A method and system for studying the influence of pore-scale wettability on shale oil imbibition

Abstract

The application provides a research method and system for the influence of pore-scale wettability on shale oil imbibition, and establishes a method for simulating pore-scale high-pressure imbibition based on a laminar flow-phase field-compressible fluid model of Comsol software; a real core pore structure model is established based on a scanning electron microscope photo of a shale core; according to pore type identification, effective characterization of complex wettability is realized by changing the contact angles of different pores; and accurate evaluation of the influence of conditions such as oleophilicity, hydrophilicity and mixed wettability on imbibition is realized.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of unconventional oil and gas exploitation, and particularly relates to a method and system for researching influence of pore-scale wettability on shale oil imbibition. BACKGROUND

[0002] Generally, low-permeability oil reservoirs are developed by using the method of rapid flowback after fracturing to reduce fracturing fluid damage. However, it is proved by the production practice of many shale oil and gas wells in multiple basins in China that imbibition promotes fracturing fluid to enter the formation to displace and produce shale oil and gas, thereby reducing the water content and flowback rate of elastic development, and improving cumulative oil production and recovery degree. Studies show that hydrophilic wettability is the basis for imbibition, shale reservoirs develop micro-nano pores, inorganic pores and organic pores coexist, and the wettability is complex. The influence of wettability on imbibition is not deep, and there is a lack of effective technical method for evaluating the influence of wettability.

[0003] Core-scale imbibition experiment is the main way to study the mechanism of imbibition and evaluate the influence of imbibition. Shale oil reservoirs develop inorganic pores and organic pores, the wettability of inorganic pores is hydrophilic, and the wettability of organic pores is oleophilic. Because the pore structures of shale are different and the wettability of different pores is greatly different, the core imbibition experiment for evaluating the influence of wettability on imbibition has poor comparability and is difficult to explain the influence mechanism. The mechanism of pore-scale imbibition is mainly realized through microfluidic experiment and microsimulation, both of which can directly show the process of pore-scale imbibition and compare the influence of different parameters on imbibition, thereby providing important support for in-depth explanation of the mechanism of imbibition.

[0004] At present, there are still some deficiencies in the evaluation of the influence of wettability on imbibition, which are specifically as follows: (1) the core experiment has poor comparability, and it is difficult to accurately evaluate the influence of wettability and mixed wettability on imbibition; (2) the microfluidic experiment is greatly limited by experimental equipment and conditions, and the wettability of the pore model is difficult to accurately and freely control; (3) the microfluidic experiment and simulation research use ideal pore structure conceptual model, and it is difficult to reflect the real shale pore structure and wettability; (4) there is a lack of evaluation method for the influence of wettability under the condition of mixed wettability of organic pores and inorganic pores. SUMMARY

[0005] In view of the above problems, the present application is proposed to provide a method and system for researching the influence of pore-scale wettability on shale oil imbibition to overcome the above problems or at least partially solve the above problems.

[0006] According to one aspect of the present application, there is provided a method for researching the influence of pore-scale wettability on shale oil imbibition, the method comprising:

[0007] Step S1: scanning electron microscopy analysis of shale samples to obtain high-resolution pore structure photos of real cores, selecting representative positions from the pore structure photos, and extracting the pore structure to obtain a natural pore structure atlas of the shale core;

[0008] Step S2: importing the natural pore structure atlas into the software, adding main cracks and random secondary cracks to simulate artificial fractures, and completing a two-dimensional pore structure atlas for visual simulation;

[0009] Step S3: considering the influence of fluid compressibility, setting the density and viscosity variation curves of fracturing fluid and shale oil at different pressures;

[0010] Step S4: setting the wet wall of the natural pore structure, and assigning values to the contact angles of different pores to represent wettability according to the pore types in the scanning electron microscope photos;

[0011] Step S5: setting the initial conditions and fluid properties, selecting the laminar flow-phase field model, and sequentially setting the parameters;

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

[0013] Step S7: data processing, and comparing the influence of wettability on imbibition.

[0014] Optionally, the sequentially setting parameters in step S5 specifically includes: initial fluid distribution, initial pressure, interfacial tension, boundary conditions, grid division, and time step parameters.

[0015] Optionally, the step S7: data processing, and comparing the influence of wettability on imbibition specifically includes: data processing, calculating fluid saturation, water cut, and flowback rate parameters at different times according to pressure, density, and surface area, and comparing the influence of wettability on imbibition.

[0016] Optionally, the step S1 is based on the high-resolution pore structure of the real shale core obtained by scanning electron microscopy, and a two-dimensional natural pore structure model is established by using CAD to extract connected pores.

[0017] Optionally, in the step S3, during the fracturing development of the shale reservoir, the injection pressure and the formation pressure differ greatly, the influence of fluid compressibility on the viscosity and density of the fluid is considered, and the influence of stress sensitivity is also considered to improve the simulation accuracy.

[0018] Optionally, the wettability is a key parameter affecting imbibition in the step S4, the wettability is represented by the contact angle, and the influence of different contact angles on wettability is compared;

[0019] The mixed-wetting phenomenon is obvious in shale oil reservoirs. According to the scanning electron microscope, organic pores and inorganic pores are identified, and the contact angle of different types of pores is directly reflected by the mixed-wetting influence.

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

[0021] Optionally, in the step S6, the fracturing fluid injection, imbibition and flowback process is simulated, the inlet pressure is higher than the initial pressure, the fracturing fluid injection is ensured, and the constant pressure injection and variable pressure injection modes are selected.

[0022] Optionally, in the step S7, according to the pressure, fluid viscosity and surface area, the fluid distribution, oil production rate, water cut and flowback rate parameters at different times are calculated, and the production rule and recovery degree are analyzed.

[0023] Fracturing fluid injection amount calculation:

[0024] V f = ρ w1i *V*S wi

[0025] In the formula, V f is the total injection amount of fracturing fluid, Kg; ρ w1i is the fracturing fluid density when stopping injection, Kg / m 3 ; V is the total volume of the model, m 3 ; S wi is the saturation when stopping injection of fracturing fluid, %.

[0026] Water cut calculation:

[0027]

[0028] In the formula, f w is the produced liquid water cut, %; ρ w1m and ρ w1n are the densities of fracturing fluid at m and n times, Kg / m 3 ; S wm and S wn are the saturations of fracturing fluid at m and n times, %; ρ o1m and ρ o1n are the densities of shale oil at m and n times, Kg / m 3 ; S om and S on are the saturations of shale oil at m and n times, %.

[0029] Flowback rate calculation:

[0030]

[0031] In the formula, β is a flowback rate, %; ρ is a shale oil density, Kg / m w1t t is a time, Kg / m 3 ; S wt t is a time, %;

[0032] The recovery degree is calculated as follows:

[0033]

[0034] In the formula, R is a recovery degree, %; ρ is a shale oil density, Kg / m o1i t is a time, Kg / m 3 ; S oi t is a time, %; ρ is a shale oil density, Kg / m o1t t is a time, Kg / m 3 ; S ot t is a time, %.

[0035] The application further provides a research system for the influence of pore-scale wettability on shale oil imbibition, which applies the research method for the influence of pore-scale wettability on shale oil imbibition, and the research system comprises the following modules:

[0036] A natural pore structure chart obtaining module is used for obtaining a high-resolution pore structure photo of a real core by performing scanning electron microscope analysis on a shale sample, selecting a representative position from the pore structure photo, and extracting and describing the pore structure to obtain a natural pore structure chart of the shale core.

[0037] A visual simulation module is used for importing the natural pore structure chart into software, adding a main fracture and random secondary fractures to simulate artificial fractures, and completing a two-dimensional pore structure chart of visual simulation.

[0038] A density and viscosity change curve setting module is used for considering the influence of fluid compressibility, and setting the density and viscosity change curves of the fracturing fluid and the shale oil under different pressures.

[0039] A contact angle assignment and characterization module is used for setting the wet wall of the natural pore structure, assigning and characterizing the wettability of different pores according to the pore types of the scanning electron microscope photos.

[0040] An initial condition setting module is used for setting the initial conditions and fluid properties, selecting a laminar flow-phase field model, and sequentially setting parameters.

[0041] An imbibition mechanism analysis module is used for simulating the fracturing fluid injection, imbibition and flowback process according to the boundary conditions, and analyzing the imbibition mechanism through the fluid distribution change.

[0042] A data processing module is used for data processing to compare the influence of wettability on imbibition.

[0043] The application provides a method and system for researching influence of pore-scale wettability on shale oil imbibition, and establishes a method for simulating pore-scale high-pressure imbibition based on a laminar flow-phase field-compressible fluid model of Comsol software; a real core pore structure model is established based on a scanning electron microscope photograph of a shale core; effective characterization of complex wettability is realized by changing contact angles of different pores according to pore type identification; and accurate evaluation of influences of oil-wet, water-wet and mixed-wet conditions on imbibition is realized.

[0044] The above description is only a summary of the technical scheme of the application, in order to more clearly understand the technical means of the application, the application can be implemented according to the content of the specification, and in order to make the above and other purposes, characteristics and advantages of the application more obvious and easy to understand, the following specific embodiments of the application are described. BRIEF DESCRIPTION OF DRAWINGS

[0045] In order to more clearly illustrate the technical scheme of the embodiments of the application, the following will briefly introduce the drawings needed to be used in the embodiment description. Obviously, the drawings in the following description are only some embodiments of the application, and for those skilled in the art, other drawings can also be obtained without creative labor on the basis of these drawings.

[0046] Figure 1 A flowchart of a method for researching influence of pore-scale wettability on shale oil imbibition is provided for the embodiments of the application;

[0047] Figure 2 A scanning electron microscope and a two-dimensional pore structure model diagram of a shale core pore structure are provided for the embodiments of the application;

[0048] Figure 3 A shale core pore structure hydrophilic uniform wettability model diagram in a specific embodiment of the application;

[0049] Figure 4 A hydrophilic wettability fluid saturation field diagram in a specific embodiment of the application;

[0050] Figure 5 An oil-wet wettability fluid saturation field diagram in a specific embodiment of the application;

[0051] Figure 6 A shale core pore structure mixed wettability model diagram in a specific embodiment of the application;

[0052] Figure 7 A mixed wettability fluid saturation field diagram in a specific embodiment of the application. DETAILED DESCRIPTION

[0053] Exemplary embodiments of the present disclosure will be described in greater detail below with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it is understood that the present disclosure can be embodied in various forms without being limited by the embodiments set forth herein. Rather, these embodiments are provided so that the present disclosure will be thorough and complete, and will fully convey the scope of the present disclosure to those skilled in the art.

[0054] The terms "include" and "have" and any variations thereof in the specification, claims and drawings of the present disclosure are intended to cover the non-exclusive inclusion, for example, the inclusion of a series of steps or units.

[0055] The technical solutions of the present application will be described in further detail below in conjunction with the drawings and examples.

[0056] Example 1

[0057] In an embodiment 1 of the present application, Figure 1 is a flow chart of a method for studying the influence of pore-scale wettability on shale oil imbibition, which comprises: 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, setting contact angles of different pores to represent wettability, simulating high-pressure imbibition process under different wettability conditions, and dynamically comparing and analyzing the influence of wettability on imbibition. Specifically, it includes the following steps:

[0058] Step 1) Select a rectangular lamellar structure with a width of 700 μm and a height of 650 μm from the scanning electron microscope high-resolution pore structure picture of the shale sample, and use CAD software to extract the natural lamellar pore structure plate of the shale core. The pore diameter mainly ranges from 0.1 to 10 μm;

[0059] 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 random secondary cracks on the left side of the natural pore structure, complete the visualized two-dimensional pore structure plate, as shown in Figure 2 ;

[0060] Step 3) Considering the influence of fluid compressibility, set the density and viscosity variation curves of fracturing fluid and shale oil under different pressures;

[0061] Step 4) Set the wettability wall of the natural pore structure, and the contact angle is 45°, which is hydrophilic, as shown in Figure 3 ;

[0062] Step 5) Initial time, saturated oil phase in natural pore structure, saturated water phase in artificial fracture; in combination with the 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; the initial pressure of the system is constant at 50 MPa;

[0063] Step 6) Fracturing process simulation, close the outlet, inject fracturing fluid at a high pressure of 80 MPa at the inlet, simulation time 20 ms, time step 1 ms; soak process simulation, close the inlet to simulate the 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;

[0064] Step 7) Data processing, calculate the fluid saturation, water cut and flowback rate at different times according to the pressure, density and surface area, and the saturation field is shown in Figure 4 . The recovery degree of elastic development is 24%, and the flowback rate is 61%.

[0065] Fracturing fluid injection amount calculation:

[0066] V f = ρ w1i *V*S wi

[0067] In the formula, V f is the total injection amount of fracturing fluid, Kg; ρ w1i is the density of fracturing fluid when injection is stopped, Kg / m 3 ; V is the total volume of the model, m 3 ; S wi is the saturation when injection of fracturing fluid is stopped, %.

[0068] Water cut calculation:

[0069]

[0070] In the formula, f w is the water cut of produced liquid, %; ρ w1m and ρ w1n are the densities of fracturing fluid at times m and n, Kg / m 3 ; S wm and S wn are the saturations of fracturing fluid at times m and n, %; ρ o1m and ρ o1n are the densities of shale oil at times m and n, Kg / m 3 ; S om and S on are the saturations of shale oil at times m and n, %.

[0071] Flowback rate calculation:

[0072]

[0073] wherein β is a flowback rate, %; p is a shale oil density, Kg / m w1t — density of fracturing fluid at time t, Kg / m 3 ; S wt — saturation of fracturing fluid at time t, %.

[0074] Degree of recovery calculation:

[0075]

[0076] wherein R is a degree of recovery, %; p is a shale oil density, Kg / m o1i — density of fracturing fluid at time t, Kg / m 3 ; S oi — saturation of fracturing fluid at time t, %. o1t — density of fracturing fluid at time t, Kg / m 3 ; S ot — saturation of fracturing fluid at time t, %.

[0077] Example 2:

[0078] In one embodiment 2 of the present application, the influence of oil-wetting on imbibition is simulated by changing the contact angle based on Example 1. The specific steps include the following:

[0079] Step 1) A rectangular lamella structure with a width of 700 μm and a height of 650 μm is selected from the scanning electron microscope high-resolution pore structure photo of the shale sample, and a natural lamella pore structure template of the shale core is extracted by using CAD software, with a pore diameter mainly ranging from 0.1 to 10 μm;

[0080] Step 2) The extracted natural pore structure template is imported into Comsol software, and a rectangular simulated artificial fracture with a width of 50 μm and a height of 650 μm and random secondary cracks are added to the left side of the natural pore structure to complete the visual simulation of the two-dimensional pore structure template, as shown in Figure 2 ;

[0081] Step 3) The influence of fluid compressibility is considered, and the density and viscosity variation curves of the fracturing fluid and the shale oil under different pressures are set;

[0082] Step 4) The wetting wall of the natural pore structure is set, with a contact angle of 135° and oil-wetting;

[0083] Step 5) The initial moment, the natural pore structure is saturated with oil phase, and the artificial fracture is saturated with water phase; in combination with the 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 constant at 50 MPa;

[0084] Step 6) Fracturing process simulation, close the outlet, inject fracturing fluid at a high pressure of 80 MPa at the inlet, simulate for 20 ms, and the time step is 1 ms; soak process simulation, close the inlet to simulate the shut-in process, simulate for 300 ms, and the time step is 1 ms; oil production process simulation, step down the outlet pressure to 20 MPa to simulate the elastic development process, simulate for 120 ms, and the time step is 1 ms;

[0085] Step 7) Data processing, calculate the fluid saturation, water cut and flowback rate at different moments according to the pressure, density and surface area, as shown in Figure 5 . The recovery degree of elastic development is 15%, and the flowback rate is 97%.

[0086] Example 3:

[0087] In one embodiment of the present application, based on example 1, a mixed wetting model is established according to the distribution characteristics of shale organic pores and inorganic pores to simulate the influence of mixed wetting on imbibition. It specifically includes the following steps:

[0088] Step 1) Select a rectangular lamellar structure with a width of 700 μm and a height of 650 μm from the scanning electron microscope high-resolution pore structure photo of the shale sample, and use CAD software to extract the natural lamellar pore structure template of the shale core, with a pore diameter mainly ranging from 0.1 to 10 μm;

[0089] Step 2) Import the extracted natural pore structure template into Comsol software, and add a rectangular simulated artificial fracture with a width of 50 μm and a height of 650 μm and random secondary cracks on the left side of the natural pore structure, to complete the visualization of the two-dimensional pore structure template, as shown in Figure 2 ;

[0090] Step 3) Considering the influence of fluid compressibility, set the density and viscosity variation curves of the fracturing fluid and shale oil at different pressures;

[0091] Step 4) According to the distribution of shale organic pores and inorganic pores, set the organic pores to be slightly oil-wet with a contact angle of 135°, and set the inorganic pores to be slightly water-wet with a contact angle of 45°, as shown in Figure 6 ;

[0092] Step 5) saturated oil phase in natural pore structure at initial moment, saturated water phase in artificial fracture; in combination with production practice, lower end of artificial fracture is set as inlet during fracturing process and outlet during oil production process, and water is injected at inlet end; initial pressure of system is constant pressure of 50 MPa;

[0093] Step 6) fracture process simulation, close outlet, inject fracturing fluid at high pressure of 80 MPa at inlet, simulation time is 20 ms, and time step is 1 ms; soak process simulation, close inlet to simulate shut-in process, simulation time is 300 ms, and time step is 1 ms; oil production process simulation, step down outlet pressure to 20 MPa to simulate elastic development process, simulation time is 120 ms, and time step is 1 ms;

[0094] Step 7) data processing, parameters such as fluid saturation, water cut and flowback rate at different moments are calculated according to pressure, density and surface area, as shown in Fig. 5. The recovery degree of elastic development is 19%, and the flowback rate is 84%. Figure 7

[0095] Beneficial effects: (1) a method for simulating pore-scale high-pressure imbibition based on Comsol software laminar flow-phase field-compressible fluid model is established; (2) a real core pore structure model is established based on shale core scanning electron microscope photos; (3) effective characterization of complex wettability is realized by changing contact angles of different pores according to pore type identification; (4) accurate evaluation of influence of conditions such as oleophilic, hydrophilic and mixed wettability on imbibition is realized.

[0096] The above detailed description further describes the purpose, technical scheme and beneficial effects of the present application, and it should be understood that the above is only a specific embodiment of the present application, and is not used to limit the protection scope of the present application, and any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included in the protection scope of the present application.​

Claims

1. A method for investigating the effect of pore-scale wettability on shale oil imbibition, characterized in that, The research method comprises: Step S1: shale samples are subjected to scanning electron microscope analysis to obtain high-resolution pore structure photos of real cores, representative positions are selected from the pore structure photos, and a natural pore structure portfolio of the shale core is extracted to depict the pore structure; Step S2: the natural pore structure portfolio is imported into software, and main cracks and random secondary cracks are added to simulate artificial fractures, thereby completing a two-dimensional pore structure portfolio of the visual simulation; Step S3: the influence of fluid compressibility is considered, and the density and viscosity variation curves of the fracturing fluid and shale oil under different pressures are set; Step S4: the wet wall of the natural pore structure is set, and the contact angle of different pores is valued according to the pore type of the scanning electron microscope photo to represent the wettability; Step S5: initial conditions and fluid properties are set, a laminar flow-phase field model is selected, and parameters are sequentially set; Step S6: the injection, imbibition and flowback processes of the fracturing fluid are simulated according to the boundary conditions, and the imbibition mechanism is analyzed through fluid distribution changes; Step S7: data processing is performed, and the influence of wettability on imbibition is compared.

2. The method of claim 1, wherein the method is characterized by: The sequential parameter setting in step S5 specifically comprises: initial fluid distribution, initial pressure, interfacial tension, boundary conditions, mesh division, and time step parameters.

3. The method of claim 1, wherein the method is characterized by: The data processing in step S7 specifically comprises: data processing, calculation of fluid saturation, water cut and flowback rate parameters at different times according to pressure, density and surface area, and comparison of the influence of wettability on imbibition.

4. The method of claim 1, wherein the method is characterized by: Step S1 is based on the high-resolution pore structure of the real shale core obtained by the scanning electron microscope, and a two-dimensional natural pore structure model is established by using CAD to extract connected pores.

5. The method of claim 1, wherein the method is characterized by: In step S3, during the fracturing development of the shale reservoir, the injection pressure and the formation pressure differ greatly, the influence of fluid compressibility on the viscosity and density of the fluid is considered, and the influence of stress sensitivity is also considered to improve the simulation accuracy.

6. The method of claim 1, wherein the method is characterized by: In step S4, wettability is a key parameter affecting imbibition, wettability is represented by a contact angle, and the influence of wettability is compared by setting different contact angles; The mixed wettability of the shale reservoir is obvious, and the contact angle of different types of pores is valued according to the organic pores and inorganic pores identified by the scanning electron microscope, which directly reflects the influence of mixed wettability.

7. The method of claim 1, wherein the method is characterized by: In step S5, the laminar flow-phase field-compressible fluid model of the Comsol software is selected, the natural pore structure is completely filled with oil, the artificial fracture is completely filled with water, and the model inlet and outlet are the same path.

8. The method of claim 1, wherein the method is characterized by: In step S6, the injection, imbibition and flowback processes of the fracturing fluid are simulated, the inlet pressure is higher than the initial pressure to ensure the injection of the fracturing fluid, and the constant pressure injection and variable pressure injection modes are selected.

9. The method of claim 1, wherein the method is characterized by: In step S7, fluid distribution, oil production rate, water cut and flowback rate parameters at different times are calculated according to pressure, fluid viscosity and surface area, and the production rule and recovery degree are analyzed; Fracturing fluid injection amount calculation: V f = p w1i * V * S wi where V f Total volume of fracturing fluid injected, m3 w1i Density of fracturing fluid at the time of stopping injection, Kg / m 3 V - total volume of the model, m 3 S wi Saturation at the time of stopping injection of fracturing fluid, % Water cut calculation: wherein f w — water cut of produced fluid, %; p w1m , p w1n — density of fracturing fluid at time m, n, Kg / m 3 ; S wm 、S wn — m, n moment of fracturing fluid saturation, %; p o1m , p o1n — density of shale oil at time m, n, Kg / m 3 ; S om 、S on — m, n, shale oil saturation, %; Flowback rate calculation: where β - flowback rate, %; p w1t - density of fracturing fluid at time t, Kg / m 3 ; S wt - saturation of fracturing fluid at time t, %; Recovery degree calculation: where R = percent recovery; p = pressure, kg / m o1i — density of shale oil at the time of stopping injection, kg / m 3 ; S oi — Shale oil saturation at the end of the frac injection, %; p o1t — density of shale oil at time t, Kg / m 3 ; S ot — saturation of shale oil at time t, %.

10. A system for studying the effect of pore-scale wettability on shale oil imbibition, applying the method for studying the effect of pore-scale wettability on shale oil imbibition according to any one of claims 1-9, characterized in that, The research system comprises: The natural pore structure template acquisition module is configured to perform scanning electron microscope analysis on the shale sample to obtain a high-resolution pore structure photo of the real core, select a representative position from the pore structure photo, and extract and depict the pore structure to obtain a natural pore structure template of the shale core; The visual simulation module is configured to import the natural pore structure template into software, add a main fracture and random secondary fractures to simulate artificial fractures, and complete a two-dimensional pore structure template for visual simulation; The density and viscosity change curve setting module is configured to consider the influence of fluid compressibility, and set the density and viscosity change curves of the fracturing fluid and the shale oil under different pressures; The contact angle assignment and characterization module is configured to set the wetting wall of the natural pore structure, assign and characterize the wettability of different pores according to the pore types of the scanning electron microscope photo, and set the initial conditions and fluid properties, select a laminar flow-phase field model, and sequentially set the parameters; The imbibition mechanism analysis module is configured to simulate the fracturing fluid injection, imbibition and flowback process according to the boundary conditions, and analyze the imbibition mechanism through the fluid distribution change; The data processing module is configured to process data and compare the influence of wettability on imbibition. ​

Images