Predictive methods for fluid migration behavior during CO2 injection mining of coal seams with natural fractures

Abstract

This invention provides a method for predicting fluid migration behavior during CO2 injection mining of coal seams containing natural fractures, belonging to the field of coalbed methane exploration. The method includes: constructing a flow model suitable for describing fluid migration velocity within fractures and a modified gas-phase mass conservation equation; constructing a geological model of a coalbed methane reservoir containing natural fractures based on exploration data, dividing the model into grids, and setting initial and boundary conditions; and solving for the spatiotemporal evolution characteristics of methane and carbon dioxide concentrations within each grid cell of the geological model based on the modified gas-phase mass conservation equation, obtaining their temporal and spatial distributions. This invention fully considers the influence of the presence of natural fractures in coalbed methane on the migration behavior of methane and carbon dioxide, overcoming the limitations of existing studies that neglect the role of natural fractures, leading to biased prediction results, and achieving accurate prediction of fluid migration behavior during CO2 injection mining of coal seams containing natural fractures.

Description

Technical Field

[0001] This invention belongs to the field of coalbed methane exploration and development, specifically relating to a method for predicting fluid migration behavior during CO2 injection mining of coal seams containing natural fractures. Background Technology

[0002] Enhanced Coal Bed Methane Recovery (CO2-ECBM) technology is a key technological approach that balances efficient coalbed methane development with carbon emission reduction. Its core logic involves injecting carbon dioxide into the coal seam, utilizing its stronger adsorption affinity for the coal matrix to displace methane adsorbed on the coal surface, thereby achieving efficient coalbed methane extraction. Compared to traditional single-extraction coalbed methane extraction methods, this technology not only significantly improves the ultimate recovery rate of coalbed methane but also stably sequesters the injected carbon dioxide within the coal seam, creating a long-term carbon sequestration effect. This helps reduce greenhouse gas emissions and facilitates the large-scale development of low-carbon clean energy, making it an important tool for synergistically promoting energy utilization and environmental protection. Simultaneously, the adsorption and diffusion behavior of CO2 within the coal seam, as well as the competitive adsorption process with methane, provides a new research platform for elucidating the gas migration mechanisms and adsorption characteristics of coal reservoirs. Therefore, in-depth research on the multi-field coupling mechanism and dynamic evolution law in CO2-enhanced coalbed methane extraction has important theoretical guidance and engineering practical value for improving the utilization efficiency of coalbed methane resources and promoting the recycling of carbon resources.

[0003] Current mainstream research on CO2-displaced coalbed methane (CO2-ECBM) still assumes homogeneous coal seams, focusing on the replacement capacity of CO2 and CH4 and gas production performance. However, this premise deviates significantly from the actual geological situation—natural fractures are widely developed in coal seams but have long been overlooked. Geological exploration has confirmed that brittle components such as vitrinite and soluble minerals such as calcite in coal rock are prone to induce the formation of natural fractures during geological evolution, and these fractures are often interconnected to form a continuous network. The permeability of these natural fractures is 2 to 4 orders of magnitude higher than that of the coal matrix (typically 0.01~1 mD), which completely changes the gas transport pattern within the coal seam: the "uniform diffusion" under the original homogeneous assumption is transformed into "rapid conduction along the dominant path" along fracture channels. This change not only exacerbates the heterogeneity of CO2-CH4 two-phase transport but also makes the adsorption-desorption kinetics more complex. The traditional Darcy's law can no longer accurately describe this type of fluid seepage-transport behavior, necessitating the construction of a flow model suitable for describing the fluid transport velocity within fractures. Ignoring the influence of natural fractures will lead to biased judgments on gas migration behavior, making it difficult to reflect the true displacement mechanism. Therefore, it is necessary to systematically incorporate the flow process of natural fractures into the CO2-CH4 displacement model to reveal the migration characteristics of single-phase gas in fractured coal seams, thereby improving the accuracy of fluid migration behavior prediction during CO2 injection mining of coal seams with natural fractures. Summary of the Invention

[0004] The purpose of this invention is to provide a method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures, so as to achieve accurate prediction of the fluid migration behavior of CH4 and CO2 in coal seams under CO2 injection mining conditions, thereby clarifying the influence of natural fracture development characteristics on the spatiotemporal evolution of CH4 and CO2 concentrations, and providing theoretical and technical support for CO2-ECBM engineering exploration and development of coal seams with natural fractures.

[0005] The technical solution of this invention is as follows:

[0006] A method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures includes the following steps:

[0007] S1: Based on the gas transport characteristics of the natural fracture-matrix dual medium, a flow model suitable for describing the fluid transport velocity within the fracture is constructed; a modified mass conservation equation for methane and carbon dioxide is established.

[0008] S2: Construct a geological model of a coalbed methane reservoir containing natural fractures based on actual exploration data and a random fracture generation function. Perform unstructured grid subdivision on the geological model of the coalbed methane reservoir and set initial and boundary conditions for the geological model of the coalbed methane reservoir based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions.

[0009] S3: Apply the modified mass conservation equation constructed in step S1 to the geological model of a coalbed methane reservoir with natural fractures, in which the grid division, initial conditions and boundary conditions were set in step S2, to solve for the relevant characteristics of fluid migration behavior, thereby realizing the effective prediction of fluid migration behavior during CO2 injection mining of coal seams with natural fractures.

[0010] Furthermore, in step S1, the flow model construction process for fluid transport velocity is as follows:

[0011] To address the non-Darcy flow characteristics of fluids in coal seams containing natural fractures, an inertial force correction term is introduced into Darcy's law to obtain a modified Darcy's law. A gas phase velocity calculation equation is then constructed using this modified Darcy's law to accurately describe the transport velocities of methane and carbon dioxide within the fractures. The expression for the gas phase velocity calculation equation is as follows:

[0012]

[0013]

[0014] In the formula, The methane flow rate; The permeability of methane; The viscosity of methane; Methane pressure; The density of methane; It is the acceleration due to gravity; This refers to the carbon dioxide flow rate; Carbon dioxide permeability; Carbon dioxide pressure; The viscosity of carbon dioxide; The density of carbon dioxide; Inertial force correction term (non-Darcy term); This is the non-Darcy flow coefficient.

[0015] Furthermore, in step S1, the modified mass conservation equations for methane and carbon dioxide are established based on the following:

[0016] Based on the obtained gas phase flow rate calculation equation, combined with the gas phase saturation calculation equation and the Langmuir gas adsorption equation, adsorption source term parameters are provided for the methane mass conservation equation and the carbon dioxide mass conservation equation, achieving an accurate description of the entire gas transport process; the corrected gas phase mass conservation equation is as follows:

[0017]

[0018]

[0019] in, The effective porosity of coal seams containing natural fractures; This represents the saturation level of the gas phase (methane and carbon dioxide). For Hamiltonian operators; This represents the mass fraction of methane in the gas phase. The rate of methane mass reduction due to adsorption; Indicates the mass of methane adsorbed; This represents the mass fraction of carbon dioxide in the gas phase. The rate of decrease in carbon dioxide mass due to adsorption; The mass of carbon dioxide adsorbed.

[0020] Furthermore, the gas phase saturation in the modified gas phase mass conservation equation... Calculated by the following formula:

[0021]

[0022] In the formula, The density is the gas phase density. ; The gas flow rate is... ; This is the mass source term for gas adsorption.

[0023] Furthermore, the mass source term in the modified gas-phase mass conservation equation includes the adsorption process, thus constructing the Langmuir gas adsorption equation:

[0024]

[0025]

[0026] In the formula, The mass of methane adsorbed; This represents the saturated adsorption volume of methane. Methane pressure; The pressure of methane after reaching saturation adsorption capacity; The mass of carbon dioxide adsorbed; This represents the saturated adsorption volume of carbon dioxide. Carbon dioxide pressure; The pressure of carbon dioxide after reaching saturation adsorption capacity.

[0027] Furthermore, the specific process of step S2 is as follows:

[0028] S2.1: Collect actual exploration data of coalbed methane reservoirs in the target area, including the horizontal width and vertical height range of the coalbed methane reservoirs, as well as geological parameters such as porosity, permeability, density, length, direction, and pore size of natural fractures. At the same time, obtain physical property parameters such as porosity, permeability, and reservoir density of the coal matrix; construct an initial reservoir model of the CO2-ECBM target area without natural fractures.

[0029] S2.2: Based on the above exploration data and random fracture generation function, construct a discrete fracture network model and complete the fracture attribute settings. Add the discrete fracture network model to the initial reservoir model obtained in step S2.1 to construct a geological model of coalbed methane reservoir containing natural fractures that fits the real geological conditions. This model can accurately reflect the spatial distribution difference between the dense natural fracture area and the matrix area.

[0030] S2.3: The geological model of coalbed methane reservoirs containing natural fractures is divided using a free triangular unstructured grid. The grid is densified in areas with dense natural fractures and conventional grid is used in coal matrix areas. The size of the largest grid cell is controlled to be 3 times the size of the smallest grid cell to ensure that the grid cells accurately reflect the reservoir differences in different spatial locations.

[0031] S2.4: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set the initial conditions for the geological model of coalbed methane reservoir with natural fractures. The initial conditions include the initial coalbed methane reservoir pressure, the initial coalbed methane reservoir temperature, the initial gas phase saturation, and the initial methane concentration and carbon dioxide concentration.

[0032] S2.5: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set boundary conditions for the geological model of coalbed methane reservoirs with natural fractures. The boundary conditions include the upper boundary pressure, lower boundary pressure, methane production well pressure, carbon dioxide injection well pressure, and well boundary gas concentration of methane production well and carbon dioxide injection well.

[0033] Furthermore, the discrete fracture network model is constructed based on a random fracture generation function, and the discrete fracture network model is characterized by the distribution characteristics of natural fractures, including the location distribution characteristics, length distribution characteristics, orientation distribution characteristics, and pore size distribution characteristics of natural fractures.

[0034] The location distribution characteristics of the natural fissures for:

[0035]

[0036] Where x represents the location of the crack; , These are the minimum and maximum boundary coordinates of the reservoir where the natural fracture is located in a certain direction (xy), and the center or end point of the fracture is randomly generated within this interval.

[0037] The length distribution characteristics of the natural fissures for:

[0038]

[0039] in, The power law exponent has a value range of 2.0 to 3.5. Let be a random variable, representing the actual length of a single natural fracture within the reservoir; This represents the minimum characterizable length of a natural fracture within a coalbed methane reservoir. This represents the maximum extension length of natural fissures, and this distribution conforms to the actual characteristics of natural fissures: "many small fissures and few large fissures."

[0040] The directional distribution characteristics of the natural fissures for:

[0041]

[0042] in, Angular deviation of the natural fracture direction, unit: rad; The dispersion coefficient ranges from 0.1 to 10. The larger the angle, the more concentrated the direction is around the mean angle;

[0043] The pore size distribution characteristic b of the natural fracture is:

[0044]

[0045] Among them, the fracture aperture It is proportional to the crack length L. It is a proportionality constant; this function satisfies the geological law that the longer the fracture, the larger its aperture.

[0046] Furthermore, the specific implementation of step S3 is as follows:

[0047] Substitute the revised methane and carbon dioxide mass conservation equations from step S1 into the geological model of the coalbed methane reservoir with natural fractures obtained in step S2, and solve for the methane mass fraction in each grid cell of the coalbed methane reservoir geological model. and the mass fraction of carbon dioxide ;

[0048] Based on the obtained methane mass fraction With carbon dioxide mass fraction The gas phase density calculated from the equation of state is used to further derive the molar concentrations of methane and carbon dioxide within each grid cell, thereby obtaining the spatiotemporal evolution characteristics of methane concentration and carbon dioxide concentration.

[0049] An electronic device includes a memory, a processor, and a computer program stored in the memory and executable on the processor; when the processor executes the computer program, the electronic device performs the method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures.

[0050] A storage medium comprising a computer program that, when run on an electronic device, causes the electronic device to perform the method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures.

[0051] The beneficial effects of this invention are as follows: The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures proposed in this invention can reveal the mass migration characteristics of methane and carbon dioxide during CO2-ECBM and quantify long-term methane concentration changes. Compared with existing technologies, this invention fully considers the influence of the presence of natural fractures in coalbed methane on the migration behavior of methane and carbon dioxide in the model, overcoming the limitation of existing studies that ignore the role of natural fractures and thus lead to biased prediction results, achieving accurate prediction of fluid migration behavior during CO2 injection mining of coal seams with natural fractures. Attached Figure Description

[0052] Figure 1 This is a flowchart illustrating the prediction method described in an embodiment of the present invention.

[0053] Figure 2 This is a schematic diagram of a coalbed methane reservoir geological model in an embodiment of the present invention.

[0054] Figure 3 This is a schematic diagram showing the evolution of methane concentration in natural fissures over 20 years, calculated in an embodiment of the present invention.

[0055] Figure 4 This is a schematic diagram illustrating the evolution of carbon dioxide concentration over 20 years with or without natural fissures, calculated in an embodiment of the present invention. Detailed Implementation

[0056] The embodiments of the present invention will be described in further detail below with reference to the accompanying drawings and examples. The following examples are for illustrative purposes only and should not be construed as limiting the scope of the invention.

[0057] like Figure 1As shown, this invention provides a method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures. Specifically, it is a method for predicting methane and carbon dioxide concentrations during CO2 injection mining of coal seams with natural fractures, comprising the following steps:

[0058] S1. Based on the gas transport behavior of natural fractures and matrix, a flow model suitable for describing the fluid transport velocity within fractures is constructed, and a modified mass conservation equation for methane and carbon dioxide is further established; the specific process includes:

[0059] The flow rates of the gaseous components (methane and carbon dioxide) are calculated using the modified Darcy's law. The specific equation for calculating the gaseous flow rate is as follows:

[0060]

[0061]

[0062] In the formula, The methane flow rate; The permeability of methane; The viscosity of methane; Methane pressure; The density of methane; It is the acceleration due to gravity; This refers to the carbon dioxide flow rate; Carbon dioxide permeability; Carbon dioxide pressure; The viscosity of carbon dioxide; The density of carbon dioxide; Inertial force correction term (non-Darcy term); This is the non-Darcy flow coefficient.

[0063] The revised mass conservation equations for methane and carbon dioxide are as follows:

[0064]

[0065] in, The effective porosity of coal seams containing natural fractures; This refers to gas phase saturation. For Hamiltonian operators; The density of methane; This represents the mass fraction of methane in the gas phase. The rate of methane mass reduction due to adsorption; Indicates the mass of methane adsorbed; This represents the mass fraction of carbon dioxide in the gas phase. The rate of decrease in carbon dioxide mass due to adsorption; The mass of carbon dioxide adsorbed;

[0066] Gas saturation in the corrected mass conservation equation for the gas phase Calculated by the following formula:

[0067]

[0068] In the formula, This refers to the gas phase density. This refers to the gas flow rate; For the mass source term of gas adsorption; where,

[0069]

[0070] The mass source term in the modified gas-phase mass conservation equation includes the adsorption process, thus constructing the Langmuir gas adsorption equation:

[0071]

[0072]

[0073] In the formula, The mass of methane adsorbed; This represents the saturated adsorption volume of methane. Methane pressure; The pressure of methane after reaching saturation adsorption capacity; The mass of carbon dioxide adsorbed; This represents the saturated adsorption volume of carbon dioxide. Carbon dioxide pressure; The pressure of carbon dioxide after reaching saturation adsorption capacity.

[0074] S2. Construct a geological model of a coalbed methane reservoir containing natural fractures, perform unstructured mesh generation on the model, and set initial and boundary conditions for the model. The specific process is as follows:

[0075] S2.1: Collect exploration data of coalbed methane reservoirs in the target area, including the horizontal width and vertical height range of the coalbed methane reservoirs, as well as geological parameters such as porosity, permeability, density, length, direction, and pore size of natural fractures. At the same time, obtain physical property parameters such as porosity, permeability, and reservoir density of the coal matrix. First, construct an initial reservoir model (excluding natural fractures) for the CO2-ECBM target area.

[0076] S2.2: Based on the above exploration data and the random fracture generation function, construct a discrete fracture network model and complete the fracture attribute settings. Add the discrete fracture network model to the initial reservoir model obtained in step S2.1 to construct a geological model of a coalbed methane reservoir containing natural fractures that conforms to real geological conditions; specifically including:

[0077] S2.2.1: Construct a discrete fracture network model based on a random fracture generation function. The discrete fracture network model is characterized by the distribution characteristics of natural fractures, including the location distribution characteristics, length distribution characteristics, direction distribution characteristics, and aperture distribution characteristics of natural fractures.

[0078] The location distribution characteristics of the natural fissures Characterized by a uniform random distribution function:

[0079]

[0080] Where x represents the location of the crack; , These are the minimum and maximum boundary coordinates of the reservoir where the natural fracture is located in a certain direction (xy), and the center or end point of the fracture is randomly generated within this interval.

[0081] The length distribution characteristics of the natural fissures Using a power-law distribution function:

[0082]

[0083] in, The power-law exponent is set to 2.0; Let be a random variable, representing the actual length of a single natural fracture within the reservoir; This represents the minimum characterizable length of a natural fracture within a coalbed methane reservoir. This is the maximum extension length of the natural fissure.

[0084] The directional distribution characteristics of the natural fissures Using the Fisher distribution function:

[0085]

[0086] in, Angular deviation of the natural fracture direction, unit: rad; The dispersion coefficient is set to 0.1.

[0087] The pore size distribution characteristic b of the natural fracture adopts a size ratio distribution function:

[0088]

[0089] Among them, the fracture aperture It is proportional to the crack length L. It is a proportionality constant.

[0090] S2.2.2: Add the discrete fracture network model constructed in step S2.2.1 to the initial reservoir model constructed in step S2.1 to obtain a coalbed methane reservoir formation model containing natural fractures.

[0091] S2.3: The geological model of coalbed methane reservoirs containing natural fractures is divided using a free triangular unstructured grid. The grid is densified in areas with dense natural fractures and conventional grid is used in coal matrix areas. The size of the largest grid cell is controlled to be three times the size of the smallest grid cell to ensure that the grid cells accurately reflect the reservoir differences in different spatial locations.

[0092] S2.4: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set the initial conditions for the geological model of coalbed methane reservoirs with natural fractures. The initial conditions include the initial coalbed methane reservoir pressure, the initial coalbed methane reservoir temperature, the initial gas phase saturation, and the initial methane concentration and carbon dioxide concentration.

[0093] S2.5: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set boundary conditions for the geological model of coalbed methane reservoirs with natural fractures. The boundary conditions include the upper boundary pressure, lower boundary pressure, methane production well pressure, carbon dioxide injection well pressure, and well boundary gas concentration of methane production well and carbon dioxide injection well.

[0094] Specifically, such as Figure 2 As shown, in this embodiment, the simulated domain is 150m long, 150m wide, and 5m high. The coal matrix has a porosity of 0.037, a permeability of 5mD, and a reservoir density of 1370kg / m³. 3 The porosity of the natural fracture is 0.018, the permeability is 500 mD, and the linear density is 0.3 m³. -1 Length 1-8m, orientation 50°-80°, orifice diameter 0.01-0.25m. Initial conditions: initial pressure 5 MPa, initial temperature 300 K. Lower boundary pressure 5 MPa, upper boundary pressure 5 MPa. Methane production well pressure 0.5 MPa, carbon dioxide injection well pressure 8 MPa. Initial methane concentration 18.971 kg / m³. 3 The concentration of methane at the perimeter is 0 kg / m³. 3 The initial carbon dioxide concentration was 0 kg / m³. 3 The carbon dioxide concentration at the four boundaries is 0 kg / m³. 3 .

[0095] S3. The modified mass conservation equation constructed in step S1 is applied to the geological model of coalbed methane reservoir after grid partitioning, initial conditions and boundary conditions are set in step S2. The spatiotemporal evolution characteristics of CH4 and CO2 concentrations in each grid cell of the geological model are solved to obtain their distribution in time and space. This enables effective prediction of fluid migration behavior during the extraction of CH4 and CO2 from coal seams with natural fractures.

[0096] Specifically, the methane and carbon dioxide mass conservation equations corrected in step S1 are substituted into the geological model of the coalbed methane reservoir with natural fractures obtained in step S2 to solve for the mass fractions of methane and carbon dioxide in each grid cell of the coalbed methane reservoir geological model. Then, combined with the gas phase density (calculated from the equation of state), the molar concentrations of methane and carbon dioxide in each grid cell are further derived. This concentration distribution directly reflects the spatiotemporal evolution characteristics of the gas within the reservoir, providing fundamental data for analyzing migration patterns and adsorption-desorption kinetics.

[0097] In this embodiment, as Figure 3 This diagram illustrates the calculated methane concentration evolution over 20 years with and without natural fractures. It compares the spatiotemporal evolution of methane molar concentration under CO2 displacement in coal seams with and without natural fractures. Without natural fractures, methane desorption and migration rates are extremely slow, with concentrations at low levels and small diffusion ranges at all time points. With natural fractures, methane migrates rapidly along the dominant fracture pathways, with local increases starting from 100–300 days, exhibiting a gradient distribution across the entire reservoir by 3000 days, and reaching 2.5 × 10⁻⁶ by 7200 days. 3 mol / m 3 The saturated state visually demonstrates the significant promoting effect of natural fissures on methane desorption and migration. For example... Figure 4 This diagram illustrates the evolution of carbon dioxide concentration in coal seams with and without natural fractures over a 20-year period. It compares the spatiotemporal evolution of CO2 concentration in coal seams with and without natural fractures, echoing the evolution of methane. Without natural fractures, CO2 diffusion is slow, resulting in limited concentration increases within the reservoir. With natural fractures, CO2 rapidly infiltrates and fills the reservoir along the fractures, with concentration coverage and values ​​at each time point significantly higher than in the fracture-free group. This clearly verifies that natural fractures are the dominant pathway for CO2 transport in coal seams, and also confirms the rationality and accuracy of the model in this invention in considering natural fractures.

[0098] The embodiments listed in this invention are merely illustrative and explanatory, and are not intended to exhaustively limit the scope of protection of this invention, nor are they intended to confine this invention to the specific implementation forms disclosed. For those skilled in the art, various modifications and variations based on this invention are readily apparent. The selection and description of the above embodiments are intended to more clearly reveal the principles and practical application value of this invention, thereby enabling those skilled in the art to fully understand the technical concept of this invention and design various implementation schemes adapted to specific application scenarios and capable of various adjustments and modifications.

Claims

1. A method for predicting fluid transport behavior during CO2 injection into a naturally fractured coal seam, characterized by, include: S1: Based on the gas transport characteristics of the natural fracture-matrix dual medium, a flow model suitable for describing the fluid transport velocity within the fracture is constructed; a modified mass conservation equation for methane and carbon dioxide is established. S2: Construct a geological model of a coalbed methane reservoir containing natural fractures, perform unstructured meshing on the geological model of the coalbed methane reservoir, and set initial and boundary conditions for the geological model of the coalbed methane reservoir. S3: Apply the modified mass conservation equation constructed in step S1 to the geological model of a coalbed methane reservoir containing natural fractures, for which mesh generation, initial conditions and boundary conditions have been set in step S2, to solve for the fluid migration behavior characteristics.

2. The method for predicting fluid transport behavior during CO2 mining process in natural fracture-containing coal seams according to claim 1, characterized in that, In step S1, the flow model construction process for fluid transport velocity is as follows: To address the non-Darcy flow characteristics of fluids in coal seams containing natural fractures, an inertial force correction term is introduced into Darcy's law to obtain a modified Darcy's law. A gas phase velocity calculation equation is then constructed using this modified Darcy's law; the expression for the gas phase velocity calculation equation is as follows: wherein is the methane flow rate; is the permeability of methane; is the viscosity of methane; is the methane pressure; is the density of methane; is the acceleration due to gravity; is the carbon dioxide flow rate; is the permeability of carbon dioxide; is the carbon dioxide pressure; is the viscosity of carbon dioxide; is the density of carbon dioxide; is the inertial force correction term; is the non-Darcy flow coefficient.

3. The method for predicting fluid transport behavior during CO2 mining process in natural fracture containing coal seams as claimed in claim 2 wherein, In step S1, the modified mass conservation equations for methane and carbon dioxide are established based on the following method: Based on the obtained gas phase flow rate calculation equation, combined with the gas phase saturation calculation equation and the Langmuir gas adsorption equation, adsorption source term parameters are provided for the methane mass conservation equation and the carbon dioxide mass conservation equation. The corrected gas phase mass conservation equation is as follows: wherein, is the effective porosity of the coalbed reservoir containing natural fractures; is the gas phase saturation; is the Hamiltonian operator; is the mass fraction of methane in the gas phase; is the rate of methane mass decrease due to adsorption; denotes the methane adsorption mass; is the mass fraction of carbon dioxide in the gas phase; is the rate of carbon dioxide mass decrease due to adsorption; is the carbon dioxide adsorption mass.

4. The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures according to claim 3, characterized in that, Gas phase saturation in the modified gas phase mass conservation equation Calculated by the following formula: In the formula, The density is the gas phase density. ; The gas flow rate is... ; This is the mass source term for gas adsorption.

5. The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures according to claim 3 or 4, characterized in that, The mass source term in the modified gas-phase mass conservation equation includes the adsorption process, thus constructing the Langmuir gas adsorption equation: In the formula, The mass of methane adsorbed; This represents the saturated adsorption volume of methane. Methane pressure; The pressure of methane after reaching saturation adsorption capacity; The mass of carbon dioxide adsorbed; This represents the saturated adsorption volume of carbon dioxide. Carbon dioxide pressure; The pressure of carbon dioxide after reaching saturation adsorption capacity.

6. The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures according to claim 1, characterized in that, The specific process of step S2 is as follows: S2.1: Collect actual exploration data of coalbed methane reservoirs in the target area, including the horizontal width and vertical height range of the coalbed methane reservoirs, as well as the porosity, permeability, density, length, direction, and pore size geological parameters of natural fractures. At the same time, obtain the porosity, permeability, and reservoir density physical property parameters of the coal matrix; construct an initial reservoir model of the CO2-ECBM target area without natural fractures. S2.2: Based on the above exploration data and random fracture generation function, construct a discrete fracture network model and complete the fracture attribute setting. Add the discrete fracture network model to the initial reservoir model obtained in step S2.1 to construct a geological model of coalbed methane reservoir with natural fractures that fits the real geological conditions. S2.3: The geological model of coalbed methane reservoirs containing natural fractures is divided using a free triangular unstructured grid. The grid is densified in areas with dense natural fractures and conventional grid is used in coal matrix areas. The size of the largest grid cell is controlled to be 3 times the size of the smallest grid cell to ensure that the grid cells accurately reflect the reservoir differences in different spatial locations. S2.4: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set the initial conditions for the geological model of coalbed methane reservoir with natural fractures. The initial conditions include the initial coalbed methane reservoir pressure, the initial coalbed methane reservoir temperature, the initial gas phase saturation, and the initial methane concentration and carbon dioxide concentration. S2.5: Based on the geological conditions of the target area of ​​CO2-ECBM and the field conditions, set boundary conditions for the geological model of coalbed methane reservoirs with natural fractures. The boundary conditions include the upper boundary pressure, lower boundary pressure, methane production well pressure, carbon dioxide injection well pressure, and well boundary gas concentration of methane production well and carbon dioxide injection well.

7. The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures according to claim 6, characterized in that, The discrete fracture network model is constructed based on a random fracture generation function. The discrete fracture network model is characterized by the distribution characteristics of natural fractures, including the location distribution characteristics, length distribution characteristics, orientation distribution characteristics, and pore size distribution characteristics of natural fractures. The location distribution characteristics of the natural fissures for: Where x represents the location of the crack; , These are the minimum and maximum boundary coordinates of the reservoir where the natural fracture is located in a certain direction (xy), and the center or end point of the fracture is randomly generated within this interval. The length distribution characteristics of the natural fissures for: in, The power law exponent has a value range of 2.0 to 3.

5. Let be a random variable, representing the actual length of a single natural fracture within the reservoir; This represents the minimum characterizable length of a natural fracture within a coalbed methane reservoir. This is the maximum extension length of the natural fissure. The directional distribution characteristics of the natural fissures for: in, Angular deviation of the natural fracture direction, unit: rad; The dispersion coefficient ranges from 0.1 to 10. The pore size distribution characteristic b of the natural fracture is: Among them, the fracture aperture It is proportional to the crack length L. It is a proportionality constant.

8. The method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures according to claim 7, characterized in that, The specific implementation method of step S3 is as follows: Substitute the methane mass conservation equation and carbon dioxide mass conservation equation modified in step S1 into the geological model of the coalbed methane reservoir with natural fractures obtained in step S2, and solve for the mass fraction of methane and carbon dioxide in each grid cell of the geological model of the coalbed methane reservoir. Based on the obtained methane and carbon dioxide mass fractions and the gas phase density calculated from the equation of state, the molar concentrations of methane and carbon dioxide in each grid cell are further derived, and the spatiotemporal evolution characteristics of methane concentration and carbon dioxide concentration are obtained.

9. An electronic device comprising a memory, a processor, and a computer program stored in the memory and capable of running on the processor; characterized in that, When the processor executes the computer program, it causes the electronic device to perform the method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures as described in any one of claims 1 to 8.

10. A storage medium comprising a computer program, characterized in that, When the computer program is run on an electronic device, the electronic device performs the method for predicting fluid migration behavior during CO2 injection mining of coal seams with natural fractures as described in any one of claims 1 to 8.

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