Shale oil fracturing, well closing and drainage and mining integrated simulation method

Abstract

The invention provides a shale oil fracturing, well closing and drainage and mining integrated simulation method. The method comprises the following steps: step 1, establishing a discrete matrix system; 2, establishing a discrete fracture system; step 3, constructing an embedded discrete fracture-dual medium coupling seepage model; 4, different stages are distinguished, and pore pressure is obtained according to the working system; step 5, calculating and updating physical property parameters under each time step in different stages; and 6, solving a control equation of the embedded discrete fracture-double medium coupling seepage model in the current time step, and carrying out integrated simulation on the fracturing stage, the well closing stage and the drainage and mining stage of shale oil. According to the shale oil fracturing, well closing and drainage and production integrated simulation method, a full-cycle model comprehensively considering a fracture-inorganic matter-organic matter physical property field, a fluid field and a pressure field in the fracturing-well closing-production stage is established, and accurate characterization of the fracturing fluid imbibition effect and reservoir energization is achieved.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of shale oil numerical simulation, and particularly relates to a shale oil fracturing, huff and puff and production integration simulation method. BACKGROUND

[0002] Under the background of energy shortage and climate change, the exploration and development of shale oil has attracted widespread attention from the international community. Large-scale hydraulic fracturing is one of the key technologies for successful economic exploitation of shale oil. In the early stage of shale oil development, fracturing-flowback-depletion development is mostly used. Under the condition of insufficient natural energy, the decline rate can reach 20%-40% in the first few months, which greatly affects the development effect.

[0003] Field practice has proved that formulating a reasonable huff and puff system after fracturing has a significant effect on reducing the decline rate. There is some controversy in the industry about huff and puff systems. In 2014, Sharak summarized that huff and puff and delayed production would have an adverse effect on production. However, Fan had a different understanding of the huff and puff system. Research found that huff and puff would not necessarily cause damage to the reservoir, and sometimes it could even increase its production. Cheng et al. found that during the huff and puff period, capillary force forced more water to be imbibed into deeper rock matrix, resulting in water lock self-relief mechanism, which increased gas production and reduced water production. From some field data, it can be found that the productivity of a large number of low-flowback-rate wells has not been seriously affected, and even the lower the flowback rate, the higher the productivity of the well. The effect of fracturing fluid retention on unconventional reservoirs has undergone a process from "damage" to "flooding". For shale reservoirs suitable for huff and puff, high-energy fracturing fluid can be injected into the formation without immediate flowback, and the high-energy fracturing fluid can gradually diffuse to the unmodified area to supplement the formation energy and achieve the effect of energy storage fracturing. However, at present, there is no relevant work on the production mechanism of huff and puff and flowback rules. After the injection of high-energy fracturing fluid, the imbibition effect, huff and puff time, water saturation and other factors have an unclear effect on reservoir energy, oil and water distribution rules in the fracturing-huff and puff-production stages. Therefore, it is of great significance to carry out a full-cycle simulation study of the huff and puff-flowback rules of high-energy fracturing fluid injection in shale oil fracturing development, to clarify the fracturing fluid flooding mechanism and formulate a reasonable development policy.

[0004] In the Chinese patent application No. CN201911151497.6, a method for simulating the integration of the hydraulic fracturing and flowback production process of shale gas reservoirs is disclosed. The method comprises the following steps: (S1) setting the potential extension path of the fracture based on the distribution of natural fractures in the formation, the magnitude and direction of in-situ stress; (S2) dividing the space into unstructured grids using triangular elements with all potential fractures as grid boundaries; (S3) calculating the pressure and saturation in the fracture and matrix grids during the fracturing, flowback, and production processes using a gas-water two-phase discrete fracture model based on unstructured grids; (S4) simulating the fracture extension process; (S5) when the fracturing fracture encounters a natural fracture during forward extension, judging the fracture intersection behavior; (S6) simulating the flowback and production processes after the fracturing extension process simulation is completed. The method combines the discrete fracture model with dynamic fractures, considers the two-phase flow of fracturing fluid and shale gas in the formation, and realizes the integrated simulation of the hydraulic fracturing and flowback production process of shale gas reservoirs.

[0005] In the Chinese patent application No. CN202010651900.8, a method and system for predicting the flowback rate of fracturing fluid after pressure fracturing in tight reservoir horizontal wells are disclosed. The method comprises the following steps: establishing a one-dimensional unsteady seepage mathematical model to calculate the formation pressure of a typical seepage unit, and calculating the formation static pressure before flowback according to the formation pressure of the typical seepage unit; establishing a one-dimensional unsteady seepage diffusion model to calculate the water saturation of the typical seepage unit; establishing a one-dimensional unsteady seepage mathematical model to calculate the formation pressure of the typical seepage unit, and calculating the fracture production according to the formation pressure; calculating the fluid slug acting length by the material balance method of production, and calculating the fracturing fluid flowback volume of the typical seepage unit according to the fluid slug acting length, to obtain the fracturing fluid flowback rate of the tight reservoir horizontal well. The method considers the three stages of fracturing and well soaking, and uses an analytical method to solve the mathematical model, which is more comprehensive and has a more sufficient theoretical basis, and is suitable for field operation.

[0006] In the Chinese patent application No. CN202110971711.3, a method for evaluating the fracturing effect of coalbed methane reservoirs based on physical constraints is disclosed, which belongs to the field of oil reservoir development. The method comprises the following steps: constructing a data set based on the dynamic and static data provided by the oil and gas field; establishing a data cleaning algorithm based on the physical background for dynamic data; constructing an error guidance equation under the guidance of "data + physics" based on direct parameter control and indirect physical constraints; establishing a combination network considering the actual importance of dynamic and static data dimensions and physical parameters; constructing training and test sets through cyclic combination mode; based on the training and test sets, using the error guidance equation to construct a new residual function, and training and testing the combination network model through the back propagation algorithm to obtain the optimal fracturing effect evaluation model; establishing the Gai algorithm to define the contribution of each input parameter to the fracture half-length and the permeability after fracturing.

[0007] The above prior art is quite different from the present application, and cannot solve the technical problems we want to solve, therefore we have invented a new shale oil fracturing, huff and puff and drainage integrated simulation method. SUMMARY

[0008] The purpose of the present application is to provide a shale oil fracturing, huff and puff and drainage integrated simulation method that can obtain the energy and fluid distribution of different scale media in the whole life cycle of shale oil fracturing development, and is used for clarifying the fracturing fluid assisted drive mechanism and optimizing the development strategy.

[0009] The purpose of the present application can be achieved by the following technical measures: a shale oil fracturing, huff and puff and drainage integrated simulation method, which comprises:

[0010] Step 1, establishing a discrete matrix system;

[0011] Step 2, establishing a discrete fracture system;

[0012] Step 3, constructing an embedded discrete fracture-dual medium coupled seepage model;

[0013] Step 4, distinguishing different stages and obtaining pore pressure according to the working system;

[0014] Step 5, calculating and updating the physical property parameters of each time step in different stages;

[0015] Step 6, solving the embedded discrete fracture-dual medium coupled seepage model control equation in the current time step, and integrally simulating the process of the fracturing stage, the huff and puff stage and the drainage stage of the shale oil.

[0016] The purpose of the present application can also be achieved by the following technical measures: in step 1, inputting the grid parameters of the model and the initial porosity / permeability parameters of the inorganic matter, calculating the initial apparent porosity / permeability of the organic matter according to the initial porosity / permeability parameters, and using the DK model to subdivide the representation of the organic matter and the inorganic matter.

[0017] In step 1, the apparent permeability of the fracture is:

[0018]

[0019] In the above formula: is the initial apparent permeability of the fracture; p Fint is the initial pressure of the fracture in the fracturing stage; H f is the fracture height, unit: m; u is the Poisson's ratio; E is the elastic modulus, unit: MPa; P f is the net pressure of the fluid in the fracture, unit: MPa; apparent porosity of the fracture;

[0020] apparent porosity of the fracture is:

[0021]

[0022] in the above formula: initial apparent porosity of the fracture; V m (t) is the volume of proppant injected at time t, in m 3 ; x f is the length of the vertical fracture, in m.

[0023] In step 2, the spatial position of the hydraulic fracture plane and the related attributes are input, and the ADFNE is used to randomly generate a natural fracture network based on the existing matrix system discrete fracture plane.

[0024] In step 3, the matrix and fracture unit grid structure and rock properties are integrated, the flow properties of organic matter, inorganic matter and fractures are given respectively, the initial conditions and boundary conditions are added, and the simulation end times t f , t s , t p and the total time of the fracturing, shut-in and production stages are determined.

[0025] In step 4, the current stage is determined according to the initial value and the time step: it is divided into fracturing, shut-in and production stages, the current working system is determined for different stages, and the pore pressure of each medium at the current time step is obtained.

[0026] In step 5, according to the working system of different stages, the physical property parameters of organic matter, inorganic matter and fractures are updated, including the porosity and permeability of each grid, and the pore volume, conductivity and wellbore index are further calculated and updated; if the current time step is at the end time of the fracture stage or the end time of the shut-in stage, the parameters at the end of the previous stage are assigned as the initial parameters of the next stage.

[0027] In step 5, in the embedded discrete fracture-dual medium coupled seepage model, the shale oil in the fracturing stage:

[0028] the permeability of the fracture is:

[0029]

[0030] in the above formula: permeability of the fracture in the fracturing stage; p Fint initial pressure of the fracture in the fracturing stage; H f fracture height, in m; u is the Poisson's ratio; E is the elastic modulus, in MPa; P f net pressure of the fluid in the fracture, in MPa; the porosity of the fracture;

[0031] the porosity of the fracture;

[0032]

[0033] In the above formula: the porosity of the fracture in the fracturing stage; V m (t) is the volume of the proppant injected at time t, in m 3 ; x f is the length of the vertical fracture, in m.

[0034] In the embedded discrete fracture-dual media coupled seepage model, the shale oil in the soaking stage is:

[0035] the permeability of the fracture;

[0036]

[0037] In the above formula: the permeability of the fracture in the soaking stage; p Sint is the initial pressure of the fracture in the soaking stage; σ c is the confining stress; σ1 is the maximum effective stress that makes the fracture completely closed; α b is the stress sensitivity coefficient; is the permeability under zero confining pressure; m is a constant related to the roughness of the fracture surface; is the initial permeability of the fracture in the soaking stage; F k is the permeability correction factor;

[0038] the porosity of the fracture;

[0039]

[0040] In the above formula: the porosity of the fracture in the soaking stage; is the initial porosity of the fracture in the soaking stage.

[0041] In the embedded discrete fracture-dual media coupled seepage model, the shale oil in the production stage is:

[0042] the apparent porosity of the organic matter;

[0043]

[0044] In the above formula: the apparent porosity of the organic matter in the production stage; p int is the initial pressure of the organic matter and inorganic matter in the production stage; C a is the adsorbed gas concentration, mol / m3 ; Z is the gas compressibility factor; R is the universal gas constant, 8.314 J / (K-mol); T is the reservoir temperature, K; Φ dc is the dynamic porosity; is the elliptical pore adsorbed gas volume; is the rectangular pore adsorbed gas volume; V P is the pore volume; is the elliptical pore free gas volume; is the rectangular pore free gas volume;

[0045] The apparent permeability of the organic matter is:

[0046]

[0047] In the above equations: is the apparent permeability of the organic matter during the production phase; a r is the sparse effect correction factor, which is a dimensionless quantity; τ is the tortuosity; τ s is the roughness; D a is the surface diffusion coefficient of the adsorbed gas; μ g is the gas viscosity; N is the shape factor order; F e is the slip coefficient; is the shape factor, dimensionless; λ dc is the free gas pore radius; N e is the free gas pore radius; Kn Knudsen number;

[0048] The porosity of the inorganic matter is:

[0049]

[0050] In the above equations: is the porosity of the inorganic matter during the production phase; is the initial porosity of the inorganic matter during the production phase; C im is the compressibility of the inorganic matter;

[0051] The permeability of the inorganic matter is:

[0052]

[0053] In the above equations: K im is the permeability of the inorganic matter during the production phase; is the initial permeability of the inorganic matter during the production phase;

[0054] The porosity of the fracture is:

[0055]

[0056] In the above equations: porosity of the fracture at the production stage; p Pint initial pressure of the fracture at the production stage; initial porosity of the fracture at the production stage; C f compressibility of the fracture;

[0057] permeability of the fracture is:

[0058]

[0059] In the above formula: permeability of the fracture at the production stage; initial permeability of the fracture at the production stage; a b Biot constant.

[0060] In step 6, the embedded discrete fracture-dual medium coupled seepage model control equation in the current time step is solved; the embedded discrete fracture-dual medium coupled seepage model is solved by using two-point flow approximation-finite volume method, and the AD backend is combined with the AMG method to quickly solve the sparse linear system in the current time step; steps 4 to 6 are repeated until the cumulative simulation time is greater than the total simulation time, so that the processes of the fracturing stage, the soaking stage and the production stage of the shale oil are simulated integrally, and the energy and fluid distribution of the shale oil in the whole life cycle of the fracturing development of different scales of media are obtained.

[0061] In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of the shale oil in the fracture, the organic matter and the inorganic matter in the fracturing stage are in turn:

[0062]

[0063] In the above formula: f i is a fracture unit, f i ∈{1,N f}, wherein N f is the number of fracture units in the fracture; is the porosity of the fracture unit f i at the fracturing stage; is the density of the fracture, with the unit of kg / m 3 ; is the saturation of the flow phase a in the fracture f i ; is the permeability of the fracture unit f i at the fracturing stage; is the relative permeability of the flow phase a in the fracture; is the viscosity of the flow phase a in the fracture; is a gradient; is the potential gradient of the flow phase a in the fracture at the fracturing stage; is the opening of the fracture unit fi; f is the fracture unit in the fracturing stage i Source and sink terms in ; is the crack unit f i Flow coupling term to inorganic mass unit; is the flow coupling term from fracture element fi to fracture element fj; is the apparent porosity of organic matter; is the density of organic matter, in kg / m 3 ; is the saturation of fluid phase α in organic matter; is the apparent permeability of organic matter; is the relative permeability of fluid phase α in organic matter; is the viscosity of the fluid phase α in the organic matter; is the potential gradient of fluid phase α in organic matter during the fracturing stage; is the flow coupling term from organic matter unit to inorganic matter unit; is the porosity of inorganic matter during the fracturing stage; is the density of inorganic matter, in kg / m 3 ; is the saturation of the inorganic medium phase α; is the permeability of inorganic matter during the fracturing stage; is the relative permeability of the fluid phase α in the inorganic matter; is the viscosity of the fluid phase α in the inorganic matter; is the potential gradient of fluid phase α in inorganic matter during the fracturing stage; is the flow coupling term from inorganic matter unit to organic matter unit; is the flow coupling term from inorganic element to fracture element.

[0064] In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of fractures, organic matter, and inorganic matter during the well-blocking stage of shale oil are:

[0065]

[0066] In the above formula: f is the fracture unit in the well blocking stage i Porosity; f is the fracture unit in the well blocking stage i penetration rate; is the potential gradient of the fluid phase α in the fracture during the well blocking stage; is the potential gradient of the fluid phase α in the organic matter during the well-blocking stage; The porosity of inorganic matter in the well-blocking stage; is the permeability of inorganic matter in the wellbore stage; is the potential gradient of the inorganic medium phase α during the wellbore stage.

[0067] In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of fractures, organic matter, and inorganic matter during the shale oil drainage stage are:

[0068]

[0069] In the above formula: f is the fracture unit in the drainage stage i Porosity; The fracture unit f in the drainage stage i penetration rate; is the potential gradient of the fluid phase α in the fracture during the drainage stage; is the potential gradient of the flow phase α in the organic matter during the drainage stage; is the porosity of organic matter during the drainage stage; is the permeability of organic matter during the drainage stage; is the potential gradient of the flow phase α in the inorganic matter during the drainage stage.

[0070] The purpose of the present invention can also be achieved through the following technical measures: an integrated simulation system for shale oil fracturing, well blocking and drainage. The integrated simulation system for shale oil fracturing, well blocking and drainage adopts an integrated simulation method for shale oil fracturing, well blocking and drainage to perform integrated simulation of the fracturing stage, well blocking stage and drainage stage of shale oil, and obtain the medium energy and fluid distribution at different scales throughout the life cycle of shale oil fracturing development.

[0071] The integrated simulation method of shale oil fracturing, well blocking and drainage in the present invention takes into account the variation characteristics of physical parameters of media at different scales, such as fractures, inorganic matter and organic matter, and the multi-scale media migration mechanism during the fracturing-well blocking-drainage stage of the shale reservoir, and adopts the hybrid numerical model method of EDFM coupled with DPDK to construct a numerical simulation method for the entire cycle of shale oil fracturing development, fracturing-well blocking-drainage.

[0072] The present invention establishes an embedded discrete fracture-dual medium coupled seepage model to subdivide and characterize various types of media, and combines the quantitative characterization method of organic apparent porosity / permeability and the opening and closing laws of fractures to establish a full-cycle model that comprehensively considers the fracture-inorganic matter-organic matter physical property field, fluid field, and pressure field in the fracturing-well blocking-production stage, thereby achieving accurate characterization of the fracturing fluid imbibition effect and reservoir energy enhancement. BRIEF DESCRIPTION OF THE DRAWINGS

[0073] Figure 1 Schematic diagram of the embedded discrete fracture-dual medium coupled seepage model of the present invention;

[0074] Figure 2 A top view of the bottom of a hybrid representation model in one embodiment of the present invention;

[0075] Figure 3 The connection diagram of the embedded discrete fracture-dual medium coupled percolation model in a specific embodiment of the present application;

[0076] Figure 4 The flow chart of a specific embodiment of the shale oil fracturing, huff and puff and integrated simulation method of the present application;

[0077] Figure 5 The initial attribute distribution map of the matrix system in a specific embodiment of the present application;

[0078] Figure 6 The fracture distribution map in a specific embodiment of the present application;

[0079] Figure 7 The relative permeability curve of each medium in a specific embodiment of the present application;

[0080] Figure 8 The pressure distribution map of models I-III at the end of the production in a specific embodiment of the present application;

[0081] Figure 9 The cumulative injection and bottom hole pressure change curve of models I-III in the fracturing stage in a specific embodiment of the present application;

[0082] Figure 10 The organic matter and inorganic matter daily contribution and cumulative contribution curve of models I-III after opening well production in a specific embodiment of the present application;

[0083] Figure 11 The schematic diagram of the matrix permeability, matrix porosity and fracture shape distribution of the model in a specific embodiment of the present application;

[0084] Figure 12 The schematic diagram of the pressure distribution of each stage according to the initial model simulation in a specific embodiment of the present application;

[0085] Figure 13 The schematic diagram of the daily oil and gas production fitting result in a specific embodiment of the present application;

[0086] Figure 14 The schematic diagram of the pressure and oil saturation distribution of the fitted model in each stage in a specific embodiment of the present application. DETAILED DESCRIPTION

[0087] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present application. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.

[0088] It is to be understood that the terms used herein are for the purpose of describing particular embodiments only and are not intended to limit exemplary embodiments according to the present application. As used herein, the singular forms are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms "comprises" and / or "comprising," when used in this specification, specify the presence of stated features, steps, operations, elements, and / or components, but do not preclude the presence or addition of one or more other features, steps, operations, elements, components, and / or groups thereof.

[0089] Figure 4 The flow chart of the shale oil fracturing, huff and puff, and drainage integrated simulation method of the present application can be divided into four parts: discrete matrix system, discrete fracture system, construction of initial multi-scale physical model, and full-cycle multi-scale numerical solution. The shale oil fracturing, huff and puff, and drainage integrated simulation method specifically includes:

[0090] (S1) Establish a discrete matrix system. Input the grid parameters of the model and the initial porosity / permeability parameters of inorganic matter, calculate the initial apparent porosity / permeability of organic matter according to the initial porosity / permeability parameters, and use the DK model to subdivide the representation of organic matter and inorganic matter.

[0091] The apparent permeability of the fracture is:

[0092]

[0093] In the above formula: is the initial apparent permeability of the fracture; p Fint is the initial pressure of the fracture in the fracturing stage; H f is the fracture height, in m; u is the Poisson's ratio; E is the elastic modulus, in MPa; P f is the net pressure of the fluid in the fracture, in MPa; is the apparent porosity of the fracture;

[0094] The apparent porosity of the fracture is:

[0095]

[0096] In the above formula: is the initial apparent porosity of the fracture; V m (t) is the volume of proppant injected at time t, in m 3 ; x f is the length of the vertical fracture, in m.

[0097] (S2) Establish a discrete fracture system. Input the spatial position of the hydraulic fracture plane and related attributes, use ADFNE to randomly generate a natural fracture network, and base the discrete fracture plane on the existing matrix system.

[0098] (S3) Constructing the embedded discrete fracture-dual medium coupled seepage model. Integrating the matrix and fracture cell grid structure and rock properties, respectively giving the flow properties of organic matter, inorganic matter and fractures, determining the initial conditions and adding boundary conditions, and determining the simulation end time t of each stage of fracturing, soaking and production according to the input parameter values. f s p and total time.

[0099] (S4) Distinguishing different stages and obtaining pore pressure according to the working system. According to the initial value and time step, the current stage is determined: when the cumulative simulation time T c is less than or equal to the simulation end time t f of the fracturing stage set by pressure, the stage is the fracturing stage, and the fracturing system of the horizontal well at this time step is determined according to the input parameter value; when the cumulative simulation time T c is greater than the simulation end time t f of the fracturing stage and less than or equal to the simulation end time t s of the soaking stage, the stage is the soaking stage, and the soaking system of the horizontal well at this time step is determined according to the input parameter value; when the cumulative simulation time T c is greater than the simulation end time t s of the soaking fracturing stage and less than or equal to the simulation end time t p of the production stage, the stage is the production stage, and the production system of the horizontal well at this time step is determined according to the input parameter value. After determining the stage and working system of the current time period, the pore pressure of each medium at the current time step is obtained.

[0100] (S5) Calculating and updating the physical property parameters of each time step in different stages.

[0101] According to the working system of different stages, the physical property parameters of organic matter, inorganic matter and fractures are updated by using the formula, such as the porosity and permeability of each grid, and the pore volume, conductivity coefficient and wellbore index are further calculated and updated. If the cumulative simulation time T c is equal to the simulation end time t f of the fracturing stage or the simulation end time t s of the soaking fracturing stage, the parameters at the end of the last stage are assigned as the initial parameters of the next stage.

[0102] Preferably, in the shale oil fracturing, soaking and production integrated simulation method, in the embedded discrete fracture-dual medium coupled seepage model, the permeability of the fracture in the fracturing stage is:

[0103]

[0104] ​​​

[0105] In the above formula: p is the permeability of the fracture in the fracturing stage; p Fint H is the initial pressure of the fracture in the fracturing stage; H f H is the initial pressure of the fracture in the fracturing stage; H f P is the net pressure of the fluid in the fracture, in MPa; φ is the porosity of the fracture;

[0106] The porosity of the fracture is:

[0107]

[0108] In the above formula: V is the porosity of the fracture in the fracturing stage; V m (t) is the volume of the proppant injected at time t, in m 3 ; x f L is the length of the vertical fracture, in m.

[0109] Preferably, in the shale oil fracturing, huff and puff, and integrated simulation method, in the embedded discrete fracture-dual medium coupling seepage model, when the shale oil is in the huff and puff stage:

[0110] The permeability of the fracture is:

[0111]

[0112] In the above formula: p is the permeability of the fracture in the fracturing stage; p Sint H is the initial pressure of the fracture in the fracturing stage; H c σ is the confining stress; σ1 is the maximum effective stress that completely closes the fracture; α b is the stress sensitivity coefficient; is the permeability under zero confining pressure; m is a constant related to the roughness of the fracture surface; F is the initial permeability of the fracture in the huff and puff stage; F k is the permeability correction factor;

[0113] The porosity of the fracture is:

[0114]

[0115] In the above formula: V is the porosity of the fracture in the fracturing stage; V V is the initial porosity of the fracture in the huff and puff stage.

[0116] Preferably, in the shale oil fracturing, huff and puff and integrated simulation method, in the embedded discrete fracture-dual medium coupling seepage model, the shale oil in the production stage is:

[0117] The apparent porosity of the organic matter is:

[0118]

[0119] In the above formula: is the apparent porosity of the organic matter in the production stage; p int is the initial pressure of the organic matter and inorganic matter in the production stage; C a is the adsorbed gas concentration, mol / m 3 ; Z is the gas compression factor; R is the universal gas constant, 8.314 J / (K·mol); T is the reservoir temperature, K; Φ dc is the dynamic porosity; is the elliptical pore adsorbed gas volume; is the rectangular pore adsorbed gas volume; V P is the pore volume; is the elliptical pore free gas volume; is the rectangular pore free gas volume.

[0120] The apparent permeability of the organic matter is:

[0121]

[0122] In the above formula: is the apparent permeability of the organic matter in the production stage; α r is the sparse effect correction coefficient, which is a dimensionless quantity; τ is the tortuosity; τ s is the roughness; D a is the surface diffusion coefficient of the adsorbed gas; μ g is the gas viscosity; N is the shape factor classification number; F e is the slip coefficient; is the shape factor, dimensionless; λ dc is the free gas pore diameter; N e is the free gas pore diameter; Kn Knudsen number.

[0123] The porosity of the inorganic matter is:

[0124]

[0125] In the above formula: is the porosity of the inorganic matter in the production stage; is the initial porosity of the inorganic matter in the production stage; C im is the compressibility coefficient of the inorganic matter;

[0126] The permeability of the inorganic matter is:

[0127]

[0128] In the above formula, K im is the permeability of the inorganic matter in the production stage; is the initial permeability of the inorganic matter in the production stage;

[0129] The porosity of the fracture is:

[0130]

[0131] In the above formula, p is the porosity of the fracture in the production stage; Pint is the initial pressure of the fracture in the production stage; is the initial porosity of the fracture in the production stage; f is the compressibility of the fracture;

[0132] The permeability of the fracture is:

[0133]

[0134] In the above formula, a is the permeability of the fracture in the production stage; is the initial permeability of the fracture in the production stage; b is the Biot constant.

[0135] (S6) Solving the embedded discrete fracture-dual medium coupled seepage model control equation in the current time step. The embedded discrete fracture-dual medium coupled seepage model is solved by using two-point flow approximation-finite volume method, and AD backend is combined with AMG method to quickly solve the sparse linear system in the current time step. Repeat (S4) to (S6) until the cumulative simulation time T c is greater than the total simulation time T t , and output the simulation results of the pressure-squeeze-production whole cycle mixed model. Thus, the processes of the fracturing stage, the well shut-in stage and the production stage of shale oil are simulated integrally, and the energy and fluid distribution of different scale media in the whole life cycle of shale oil fracturing development are obtained.

[0136] Preferably, in the shale oil fracturing, well shut-in and production integrated simulation method, the control equations of shale oil in the fracture, organic matter and inorganic matter in the fracturing stage of the embedded discrete fracture-dual medium coupled seepage model are in turn:

[0137]

[0138] In the above formula, f i is a fracture unit, f i ∈{1, Nf}, wherein N f is the number of fracture elements in the fracture; is the porosity of fracture element f i for the fracturing stage; is the density of the fracture in kg / m 3 ; is the saturation of the fluid phase a in the fracture f i ; is the permeability of fracture element f i for the fracturing stage; is the relative permeability of the fluid phase a in the fracture; is the viscosity of the fluid phase a in the fracture; is the gradient; is the potential gradient of the fluid phase a in the fracture for the fracturing stage; is the opening of fracture element f i ; is the source-sink term in fracture element f i for the fracturing stage; is the flow coupling term from fracture element f i to the inorganic element; is the flow coupling term from fracture element fi to fracture element fj; is the apparent porosity of the organic matter; is the density of the organic matter in kg / m 3 ; is the saturation of the fluid phase a in the organic matter; is the apparent permeability of the organic matter; is the relative permeability of the fluid phase a in the organic matter; is the viscosity of the fluid phase a in the organic matter; is the potential gradient of the fluid phase a in the organic matter for the fracturing stage; is the flow coupling term from the organic element to the inorganic element; is the porosity of the inorganic matter for the fracturing stage; is the density of the inorganic matter in kg / m 3 ; is the saturation of the fluid phase a in the inorganic matter; is the permeability of the inorganic matter for the fracturing stage; is the relative permeability of the fluid phase a in the inorganic matter; is the viscosity of the fluid phase a in the inorganic matter; is the potential gradient of the fluid phase a in the inorganic matter for the fracturing stage; is the flow coupling term from the inorganic element to the organic element; is the flow coupling term from the inorganic element to the fracture element.

[0139] Preferably, in the shale oil fracturing, huff and puff and drainage integrated simulation method, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of the shale oil in the fracture, organic matter and inorganic matter in the huff and puff stage are as follows:

[0140]

[0141] In the above formulae: is the porosity of the fracture unit f i in the huff and puff stage; is the permeability of the fracture unit f i in the huff and puff stage; is the potential gradient of the flow phase a in the fracture in the huff and puff stage; is the potential gradient of the flow phase a in the organic matter in the huff and puff stage; is the porosity of the inorganic matter in the huff and puff stage; is the permeability of the inorganic matter in the huff and puff stage; is the potential gradient of the flow phase a in the inorganic matter in the huff and puff stage.

[0142] Preferably, in the shale oil fracturing, huff and puff and drainage integrated simulation method, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of the shale oil in the fracture, organic matter and inorganic matter in the huff and puff stage are as follows:

[0143]

[0144] In the above formulae: is the porosity of the fracture unit f i in the drainage stage; is the permeability of the fracture unit f i in the drainage stage; is the potential gradient of the flow phase a in the fracture in the drainage stage; is the potential gradient of the flow phase a in the organic matter in the drainage stage; is the porosity of the organic matter in the drainage stage; is the permeability of the organic matter in the drainage stage; is the potential gradient of the flow phase a in the inorganic matter in the drainage stage.

[0145] The following are several specific embodiments of the application

[0146] Embodiment 1

[0147] In the specific embodiment 1 of the application, the shale oil fracturing, huff and puff and drainage integrated simulation method comprises the following steps:

[0148] S1, based on the reservoir reconstruction characteristics of shale oil volume fracturing horizontal well, organic matter or inorganic matter is characterized by double medium coarse subdivision, and hydraulic fracture or natural fracture morphology is explicitly characterized by EDFM, and an embedded discrete fracture-double medium coupling seepage model is established; wherein the embedded discrete fracture-double medium coupling seepage model separately analyzes the physical parameters and control equations of each medium in the fracturing stage, the well soaking stage and the production stage of shale oil, and takes the physical parameters of the medium at the end of the last stage as the initial value of the physical parameters of the medium in the next stage; wherein the medium physical parameters at least include porosity and permeability.

[0149] In this embodiment, based on the reservoir reconstruction characteristics of shale oil volume fracturing horizontal well, the double permeability medium model (DPDK) and the embedded discrete fracture model (EDFM) are coupled together to establish a coupling seepage physical model characterized by double medium coarse subdivision of organic matter / inorganic matter and EDFM explicit representation of hydraulic fracture / natural fracture morphology, as shown in Figure 1 For the organic matter / inorganic matter porous medium with developed matrix blocks, the inorganic matter can be discretely established as a cubic geometry, and is assumed to have ultra-low water saturation; it is assumed that the organic matter is located in the inorganic matter with elliptical and rectangular shape pores, and the special seepage mechanism of microscale is considered. Figure 1 Figures (a), (b), (c) and (d) are respectively schematic diagrams of three types of complex fracture shapes directly embedded in a reservoir model, a simplified model of organic matter-inorganic matter double medium, an actual model of organic matter-inorganic matter double medium, and a schematic diagram of fluid migration in nanometer pores of kerogen. Under the interaction of pressure in the fracture and pressure in the matrix block, the fluid in the mixed characterization model can flow according to the following paths, as shown in Figure 2 : internal migration of organic matter porous medium, multi-scale mass transfer between organic matter porous medium and inorganic matter porous medium, internal migration of inorganic matter porous medium, multi-scale mass transfer between inorganic matter porous medium and fracture, multi-scale mass transfer between natural fracture and hydraulic fracture, internal migration of fracture, and multi-scale mass transfer between hydraulic fracture and horizontal well.

[0150] For high-conductivity hydraulic fractures, microseismic technology and fracture inversion technology can be used to obtain their distribution and morphology; in view of the uncertainty of natural fractures, the open-source ADFNE code is used in this embodiment to randomly generate a set of natural fracture network distributions to consider the influence of their distribution and physical properties on imbibition effect and reservoir energy enhancement.

[0151] S2, the two-point flow approximation-finite volume method is used to solve the embedded discrete fracture-double medium coupling seepage model, and the fracturing stage, the well soaking stage and the production stage of shale oil are simulated integrally to obtain the energy and fluid distribution of different scale media in the whole life cycle of shale oil fracturing development.

[0152] The solution of the model can be performed by using the fully implicit Euler method for time discretization and two-point flux approximation-finite volume method (TPFA-FVM) for discretizing the control equations. For the flux term, the divergence operator (div) and the gradient operator (grad) are used to realize the numerical discretization. Taking the control equation of the fracturing stage as an example, the discrete numerical form can be written as:

[0153]

[0154] In the above formula, n+1 represents the current time step, n represents the previous time step; R is the residual value; V is the bulk volume of the grid cell; the mobility λ α is defined as the ratio of the relative permeability of phase α in the medium to the viscosity μ α of the phase. p e is the pressure at the equivalent radius, with the unit of MPa; T is the conduction coefficient between the media, with the unit of mD·m; WI is the effective wellbore index of the perforation cell and the fracture cell, with the unit of mD·m. The mathematical formula of various conduction coefficients and wellbore indexes has been made by the predecessors, and will not be repeated here. It can be found from the above formula (16) that there are six kinds of cell connection modes, in which the connection in the flux term is the standard adjacent connection, which is represented by the subscript nc; the connection in the source / sink term is the non-adjacent connection, which is represented by the subscript nnc. The position and connection relationship of these connection modes in the grid domain and the calculation domain can be seen in Figure 3 , Figure 3 om1-om4 are four organic matter cells, im1-im4 are four inorganic matter cells, f1-f3 and f4-f6 are three fracture cells on two fracture planes respectively, and w1 represents the perforation cell of the horizontal well.

[0155] This embodiment takes the oil phase pressure p g and the water saturation S w as the main variables x, integrates all the discrete equations, and obtains the nonlinear equation group which can be expressed in the form of short vectors:

[0156] R(x n+1 ; x n )=0 (17)

[0157] The equation group can be solved at each time step by using the iteration scheme in the following formula (18)

[0158]

[0159] In the above formula, i represents the number of nonlinear iterations; the partial derivative is the Jacobian matrix J, and δx i+1is the Newton update for the i+1 iteration. For a given tolerance level e, the iteration process continues until the convergence condition is satisfied. Meanwhile, this paper combines algebraic multigrid method—AMGCL with diagonal row-major MEX-accelerated AD backends to solve large sparse linear systems quickly and stably. Similarly, the control equations of the well shut-in and production stages are discretized and numerically solved to obtain the numerical solutions of the reservoir (pressure p and saturation S) and the well (well bottom pressure p wf and production Q) for each stage.

[0160] As shown in Figure 4 , the establishment and solution of the embedded discrete fracture-dual medium coupled seepage model of the embodiment can be roughly divided into four parts: discrete matrix system, discrete fracture system, construction of initial multi-scale physical model, and full-cycle multi-scale numerical solution.

[0161] Embodiment 2

[0162] In a specific embodiment 2 of the application, three groups of models are set up for comparison to verify the correctness and necessity of the model herein: (I) EDFM-DPDK model with pressure dependence, (II) EDFM-DPDK model without pressure dependence, and (III) traditional numerical simulation model without pressure dependence. The average values and non-uniform distributions of the permeability, porosity, and water and oil saturation of organic and inorganic matter can be seen in Figure 5 . The fracture distribution is as follows: Figure 6 (a) is the explicit fracture plane characterized by EDFM, (b) is the host matrix unit of the EDFM fracture plane, and (c) is the implicit fracture unit characterized by the equivalent physical method. The opening of the explicit hydraulic fracture in models I-II is 0.04 m, and the permeability is 20 D; the implicit fracture opening is set to 1 m, so the equivalent permeability of model III is 0.8 D, and the equivalent porosity is calculated accordingly.

[0163] The relative permeability and capillary pressure of each medium in the model often satisfy different relationships, in which the fracture and inorganic matter are hydrophilic media, and the organic matter is hydrophobic media, and the relative permeability curve can be seen in Figure 7 . Here we ignore the capillary pressure effect of the media in models I-III. The remaining reservoir simulation establishment parameters can be seen in Table 1.

[0164] Table 1 Representative parameters for the establishment of the conceptual example model

[0165]

[0166] The fracturing time is set to 4 hours (4000 m 3), huff and puff time 40 days, and drainage and production time 360 days. Although the equivalent property method in Model III magnifies the flow relationship between the equivalent fracture element and the matrix element, making the bottom hole pressure of Model III lower than that of Model II in the fracturing stage ( Figure 9 ), the results of Model II and Model III are almost the same in terms of the remaining pressure of organic matter / inorganic matter ( Figure 8 ) and the contribution of organic matter / inorganic matter ( Figure 10 ), verifying the correctness of the model. When the pressure-dependent relationship of each medium is considered, it can be found that, in the fracturing stage, the bottom hole pressure of Model I is slightly lower than that of Model II due to the increase in the porosity / permeability of inorganic matter ( Figure 9 ). In the drainage stage, the porosity / permeability of each medium in Model I is greatly reduced under the effect of stress sensitivity, making the production and water production of Model I much smaller than those of Model II, and it can be found from Figure 8 that the pressure sweep area of Model I is smaller than that of Model II.

[0167] Example 3

[0168] In a specific embodiment 3 of the application, a field-scale model is established for Well M of an oilfield and a history is simulated to verify the universality and practicability of the model.

[0169] The initial basic parameters of the model of the example are as follows: the model grid parameters and injection and production parameters are shown in the following table, and the matrix permeability, matrix porosity, and fracture shape distribution are shown in Figure 11 . The pressure distribution obtained by the simulation of each stage according to the initial model is shown in Figure 12 .

[0170] Table 2 Actual block model parameters

[0171]

[0172] According to the actual production performance of Well M, the daily oil production is fitted with a time step of ten days, and the fitting results of the daily oil production and the daily gas production are shown in Figure 13 . The fitting rate is 87.32%, which meets the engineering requirements. Figure 14 The pressure and oil saturation distribution of each stage of the fitted model. It can be found that the simulation method can be applied to actual production and obtain simulation results close to field data, proving that the shale oil fracturing, huff and puff, and drainage and production integrated simulation method has universality and practicability.

[0173] Finally, it should be noted that the above only describes the preferred embodiments of the present application and is not intended to limit the present application. Although the present application has been described in detail with reference to the foregoing embodiments, those skilled in the art will appreciate that modifications can be made to the technical solutions described in the foregoing embodiments, or some of the technical features thereof can be replaced equivalently, without departing from the spirit and principle of the present application. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present application should be included in the protection scope of the present application.

[0174] All that is not described in the specification is known to those skilled in the art.

Claims

1. An integrated simulation method for shale oil fracturing, well blocking and drainage, characterized in that: The integrated simulation method for shale oil fracturing, well blocking and drainage includes: Step 1, establishing a discrete matrix system; Step 2, establishing a discrete crack system; Step 3: construct an embedded discrete fracture-dual medium coupled seepage model; Step 4, distinguish different stages and obtain pore pressure according to the working system; Step 5: Calculate and update the physical property parameters at each time step in different stages; Step 6: Solve the control equations of the embedded discrete fracture-dual medium coupled seepage model in the current time step, and perform an integrated simulation of the shale oil fracturing stage, well blocking stage, and drainage stage.

2. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 1, characterized in that: In step 1, the model grid parameters and the initial porosity / permeability parameters of the inorganic matter are input, the initial apparent porosity / permeability of the organic matter is calculated based on the initial porosity / permeability parameters, and the DK model is used to subdivide and characterize the organic and inorganic matter.

3. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 2, characterized in that: In step 1, the apparent permeability of the fracture is: In the above formula: is the initial apparent permeability of the fracture; p Fint is the initial pressure of the crack during the fracturing stage; H f is the crack height, in m; u is the apparent Poisson's ratio; E is the elastic modulus, in MPa; P f is the net pressure of the fluid in the fracture, in MPa; is the apparent porosity of the fracture; The apparent porosity of the fracture is: In the above formula: is the initial apparent porosity of the fracture; V m (t) is the volume of proppant injected at time t, in m 3 ;x f is the length of the vertical crack in m.

4. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 1, characterized in that: In step 2, the spatial location and related properties of the hydraulic fracture plane are input, and ADFNE is used to randomly generate a natural fracture network and discretize the fracture plane based on the existing matrix system.

5. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 1, characterized in that: In step 3, the matrix and fracture unit grid structures and rock properties are integrated, the flow properties of organic matter, inorganic matter and fractures are given respectively, the initial conditions are determined and boundary conditions are added, and the simulation end time t of each stage of fracturing, well blocking and production is determined. f , t s , t p and total time.

6. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 1, characterized in that: In step 4, the current stage is determined based on the initial value and time step: it is divided into fracturing, well blocking, and production stages. The current working system is determined for different stages, and the pore pressure of each medium in the current time step is obtained.

7. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 6, characterized in that: In step 5, according to the working system of different stages, the physical properties of organic matter, inorganic matter and fractures are updated, including the porosity and permeability of each grid, and the pore volume, conductivity coefficient and wellbore index are further calculated and updated; if the current time step is at the end time of the fracture stage or the end time of the wellbore blocking stage, the parameters at the end of the previous stage are assigned as the initial parameters of the next stage.

8. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 7, characterized in that: In step 5, in the embedded discrete fracture-dual medium coupled seepage model, when shale oil is in the fracturing stage: The permeability of the crack is: In the above formula: is the permeability of the fracture during the fracturing stage; p Fint is the initial pressure of the crack during the fracturing stage; H f is the crack height, in m; u is the apparent Poisson's ratio; E is the elastic modulus, in MPa; P f is the net pressure of the fluid in the fracture, in MPa; is the porosity of the fracture; The porosity of the crack is: In the above formula: V is the porosity of the fracture during the fracturing stage; m (t) is the volume of proppant injected at time t, in m 3 ;x f is the length of the vertical crack in m.

9. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 7, characterized in that: In step 5, in the embedded discrete fracture-dual medium coupled seepage model, when shale oil is in the well blocking stage: The permeability of the crack is: In the above formula: is the permeability of the fracture in the well blocking stage; p Sint is the initial pressure of the fracture in the well blocking stage; σ c is the confining stress; σ1 is the maximum effective stress that completely closes the crack; α b is the stress sensitivity coefficient; is the permeability under zero confining pressure; m is a constant related to the surface roughness of the fracture; is the initial permeability of the fracture in the well blocking stage; F k is the permeability correction factor; The porosity of the crack is: In the above formula: is the porosity of the fractures during the well blocking stage; is the initial porosity of the fracture in the well blocking stage.

10. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 7, characterized in that: In step 5, in the embedded discrete fracture-dual medium coupled seepage model, during the shale oil drainage stage: The apparent porosity of organic matter is: In the above formula: is the apparent porosity of organic matter during the drainage stage; p int is the initial pressure of organic matter and inorganic matter in the drainage stage; C a is the adsorbed gas concentration, mol / m 3 ; Z is the gas compressibility factor; R is the universal gas constant, 8.314 J / (K·mol); T is the reservoir temperature, K; Φ dc is the dynamic porosity; is the volume of gas adsorbed in the elliptical pore; is the volume of gas adsorbed in rectangular pores; V P is the pore volume; is the free gas volume of the elliptical pore; is the free gas volume of rectangular pores; The apparent permeability of organic matter is: In the above formula: is the apparent permeability of organic matter in the drainage stage; α r is the sparse effect correction coefficient, which is a dimensionless quantity; τ is the tortuosity; τ s is the roughness; D a is the surface diffusion coefficient of the adsorbed gas; μ g is the gas viscosity; N is the shape factor grade number; F e is the slip coefficient; is the shape factor, dimensionless; λ dc is the free air pore diameter; N e is the free air pore diameter; Kn Knudsen number; The porosity of inorganic matter is: In the above formula: is the porosity of inorganic matter during the drainage stage; is the initial porosity of inorganic matter in the drainage stage; C im is the compressibility coefficient of inorganic matter; The permeability of inorganic matter is: In the above formula: K im is the permeability of inorganic matter during the drainage stage; is the initial permeability of inorganic matter during the drainage stage; The porosity of the crack is: In the above formula: is the porosity of the fractures during the drainage stage; p Pint is the initial pressure of the fracture during the drainage stage; is the initial porosity of the fracture during the drainage stage; C f is the compression coefficient of the crack; The permeability of the crack is: In the above formula: is the permeability of the fracture during the drainage stage; is the initial permeability of the fracture during the drainage stage; α b is the Biot constant.

11. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 1, characterized in that: In step 6, the control equations of the embedded discrete fracture-dual medium coupled seepage model in the current time step are solved; the two-point flow approximation-finite volume method is used to solve the embedded discrete fracture-dual medium coupled seepage model, and the AD backend combined with the AMG method is used to quickly solve the sparse linear system in the current time step; steps 4 to 6 are repeated until the cumulative simulation time is greater than the total simulation time, thereby performing an integrated simulation of the shale oil fracturing stage, the well blocking stage, and the drainage stage process, and obtaining the medium energy and fluid distribution at different scales throughout the life cycle of shale oil fracturing development.

12. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 11, characterized in that: In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the governing equations of fractures, organic matter, and inorganic matter in shale oil during the fracturing stage are: In the above formula: f i is the crack unit, f i ∈{1,N f }, where N f is the number of crack units in the crack; f is the fracture unit in the fracturing stage i Porosity; is the density of the crack, in kg / m 3 ; For crack f i saturation of the intermediate phase α; f is the fracture unit in the fracturing stage i penetration rate; is the relative permeability of the fluid phase α in the fracture; is the viscosity of the fluid phase α in the fracture; is the potential gradient of the fluid phase α in the fracture during the fracturing stage; is the crack unit f i The opening degree; f is the fracture unit in the fracturing stage i Source and sink terms in ; is the crack unit f i Flow coupling term to inorganic mass unit; is the crack unit f i To the crack unit f j The flow coupling term; is the apparent porosity of organic matter; is the density of organic matter, in kg / m 3 ; is the saturation of fluid phase α in organic matter; is the apparent permeability of organic matter; is the relative permeability of fluid phase α in organic matter; is the viscosity of the fluid phase α in the organic matter; is the potential gradient of fluid phase α in organic matter during the fracturing stage; is the flow coupling term from organic matter unit to inorganic matter unit; is the porosity of inorganic matter during the fracturing stage; is the density of inorganic matter, in kg / m 3 ; is the saturation of the inorganic medium phase α; is the permeability of inorganic matter during the fracturing stage; is the relative permeability of the fluid phase α in the inorganic matter; is the viscosity of the fluid phase α in the inorganic matter; is the potential gradient of fluid phase α in inorganic matter during the fracturing stage; is the flow coupling term from inorganic matter unit to organic matter unit; is the flow coupling term from inorganic element to fracture element.

13. The shale oil fracturing, well blocking and drainage integrated simulation method according to claim 12, characterized in that: In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of fractures, organic matter, and inorganic matter during the well-blocking stage of shale oil are: In the above formula: f is the fracture unit in the well blocking stage i Porosity; f is the fracture unit in the well blocking stage i penetration rate; is the potential gradient of the fluid phase α in the fracture during the well blocking stage; is the potential gradient of the fluid phase α in the organic matter during the well-blocking stage; is the porosity of inorganic matter in the well-blocking stage; is the permeability of inorganic matter in the wellbore stage; is the potential gradient of the inorganic medium phase α during the wellbore stage.

14. The integrated simulation method for shale oil fracturing, well blocking and drainage according to claim 13, characterized in that: In step 6, in the embedded discrete fracture-dual medium coupled seepage model, the control equations of fractures, organic matter, and inorganic matter during the shale oil drainage stage are: In the above formula: The fracture unit f in the drainage stage i Porosity; The fracture unit f in the drainage stage i penetration rate; is the potential gradient of the fluid phase α in the fracture during the drainage stage; is the potential gradient of the flow phase α in the organic matter during the drainage stage; is the porosity of organic matter during the drainage stage; is the permeability of organic matter during the drainage stage; is the potential gradient of the flow phase α in the inorganic matter during the drainage stage.

15. Shale oil fracturing, well blocking and drainage integrated simulation system, characterized by: The shale oil fracturing, well blocking and drainage integrated simulation system adopts the shale oil fracturing, well blocking and drainage integrated simulation method described in any one of claims 1 to 14 to perform integrated simulation of the shale oil fracturing stage, well blocking stage and drainage stage processes, and obtains the medium energy and fluid distribution at different scales throughout the life cycle of shale oil fracturing development.

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