Prediction methods for formation damage behavior during CO2 saline water storage

Abstract

This method for predicting formation damage behavior during CO2 storage in saline aquifers falls under the field of CO2 geological storage. It addresses the problem of predicting the long-term stability of CO2 storage. The key points are: constructing a mechanism model for formation damage induced by CO2 storage in saline aquifers based on the tensile and shear damage mechanisms of soil and rock masses; establishing a reservoir geological model for CO2 storage in saline aquifers based on field exploration data of soil and rock masses; dividing the reservoir geological model into grids to obtain several grid cells reflecting different spatial distribution locations of CO2 in the saline aquifer; and setting initial and boundary conditions for the reservoir geological model. Finally, based on the formation damage mechanism model, solving for the spatiotemporal evolution characteristics of damage factors in each grid cell of the reservoir geological model yields the temporal and spatial distribution of damage factors.

Description

Technical Field

[0001] This invention belongs to the field of CO2 geological storage, and specifically discloses a method for predicting formation damage behavior during CO2 saline aquifer storage. Background Technology

[0002] CO2 sequestration in saline aquifers is one of the most promising technological approaches to achieving carbon emission reduction and underground carbon fixation. Compared to oil and gas reservoirs or coal seams, deep saline aquifers are widely distributed, have enormous reserves, and possess good sealing properties and regional applicability, enabling large-scale carbon dioxide sequestration globally. Injecting CO2 into deep saline aquifers allows for long-term stable storage through various mechanisms, including dissolution, capillary retention, and other mineral reactions. This not only effectively reduces atmospheric CO2 concentrations but also promotes the engineering application of carbon capture and storage (CCS) technology, providing crucial geological support for achieving carbon neutrality. Therefore, studying the transport and sequestration mechanisms of CO2 in saline aquifers is of significant scientific and engineering value for ensuring sequestration safety, improving storage efficiency, and assessing long-term stability.

[0003] During CO2 sequestration in saline aquifers, stress redistribution occurs in the formation under high-pressure injection. If the local stress state satisfies the maximum tensile stress or the Mohr-Coulomb criterion, tensile or shear damage will occur in the rock mass, respectively. Formation damage not only alters pore structure and permeability but also affects heat transfer characteristics and mechanical strength, directly impacting CO2 transport pathways and sequestration safety. However, existing research largely focuses on the CO2 seepage process, lacking a systematic characterization of sequestration-induced formation damage evolution and failing to establish a coupling relationship between rock stress-strain response and formation damage. This deficiency leads to insufficient understanding of formation structural changes caused by CO2 injection and long-term sequestration stability, making it difficult to accurately assess the integrity of the sequestration zone and potential leakage risks. Therefore, establishing a multiphysics-coupled prediction model based on damage mechanics to quantitatively describe formation damage evolution during sequestration is crucial for ensuring safe CO2 sequestration and long-term stability. Summary of the Invention

[0004] To address the problem of predicting the stability of long-term CO2 storage, a method for predicting formation damage behavior during CO2 saline aquifer storage, as described in some embodiments of this application, includes the following steps:

[0005] Based on the tensile and shear damage mechanisms of rock and soil, a mechanism model for formation damage induced by carbon dioxide during saline water storage is constructed, including a mechanism model for tensile failure formation damage and a mechanism model for shear failure formation damage.

[0006] Based on the field exploration data of the rock and soil mass, a reservoir geological model for carbon dioxide sequestration in the saline aquifer was established. The reservoir geological model was divided into grids to obtain several grid cells that reflect the different spatial distribution locations of carbon dioxide in the saline aquifer. The initial conditions and boundary conditions of the reservoir geological model were also set.

[0007] Based on the formation damage mechanism model, the spatiotemporal evolution characteristics of the damage factors of each grid cell in the reservoir geological model are solved to obtain the temporal and spatial distribution of the damage factors.

[0008] The method for predicting formation damage behavior during CO2 saline aquifer storage according to some embodiments of this application further includes obtaining the fracture risk level of the rock skeleton based on the temporal and spatial distribution of formation damage factors.

[0009] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, the mechanism model for formation damage induced by carbon dioxide during saline aquifer storage includes:

[0010] When the stress state of the formation satisfies the tensile failure criterion, tensile failure occurs in the formation, which is expressed as:

[0011]

[0012] In the formula, This indicates the stress that causes tensile failure in the formation. Indicates the maximum effective principal stress; Indicates uniaxial tensile strength;

[0013] When the stress state of the formation satisfies the shear failure criterion, shear failure occurs in the formation, which is expressed as:

[0014]

[0015] In the formula, This represents the stress that causes shear failure in the formation. Indicates the minimum effective principal stress; Indicates uniaxial compressive strength; Indicates the internal friction angle of the rock; The sine function value representing the internal friction angle of the rock;

[0016] When the tensile failure criterion is met, the relationship between the damage variable and the principal strain is expressed as follows:

[0017]

[0018] In the formula, Indicates damage factor; Indicates the maximum effective principal strain; Indicates the peak tensile principal strain;

[0019] When the shear failure criterion is satisfied, the relationship between the damage variable and the principal strain is expressed as follows:

[0020]

[0021] In the formula, Indicates the minimum effective principal strain; Indicates the peak compressive principal strain;

[0022] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, the geological exploration data of the saline aquifer includes the height and horizontal width of the saline aquifer.

[0023] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, the initial conditions for setting the reservoir geological model include initial carbon dioxide saturation, initial saline aquifer pressure, and initial saline aquifer temperature.

[0024] According to the prediction method for formation damage behavior during CO2 saline reservoir storage in some embodiments of this application, the boundary conditions of the reservoir geological model include the upper boundary pressure, lower boundary pressure, CO2 injection well pressure, upper boundary temperature, and lower boundary temperature of the reservoir geological model.

[0025] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, the meshing method includes adaptive triangular meshing.

[0026] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, the size of the largest grid cell is 3-5 times the size of the smallest grid cell.

[0027] The method for predicting formation damage behavior during CO2 saline aquifer sequestration according to some embodiments of this application also includes...

[0028] Construct a damage rock property calculation model based on damage factors to characterize the influence of formation damage on rock seepage, heat transfer and mechanical properties;

[0029] Based on the damage rock property calculation model, the spatiotemporal evolution characteristics of the effective permeability, thermal conductivity, and Young's modulus of the damaged rocks in each grid cell of the reservoir geological model are solved, and the distribution of the effective permeability, thermal conductivity, and Young's modulus of the damaged rocks in time and space is obtained.

[0030] According to the prediction method for formation damage behavior during CO2 saline aquifer storage in some embodiments of this application, a damage rock property calculation model based on damage factors is constructed to characterize the influence of formation damage on rock seepage, heat transfer, and mechanical properties, including...

[0031] The calculation model for damage and rock properties in rock seepage is expressed as follows:

[0032]

[0033] In the formula, Indicates the inherent permeability of the rock. This indicates the effective permeability of the rock after considering formation damage. Represents an exponential function. Represents the permeability coefficient. Indicates damage factor;

[0034] The calculation model for damage rock properties in rock heat transfer is expressed as follows:

[0035]

[0036] In the formula, This represents the thermal conductivity of the rock before any damage occurs. This indicates the thermal conductivity of the damaged rock. Indicates the thermal conductivity coefficient;

[0037] The mechanical property damage rock property calculation model is expressed as follows:

[0038] )

[0039] In the formula, This represents the Young's modulus of the rock before any damage occurs. This indicates the Young's modulus of the rock after damage.

[0040] Beneficial effects: The present invention proposes a method for predicting formation damage behavior during CO2 saline aquifer storage. By establishing a multi-physics field coupling prediction model based on damage mechanics, it can quantitatively describe the evolution of tensile and shear damage in formations during CO2 storage. Furthermore, based on damage factors, it can further effectively reveal the coupling mechanism between formation stress, seepage, and heat transfer. It overcomes the shortcomings of existing studies that do not consider the formation damage process, leading to inaccurate assessment of storage safety, and achieves reliable prediction of the long-term stability of CO2 storage. Attached Figure Description

[0041] Figure 1 This is a flowchart of a method for predicting formation damage behavior during CO2 saline aquifer storage in an embodiment of the present invention.

[0042] Figure 2 This is a schematic diagram of the saline reservoir geological model used in the embodiments of the present invention.

[0043] Figure 3 This is a schematic diagram of the evolution of damage factors calculated in an embodiment of the present invention.

[0044] Figure 4 The spatiotemporal evolution characteristics of the effective permeability, thermal conductivity, and Young's modulus of the damaged rock calculated in the embodiments of the present invention are shown. Detailed Implementation

[0045] 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.

[0046] like Figure 1 As shown in the figure, this invention provides a method for predicting formation damage behavior during CO2 saline aquifer storage, comprising the following steps:

[0047] S1. Based on the tensile and shear damage mechanisms of soil and rock masses, a mechanism model for formation damage induced by carbon dioxide saline water layer sequestration is constructed, as follows:

[0048] When the stress state of the formation satisfies the maximum tensile stress criterion, tensile failure will occur; similarly, when the stress state satisfies the Mohr-Coulomb criterion, shear failure will occur. These conditions can be expressed as:

[0049]

[0050]

[0051] in, This indicates the stress that causes tensile failure in the formation. This represents the stress that causes shear failure in the formation. The maximum effective principal stress; Uniaxial tensile strength; The minimum effective principal stress; Uniaxial compressive strength; The internal friction angle of the rock.

[0052] Based on the above conditions, we can determine which failure criterion the stress state of the formation satisfies.

[0053] When the tensile failure criterion is met, the damage factor can be quantified by the principal strain:

[0054]

[0055] in, Damage factor; To achieve the maximum effective principal strain; The peak tensile principal strain is denoted as .

[0056] Similarly, when the shear failure criterion is satisfied, the relationship between the damage variable and the principal strain can be expressed as:

[0057]

[0058] in, To achieve the maximum effective principal strain; The peak compressive principal strain.

[0059] S2. Based on the influence of formation damage on rock seepage, heat transfer, and mechanical properties, a calculation model for the properties of damaged rocks is established, as follows:

[0060] The effective permeability of sediments varies with formation damage:

[0061]

[0062] in, The inherent permeability of the rock; To account for the effective permeability of rocks after formation damage; Represents an exponential function; Represents the permeability coefficient. Indicates damage factor.

[0063] The effect of formation damage on the thermal conductivity of the rock skeleton can be expressed as:

[0064]

[0065] in, The thermal conductivity of the rock before damage occurs; The thermal conductivity of the damaged rock; This represents the thermal conductivity coefficient.

[0066] Furthermore, formation damage is accompanied by a decrease in the mechanical properties of sediments, which can be expressed as:

[0067] )

[0068] in, The Young's modulus of the rock before damage occurs; This represents the Young's modulus of the damaged rock.

[0069] S3. Based on field exploration data, establish a reservoir geological model of the carbon dioxide saline water reservoir area, divide the reservoir geological model into grids, and set initial and boundary conditions. The grid division method includes adaptive triangular grid division. Preferably, the size of the largest grid cell is 3-5 times the size of the smallest grid cell. Specifically, setting the initial conditions of the saline water reservoir geological model includes: setting the initial carbon dioxide saturation, initial saline water pressure, and initial saline water temperature of the reservoir geological model. It also includes setting the upper boundary pressure, lower boundary pressure, carbon dioxide injection well pressure, upper boundary temperature, and lower boundary temperature of the reservoir geological model.

[0070] like Figure 2 As shown, the simulation domain has a width of 4000 m and a height of 20 m. Initially, the carbon dioxide saturation is 0, the initial saline aquifer pressure is 26 MPa, and the initial saline aquifer temperature is 323.15 K. The lower boundary pressure is 26 MPa, the upper boundary pressure is 26 MPa, the lower boundary temperature is 323.15 K, the upper boundary temperature is 323.15 K, and the carbon dioxide injection well pressure is 30 MPa.

[0071] S3. Using the formation damage mechanism model constructed in step S1, the spatiotemporal evolution characteristics of damage factors within each grid cell of the reservoir geological model are solved to obtain the temporal and spatial distribution of damage factors. Based on the temporal and spatial distribution of formation damage factors, the fracture risk level of the rock skeleton can be obtained. The spatiotemporal evolution characteristics refer to the different damage factors of each grid at different times, reflecting the characteristics of damage factors changing over time at different locations within a continuous time range.

[0072] S4. Using the formation damage mechanism model constructed in step S1, solve the spatiotemporal evolution characteristics of the effective permeability, thermal conductivity, and Young's modulus of the damaged rocks in each grid cell of the reservoir geological model, so as to realize the effective prediction of formation damage behavior during CO2 saline water storage. It can not only predict the loss factor, but also predict the impact of formation damage on rock seepage, heat transfer and mechanical properties based on the damage factor, so as to realize the effective and comprehensive spatiotemporal prediction of formation damage behavior during CO2 saline water storage.

[0073] In this embodiment, as Figure 3 The diagram illustrates the spatiotemporal evolution of formation damage around the well within 60 minutes of extraction. The results show that after CO2 injection begins, the damage evolves radially along the formation surrounding the injection well. After 60 minutes, the horizontal damage extent is approximately 1 m, and the damage factor of the local rock skeleton can reach 0.8, indicating an extremely high risk of fracture and fracture channel formation. In this field, a damage factor of 1 is typically considered a complete fracture; the closer the value is to 1, the higher the potential risk of fracture. Figure 4The diagram shows the spatiotemporal evolution of formation permeability, thermal conductivity, and Young's modulus within 60 minutes of mining. The results indicate that after formation damage, the maximum permeability and thermal conductivity can increase to 5000 mD and 140 W / (m·K), respectively. However, the Young's modulus decreases to 2 GPa.

[0074] 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 of predicting the behavior of formation damage during a saline aquifer sequestration process, comprising: a method of predicting the behavior of formation damage during a saline aquifer sequestration process, characterized by: Includes the following steps: Based on the tensile and shear damage mechanisms of rock and soil, a mechanism model for formation damage induced by carbon dioxide during saline water storage is constructed, including a mechanism model for tensile failure formation damage and a mechanism model for shear failure formation damage. Based on the field exploration data of the rock and soil mass, a reservoir geological model for the sequestration of carbon dioxide in the saline aquifer was established. The reservoir geological model was divided into grids to obtain several grid cells that reflect the different spatial distribution locations of carbon dioxide in the saline aquifer. The initial conditions and boundary conditions of the reservoir geological model were also set. Based on the formation damage mechanism model, the spatiotemporal evolution characteristics of the damage factors of each grid cell in the reservoir geological model are solved to obtain the temporal and spatial distribution of the damage factors. Among them, the mechanism model for formation damage induced by carbon dioxide during saline aquifer storage includes: When the stress state of the formation satisfies the tensile failure criterion, tensile failure occurs in the formation, which is expressed as: In the formula, This indicates the stress that causes tensile failure in the formation. Indicates the maximum effective principal stress; Indicates uniaxial tensile strength; When the stress state of the formation satisfies the shear failure criterion, shear failure occurs in the formation, which is expressed as: In the formula, This represents the stress that causes shear failure in the formation. Indicates the minimum effective principal stress; Indicates uniaxial compressive strength; Indicates the internal friction angle of the rock; The sine function value representing the internal friction angle of the rock; When the tensile failure criterion is met, the relationship between the damage variable and the principal strain is expressed as follows: In the formula, Indicates damage factor; Indicates the maximum effective principal strain; Indicates the peak tensile principal strain; When the shear failure criterion is satisfied, the relationship between the damage variable and the principal strain is expressed as follows: In the formula, Indicates the minimum effective principal strain; This represents the peak compressive principal strain.

2. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, It also includes determining the fracture risk level of the rock skeleton based on the temporal and spatial distribution of formation damage factors.

3. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, The geological exploration data of the saline aquifer includes the height and horizontal width of the aquifer.

4. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, The initial conditions for setting up a reservoir geological model include initial carbon dioxide saturation, initial saline water pressure, and initial saline water temperature.

5. The method according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, The boundary conditions for setting the reservoir geological model include the upper boundary pressure, lower boundary pressure, carbon dioxide injection well pressure, upper boundary temperature, and lower boundary temperature of the reservoir geological model.

6. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, The meshing method includes adaptive triangular meshing.

7. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, The size of the largest grid cell is 3-5 times the size of the smallest grid cell.

8. The one according to claim 1 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, Also includes Construct a damage rock property calculation model based on damage factors to characterize the influence of formation damage on rock seepage, heat transfer and mechanical properties; Based on the damage rock property calculation model, the spatiotemporal evolution characteristics of the effective permeability, thermal conductivity, and Young's modulus of the damaged rocks in each grid cell of the reservoir geological model are solved, and the distribution of the effective permeability, thermal conductivity, and Young's modulus of the damaged rocks in time and space is obtained.

9. The one according to claim 8 A method for predicting formation damage behavior during saline aquifer storage, characterized in that, in, A damage-based model for calculating rock properties, characterized by damage factors, is constructed to represent the influence of formation damage on rock seepage, heat transfer, and mechanical properties. The calculation model for damage and rock properties in rock seepage is expressed as follows: In the formula, Indicates the inherent permeability of the rock. This indicates the effective permeability of the rock after considering formation damage. Represents an exponential function. Represents the permeability coefficient. Indicates damage factor; The calculation model for damage rock properties in rock heat transfer is expressed as follows: In the formula, This represents the thermal conductivity of the rock before any damage occurs. This indicates the thermal conductivity of the damaged rock. Indicates the thermal conductivity coefficient; The mechanical property damage rock property calculation model is expressed as follows: ) In the formula, This represents the Young's modulus of the rock before any damage occurs. This indicates the Young's modulus of the rock after damage.

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