imbibition and is difficult to explain the impact mechanism. The pore-scale imbibition mechanism is mainly realized through microfluidic experiments and microscopic simulations. The two methods can intuitively display the pore-scale imbibition process and compare the effects of different parameters on imbibition, providing important support for in-depth interpretation of the imbibition mechanism.

[0004] At present, there are still some shortcomings in the evaluation of the effect of wettability on imbibition, which are as follows: (1) The core experiment is not very comparable, and it is difficult to accurately evaluate the effect of wettability and mixed wetting on imbibition; (2) Microfluidic experiments are greatly restricted by experimental equipment and conditions, and the wettability of pore models is difficult to accurately and freely control; (3) Microfluidic experiments and simulation studies use an ideal pore structure conceptual model, which is difficult to reflect the actual shale pore structure and wettability; (4) There is a lack of evaluation methods for the wettability effect under the conditions of mixed wetting of organic pores and inorganic pores. Summary of the invention

[0005] In view of the above problems, the present invention is proposed to provide a method and system for studying the effect of pore-scale wettability on shale oil imbibition that overcomes the above problems or at least partially solves the above problems.

[0006] According to one aspect of the present invention, a method for studying the effect of pore-scale wettability on shale oil imbibition is provided, wherein the determination method comprises:

[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: import the natural pore structure map into the software, and add the main fractures and random secondary fractures to simulate the artificial fractures, so as to complete the two-dimensional pore structure map of the visual simulation;

[0009] Step S3: Considering the influence of fluid compressibility, setting density and viscosity change curves of fracturing fluid and shale oil under different pressures;

[0010] Step S4: setting the wetting wall of the natural pore structure, assigning contact angles of different pores according to the pore types in the scanning electron microscope photograph to characterize the wettability;

[0011] Step S5: Set initial conditions and fluid properties, select the laminar flow-phase field model, and set parameters in sequence;

[0012] Step S6: simulating the fracturing fluid injection, imbibition and flowback processes according to the boundary conditions, and analyzing the imbibition mechanism through the change of fluid distribution;

[0013] Step S7: Data processing, comparing the effect of wettability on imbibition.

[0014] Optionally, the parameters set in sequence in step S5 specifically include: initial fluid distribution, initial pressure, interface tension, boundary conditions, grid division, and time step parameters.

[0015] Optionally, the step S7: data processing, comparing the effect of wettability on imbibition specifically includes: data processing, calculating parameters such as fluid saturation, water content and return flow rate at different times according to pressure, density and surface integral, and comparing the effect of wettability on imbibition.

[0016] 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.

[0017] Optionally, during the shale reservoir fracturing development in step S3, there is a large difference between the injection pressure and the formation pressure, and the effect of the fluid compressibility on the fluid viscosity and density is considered, while the effect of stress sensitivity is considered to improve the simulation accuracy.

[0018] Optionally, the wettability in step S4 is a key parameter affecting the imbibition effect, and the wettability is characterized by the contact angle, and different contact angles are set to compare the effects of the wettability;

[0019] The mixed wetting phenomenon is obvious in shale oil reservoirs. The contact angle assignment of different types of pores directly reflects the influence of mixed wetting by identifying organic pores and inorganic pores using scanning electron microscopy.

[0020] Optionally, in step S5, the Comsol software laminar flow-phase field-compressible fluid model is selected, the natural pore structure is completely filled with oil, the artificial fractures are completely filled with water, and the model inlet and outlet are the same path.

[0021] Optionally, in step S6, the fracturing fluid injection, imbibition and flowback processes are simulated, and the inlet pressure is higher than the initial pressure to ensure the injection of the fracturing fluid, while the constant pressure injection and variable pressure injection methods are selected.

[0022] Optionally, in step S7, the fluid distribution, oil production rate, water content and flowback rate parameters at different times are calculated according to the pressure, fluid viscosity and surface integral, and the producing law and recovery degree are analyzed;

[0023] Calculation of fracturing fluid injection volume:

[0024] V f =ρ w1i *V*S wi

[0025] Where V f ——Total injection volume of fracturing fluid, m 2 ρ w1i ——Fracturing fluid density when injection is stopped, Kg / m 3 ; V——total area of ​​the model, m 2 ; S wi Saturation when fracturing fluid injection stops, %;

[0026] Moisture content calculation:

[0027]

[0028] In the formula, f w ——Water content of output fluid, %; ρ w1m , w1n ——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 ——Density of shale oil at time m and n, Kg / m 3 ; S om , S on --—Shale oil saturation at time m and n, %;

[0029] Calculation of flowback rate:

[0030]

[0031] In the formula, β is the flowback rate, %; ρ w1t ——Density of fracturing fluid at time t, Kg / m 3 ; S wt ——Fracturing fluid saturation at time t, %.

[0032] Calculation of extraction degree:

[0033]

[0034] Where, R is the degree of recovery, %; ρ o1i ——Shale oil density when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops, %; ρ o1t ——Density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t, %.

[0035] The present invention also provides a research system for the influence of pore-scale wettability on shale oil imbibition, and the research method for the influence of pore-scale wettability on shale oil imbibition described above is applied, and the determination system comprises:

[0036] 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;

[0037] Visual simulation module, used to import natural pore structure diagram into the software, and add primary fractures and random secondary fractures to simulate artificial fractures, thus completing the two-dimensional pore structure diagram of visual simulation;

[0038] Density and viscosity change curve setting module, used to consider the influence of fluid compressibility and set the density and viscosity change curves of fracturing fluid and shale oil under different pressures;

[0039] The contact angle assignment characterization module is used to set the wetting wall of the natural pore structure and assign contact angles of different pores to characterize wettability according to the pore types in the scanning electron microscope photos;

[0040] The initial condition setting module is used to set the initial conditions and fluid properties, select the laminar flow-phase field model, and set the parameters in sequence;

[0041] The imbibition mechanism analysis module is used to simulate the fracturing fluid injection, imbibition and flowback process according to boundary conditions, and analyze the imbibition mechanism through the change of fluid distribution;

[0042] Data processing module, used for data processing and comparison of the effect of wettability on imbibition.

[0043] The present invention provides a method and system for studying the influence of pore-scale wettability on shale oil imbibition, establishes a method for simulating pore-scale high-pressure imbibition based on a laminar flow-phase field-compressible fluid model of Comsol software; establishes a real core pore structure model based on scanning electron microscope photos of shale cores; realizes effective characterization of complex wettability by changing the contact angles of different pores according to pore type identification; and realizes accurate evaluation of the influence of oil-wetting, water-wetting, mixed wetting and other conditions on imbibition.

[0044] 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

[0045] 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.

[0046] Figure 1 A flow chart of a method for studying the effect of pore-scale wettability on shale oil imbibition provided in an embodiment of the present invention;

[0047] Figure 2 A scanning electron microscope and a two-dimensional pore structure model diagram of a shale core provided in an embodiment of the present invention;

[0048] Figure 3 It is a diagram of a hydrophilic and uniform wetting model of a shale core pore structure in a specific embodiment of the present invention;

[0049] Figure 4 is a saturation field diagram of a hydrophilic wetting fluid in a specific embodiment of the present invention;

[0050] Figure 5 is a saturation field diagram of an oleophilic wetting fluid in a specific embodiment of the present invention;

[0051] Figure 6 is a mixed wetting model diagram of shale core pore structure in a specific embodiment of the present invention;

[0052] Figure 7 It is a saturation field diagram of a mixed wetting fluid in a specific embodiment of the present invention. DETAILED DESCRIPTION

[0054] 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.

[0055] 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.

[0056] The technical solution of the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments.

[0057] Embodiment 1:

[0058] In one embodiment 1 of the present invention, Figure 1 This is a flow chart of a research method for the effect of pore-scale wettability on shale oil imbibition of the present invention, including: establishing a two-dimensional real shale core pore structure model based on scanning electron microscope images, setting basic parameters and initial conditions based on Comsol software, setting contact angles of different pores to characterize wettability, simulating high-pressure imbibition processes under different wetting conditions, and dynamically comparing and analyzing the effect of wettability on imbibition. Specifically, it includes the following steps:

[0059] Step 1) A rectangular laminar structure with a width of 700 μm and a height of 650 μm is selected from a scanning electron microscope high-resolution pore structure photograph of a shale sample, and a natural laminar pore structure plate of the shale core is extracted using CAD software, wherein the pore diameter mainly ranges from 0.1 to 10 μm;

[0060] 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 2 As shown;

[0061] Step 3) Considering the influence of fluid compressibility, density and viscosity change curves of fracturing fluid and shale oil under different pressures are set;

[0062] Step 4) Setting the wetting wall of the natural pore structure, the contact angle is 45°, and the hydrophilic wetting is as follows: Figure 3 As shown;

[0063] Step 5) 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 as 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;

[0064] Step 6) Fracturing process simulation, closing the outlet, injecting fracturing fluid at an inlet high pressure of 80 MPa, simulation time 20 ms, time step 1 ms; well shut-in process simulation, closing the inlet to simulate the well shut-in process, simulation time 300 ms, time step 1 ms; oil production process simulation, step-down the outlet pressure to 20 MPa to simulate the elastic development process, simulation time 120 ms, time step 1 ms;

[0065] Step 7) Data processing: Calculate fluid saturation, water content, flowback rate and other parameters at different times based on pressure, density and surface integral. The saturation field is as follows: Figure 4 As shown in the figure, the recovery rate of elastic development is 24% and the flowback rate is 61%.

[0066] Calculation of fracturing fluid injection volume:

[0067] V f =ρ w1i *V*S wi

[0068] Where V f ——Total injection volume of fracturing fluid, m 2 ρ w1i ——Fracturing fluid density when injection is stopped, Kg / m 3 ; V——total area of ​​the model, m 2 ; S wi ——Saturation when fracturing fluid injection stops, %.

[0069] Moisture content calculation:

[0070]

[0071] In the formula, f w ——Water content of output fluid, %; ρ w1m , w1n ——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 ——Density of shale oil at time m and n, Kg / m 3 ; S om , S on ——Shale oil saturation at time m and n, %.

[0072] Calculation of flowback rate:

[0073]

[0074] In the formula, β is the flowback rate, %; ρ w1t ——Density of fracturing fluid at time t, Kg / m 3 ; S wt ——Fracturing fluid saturation at time t, %.

[0075] Calculation of extraction degree:

[0076]

[0077] Where, R is the degree of recovery, %; ρ o1i ——Shale oil density when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops, %; ρ o1t ——Density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t, %.

[0078] Embodiment 2:

[0079] In an embodiment 2 of the present invention, based on the embodiment 1, the contact angle is changed to simulate the effect of lipophilic wetting on the absorption effect. Specifically, the following steps are included:

[0080] Step 1) A rectangular laminar structure with a width of 700 μm and a height of 650 μm is selected from a scanning electron microscope high-resolution pore structure photograph of a shale sample, and a natural laminar pore structure plate of the shale core is extracted using CAD software, wherein the pore diameter mainly ranges from 0.1 to 10 μm;

[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 2 As shown;

[0082] Step 3) Considering the influence of fluid compressibility, density and viscosity change curves of fracturing fluid and shale oil under different pressures are set;

[0083] Step 4) setting the wetting wall of the natural pore structure, the contact angle is 135°, and the lipophilic wetting;

[0084] Step 5) 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 as 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;

[0085] Step 6) Fracturing process simulation, closing the outlet, injecting fracturing fluid at an inlet high pressure of 80 MPa, simulation time 20 ms, time step 1 ms; well shut-in process simulation, closing the inlet to simulate the well shut-in process, simulation time 300 ms, time step 1 ms; oil production process simulation, step-down the outlet pressure to 20 MPa to simulate the elastic development process, simulation time 120 ms, time step 1 ms;

[0086] Step 7) Data processing: Calculate parameters such as fluid saturation, water content and flowback rate at different times based on pressure, density and surface integral, such as Figure 5 As shown in the figure, the recovery rate of elastic development is 15% and the flowback rate is 97%.

[0087] Embodiment 3:

[0088] In one embodiment 2 of the present invention, based on the example 1, a mixed wetting model is established according to the distribution characteristics of organic pores and inorganic pores in shale to simulate the influence of mixed wetting on imbibition. Specifically, the following steps are included:

[0089] Step 1) A rectangular laminar structure with a width of 700 μm and a height of 650 μm is selected from a scanning electron microscope high-resolution pore structure photograph of a shale sample, and a natural laminar pore structure plate of the shale core is extracted using CAD software, wherein the pore diameter mainly ranges from 0.1 to 10 μm;

[0090] 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 2 As shown;

[0091] Step 3) Considering the influence of fluid compressibility, density and viscosity change curves of fracturing fluid and shale oil under different pressures are set;

[0092] Step 4) According to the distribution of organic and inorganic pores in shale, the organic pores are set to be oil-wetting with a contact angle of 135°, and the inorganic pores are set to be hydrophilic with a contact angle of 45°. Figure 6 As shown;

[0093] Step 5) 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 as 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;

[0094] Step 6) Fracturing process simulation, closing the outlet, injecting fracturing fluid at an inlet high pressure of 80 MPa, simulation time 20 ms, time step 1 ms; well shut-in process simulation, closing the inlet to simulate the well shut-in process, simulation time 300 ms, time step 1 ms; oil production process simulation, step-down the outlet pressure to 20 MPa to simulate the elastic development process, simulation time 120 ms, time step 1 ms;

[0095] Step 7) Data processing: Calculate parameters such as fluid saturation, water content and flowback rate at different times based on pressure, density and surface integral, such as Figure 7 As shown in the figure, the recovery rate of elastic development is 19% and the flowback rate is 84%.

[0096] Beneficial effects: (1) A method for simulating high-pressure imbibition at the pore scale based on the Comsol software laminar flow-phase field-compressible fluid model was established; (2) A real core pore structure model was established based on scanning electron microscope photos of shale cores; (3) According to pore type identification, effective characterization of complex wettability was achieved by changing the contact angles of different pores; (4) An accurate evaluation of the effects of oil-wetting, water-wetting, and mixed wetting conditions on imbibition was achieved.

[0097] 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 studying the effect of pore-scale wettability on shale oil imbibition, characterized in that: The determination 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: import the natural pore structure map into the software, and add the main fractures and random secondary fractures to simulate the artificial fractures, so as to complete the two-dimensional pore structure map of the visual simulation; Step S3: Considering the influence of fluid compressibility, setting density and viscosity change curves of fracturing fluid and shale oil under different pressures; Step S4: setting the wetting wall of the natural pore structure, assigning contact angles of different pores according to the pore types in the scanning electron microscope photograph to characterize the wettability; Step S5: Set initial conditions and fluid properties, select the laminar flow-phase field model, and set parameters in sequence; Step S6: simulating the fracturing fluid injection, imbibition and flowback processes according to the boundary conditions, and analyzing the imbibition mechanism through the change of fluid distribution; Step S7: Data processing, comparing the effect of wettability on imbibition.

2. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: The parameters set in step S5 include: initial fluid distribution, initial pressure, interface tension, boundary conditions, grid division, and time step parameters.

3. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: The step S7: data processing, comparing the effect of wettability on imbibition specifically includes: data processing, calculating parameters such as fluid saturation, water content and flowback rate at different times according to pressure, density and surface integral, and comparing the effect of wettability on imbibition.

4. The method for studying the effect of pore-scale wettability on shale oil imbibition 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.

5. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: During the shale reservoir fracturing development in step S3, there is a large difference between the injection pressure and the formation pressure. The influence of the fluid compressibility on the fluid viscosity and density is considered, and the influence of stress sensitivity is considered to improve the simulation accuracy.

6. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: The wettability in step S4 is a key parameter that affects the imbibition effect. The wettability is characterized by the contact angle, and different contact angles are set to compare the effects of the wettability. The mixed wetting phenomenon is obvious in shale oil reservoirs. The contact angle assignment of different types of pores directly reflects the influence of mixed wetting by identifying organic pores and inorganic pores using scanning electron microscopy.

7. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: In step S5, the Comsol software laminar flow-phase field-compressible fluid model is selected, the natural pore structure is completely filled with oil, the artificial fractures are completely filled with water, and the model inlet and outlet are the same path.

8. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: In step S6, the fracturing fluid injection, imbibition and flowback process are simulated, and the inlet pressure is higher than the initial pressure to ensure the injection of the fracturing fluid. At the same time, the constant pressure injection and variable pressure injection methods are selected.

9. The method for studying the effect of pore-scale wettability on shale oil imbibition according to claim 1, characterized in that: In step S7, the fluid distribution, oil production rate, water content and flowback rate parameters at different times are calculated according to the pressure, fluid viscosity and surface integral, and the production law and recovery degree are analyzed; 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 ——Fracturing fluid density 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 ——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 ——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 ——Density of fracturing fluid at time t, Kg / m 3 ; S wt ——Fracturing fluid saturation at time t, %. Calculation of extraction degree: Where, R is the degree of recovery, %; ρ o1i ——Shale oil density when fracturing injection stops, Kg / m 3 ; S oi ——Shale oil saturation when fracturing injection stops, %; ρ o1t ——Density of shale oil at time t, Kg / m 3 ; S ot ——Shale oil saturation at time t, %.

10. A system for studying the effect of pore-scale wettability on shale oil imbibition, using a method for studying the effect of pore-scale wettability on shale oil imbibition as described in any one of claims 1 to 9, characterized in that: The determination 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; Visual simulation module, used to import natural pore structure diagram into the software, and add primary fractures and random secondary fractures to simulate artificial fractures, thus completing the two-dimensional pore structure diagram of visual simulation; Density and viscosity change curve setting module, used to consider the influence of fluid compressibility and set the density and viscosity change curves of fracturing fluid and shale oil under different pressures; The contact angle assignment characterization module is used to set the wetting wall of the natural pore structure and assign contact angles of different pores to characterize wettability according to the pore types in the scanning electron microscope photos; The initial condition setting module is used to set the initial conditions and fluid properties, select the laminar flow-phase field model, and set the parameters in sequence; The imbibition mechanism analysis module is used to simulate the fracturing fluid injection, imbibition and flowback process according to boundary conditions, and analyze the imbibition mechanism through the change of fluid distribution; Data processing module, used for data processing and comparison of the effect of wettability on imbibition.

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