A p-EDFM-based method for evaluating the productivity of marine-continental transitional shale gas

Abstract

This invention discloses a p-EDFM-based method for evaluating the productivity of marine-continental transitional shale gas. Addressing the vertical heterogeneity of marine-continental transitional shale, the matrix grid is layered, and physical property parameters and corresponding apparent permeability models for different rocks are introduced. The fracture surface is dimensionality-reduced based on artificial fracture parameters, and the crossflow coefficient is used to characterize the pressure exchange between grids. Further calculations of flow exchange between different grids are performed, and the productivity of each lithology can be obtained through stratigraphic tracing. The combination of a multiple continuous medium model and an embedded discrete fracture model overcomes the shortcomings of their respective models, better reflecting the widely distributed microfractures, large-scale artificial fractures, and heterogeneous stratigraphic characteristics of transitional shale gas reservoirs. In addition to evaluating the productivity of marine-continental transitional shale gas, the method proposed in this invention can also be extended to the productivity calculation of unconventional oil and gas reservoirs, demonstrating significant application value.

Description

Technical Field

[0001] This invention relates to the field of shale gas exploration and development technology, and in particular to a method for evaluating the production capacity of marine-continental transitional shale gas based on p-EDFM. Background Technology

[0002] The development of shale gas reservoirs in the transitional facies between marine and onshore environments faces numerous challenges, primarily including vertically stacked lithologies, poor lateral continuity, thin favorable stratigraphic layers, and differentiated enrichment patterns in shale gas due to the variability of sedimentary environments. These factors result in significant fluctuations in shale gas well production and make well productivity prediction difficult. Currently, multi-stage hydraulic fracturing horizontal well technology is commonly used for shale gas reservoir development. After hydraulic fracturing, a complex fracture network structure is formed, requiring precise characterization of fracture morphology and physical properties in productivity assessment to ensure the accuracy and reliability of the assessment.

[0003] Fracture characterization methods are mainly divided into explicit and implicit methods. Implicit fracture characterization methods treat a large number of discrete and disordered reservoir fractures as a continuous medium. In 1963, Warren and Root proposed a fracture-matrix dual-medium model, setting porosity and permeability parameters for the two systems separately. In 1976, Kazemi modified the Warren-Root model by constructing a multiphase fluid conduction function considering capillary forces and matrix shape factors. In 1985, Pruess et al. further proposed a multi-medium model, further refining the matrix system in the dual-medium model. These models have become classic methods for implicit fracture characterization and simulating fractured reservoirs. However, for horizontal wells with complex fracture networks, these methods have significant errors compared to reality. To address this, researchers increasingly use explicit fracture characterization methods. Explicit characterization methods model each fracture individually, with the discrete fracture model (DFN) being a commonly used simulation method. The DFN model can well characterize the distribution properties of fractures in the reservoir, but it still suffers from significant distortion in describing the matrix system. To address this, in 2000, Lee et al. proposed the Embedded Discrete Fracture Model (EDFM), which constructs two systems—fracture and matrix—and connects them using connection pairs. EDFM inherits the advantages of the DFN model, effectively constructing complex fracture systems without requiring mesh fitting to the fracture morphology or local refinement, thus significantly reducing computational costs. In 2017, Tene et al. further proposed the p-EDFM model, improving upon EDFM's shortcomings in simulating low-permeability fractures.

[0004] Currently, these methods are typically used to evaluate the productivity of the entire gas reservoir. However, due to the existence of multiple strata in marine-continental transitional shale, it is difficult to accurately track the productivity changes of each stratum. Therefore, there is an urgent need to conduct targeted research to optimize the calculation methods of existing models and achieve accurate tracking of the production of each stratum in marine-continental transitional shale. Summary of the Invention

[0005] To address the problem that existing gas reservoir productivity evaluation methods are unable to accurately track productivity changes in each stratum of marine-continental transitional shale, this invention provides a p-EDFM-based method for evaluating the gas productivity of marine-continental transitional shale.

[0006] The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM provided by this invention comprises the following steps:

[0007] S1: Obtain basic parameters of reservoir, fracture, and well;

[0008] The parameters obtained include the geometric parameters of the matrix, fractures, and well, the basic physical properties of the matrix and fractures, and the gas-water permeability curves and capillary force curves of the matrix and fractures, as well as the gas-water two-phase PVT data, wellbore parameters, and skin factor.

[0009] S2: Use orthogonal meshes to divide the matrix and use an embedded discrete crack model to couple natural cracks, artificial cracks and matrix meshes.

[0010] The matrix and cracks are coupled using connection pairs. Specifically, this includes the following three types of connection pairs:

[0011] The first method involves calculating the connection between the crack mesh and the matrix mesh when they intersect.

[0012]

[0013] in,

[0014]

[0015] In the formula, the subscript i represents the crack mesh, and the subscripts j and k represent the matrix mesh; G mf For the connection pair of the crack mesh and the matrix mesh, m 3 G m For the connection pairs between matrix meshes, m 3 G f For the connection pairs between crack meshes, m 3 A mf m is the projected area of ​​the crack mesh onto the matrix mesh. 2 ;k m The matrix permeability is expressed in μm. 2 ;k f The permeability of the fracture is expressed in μm. 2 ;d mf The characteristic distance between the matrix mesh and the crack mesh is m; is the crack; A f m is the crack area. 2 ; Let m be the crack aperture of crack mesh i; x be the crack opening.n dV is the normal distance from the volumetric element to the crack, in meters; dV is the volumetric element of the mesh block, in meters. 3 V is the mesh volume, m 3 .

[0016] The second method involves calculating the connection pairs of different cracks when they intersect.

[0017]

[0018] in,

[0019]

[0020] In the formula, G ff For the connection pairs where different crack meshes intersect, m 3 G ffi For the connection pair of the i-th crack mesh, m 3 ;β c k is the shape factor, which is dimensionless. fi Let be the permeability of the i-th crack mesh, in μm. 2 ;ω fi Let m be the aperture of the i-th crack; L be the value of the crack. int The length of the intersection line of the two cracks, in meters (m); d fi dS is the average distance from the i-th crack mesh to the intersection line, in meters; i Let m be the area element of the i-th crack mesh. 2 S i Let m be the area of ​​the i-th crack mesh. 2 ;x n Let m be the normal distance from the area element to the intersection line of the crack.

[0021] The third method involves calculating the connection pairs of adjacent crack meshes within the same crack:

[0022]

[0023] in,

[0024]

[0025] In the formula, G f m represents the connection pair when adjacent crack meshes intersect. 3 G fi For the connection pair of the i-th crack mesh, m 3 ;β c k is the shape factor, which is dimensionless. fi Let be the permeability of the i-th crack mesh, in μm. 2 A f The common area of ​​adjacent cracks, m 2;d fi Let m be the average distance from the i-th crack mesh to the intersection line.

[0026] S3: Set the crack mesh where the wellbore intersects with the artificial crack to a wellbore mesh;

[0027] When a fracture intersects with the wellbore mesh, the fracture mesh at the intersection with the wellbore trajectory is treated as a wellbore mesh, and the calculation method is as follows:

[0028]

[0029] in,

[0030]

[0031] In the formula, WI is the fracture-to-wellbore connection coefficient, m 3 Δθ is the angle between the wellbore trajectory and the fracture center, dimensionless; k f The permeability of the fracture is expressed in μm. 2 ;ω f For crack aperture, m; r e For the effective wellbore radius, m; r w L is the actual wellbore radius, in meters; s is the skin coefficient, dimensionless. f Where h is the crack length, in meters (m); f Let be the height of the crack segment, in meters (m).

[0032] S4: Calculate the apparent permeability of the matrix, using appropriate calculation methods depending on the matrix type:

[0033] (1) For shale layers, the formula for calculating apparent permeability is as follows:

[0034]

[0035] in,

[0036]

[0037] In the formula, ρ g The density of gas in porous media is kg / m³. 3 μ g K0 is the gas viscosity in the porous medium, Pa·s; k0 is the permeability of the porous medium, μm. 2 Kn is the Knudsen coefficient, dimensionless; λ is the mean free path of the molecule, m; D is the diameter of the gill, m; M g ρ is the molar mass of a gas molecule, g / mol; P is the pressure in the porous medium, MPa; Z is the compressibility factor, dimensionless; R is the gas constant, with a value of 8.31 × 10⁻⁶. -3J / (mol·K); T is the temperature of the porous medium, K; α is the gas rarefaction coefficient, dimensionless; b is the slip factor, dimensionless; C g The gas compressibility coefficient is expressed in MPa. -1 ;D sur Let m be the gas surface diffusion coefficient. 2 / s;P sc Atmospheric pressure under standard conditions, MPa; T sc Temperature under standard conditions, K; ρ r Density of rock, g / cm³ 3 ;P L Langmuir pressure, MPa; V L Let m be the volume of langmuir. 3 .

[0038] (2) For sandstone reservoirs, the formula for calculating apparent permeability is as follows:

[0039]

[0040] (3) For coal-rock reservoirs, the formula for calculating apparent permeability is as follows:

[0041]

[0042] S5: Deriving seepage equations for the matrix, natural fractures, and artificial fractures based on the continuity equation and the motion equation:

[0043] The equation for vapor phase flow in the matrix is:

[0044]

[0045] in,

[0046]

[0047] In the formula, k mg m is the absolute permeability of the matrix. 2 ;k app,m B represents the apparent permeability of the matrix, which is dimensionless. mg μ is the gas phase volume coefficient of the matrix, dimensionless. mg P is the viscosity of the gas phase, Pa·s; mg The pressure of the matrix system is MPa; ρ mg The density of the matrix gas phase is kg / m³. 3 g is the acceleration due to gravity, 9.8 m / s². 2 h m The height of the matrix system is represented in meters (m); q fm,g The gas phase flow exchange rate between the fracture system and the matrix system, m 3 / s;φm S represents the porosity of the matrix, dimensionless; mg ρ represents the matrix gas phase saturation, which is dimensionless. r Density of the matrix rock, kg / m³ 3 ;q dec For matrix desorption flow rate, m 3 / kg·s;V e The amount of adsorbed gas at adsorption equilibrium is m. 3 / kg.

[0048] The vapor phase seepage equation for other systems (natural and artificial fractures) is:

[0049]

[0050] In the formula, the subscript s represents the system type, f represents natural cracks, and F represents artificial cracks; q exc,g m represents the gas phase flow exchange between this system and other systems. 3 / s;k s,g m is the absolute penetration rate of the system. 2 ;k s,rg B represents the relative gas-phase permeability of the system, dimensionless. s,g μ is the gas phase volume coefficient of the system, dimensionless. s,g P represents the viscosity of the gas phase in this system, in Pa·s; s,g The system pressure is given in MPa; ρ s,g The gas phase density of the system is kg / m³. 3 h s The height of the system, in meters (m); φ s S represents the porosity of the system, dimensionless; s,g Let be the gas phase saturation of the system, dimensionless.

[0051] The equation for liquid phase flow is:

[0052]

[0053] In the formula, the subscript s represents the system type, m represents the matrix, f represents natural cracks, and F represents artificial cracks; k s,w m is the absolute penetration rate of the system. 2 ;k s,rw B represents the relative liquid phase permeability of the system, dimensionless; s,w μ is the number of liquid phase systems in the system, dimensionless. s,w P represents the liquid phase viscosity of the system, Pa·s; s,w The system pressure is expressed in MPa; q exc,w m represents the liquid phase flow exchange between this system and other systems. 3 / s;ρ w Density of formation water, kg / m³3 h s The height of the system, in meters (m); φ s S represents the porosity of the system, dimensionless; s,g The water phase saturation of the system is dimensionless.

[0054] S6: The seepage equation is discretized using the finite volume method, and the discretized result is solved using the fully implicit Newton-Raphson iteration method to establish the final mathematical model.

[0055] The results of discretizing the seepage equation using the finite volume method are as follows:

[0056]

[0057] in,

[0058]

[0059] ψ i,s =P i,s -ρ i,s gh i,s , ψ j,s =P j,s -ρ j,s gh j,s

[0060] In the formula, subscripts i and j represent adjacent meshes i and j; subscript s represents the system type, m represents the matrix, f represents natural fractures, and F represents artificial fractures; subscript l represents the fluid type, w represents the aqueous phase, and g represents the gaseous phase; T ij,s Here, A represents the conductivity of grids i and j, in kg / Pa·s. i,j Let m be the common area of ​​grid i and grid j. 2 ;k l,s m is the fluid permeability of the system. 2 μ l,s Here is the fluid viscosity of the system, Pa·s; B l,s Let be the fluid saturation of the system, dimensionless; Let i be the dimensionless vector pointing from the center of grid i to the common surface. Let be the dimensionless vector pointing from the center of grid j to the common surface. ψ is the normal vector of the common plane, dimensionless; i,s Let ψ be the potential of grid i, MPa; j,s Let n be the potential of grid j, MPa; n is the current time step, dimensionless. Let be the dimensionless mass density in grid i of different systems at time step n+1. Let m be the flow rate in grid i of different systems at time step n+1. 3 / s;ΔVi Let P be the volume of grid i; Δt be the time step, in seconds; P i,s For the pressure of grid i in different systems, MPa; ρ i,s The fluid density in grid i of different systems is given in kg / m³. 3 h i,s Let m be the height of grid i in different systems.

[0061] Furthermore, the numerical equations obtained by solving are as follows:

[0062]

[0063] In the formula, Let m be the gas phase flow rate at step n+1. 3 / s; m is the liquid phase flow rate at step n+1. 3 / s; These represent the coefficients of the gas phase pressure change in the i-th and j-th grids at the current time step, respectively. These represent the coefficients of the liquid phase pressure change in the i-th and j-th grids at the current time step, respectively. These represent the coefficients of the change in gas saturation of the i-th and j-th grids at the current time step, respectively. Let represent the coefficients of liquid phase saturation change of the i-th and j-th grids at the current time step; g represents the gas phase, w represents the liquid phase; δP i δS represents the change in pressure. i d represents the change in saturation. g d represents the coefficients of gas phase flow exchange in the i-th and j-th grids at the current time step; w is the coefficient of liquid phase flow exchange rate for the i-th and j-th grids at the current time step.

[0064] S7: Use the mathematical model established in step S6 to evaluate the production capacity of marine-continental transitional shale gas, record the flow rate between each system at each time step, the system includes three systems: natural fractures, artificial fractures and matrix; further calculate the production of each layer.

[0065] The formulas for calculating the flow of each system are as follows:

[0066] ∑Q=∑λGΔP ij

[0067] In the formula, Q represents the flow between different systems, and m 3 / s; λ is the fluid mobility, m 2 ·s / kg; G represents the connection pair; ΔP ij The pressure difference between the two grids is expressed in MPa.

[0068] Furthermore, when calculating the production rate in step S7, the overall flow rate from the hydraulic fracturing fractures to the wellbore is calculated, which cannot accurately determine the production rate of a specific layer. Therefore, it is necessary to calculate the flow rates from the matrix and microfractures to the artificial fractures, and determine the specific production layer based on the grid numbers corresponding to the matrix and microfractures.

[0069] The flow rate of the matrix to the artificial crack is:

[0070] Q l =G mF λ l (P m -P F )

[0071] In the formula, the subscript l represents the fluid type, g for gas phase and w for liquid phase; Q l m is the fluid flow rate from the matrix to the artificial fracture. 3 / s;G mF The connection pair between the matrix and the artificial crack is dimensionless; λ l For fluid mobility, m 2 ·s / kg; P m P represents the pressure of the matrix mesh, in MPa; F The pressure of the artificial crack mesh is MPa.

[0072] The flow rate from natural fissures to artificial fissures is:

[0073] Q l =G fF λ l (P f -P F )

[0074] In the formula, G fF For the connection pair of natural and artificial cracks, dimensionless; P f The pressure of the natural cracked mesh is MPa.

[0075] Compared with the prior art, the advantages of the present invention are:

[0076] (1) This invention is based on the p-EDFM model, using a multi-continuous medium model and an embedded discrete fracture model. By dividing the target strata into matrix grids, microfracture grids, and artificial fracture grids, it achieves accurate characterization of complex fracture systems. For the vertical heterogeneity of marine-continental transitional shale, a layered processing method is adopted to process the matrix grid into layers and introduce physical property parameters of different rock types and corresponding apparent permeability models, making the description of fracture morphology and seepage characteristics more accurate.

[0077] (2) The fracture surface is reduced in dimension based on the parameters of the artificial fracture. The pressure exchange between the grids is characterized by the crossflow coefficient. The flow exchange between different grids is further calculated, and the pressure and flow exchange process between the grids is optimized. Combined with the stratigraphic tracking technology, the output of each lithology can be accurately obtained, thus solving the technical problem that traditional models cannot accurately track the stratigraphic production capacity.

[0078] (3) The combination of the multiple continuous medium model and the embedded discrete fracture model overcomes the shortcomings of their respective models. The combination of the two can better reflect the heterogeneous strata characteristics of microfractures, large-scale artificial fractures and transitional facies shale gas reservoirs that are widely distributed in shale gas reservoirs.

[0079] (4) The method of the present invention can not only improve the accuracy of the evaluation of the production capacity of shale gas reservoirs in the transitional marine-continental phase, but also has low computational cost and high model adaptability. It is suitable for the development and evaluation of unconventional oil and gas reservoirs and has wide application value.

[0080] Other advantages, objectives and features of the present invention will become apparent in part from the following description, and in part from those skilled in the art through study and practice of the invention. Attached Figure Description

[0081] Figure 1 This is a flowchart of the p-EDFM-based method for evaluating the production capacity of marine-continental transitional shale gas.

[0082] Figure 2 This invention provides a comparison of the evaluation method of this invention with the performance of commercial software.

[0083] Figure 3 This is a comparison chart of the output of each layer in the embodiment. Detailed Implementation

[0084] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0085] The data used in this embodiment comes from the publicly available literature (Numerical Simulation Study on Combined Mining of Shale Reservoirs in the Marine-Continental Transitional Facies, Chen Xuezhong, 2024), and the model parameter settings are shown in Table 1.

[0086] Table 1 Model Parameter Settings

[0087] Model parameters coal seam Shale layer dense sandstone layers Matrix porosity / % 6 3 4 <![CDATA[Matrix permeability / 10 -3 um 2 > 0.1 0.001 0.01 <![CDATA[Langmuir volume / (m 3 / t)]]> 13.98 2.35 —— Langmuir pressure / MPa 2.5 3.6 —— Matrix water saturation 0 0 40 Hydraulic fracture opening 0.01 0.01 0.01 Hydraulic fracture permeability 1 1 1 Hydraulic fracture porosity 0.01 0.01 0.01

[0088] according to Figure 1The process shown derives the differential equations for gas-water two-phase flow based on coupled p-EDFM and a multiple continuum model. The mathematical model is obtained using the method described in this invention, and a related numerical simulator is written using the Python programming language. A gas reservoir model of 1800m × 560m × 40m (length × width × height) is established with a mesh size of 40m × 40m × 10m. Eight hydraulic fractures are evenly distributed on both sides of the horizontal wellbore, and the simulated production time is 800 days. The written numerical simulator is verified using the commercial software CMG, and the verification results are as follows: Figure 2 As shown, the model established using the method of this invention fits well with commercial software, indicating that the model obtained by this invention can accurately characterize the seepage situation at each layer, and the numerical model calculation results obtained are reasonable and reliable. Figure 3 The comparison diagram of the production of each stratum shows the contribution rate of each lithological production, which is helpful for carrying out research on the complex seepage mechanism of marine-continental transitional shale gas reservoirs.

[0089] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM, characterized in that, Includes the following steps: S1: Obtain basic parameters of reservoir, fracture, and well; S2: Use orthogonal meshes to divide the matrix and use an embedded discrete crack model to couple natural cracks, artificial cracks and matrix meshes; S3: Set the crack mesh where the wellbore intersects with the artificial crack to a wellbore mesh; S4: Calculate the apparent permeability of the matrix, using appropriate calculation methods depending on the matrix type: (1) For shale layers, the formula for calculating apparent permeability is as follows: in, In the formula, ρ g The density of gas in porous media is kg / m³. 3 μ g K0 is the gas viscosity in the porous medium, Pa·s; k0 is the permeability of the porous medium, μm. 2 Kn is the Knudsen coefficient, dimensionless; λ is the mean free path of the molecule, m; D is the diameter of the gill, m; M g ρ is the molar mass of a gas molecule, g / mol; P is the pressure in the porous medium, MPa; Z is the compressibility factor, dimensionless; R is the gas constant, with a value of 8.31 × 10⁻⁶. -3 J / (mol·K); T is the temperature of the porous medium, K; α is the gas rarefaction coefficient, dimensionless; b is the slip factor, dimensionless; C g The gas compressibility coefficient is expressed in MPa. -1 ;D sur Let m be the gas surface diffusion coefficient. 2 / s;P sc Atmospheric pressure under standard conditions, MPa; T sc Temperature under standard conditions, K; ρ r Density of rock, g / cm³ 3 ;P L Langmuir pressure, MPa; V L Let m be the volume of langmuir. 3 ; (2) For sandstone reservoirs, the formula for calculating apparent permeability is as follows: (3) For coal-rock reservoirs, the formula for calculating apparent permeability is as follows: S5: Derive the seepage equations for the matrix, natural cracks, and artificial cracks based on the continuity equation and the motion equation; S6: The seepage equation is discretized using the finite volume method, and the discretized result is solved using the fully implicit Newton-Raphson iterative method to establish the final mathematical model; the numerical equations obtained are as follows: In the formula, Let m be the gas phase flow rate at step n+1. 3 / s; m is the liquid phase flow rate at step n+1. 3 / s; These represent the coefficients of the gas phase pressure change in the i-th and j-th grids at the current time step, respectively. These represent the coefficients of the liquid phase pressure change in the i-th and j-th grids at the current time step, respectively. These represent the coefficients of the change in gas saturation of the i-th and j-th grids at the current time step, respectively. Let represent the coefficients of liquid phase saturation change of the i-th and j-th grids at the current time step; g represents the gas phase, w represents the liquid phase; δP i δS represents the change in pressure. i d represents the change in saturation. g d represents the coefficients of gas phase flow exchange in the i-th and j-th grids at the current time step; w The coefficients for the liquid phase flow rate exchange rate of the i-th and j-th grids at the current time step; S7: Use the mathematical model established in step S6 to evaluate the production capacity of marine-continental transitional shale gas, record the flow rate between each system at each time step, the system includes three systems: natural fractures, artificial fractures and matrix; further calculate the production of each layer.

2. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, In step S6, the discretization of the seepage equation using the finite volume method yields the following results: in, ψ i,s =P i,s -r i,s gh i,s ,ψ j,s =P j,s -r j,s gh j,s In the formula, subscripts i and j represent adjacent meshes i and j; subscript s represents the system type, m represents the matrix, f represents natural fractures, and F represents artificial fractures; subscript l represents the fluid type, w represents the aqueous phase, and g represents the gaseous phase; T ij,s Here, A represents the conductivity of grids i and j, in kg / Pa·s. i,j Let m be the common area of ​​grid i and grid j. 2 ;k l,s m is the fluid permeability of the system. 2 μ l,s Here is the fluid viscosity of the system, Pa·s; B l,s Let be the fluid saturation of the system, dimensionless; Let i be the dimensionless vector pointing from the center of grid i to the common surface. Let be the dimensionless vector pointing from the center of grid j to the common surface. ψ is the normal vector of the common plane, dimensionless; i,s Let ψ be the potential of grid i, MPa; j,s Let n be the potential of grid j, MPa; n is the current time step, dimensionless. Let be the dimensionless mass density in grid i of different systems at time step n+1. Let m be the flow rate in grid i of different systems at time step n+1. 3 / s;ΔV i Let P be the volume of grid i; Δt be the time step, in seconds; P i,s For the pressure of grid i in different systems, MPa; ρ i,s The fluid density in grid i of different systems is given in kg / m³. 3 h i,s Let m be the height of grid i in different systems.

3. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, The parameters obtained in step S1 include the geometric parameters of the matrix, fractures, and well, the basic physical properties of the matrix and fractures, and the gas-water phase permeability curves and capillary force curves of the matrix and fractures, as well as the gas-water two-phase PVT data, wellbore parameters, and skin factor.

4. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, In step S2, the matrix and cracks are coupled using connection pairs, including the following three types of connection pairs: First, when the crack mesh and the matrix mesh intersect, the connection pair between the crack mesh and the matrix mesh; Second, when different cracks intersect, the connection pair between different cracks; Third, the connection pair between adjacent crack meshes within the same crack.

5. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, In step S3, when a fracture intersects with a wellbore grid, the fracture grid intersecting with the wellbore trajectory is processed into a wellbore grid.

6. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, In step S5, the seepage equations include the gas phase seepage equation in the matrix, the gas phase seepage equation and the liquid phase seepage equation in natural fractures, and the gas phase seepage equation and the liquid phase seepage equation in artificial fractures.

7. The method for evaluating the productivity of marine-continental transitional shale gas based on p-EDFM as described in claim 1, characterized in that, In step S7, the formulas for calculating the flow rate of each system are as follows: ∑Q=∑λGΔP ij In the formula, Q represents the flow between different systems, and m 3 / s; λ is the fluid mobility, m 2 ·s / kg; G represents the linking pair; ΔP ij The pressure difference between the two grids is expressed in MPa.

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