A method for selecting deformation monitoring locations in fractured saline aquifer CO2 sequestration formations

Abstract

This invention belongs to the field of carbon dioxide geological storage engineering. It proposes a method for selecting the monitoring location of deformation in fractured saline aquifers used for CO2 storage. The method includes: constructing a thermo-fluid-mechanical multi-field coupled model; building an initial reservoir model based on the target area for CO2 storage, and setting initial and boundary conditions for the initial reservoir model; constructing a discrete fracture network model using a random fracture generation function and setting fracture attributes, adding the fracture attributes to the initial reservoir model, and then meshing the initial reservoir model with added fracture attributes to obtain a fractured reservoir model; inputting the fractured reservoir model into the thermo-fluid-mechanical multi-field coupled model to obtain the formation deformation results over time in different grid regions of the fractured reservoir model, and selecting the grid region with the largest surface deformation as the monitoring location. This invention can select the optimal monitoring location without real-time on-site detection, making it easier to monitor safety issues in carbon dioxide geological storage.

Description

Technical Field

[0001] This invention belongs to the field of carbon dioxide geological storage engineering, and specifically discloses a method for selecting the deformation monitoring location of a CO2 storage stratum containing fractured saline water. Background Technology

[0002] To address global climate change, a series of measures have been implemented to reduce carbon emissions. Among these, carbon dioxide capture, utilization, and storage (CCS) is currently widely recognized as one of the most effective ways to reduce carbon dioxide emissions on a large scale. Extensive and in-depth research both domestically and internationally in recent years has made carbon dioxide geological storage a project with very broad prospects and significant implications for future human development. However, safety is paramount during the carbon dioxide storage process in saline aquifers.

[0003] Large-scale CO2 injection leads to a dramatic increase in pressure in the target saline aquifer. This overpressure rapidly disturbs the stress field upon injection, extending into the caprock and potentially causing significant deformation. It may also create formation fractures, which are typically highly heterogeneous, discontinuous, and anisotropic, making the study of fluid flow within fractured rock masses extremely complex and challenging. Fluid flow affects the pressure distribution of the target saline aquifer, thus impacting CO2 sequestration efficiency and safety. Therefore, understanding and simulating these fractures is crucial for predicting formation safety during underground CO2 sequestration. Due to the heterogeneity and stress variations in the rock mass, microseismic events may be triggered, and surface deformation can be detected. Formation deformation data can reflect formation movement. However, during in-situ injection, complex reservoir conditions and difficult field operations make effective monitoring of formation deformation behavior challenging. To address these issues, this paper proposes an effective method for selecting monitoring locations for formation deformation in CO2 saline aquifer sequestration based on numerical simulation studies, which is of great significance for the long-term safe sequestration of CO2. Summary of the Invention

[0004] To address the problem of difficulty in effectively monitoring formation deformation behavior during the on-site injection of carbon dioxide in existing carbon dioxide sequestration systems, this invention proposes a method for selecting the location for monitoring formation deformation in fractured saline aquifers for CO2 sequestration.

[0005] This invention provides a method for selecting the deformation monitoring location of a CO2 storage formation containing fractured saline aquifers, comprising the following steps:

[0006] S1. Based on the flow process, heat transfer process, and mechanical process of CO2 sequestration, a multi-field coupled model of heat-fluid-mechanical processes is constructed.

[0007] S2. Construct an initial reservoir model for the CO2 storage target area based on the geological conditions of the CO2 storage area and the on-site conditions, and set the initial conditions and boundary conditions of the initial reservoir model;

[0008] S3. Construct a discrete fracture network model using a random fracture generation function, set fracture attributes according to the discrete fracture network model, add the fracture attributes to the initial reservoir model obtained in step S2, and perform mesh generation on the initial reservoir model after adding the fracture attributes to obtain a fractured reservoir model.

[0009] S4. Input the fractured reservoir model obtained in step S3 into the thermo-fluid-mechanical multi-field coupling model obtained in step S1 to obtain the formation deformation results of different grid regions in the fractured reservoir model over time, and select the grid region with the largest surface deformation as the monitoring location based on the formation deformation results.

[0010] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage formation containing fractured saline aquifers includes the following steps in step S1:

[0011] S101. Establish a two-phase flow model for carbon dioxide geological sequestration, including:

[0012] The mass conservation equation for the aqueous phase is established as shown in formula (1):

[0013]

[0014] in, ρ represents the porosity of rocks. w This represents the density of the aqueous phase, expressed in kg / (m³). 3 ), S w The saturation level of the aqueous phase is represented by t, which represents time in seconds. Represents the Hamiltonian operator, v w V represents the velocity of the water phase, measured in m / s. w The solution obtained using Darcy's law is shown in formula (2):

[0015]

[0016] Where k represents absolute permeability, in mD. rw The relative permeability of the aqueous phase, μ w The viscosity of the aqueous phase is expressed in Pa·s (p). w The pressure difference is expressed in Pa, and g is the acceleration due to gravity. The relative permeability of the aqueous phase is calculated using the Van Genldchten model, as shown in formula (3).

[0017] k rw=S eff 0.5 [1-(1-S eff 1 / m ) m ] 2 (3)

[0018] Where m represents the dimensionless aperture distribution index, S eff The effective saturation is represented as shown in formula (4):

[0019]

[0020] Among them, S rw S represents the residual saturation of the aqueous phase. rc Indicates the residual saturation of the CO2 phase;

[0021] The mass conservation equation for the CO2 phase is established as shown in equation (5):

[0022]

[0023] in, This represents the CO2 phase density, with units of kg / (m³). 3 ), Indicates the saturation of the CO2 phase. The solution obtained using Darcy's law is shown in formula (6):

[0024]

[0025] in, This indicates the relative permeability of the CO2 phase. The viscosity of the CO2 phase is expressed in Pa·s. The relative permeability of the CO2 phase is calculated using the Van Genldchten model, as shown in formula (7).

[0026]

[0027] S102. Establish a heat conduction-convection model for carbon dioxide geological storage, including:

[0028] The governing equations for the heat transfer process between the aqueous and CO2 phases are constructed as shown in equation (8):

[0029]

[0030] Among them, Q T The heat source is represented by J, T represents temperature in K, and cρ is as shown in formula (9):

[0031]

[0032] Among them, c w This represents the specific heat capacity of the aqueous phase, expressed in J / (kg·K). c represents the specific heat capacity of the CO2 phase. s ρ represents the specific heat capacity of a solid phase, expressed in J / (kg·K). s The density of a solid phase is expressed in kg / m³. 3 ,

[0033] (cρv) f As shown in formula (10):

[0034]

[0035] λ represents thermal conductivity, as shown in formula (11):

[0036]

[0037] Where, λ w The thermal conductivity of the aqueous phase is expressed in W / (m·K). The thermal conductivity of the CO2 phase is expressed in W / (m·K), λ. s Thermal conductivity of a solid phase is expressed in W / (m·K).

[0038] S103. Establish a mechanical model for the geological storage of carbon dioxide, including:

[0039] The momentum balance equation for the elastic deformation of the rock and soil skeleton is constructed using the stress tensor, as shown in formula (12):

[0040]

[0041] Where σ′ represents the effective stress, in MPa, and α b Here, β represents the Biot coefficient, p indicates pore pressure in Pa, I is the unit vector, and β represents the coefficient of thermal expansion in °C. -1 E is Young's modulus, in Pa, and ρ represents the average density, in kg / m³. 3 ;

[0042] The effective stress σ′ is shown in formula (13):

[0043]

[0044] in, Let ε represent the elastic material tensor, and let ε represent the strain tensor. The strain tensor ε is shown in formula (14):

[0045]

[0046] Where u represents displacement in meters (m), and T represents transpose.

[0047] The coefficient of thermal expansion β is shown in formula (15):

[0048]

[0049] Where, β w β represents the coefficient of thermal expansion of the aqueous phase. w β represents the coefficient of thermal expansion of the CO2 phase. s The coefficient of thermal expansion of a solid phase is expressed in Kelvin (K). -1 ,

[0050] ρ is shown in formula (16):

[0051]

[0052] Where, ρ s The density of a solid phase is expressed in kg / m³. 3 .

[0053] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage stratum in a fractured saline aquifer is provided. In step S101, the dimensionless pore size distribution index m is set to 0.457. When m is set to 0.457, the simulated value of the relative permeability of the water phase matches the experimental value well.

[0054] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage formation in a fractured saline aquifer is provided. In step S2, the initial reservoir model does not contain fractures, and the initial conditions of the initial reservoir model include: setting the temperature, temperature distribution, pressure gradient, pressure distribution, gas phase saturation, liquid phase saturation, and formation prestress of the initial reservoir model.

[0055] Setting the boundary conditions of the initial reservoir model includes: setting the temperatures of the upper, lower, left, and right boundaries of the initial reservoir model; setting the pressures of the upper, lower, left, and right boundaries of the initial reservoir model; setting the pressure gradients of the upper, lower, left, and right boundaries of the initial reservoir model; setting the gas phase saturation of the upper, lower, left, and right boundaries of the initial reservoir model; setting the liquid phase saturation of the upper, lower, left, and right boundaries of the initial reservoir model; and setting the normal displacements of the upper, lower, left, and right boundaries of the initial reservoir model.

[0056] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2-sealing formation containing fractured saline water is provided. In step S2, the initial reservoir model includes, from top to bottom, an overburden, a caprock, a reservoir, and an underburden.

[0057] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage formation containing fractures is provided, wherein in step S3, the random fracture generation function is as shown in formula (17):

[0058]

[0059] Where x represents one or more of the following: fracture location, fracture length, fracture angle, or fracture diameter.

[0060] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage formation in a fractured saline aquifer includes, in step S3, the fracture attributes including fracture location, fracture length, fracture pore size, and fracture permeability.

[0061] According to some embodiments of this application, a method for selecting the deformation monitoring location of a CO2 storage stratum containing fractures is provided. In step S3, the grid division is performed using an unstructured triangular grid.

[0062] This invention proposes a method for selecting the deformation monitoring location of CO2 storage formations in fractured saline aquifers. This method can quantitatively analyze and predict formation deformation during CO2 storage. Compared with existing technologies, this invention can establish an initial reservoir model and a thermo-fluid-mechanical multi-field coupling model of the target area based on field geological exploration data during CO2 geological storage. By adding fractures, the displacement of the formation at each moment during CO2 injection is calculated. The results are processed to obtain the formation deformation evolution characteristics during injection. This method does not require real-time field detection and the detection results are accurate. The method of this invention can select the optimal monitoring location, making it easier to monitor safety issues during CO2 injection. Attached Figure Description

[0063] Figure 1 This is a flowchart illustrating a method for selecting the deformation monitoring location of a fractured saline aquifer CO2 storage formation according to the present invention.

[0064] Figure 2 This is a schematic diagram of the reservoir model selected in Embodiment 2 of the present invention;

[0065] Figure 3 This is a schematic diagram of mesh division in Embodiment 2 of the present invention;

[0066] Figure 4 This is a schematic diagram of the formation deformation over time in different grid regions in Embodiment 2 of the present invention;

[0067] Figure 5 This is a schematic diagram of the displacement at different horizontal distances from the well to the surface in Embodiment 2 of the present invention;

[0068] Figure 6 This is a schematic diagram showing the comparison between the predicted results and the actual measured values ​​in Example 2 of this invention. Detailed Implementation

[0069] 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.

[0070] Example 1

[0071] This embodiment provides a method for selecting the deformation monitoring location of a CO2-sealing stratum containing fractured saline aquifers, such as... Figure 1 As shown,

[0072] Includes the following steps:

[0073] S1. Based on the flow process, heat transfer process, and mechanical process of CO2 sequestration, a multi-field coupled model of heat-fluid-mechanical processes is constructed.

[0074] Specifically, step S1 includes the following steps:

[0075] S101. Establish a two-phase flow model for carbon dioxide geological sequestration, including:

[0076] The mass conservation equation for the aqueous phase is established as shown in formula (1):

[0077]

[0078] in, ρ represents the porosity of rocks. w This represents the density of the aqueous phase, expressed in kg / (m³). 3 ), S w The saturation level of the aqueous phase is represented by t, which represents time in seconds. Represents the Hamiltonian operator, v w V represents the velocity of the water phase, measured in m / s. w The solution obtained using Darcy's law is shown in formula (2):

[0079]

[0080] Where k represents absolute permeability, in mD. rw The relative permeability of the aqueous phase, μ w The viscosity of the aqueous phase is expressed in Pa·s (p). w The pressure difference is expressed in Pa, and g is the acceleration due to gravity. The relative permeability of the aqueous phase is calculated using the Van Genldchten model, as shown in formula (3).

[0081] k rw =seff 0.5 [1-(1-S eff 1 / m ) m ] 2 (3)

[0082] Where m represents the dimensionless pore size distribution index, and as a preferred embodiment, the dimensionless pore size distribution index m can be taken as 0.457. When m is taken as 0.457, the simulated value of the relative permeability of the aqueous phase matches the experimental value well. eff The effective saturation is represented as shown in formula (4):

[0083]

[0084] Among them, S rw S represents the residual saturation of the aqueous phase. rc Indicates the residual saturation of the CO2 phase;

[0085] The mass conservation equation for the CO2 phase is established as shown in equation (5):

[0086]

[0087] in, This represents the CO2 phase density, with units of kg / (m³). 3 ), Indicates the saturation of the CO2 phase. The solution obtained using Darcy's law is shown in formula (6):

[0088]

[0089] in, This indicates the relative permeability of the CO2 phase. The viscosity of the CO2 phase is expressed in Pa·s. The relative permeability of the CO2 phase is calculated using the Van Genldchten model, as shown in formula (7).

[0090]

[0091] S102. Establish a heat conduction-convection model for carbon dioxide geological storage, including:

[0092] The governing equations for the heat transfer process between the aqueous and CO2 phases are constructed. In a porous medium composed of liquid, gas, and solid phases, the heat transfer process between the two phases mainly includes conduction and convection. Therefore, the governing equations are shown in equation (8).

[0093]

[0094] Among them, QT The heat source is represented by J, T represents temperature in K, and cρ is as shown in formula (9):

[0095]

[0096] Among them, c w This represents the specific heat capacity of the aqueous phase, expressed in J / (kg·K). c represents the specific heat capacity of the CO2 phase. s ρ represents the specific heat capacity of a solid phase, expressed in J / (kg·K). s The density of a solid phase is expressed in kg / m³. 3 ,

[0097] (cρv) f As shown in formula (10):

[0098]

[0099] λ represents thermal conductivity, as shown in formula (11):

[0100]

[0101] Where, λ w The thermal conductivity of the aqueous phase is expressed in W / (m·K). The thermal conductivity of the CO2 phase is expressed in W / (m·K), λ. s Thermal conductivity of a solid phase is expressed in W / (m·K).

[0102] S103. Establish a mechanical model for the geological storage of carbon dioxide, including:

[0103] The momentum balance equation for the elastic deformation of the rock and soil skeleton is constructed using the stress tensor, as shown in formula (12):

[0104]

[0105] Where σ′ represents the effective stress, in MPa, and α b Here, β represents the Biot coefficient, p indicates pore pressure in Pa, I is the unit vector, and β represents the coefficient of thermal expansion in °C. -1 E is Young's modulus, in Pa, and ρ represents the average density, in kg / m³. 3 ;

[0106] The effective stress σ′ is shown in formula (13):

[0107]

[0108] in, Let ε represent the elastic material tensor, and let ε represent the strain tensor. The strain tensor ε is shown in formula (14):

[0109]

[0110] Where u represents displacement in meters (m), and T represents transpose.

[0111] The coefficient of thermal expansion β is shown in formula (15):

[0112]

[0113] Where, β w β represents the coefficient of thermal expansion of the aqueous phase. w β represents the coefficient of thermal expansion of the CO2 phase. s The coefficient of thermal expansion of a solid phase is expressed in Kelvin (K). -1 ,

[0114] ρ is shown in formula (16):

[0115]

[0116] Where, ρ s The density of a solid phase is expressed in kg / m³. 3 ;

[0117] S2. Based on the geological conditions of the CO2 storage area and the on-site conditions, construct an initial reservoir model for the target area of ​​CO2 storage, and set the initial conditions and boundary conditions of the initial reservoir model;

[0118] The initial reservoir model does not contain fractures. The initial conditions for setting the initial reservoir model include: setting the initial reservoir model's temperature, temperature distribution, pressure gradient, pressure distribution, gas phase saturation, liquid phase saturation, and formation prestress. Among them, the initial reservoir model's temperature and temperature distribution are determined by the surface temperature and geothermal gradient of the selected simulation area; the initial reservoir model's pressure gradient and pressure distribution are determined by the hydrostatic pressure gradient of the selected simulation area; and the initial reservoir model's formation prestress is determined by the self-weight of the formation and water in the selected simulation area. It is necessary to set a force to balance the self-weight of the formation and water in the opposite direction to the self-weight of the formation and water in the selected simulation area.

[0119] Setting the boundary conditions for the initial reservoir model includes: setting the temperatures of the upper, lower, left, and right boundaries; setting the pressures of the upper, lower, left, and right boundaries; setting the pressure gradients of the upper, lower, left, and right boundaries; setting the gas saturation of the upper, lower, left, and right boundaries; setting the liquid saturation of the upper, lower, left, and right boundaries; and setting the normal displacements of the upper, lower, left, and right boundaries. The temperatures of the upper, lower, and left boundaries of the initial reservoir model are determined by the selected simulation region. The temperature of the domain is determined, and the temperature of the right boundary of the initial reservoir model is a Dirichlet boundary condition. The pressure and pressure gradient of the upper, lower, and left boundaries of the initial reservoir model are determined by the pressure gradient of the selected simulation region. The pressure and pressure gradient of the right boundary of the initial reservoir model are Dirichlet boundary conditions. The gas saturation and liquid saturation of the upper, lower, and left boundaries of the initial reservoir model are all 0. The gas saturation and liquid saturation of the right boundary of the initial reservoir model are set as Dirichlet boundary conditions. The normal displacement of the right boundary of the upper, lower, and left boundaries of the initial reservoir model is set to 0. The normal displacement of the right boundary of the initial reservoir model is set to free.

[0120] The initial reservoir model consists of, from top to bottom, the overlying layer, the caprock, the reservoir, and the underlying layer.

[0121] S3. Construct a discrete fracture network model using a random fracture generation function, set fracture attributes according to the discrete fracture network model, add the fracture attributes to the initial reservoir model obtained in step S2, and perform mesh generation on the initial reservoir model after adding fracture attributes to obtain a fractured reservoir model.

[0122] The random fracture generation function is shown in equation (17):

[0123]

[0124] Where x represents one or more of the fracture location, fracture length, fracture angle, or fracture pore size; an unstructured triangular mesh was used to mesh the initial reservoir model after adding fracture attributes;

[0125] Fracture properties include fracture location, fracture length, fracture pore size, and fracture permeability;

[0126] S4. Input the fractured reservoir model obtained in step S3 into the thermo-fluid-mechanical multi-field coupling model obtained in step S1 to obtain the formation deformation results of different grid regions in the fractured reservoir model over time. Select the grid region with the largest surface deformation as the monitoring location based on the formation deformation results.

[0127] Example 2

[0128] This embodiment provides a method for selecting the deformation monitoring location of a CO2-sealing formation containing fractured saline aquifers. This embodiment selects the In Salah CCS project as the numerical parameter for simulation, and specifically includes the following steps:

[0129] S1. Based on the flow process, heat transfer process, and mechanical process of CO2 sequestration, a multi-field coupled model of heat-fluid-mechanical processes is constructed.

[0130] Specifically, step S1 includes the following steps:

[0131] S101. Establish a two-phase flow model for carbon dioxide geological sequestration, including:

[0132] The mass conservation equation for the aqueous phase is established as shown in formula (1):

[0133]

[0134] in, ρ represents the porosity of rocks. w This represents the density of the aqueous phase, expressed in kg / (m³). 3 ), S w The saturation level of the aqueous phase is represented by t, which represents time in seconds. Represents the Hamiltonian operator, v w V represents the velocity of the water phase, measured in m / s. w The solution obtained using Darcy's law is shown in formula (2):

[0135]

[0136] Where k represents absolute permeability, in mD. rw The relative permeability of the aqueous phase, μ w The viscosity of the aqueous phase is expressed in Pa·s (p). w The pressure difference is expressed in Pa, and g is the acceleration due to gravity. The relative permeability of the aqueous phase is calculated using the Van Genldchten model, as shown in formula (3).

[0137] k rw =S eff 0.5 [1-(1-S eff1 / m ) m ] 2 (3)

[0138] Where m represents the dimensionless pore size distribution index, and as a preferred embodiment, the dimensionless pore size distribution index m can be taken as 0.457. When m is taken as 0.457, the simulated value of the relative permeability of the aqueous phase matches the experimental value well. eff The effective saturation is represented as shown in formula (4):

[0139]

[0140] Among them, S rw S represents the residual saturation of the aqueous phase. rc Indicates the residual saturation of the CO2 phase;

[0141] The mass conservation equation for the CO2 phase is established as shown in equation (5):

[0142]

[0143] in, This represents the CO2 phase density, with units of kg / (m³). 3 ), Indicates the saturation of the CO2 phase. The solution obtained using Darcy's law is shown in formula (6):

[0144]

[0145] in, This indicates the relative permeability of the CO2 phase. The viscosity of the CO2 phase is expressed in Pa·s. The relative permeability of the CO2 phase is calculated using the Van Genldchten model, as shown in formula (7).

[0146]

[0147] S102. Establish a heat conduction-convection model for carbon dioxide geological storage, including:

[0148] The governing equations for the heat transfer process between the aqueous and CO2 phases are constructed. In a porous medium composed of liquid, gas, and solid phases, the heat transfer process between the two phases mainly includes conduction and convection. Therefore, the governing equations are shown in equation (8).

[0149]

[0150] Among them, Q T The heat source is represented by J, T represents temperature in K, and cρ is as shown in formula (9):

[0151]

[0152] Among them, c w This represents the specific heat capacity of the aqueous phase, expressed in J / (kg·K). c represents the specific heat capacity of the CO2 phase. s ρ represents the specific heat capacity of a solid phase, expressed in J / (kg·K). s The density of a solid phase is expressed in kg / m³. 3 ,

[0153] (cρv) f As shown in formula (10):

[0154]

[0155] λ represents thermal conductivity, as shown in formula (11):

[0156]

[0157] Where, λ w The thermal conductivity of the aqueous phase is expressed in W / (m·K). The thermal conductivity of the CO2 phase is expressed in W / (m·K), λ. s Thermal conductivity of a solid phase is expressed in W / (m·K).

[0158] S103. Establish a mechanical model for the geological storage of carbon dioxide, including:

[0159] The momentum balance equation for the elastic deformation of the rock and soil skeleton is constructed using the stress tensor, as shown in formula (12):

[0160]

[0161] Where σ′ represents the effective stress, in MPa, and α b Here, β represents the Biot coefficient, p indicates pore pressure in Pa, I is the unit vector, and β represents the coefficient of thermal expansion in °C. -1 E is Young's modulus, in Pa, and ρ represents the average density, in kg / m³. 3 ;

[0162] The effective stress σ′ is shown in formula (13):

[0163]

[0164] in, Let ε represent the elastic material tensor, and let ε represent the strain tensor. The strain tensor ε is shown in formula (14):

[0165]

[0166] Where u represents displacement in meters (m), and T represents transpose.

[0167] The coefficient of thermal expansion β is shown in formula (15):

[0168]

[0169] Where, β w β represents the coefficient of thermal expansion of the aqueous phase. w β represents the coefficient of thermal expansion of the CO2 phase. s The coefficient of thermal expansion of a solid phase is expressed in Kelvin (K). -1 ,

[0170] ρ is shown in formula (16):

[0171]

[0172] Where, ρ s The density of a solid phase is expressed in kg / m³. 3 ;

[0173] S2. Based on the geological conditions of the CO2 storage area and the on-site conditions, an initial reservoir model of the target CO2 storage area is constructed, and the initial conditions and boundary conditions of the initial reservoir model are set. In this embodiment, the In Salah CCS project is selected as the numerical parameters of the initial reservoir model, specifically including:

[0174] The initial reservoir model has a total thickness of 2000m and is divided into four strata from top to bottom: overlying layer, caprock, reservoir, and underlying layer. The reservoir is located at a depth of 1800m to 1820m. The initial reservoir model is as follows: Figure 2 As shown, the initial reservoir model has a horizontal length of 2000 m. The main physical properties of each layer are shown in Table 1. The pressure in each formation of the initial reservoir model follows hydrostatic pressure, with a constant pressure and temperature gradient of 0.033 K / m at the right boundary. At a depth of 1800 m, the upper surface temperature of the reservoir is 90 °C. The initial liquid phase saturation is 1, and the initial gas phase saturation is 0. Normal displacement is fixed at 0 on all boundaries except the top surface. For the first 2000 days of simulation, CO2 is injected at a constant rate of 5.62 × 10⁻⁶ m. -3 Considering the symmetry of the left and right boundaries, the mass flow rate at the well node is 2.81×10-3 kg / m / s.

[0175] Table 1 Main physical properties of the formation

[0176]

[0177] S3. Construct a discrete fracture network model based on a random fracture generation function, set fracture attributes according to the discrete fracture network model, add the fracture attributes to the initial reservoir model obtained in step S2, and perform mesh generation on the initial reservoir model after adding fracture attributes to obtain a fractured reservoir model.

[0178] The random fracture generation function is shown in equation (34):

[0179]

[0180] The fracture attributes are set, including fracture location, fracture length, fracture pore size, and fracture permeability. The fracture location is 1700m-1900m underground; the fracture length is 50-200m; the fracture pore size is 0.1-1mm; the fracture permeability exhibits anisotropy, with a vertical fracture permeability of 4×10⁻⁶. -12 m 2 The horizontal permeability is 4×10 -13 m 2 .

[0181] like Figure 3 As shown, an unstructured triangular mesh was used to mesh the initial reservoir model after adding fracture attributes. The entire fractured reservoir model consists of 55,898 mesh regions.

[0182] S4. Input the fractured reservoir model obtained in step S3 into the thermo-fluid-mechanical multi-field coupled model obtained in step S1 to obtain the formation deformation results over time in different grid regions of the fractured reservoir model. The results are as follows: Figure 4 As shown, Figure 5 This demonstrates the displacement at different horizontal distances from the well to the surface. Based on the formation deformation results, the area of ​​maximum surface deformation was selected as the monitoring location, and the results were compared with field measurements. The results are as follows: Figure 6 As shown.

[0183] In this embodiment, the In Salah CCS project is selected as the simulation object to quantitatively assess the temporal and spatial evolution of stratigraphic uplift. It is worth noting that the selection of the simulation object is not fixed.

[0184] The embodiments of the present invention are given for illustrative and descriptive purposes only, and are not intended to be exhaustive or to limit the invention to the forms disclosed. Many modifications and variations will be apparent to those skilled in the art. The embodiments were chosen and described in order to better illustrate the principles and practical application of the invention, and to enable those skilled in the art to understand the invention and to design various embodiments with various modifications suitable for a particular purpose.

Claims

1. A method for selecting a location for monitoring deformation of a CO2 storage formation in a fractured saline aquifer, the method comprising: determining a location for monitoring deformation of the CO2 storage formation in the fractured saline aquifer, wherein the location is determined based on a location of a fracture in the fractured saline aquifer. The method comprises the following steps: S1. Constructing a thermal-flow-force multi-field coupling model based on a CO2 storage flow process, a CO2 storage heat transfer process, and a CO2 storage mechanical process; S2. Constructing an initial reservoir model of a CO2 storage target area based on a CO2 storage area geological working condition and a field working condition, and setting initial conditions and boundary conditions of the initial reservoir model; S3. Constructing a discrete fracture network model through a random fracture generation function, setting fracture properties according to the discrete fracture network model, adding the fracture properties to the initial reservoir model obtained in step S2, and performing grid division on the initial reservoir model after adding the fracture properties to obtain a fractured reservoir model; S4. Inputting the fractured reservoir model obtained in step S3 into the thermal-flow-force multi-field coupling model obtained in step S1 to obtain formation deformation results in different grid areas in the fractured reservoir model over time, and selecting a grid area with the largest surface deformation as a monitoring position according to the formation deformation results. The step S1 comprises the following steps: S101. Establishing a two-phase flow model of CO2 geological storage, comprising: establishing a mass conservation equation of the water phase, as shown in formula (1); （1） wherein, denotes the rock porosity, denotes the water phase density, denotes the water phase saturation, t denotes time, denotes the Hamiltonian operator, denotes the water phase velocity, the water phase velocity solved by Darcy's law, as shown in equation (2): （2） wherein, represents the absolute permeability, represents the relative permeability of the water phase, represents the viscosity of the water phase, represents the pressure difference, is the gravitational acceleration, the relative permeability of the water phase is calculated using the Van Genldchten model, as shown in equation (3): （3） where m represents a dimensionless pore size distribution index, represents the effective saturation, as shown in equation (4): （4） wherein represents the residual saturation of the water phase, represents the residual saturation of the CO2 phase; establishing a mass conservation equation of the CO2 phase, as shown in formula (5); （5） wherein, represents the CO2 phase density, represents the saturation of the CO2 phase, solved by Darcy's law, as shown in equation (6): （6） wherein, represents the relative permeability of the CO2 phase, represents the viscosity of the CO2 phase, the relative permeability of the CO2 phase is calculated using the Van Genldchten model, as shown in equation (7): （7）； S102. Establishing a heat conduction-convection model of CO2 geological storage, comprising: constructing a control equation of the heat transfer process between the two-phase flow of the water phase and the CO2 phase, as shown in formula (8); （8） wherein T is the temperature of the heat source, as shown in equation (9): （9） wherein, Cp,water represents the specific heat capacity of the water phase, Cp,co2represents the specific heat capacity of the CO2phase, Cp,solid represents the specific heat capacity of the solid phase, p, solid represents the density of the solid phase, As shown in Equation (10): （10） represents thermal conductivity, as shown in Equation (11): （11） wherein, represents the thermal conductivity of the water phase, represents the thermal conductivity of the CO2 phase, represents the thermal conductivity of the solid phase; S103. Establishing a mechanical model of CO2 geological storage, comprising: constructing a momentum balance equation of the elastic deformation of the rock-soil skeleton using a stress tensor, as shown in formula (12); （12） wherein represents the effective stress, is the Biot coefficient, p represents the pore pressure, is a unit vector, represents the thermal expansion coefficient, is the Young's modulus, represents the average density, Effective stress As shown in equation (13): （13） wherein, denotes the elastic material tensor, denotes the strain tensor, the strain tensor as shown in equation (14): （14） wherein denotes displacement, denotes transposition, coefficient of thermal expansion As shown in equation (15): （15） wherein represents the thermal expansion coefficient of the water phase, represents the thermal expansion coefficient of the CO2 phase, represents the thermal expansion coefficient of the solid phase, As shown in equation (16): （16） wherein represents the density of the solid phase.

2. A method of selecting a location for monitoring deformation of a CO2 storage formation in a fractured saline aquifer according to claim 1, wherein, In the step S101, the value of the dimensionless pore size distribution index m is 0.

457.

3. A method of selecting a location for monitoring deformation of a CO2 storage formation in a fractured saline aquifer according to claim 1, wherein, In the step S2, the initial conditions of the initial reservoir model include setting the temperature, temperature distribution, pressure gradient, pressure distribution, gas phase saturation, liquid phase saturation, and formation pre-stress of the initial reservoir model; The boundary conditions of the initial reservoir model include setting the temperature of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model, setting the pressure of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model, setting the pressure gradient of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model, setting the gas phase saturation of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model, setting the liquid phase saturation of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model, and setting the normal displacement of the upper side boundary, lower side boundary, left side boundary, and right side boundary of the initial reservoir model.

4. A method for selecting a monitoring location for deformation of a CO2 storage formation in a fractured saline aquifer according to claim 1, wherein, In the step S2, the initial reservoir model comprises, from top to bottom, an overburden layer, a caprock layer, a reservoir layer, and a lower overburden layer.

5. A method for selecting a monitoring location for deformation of a CO2 storage formation in a fractured saline aquifer according to claim 1, wherein, In the step S3, the random fracture generation function is as shown in formula (17): （17） wherein x represents one or more of a fracture position, a fracture length, a fracture angle, or a fracture pore size.

6. A method of selecting a location for monitoring deformation of a CO2 storage formation in a fractured saline aquifer according to claim 5, wherein, The fracture attribute includes a fracture position, a fracture length, a fracture aperture and a fracture permeability.

7. A method for selecting a monitoring location for deformation of a CO2 storage formation in a fractured saline aquifer according to claim 1, wherein, In the step S3, the mesh division is performed by using an unstructured triangular mesh.

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