CO2 storage fracturing parameter optimization method based on integrated model of pressure crushing and sampling

Abstract

The application discloses a CO2 energy storage fracturing parameter optimization method based on a compression-mining-production integrated model, and belongs to the technical field of oil and gas field development; first, a compression-mining-production integrated model is constructed under the condition of comprehensively considering reservoir properties; second, model verification is performed; then, well bottom pressure increase under different injection and discharge capacities is simulated, a critical pressure difference of CO2 entering a micro pore throat is calculated, CO2 injection and discharge capacities are optimized under the constraint of the critical pressure difference, and a net present value index model is constructed, so that CO2 injection capacity is optimized with the maximization of economic benefits as an objective, continuous coupling description of the three stages of compression-mining-production is realized, the problem of optimizing injection capacity and injection and discharge capacity is effectively solved, and the yield increasing system is optimized; the application can perform targeted parameter design according to different unconventional gas reservoir physical characteristics and percolation mechanisms, and improve the utilization efficiency of carbon dioxide; application of the method is helpful to improving the economic benefits of a single well and provides technical support for carbon dioxide development of unconventional gas reservoirs.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, and in particular relates to a method for optimizing CO2 energy storage fracturing parameters based on an integrated fracturing and extraction model. Background Technology

[0002] Unconventional gas reservoirs are generally characterized by small pore size, extremely low permeability, and strong heterogeneity. Traditional hydraulic fracturing mainly uses water-based fracturing fluids, but in low-permeability reservoirs, it easily causes water-locking damage and reservoir sensitivity issues. CO2, as a low-viscosity, highly diffusive gaseous medium, has excellent migration capabilities in reservoirs and is widely used in CO2 energy storage fracturing technology. Currently, the common development model in engineering practice is "fracturing-shutdown-production" to improve reservoir seepage conditions and increase single-well production. However, existing numerical simulations and theoretical studies often analyze fracturing, shutdown, and production processes separately, using a staged approach. This makes it difficult to reflect the continuous evolution of reservoir pressure field, water saturation field, and seepage parameters during fracturing fluid invasion and retention, thus affecting the accurate prediction of post-fracturing production dynamics. At the same time, existing CO2 energy storage fracturing parameter design relies heavily on empirical methods and lacks quantitative optimization methods based on bottom-hole pressurization capacity and reservoir seepage characteristics.

[0003] Currently, there is a numerical simulation method for the entire process of shale oil development that considers permeation and replacement as well as stress sensitivity. However, it does not take into account that the friction of the pores will cause different injection volumes in different fractures. It can be seen that the CO2 pre-storage fracturing method has an optimal shut-in time, but it does not optimize the injection displacement and injection volume.

[0004] Therefore, it is necessary to propose an integrated fracturing-suppression-production model that can describe the entire process of fracturing, well shut-in, and production within a unified mathematical framework, and on this basis, establish a reasonable parameter optimization method to achieve the scientific optimization of key parameters of CO2 energy storage fracturing. Summary of the Invention

[0005] The purpose of this invention is to provide a method for optimizing CO2 energy storage fracturing parameters based on an integrated fracturing-seal-production model. This addresses the problem that existing technologies struggle to reflect the continuous evolution of reservoir pressure, water saturation, and seepage parameters during fracturing fluid intrusion and retention, thus affecting the accurate prediction of post-fracturing production dynamics. This invention establishes an integrated fracturing-seal-production capacity prediction model, targeting the pressure differential required for CO2 occupancy and the maximum net present value, thereby optimizing the CO2 injection rate and volume.

[0006] To achieve the above objectives, this invention provides a method for optimizing CO2 energy storage fracturing parameters based on an integrated fracturing and extraction model, comprising the following steps: S1. Based on reservoir physical properties and engineering conditions, construct an integrated production capacity prediction model for fracturing-well shut-in-production. S2. Model validation based on field production well data; S3. Based on the prediction model constructed in S1, different injection rates are simulated to monitor the effect of bottom hole pressurization and compare it with the critical pressure difference for CO2 to overcome capillary force constraints and enter the micro-hole throat, so as to optimize the injection rate. S4. Construct a parameter optimization index function to evaluate the effect of CO2 energy storage fracturing, estimate the economic benefits obtained by injecting different displacements, set optimization targets, and determine the amount of CO2 injected.

[0007] Preferably, S1 specifically includes: S101. Construct a triple-media model; S102. Based on the fracture propagation model, stress sensitivity and capillary force absorption effect, establish an integrated production capacity prediction model for fracturing-well blockage-production. S103. Set the initial conditions for the three stages of fracturing, well shut-in, and production, as well as the closed outer boundary and production inner boundary conditions.

[0008] Preferably, the specific details of building the triple medium model in S101 are as follows: Based on the triple-medium flow characteristics of the reservoir after volumetric modification, including matrix, SRV zone, and main hydraulic fractures, an embedded discrete fracture model is used to characterize the main hydraulic fractures, a dual-medium model is used to characterize the SRV zone, and a single-medium model is used to characterize the matrix.

[0009] Preferably, the specific details of the integrated fracturing-well shut-in-production capacity prediction model established in S102, which combines the fracture propagation model, stress sensitivity, and capillary force absorption effect, are as follows: S1021. Perform crack propagation modeling; The perforation erosion evolution mechanism is introduced. By calculating the local energy loss generated by fracturing fluid during high-speed flow through the perforation, the throttling effect of the perforation section on fluid flow is characterized, and the multi-fracture flow rate of fracturing fluid is adaptively allocated to determine the flow rate between different hydraulic fractures. Assuming the flow distribution is the same across all fractures, the PKN model is used to solve for the net fracture pressure. The expression is as follows: ; In the formula, ,in It is the elastic modulus; The viscosity of the fracturing fluid; This is the total pumped fracturing fluid flow rate; The filtration loss coefficient; The height of the crack; Poisson's ratio; For time; Pi; Based on crack interaction, the intensity of stress interference between cracks decreases as the crack spacing increases. The coefficient of induced stress attenuation with distance is calculated. The expression is as follows: ; In the formula, The spacing between the perforation clusters; The reservoir thickness; Calculate the crack-induced stress value The expression is as follows: ; In the formula, This is a correction factor for the position of the perforation cluster, representing the position of the outermost perforation cluster within the segment. c =0.5, other perforation cluster locations c =1; based on The fractures extend simultaneously. The dynamic distribution of fracturing fluid flow into each fracture is solved based on the corresponding conditions. Ignoring wellbore friction within the fracturing section, assuming equal fluid pressure at each perforation cluster, and that the sum of fracturing fluid flow rates into each fracture equals the total pumped fracturing fluid flow, constraints are set, expressed as follows: ; ; ; In the formula, This is the total pumped fracturing fluid flow rate; For the first Fracturing fluid flow rate pumped into the cluster perforation hole; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Fluid pressure at the crack opening; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Cluster aperture frictional resistance voltage drop; For the first Induced stress in cluster cracks; Minimum horizontal ground stress; Based on the relationship between frictional pressure drop and perforation orifice parameters, calculate the first... The expression for the flow rate of fracturing fluid pumped into the cluster perforation is as follows: ; In the formula, , where represents the coefficient of friction of the orifice. This refers to the density of the fracturing fluid. The number of perforations per cluster; The diameter of the perforation hole; For flow coefficient; Calculate the length of each cluster of cracks based on the PKN model. and width The expression is as follows: ; ; S1022. Based on the closed well model and according to the effect of carbon dioxide on rock dissolution, porosity enhancement, and permeability improvement, the change in permeability over time is expressed as follows: The change in porosity over time is expressed as: ; Calculate gas production during post-compression extraction and aqueous phase yield The expression is as follows: ; ; In the formula, This is the unit conversion factor; For the first The permeability of the main fracture; For the first The relative permeability of the gas phase in the crack; For the first The width of the main crack; For the first The average crack pressure of the crack; For the first The bottom hole flowing pressure corresponding to the fracture; This refers to the viscosity of the gas phase. This is the gas phase volume coefficient; For the first The equivalent supply radius of the crack; Where is the wellbore radius; For the first The skin coefficient of the crack; For the first The relative permeability of the water phase in the crack; The viscosity of water; This is the volume coefficient of water; Full-process gas-water two-phase flow: The equation for gas phase seepage in the main fracture is as follows: ; In the formula, For local coordinate systems; The relative permeability of the gas phase in the main fracture; The gas-phase source term of the main fracture; The gas phase flow term between the main fracture and the matrix; The main crack mesh volume; Main crack porosity; The main fracture gas phase saturation; The absolute permeability of the main crack; The main crack pressure; The volume of the main crack control body; The equation for water phase seepage in the main fracture is as follows: ; In the formula, The relative permeability of the water phase in the main fracture; The water-phase source term of the main fissure; The water phase flow term between the main fracture and the matrix; The water phase saturation of the main fracture; The equation for gas-phase seepage in microcracks is as follows: ; In the formula, For gradient / divergence operators, it represents the spatial derivative in three-dimensional space; The relative permeability of the gas phase in the microcracks; The gas phase pressure in the microcracks; This refers to the gas-phase flow term between the microcracks and the main crack; For microcrack mesh volume; Microcrack porosity; The gas phase saturation of the microcracks; This represents the absolute permeability of the microcracks; when no main cracks are embedded in the microcrack network mesh. Select 0, otherwise select 1; For shape factor; This represents the absolute permeability of the matrix. The relative permeability of the matrix gas phase; The matrix gas phase pressure; The equation for water phase seepage in microcracks is as follows: ; In the formula, The relative permeability of the water phase in the microcracks; The water phase pressure in the microcracks; This refers to the water phase flow term between the micro-fractures and the main fractures; The water phase saturation in the microcracks; The initial absolute permeability of the matrix; The relative permeability of the aqueous phase in the matrix; The pressure of the aqueous phase in the matrix; The water phase pressure in the microcracks; The equation for vapor-phase flow in the matrix is ​​as follows: ; In the formula, This represents the gas phase saturation in the matrix. This refers to the density of the shale matrix. For the Langmuir volume; For Langmuir pressure; The equation for the aqueous phase flow in the matrix is ​​as follows: In the formula, for regions in the matrix system with a microcrack network... Select 1 if the value is 1, otherwise select 0.

[0010] Preferably, the specific details of setting the initial conditions for the three stages of fracturing, well shut-in, and production, as well as the closed outer boundary and production inner boundary conditions in S103 are as follows: Set the initial fracturing conditions: The pressure distribution is defined by the following expression: ; Initial pressure distribution in the main fracture; The initial gas phase pressure distribution in the microcrack network; This represents the initial gas phase pressure distribution within the matrix. Pressure distribution in the main fracture; The gas phase pressure distribution in the microcrack network; This represents the gas phase pressure distribution within the matrix. The water saturation distribution is defined by the following expression: ; Initial water saturation distribution in the main fracture; The initial water saturation distribution in the microcracks; This represents the initial water saturation distribution in the matrix; Water saturation distribution in the main cracks; The distribution of water saturation in microcracks; The distribution of water saturation in the matrix; The well-shutdown process uses the pressure and saturation distribution at the end of fracturing as initial conditions, while the production process uses the calculation results at the end of well-shutdown as initial conditions. The outer boundary is set as a closed boundary, ignoring flow exchange and pressure transmission at the boundary. The expression is as follows: ; In the formula, This is the outer boundary of the reservoir; This represents the normal flux of the aqueous phase of the matrix. This represents the normal flux of the matrix gas phase. Matrix component / energy normal flux; The boundary within the production process is set using the following expression: ; In the formula, The pressure of the main fracture at the wellbore; This refers to the pressure of the substrate at the wellbore. Bottom hole flowing pressure; These are the coordinates of the wellbore location.

[0011] Preferably, the specific content of S2 is as follows: Based on geological feature data and construction data, the integrated production capacity prediction model of fracturing-shutdown-production constructed in S1 was verified. Reservoir physical parameters and construction parameters were input into the model for simulation calculation, and the calculation results were compared and analyzed with actual on-site production data. By historical fitting and correction of the model parameters, the simulation results were made consistent with the actual production dynamics, thus completing the rationality verification of the model.

[0012] Preferably, the specific content of S3 is as follows: A larger injection rate results in higher near-wellbore pressure, causing the boosting medium to occupy the pore throat space and reducing water entry into the pores, thus preventing water lock damage. Based on the effect of capillary tension at the gas-liquid interface, the capillary pressure difference that CO2 needs to overcome to enter the micro-pore throat is calculated, as shown in the following expression: ; In the formula, The interfacial tension of carbon dioxide; Contact angle; The radius of the throat; Overcoming capillary force constraints allows CO2 to enter the throat of the micropores, achieving a occlusion effect and reducing water lock damage.

[0013] Preferably, the specific content of S4 is as follows: A parameter optimization index function is constructed to evaluate the effectiveness of CO2 energy storage fracturing, thereby evaluating and optimizing the economic benefits of fracturing schemes. The objective function is Net Present Value (NPV), and its expression is as follows: ; In the formula, Net present value; To increase cumulative gas production; The price of natural gas; Cost of CO2 injection; For CO2 injection volume; the expression means that the newly added cumulative gas production volume = cumulative gas production volume with CO2 injection - cumulative gas production volume without CO2 injection. Engineering parameters were collected, and the integrated fracturing-well shut-in-production capacity prediction model was called to perform simulation calculations to obtain the corresponding post-fracturing production. With the maximum net present value as the objective, the construction parameters and CO2 injection volume in the CO2 energy storage fracturing process were selected as optimization variables to determine the optimal injection volume.

[0014] Therefore, the CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model described above has the following beneficial effects: (1) It realizes continuous coupled simulation of the three stages of fracturing, well shut-in and production, which breaks through the limitations of traditional staged analysis. It can accurately reflect the whole process evolution law of reservoir pressure field, water saturation field and seepage parameters, and greatly improve the accuracy of post-fracturing production dynamic prediction. (2) A quantitative optimization system based on bottom-hole pressurization capacity and reservoir seepage characteristics was constructed. The injection discharge rate was constrained by the critical pressure difference of CO2 entering the micropore throat, and the injection rate was optimized by maximizing net present value. This replaced the traditional empirical parameter design method, realized the scientific optimization of CO2 injection discharge rate and injection rate, and effectively improved CO2 utilization efficiency. (3) The model comprehensively considers key engineering and geological factors such as perforation hole resistance, fracture interaction, CO2 dissolution to increase porosity and permeability. It also constructs an adaptive seepage model for the matrix, SRV zone and main hydraulic fracture triple media. It can design targeted parameters according to the physical properties and seepage mechanism of different unconventional gas reservoirs, making it more adaptable and practical. (4) By utilizing the low viscosity and high diffusivity of CO2, combined with critical pressure difference optimization, CO2 can effectively occupy the reservoir's micropore throats, thereby reducing water-locking damage and reservoir sensitivity damage caused by traditional water-based fracturing fluids, improving reservoir seepage conditions, and increasing single-well productivity. (5) Using net present value as the core economic benefit evaluation index, the optimization of fracturing parameters is directly linked to the economic benefits of production. While achieving effective reservoir transformation, the economic rationality of fracturing operations is ensured, significantly improving the overall economic benefits and engineering applicability of CO2 fracturing development in unconventional gas reservoirs, and providing reliable technical support for the development of carbon dioxide in unconventional gas reservoirs.

[0015] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0016] Figure 1 This is a flowchart of the CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model of the present invention; Figure 2The graphs show the trends of porosity and permeability over time during the well sealing process, where (a) is the trend of permeability over time and (b) is the trend of porosity over time. Figure 3 The trend charts of bottom hole pressure and daily water production fitted to the daily gas production of well X in block Y are shown, where (a) is the trend chart of bottom hole pressure fitted to the daily gas production and (b) is the trend chart of daily water production. Figure 4 The force field contour map of the pre-CO2 energy storage fracturing SRV zone is shown, where (a) is stage one: injection of 80m 3 Force field contour map of the SRV zone for pre-CO2 energy storage fracturing with fracturing fluid, (b) is stage two: injection of 80m 3 Force field contour map of the SRV zone for CO2 pre-coal storage fracturing, (c) is stage three: injection of 1600m 3 Force field contour map of the SRV zone for fracturing with CO2 pre-fracturing fluid; Figure 5 The force field cloud diagram of the pre-CO2 energy storage fracturing matrix is ​​shown, where (a) represents stage one: injection of 80m 3 Force field cloud diagram of fracturing matrix with CO2 pre-fracturing fluid, (b) is stage two: injection of 80m 3 CO2 pre-coal storage fracturing matrix force field cloud map, (c) is stage three: injection of 1600m 3 Force field contour map of fracturing matrix with CO2 pre-fracturing fluid; Figure 6 The force field cloud maps of the SRV zone for different well closure times after CO2 energy storage fracturing are shown. Among them, (a) is the force field cloud map of the SRV zone for 3 days after CO2 energy storage fracturing, (b) is the force field cloud map of the SRV zone for 5 days after CO2 energy storage fracturing, and (c) is the force field cloud map of the SRV zone for 7 days after CO2 energy storage fracturing. Figure 7 The force field cloud maps of the matrix region for different slump times of pre-CO2 energy storage fracturing are shown below. (a) is the force field cloud map of the matrix region of the pre-CO2 energy storage fracturing well after 3 days of slump, (b) is the force field cloud map of the matrix region of the pre-CO2 energy storage fracturing well after 5 days of slump, and (c) is the force field cloud map of the matrix region of the pre-CO2 energy storage fracturing well after 7 days of slump. Figure 8 Pressure field cloud map of the SRV zone after 500 days of CO2 energy storage fracturing production; Figure 9 Pressure field cloud map of the matrix region after 500 days of CO2-storage fracturing production; Figure 10 Bottom hole pressure curves for well M in block Y under different CO2 injection rates; Figure 11 This is a net present value diagram for well M in block Y under different CO2 injection rates. Detailed Implementation

[0017] To make the objectives, technical solutions, and advantages disclosed in the embodiments of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings and examples. It should be understood that the specific embodiments described herein are only used to explain the embodiments of the present invention and are not intended to limit the embodiments of the present invention. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without creative effort are within the scope of protection of this application. Examples of the embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals denote the same or similar elements or elements having the same or similar functions throughout.

[0018] It should be noted that the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion, such as a process, method, system, product, or server that includes a series of steps or units, not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such process, method, product, or device.

[0019] The following is combined with Figures 1-11 The embodiments of the present invention will be described in detail below.

[0020] Example 1 The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing-suppression-production model described in this invention has a sound theoretical basis and a simple and intuitive approach. It couples the fracturing-suppression-production process, comprehensively considers fracture propagation and orifice friction, and optimizes parameters. It can describe the integrated fracturing-suppression-production process under comprehensive consideration of reservoir properties and engineering conditions. It also considers the impact of orifice friction on flow distribution, demonstrating the bottom hole pressurization effect under different injection rates. The injection rate is optimized using the pressure difference required for CO2 to enter the micro-throat. Furthermore, CO2 occupancy overcomes the water-locking hazard of traditional fracturing. It also proposes a new optimization parameter index, the purification value, to facilitate the optimization of the injection volume during CO2 energy storage fracturing, thereby improving the overall economy and engineering applicability of fracturing operations. Figure 1 The flowchart below shows the CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model of this invention. The specific steps are as follows: S1. Based on reservoir physical properties and engineering conditions, construct an integrated production capacity prediction model for fracturing-well shut-in-production. S101. Construct a triple-media model; Based on the triple-medium flow characteristics of the reservoir after volumetric modification, including matrix, SRV zone, and main hydraulic fractures, an embedded discrete fracture model is used to characterize the main hydraulic fractures, a dual-medium model is used to characterize the SRV zone, and a single-medium model is used to characterize the matrix.

[0021] S102. Based on the fracture propagation model, stress sensitivity and capillary force absorption effect, establish an integrated production capacity prediction model for fracturing-well blockage-production. S1021. Perform crack propagation modeling; The perforation erosion evolution mechanism is introduced. By calculating the local energy loss generated by fracturing fluid during high-speed flow through the perforation, the throttling effect of the perforation section on fluid flow is characterized, and the multi-fracture flow rate of fracturing fluid is adaptively allocated to determine the flow rate between different hydraulic fractures. Assuming the flow distribution is the same across all fractures, the PKN model is used to solve for the net fracture pressure. The expression is as follows: ; In the formula, ,in It is the elastic modulus; The viscosity of the fracturing fluid; This is the total pumped fracturing fluid flow rate; The filtration loss coefficient; The height of the crack; Poisson's ratio; For time; Pi; Based on crack interaction, the intensity of stress interference between cracks decreases as the crack spacing increases. The coefficient of induced stress attenuation with distance is calculated. The expression is as follows: ; In the formula, The spacing between the perforation clusters; The reservoir thickness; Calculate the crack-induced stress value The expression is as follows: ; In the formula, This is a correction factor for the position of the perforation cluster, representing the position of the outermost perforation cluster within the segment. c =0.5, other perforation cluster locations c =1; based on The fractures extend simultaneously. The dynamic distribution of fracturing fluid flow into each fracture is solved based on the corresponding conditions. Ignoring wellbore friction within the fracturing section, assuming equal fluid pressure at each perforation cluster, and that the sum of fracturing fluid flow rates into each fracture equals the total pumped fracturing fluid flow, constraints are set, expressed as follows: ; ; ; In the formula, This is the total pumped fracturing fluid flow rate; For the first Fracturing fluid flow rate pumped into the cluster perforation hole; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Fluid pressure at the crack opening; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Cluster aperture frictional resistance voltage drop; For the first Induced stress in cluster cracks; Minimum horizontal ground stress; Based on the relationship between frictional pressure drop and perforation orifice parameters, calculate the first... The expression for the flow rate of fracturing fluid pumped into the cluster perforation is as follows: ; In the formula, , where represents the coefficient of friction of the orifice. This refers to the density of the fracturing fluid. The number of perforations per cluster; The diameter of the perforation hole; For flow coefficient; Calculate the length of each cluster of cracks based on the PKN model. and width The expression is as follows: ; ; S1022. Based on the closed well model and according to the effect of carbon dioxide on rock dissolution, porosity enhancement, and permeability improvement, the change in permeability over time is expressed as follows: The change in porosity over time is expressed as: ; Calculate gas production during post-compression extraction and aqueous phase yield The expression is as follows: ; ; In the formula, This is the unit conversion factor; For the first The permeability of the main fracture; For the first The relative permeability of the gas phase in the crack; For the first The width of the main crack; For the first The average crack pressure of the crack; For the first The bottom hole flowing pressure corresponding to the fracture; This refers to the viscosity of the gas phase. This is the gas phase volume coefficient; For the first The equivalent supply radius of the crack; Where is the wellbore radius; For the first The skin coefficient of the crack; For the first The relative permeability of the water phase in the crack; The viscosity of water; This is the volume coefficient of water; Full-process gas-water two-phase flow: The equation for gas phase seepage in the main fracture is as follows: ; In the formula, For local coordinate systems; The relative permeability of the gas phase in the main fracture; The gas-phase source term of the main fracture; The gas phase flow term between the main fracture and the matrix; The main crack mesh volume; Main crack porosity; The main fracture gas phase saturation; The absolute permeability of the main crack; The main crack pressure; The volume of the main crack control body; The equation for water phase seepage in the main fracture is as follows: ; In the formula, The relative permeability of the water phase in the main fracture; The water-phase source term of the main fissure; The water phase flow term between the main fracture and the matrix; The water phase saturation of the main fracture; The equation for gas-phase seepage in microcracks is as follows: ; In the formula, For gradient / divergence operators, it represents the spatial derivative in three-dimensional space; The relative permeability of the gas phase in the microcracks; The gas phase pressure in the microcracks; This refers to the gas-phase flow term between the microcracks and the main crack; For microcrack mesh volume; Microcrack porosity; The gas phase saturation of the microcracks; This represents the absolute permeability of the microcracks; when no main cracks are embedded in the microcrack network mesh. Select 0, otherwise select 1; For shape factor; This represents the absolute permeability of the matrix. The relative permeability of the matrix gas phase; The matrix gas phase pressure; The equation for water phase seepage in microcracks is as follows: ; In the formula, The relative permeability of the water phase in the microcracks; The water phase pressure in the microcracks; This refers to the water phase flow term between the micro-fractures and the main fractures; The water phase saturation in the microcracks; The initial absolute permeability of the matrix; The relative permeability of the aqueous phase in the matrix; The pressure of the aqueous phase in the matrix; The water phase pressure in the microcracks; The equation for vapor-phase flow in the matrix is ​​as follows: ; In the formula, This represents the gas phase saturation in the matrix. This refers to the density of the shale matrix. For the Langmuir volume; For Langmuir pressure; The equation for the aqueous phase flow in the matrix is ​​as follows: In the formula, for regions in the matrix system with a microcrack network... Select 1 if the value is 1, otherwise select 0.

[0022] S103. Set the initial conditions for the three stages of fracturing, well shut-in, and production, as well as the closed outer boundary and production inner boundary conditions.

[0023] Set the initial fracturing conditions: The pressure distribution is defined by the following expression: ; Initial pressure distribution in the main fracture; The initial gas phase pressure distribution in the microcrack network; This represents the initial gas phase pressure distribution within the matrix. Pressure distribution in the main fracture; The gas phase pressure distribution in the microcrack network; This represents the gas phase pressure distribution within the matrix. The water saturation distribution is defined by the following expression: ; Initial water saturation distribution in the main fracture; The initial water saturation distribution in the microcracks; This represents the initial water saturation distribution in the matrix; Water saturation distribution in the main cracks; The distribution of water saturation in microcracks; The distribution of water saturation in the matrix; The well-shutdown process uses the pressure and saturation distribution at the end of fracturing as initial conditions, while the production process uses the calculation results at the end of well-shutdown as initial conditions. The outer boundary is set as a closed boundary, ignoring flow exchange and pressure transmission at the boundary. The expression is as follows: ; In the formula, This is the outer boundary of the reservoir; This represents the normal flux of the aqueous phase of the matrix. This represents the normal flux of the matrix gas phase. Matrix component / energy normal flux; The boundary within the production process is set using the following expression: ; In the formula, The pressure of the main fracture at the wellbore; This refers to the pressure of the substrate at the wellbore. Bottom hole flowing pressure; These are the coordinates of the wellbore location.

[0024] S2. Model validation based on field production well data; Based on geological feature data and construction data, the integrated production capacity prediction model of fracturing-shutdown-production constructed in S1 was verified. Reservoir physical parameters and construction parameters were input into the model for simulation calculation, and the calculation results were compared and analyzed with actual on-site production data. By historical fitting and correction of the model parameters, the simulation results were made consistent with the actual production dynamics, thus completing the rationality verification of the model.

[0025] S3. Based on the prediction model constructed in S1, different injection rates are simulated to monitor the effect of bottom hole pressurization and compare it with the critical pressure difference for CO2 to overcome capillary force constraints and enter the micro-hole throat, so as to optimize the injection rate. A larger injection rate results in higher near-wellbore pressure, causing the boosting medium to occupy the pore throat space and reducing water entry into the pores, thus preventing water lock damage. Based on the effect of capillary tension at the gas-liquid interface, the capillary pressure difference that CO2 needs to overcome to enter the micro-pore throat is calculated, as shown in the following expression: ; In the formula, The interfacial tension of carbon dioxide; Contact angle; The radius of the throat; Overcoming capillary force constraints allows CO2 to enter the throat of the micropores, achieving a occlusion effect and reducing water lock damage.

[0026] S4. Construct a parameter optimization index function to evaluate the effect of CO2 energy storage fracturing, estimate the economic benefits obtained by injecting different displacements, set optimization targets, and determine the amount of CO2 injected.

[0027] A parameter optimization index function is constructed to evaluate the effectiveness of CO2 energy storage fracturing, thereby evaluating and optimizing the economic benefits of fracturing schemes. The objective function is Net Present Value (NPV), and its expression is as follows: ; In the formula, Net present value; To increase cumulative gas production; The price of natural gas; Cost of CO2 injection; For CO2 injection volume; the expression means that the newly added cumulative gas production volume = cumulative gas production volume with CO2 injection - cumulative gas production volume without CO2 injection. Engineering parameters were collected, and the integrated fracturing-well shut-in-production capacity prediction model was called to perform simulation calculations to obtain the corresponding post-fracturing production. With the maximum net present value as the objective, the construction parameters and CO2 injection volume in the CO2 energy storage fracturing process were selected as optimization variables to determine the optimal injection volume.

[0028] Example 2 Taking well M in block Y of a tight sandstone gas reservoir in a certain region as an example, firstly, based on a comprehensive consideration of reservoir physical properties and engineering conditions, an integrated fracturing-shutdown-production capacity prediction model is constructed. Secondly, considering fracture propagation models, stress sensitivity, capillary force absorption effect, and porosity erosion, a gas-water two-phase dual-porosity dual-permeability capacity model is established. Thirdly, the fracturing-shutdown-production model is characterized by changing different boundary conditions. Figure 2 The porosity and permeability of well M change over time during the well shut-in process.

[0029] Model validation was conducted. Based on geological feature data and construction data, the range of influencing factors was determined. Well X in Block Y was selected as the validation experimental well. The model was used to fit the bottom hole pressure and daily water production at a fixed daily gas production rate (production cycle of 200 days). The bottom hole pressure obtained from the model showed a similar trend to the actual bottom hole pressure, and the simulated daily water production showed a similar trend to the actual water production (e.g., ...). Figure 3 This verified the accuracy of the model; Using field data from well M in block Y, the data was input into the integrated pressure-suppression-production capacity prediction model to obtain the pressure field distribution characteristics of the SRV zone and matrix zone throughout the entire process. The pressure field cloud maps of the SRV zone and matrix zone after pressure compression are shown below. Figure 4 and Figure 5 As shown, the pressure field contour maps of the SRV zone and matrix zone during the well blockage process are as follows: Figure 6 and Figure 7 As shown, the pressure field cloud maps of the SRV region and matrix region during the production process are respectively as follows: Figure 8 and Figure 9 As shown; based on formation parameters, the pressure differential required for CO2 to enter the micropores in this area is calculated to be 2 MPa. The bottom hole boost pressure is calculated based on different injection rates (e.g., ...). Figure 10 Thus, the optimal injection displacement of well M in block Y is 4m³. 3 / min; An index model for optimizing CO2 energy storage fracturing parameters was constructed to evaluate the economic benefits obtained.

[0030] To evaluate and optimize the economic benefits of fracturing schemes, the net present value is used as the objective, and its specific expression is as follows: The price of natural gas is 1.2 yuan / m³. 3 ; The cost of CO2 injection is set at 1200 yuan / m³. 3 Based on the field data from well M in block Y, for each set of parameters, the integrated pressure-suppression-production capacity model was used for simulation calculation, yielding a corresponding cumulative gas production after pressure of 2.7086 × 10⁷ m³. 3 With the goal of maximizing net present value, the optimal CO2 injection rate during CO2 storage fracturing is determined to be 100 m³. 3 .(like Figure 11 ) Table 1 Basic Parameters of Well M Reservoir

[0031] Following the above ideas and methods, the CO2 energy storage fracturing scheme for well M was optimized. After fracturing, the block achieved significant economic benefits, indicating that the CO2 energy storage fracturing parameter optimization method based on the integrated fracturing-suppression-production model provided by this invention has significant effectiveness.

[0032] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and not to limit them. Although the present invention has been described in detail with reference to preferred embodiments, those skilled in the art should understand that modifications or equivalent substitutions can still be made to the technical solutions of the present invention, and these modifications or equivalent substitutions cannot cause the modified technical solutions to deviate from the spirit and scope of the technical solutions of the present invention.

Claims

1. A method for optimizing CO2 energy storage fracturing parameters based on an integrated fracturing and extraction model, characterized in that, Includes the following steps: S1. Based on reservoir physical properties and engineering conditions, construct an integrated production capacity prediction model for fracturing-well shut-in-production. S2. Model validation based on field production well data; S3. Based on the prediction model constructed in S1, different injection rates are simulated to monitor the effect of bottom hole pressurization and compare it with the critical pressure difference for CO2 to overcome capillary force constraints and enter the micro-hole throat, so as to optimize the injection rate. S4. Construct a parameter optimization index function to evaluate the effect of CO2 energy storage fracturing, estimate the economic benefits obtained by injecting different displacements, set optimization targets, and determine the amount of CO2 injected.

2. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 1, characterized in that, S1 specifically includes: S101. Construct a triple-media model; S102. Based on the fracture propagation model, stress sensitivity and capillary force absorption effect, establish an integrated production capacity prediction model for fracturing-well blockage-production. S103. Set the initial conditions for the three stages of fracturing, well shut-in, and production, as well as the closed outer boundary and production inner boundary conditions.

3. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 2, characterized in that, The specific details of building the triple medium model in S101 are as follows: Based on the triple-medium flow characteristics of the reservoir after volumetric modification, namely matrix, SRV zone and main hydraulic fracture, an embedded discrete fracture model is used to characterize the main hydraulic fracture, a dual-medium model is used to characterize the SRV zone, and a single-medium model is used to characterize the matrix.

4. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 3, characterized in that, The specific details of the integrated fracturing-well shut-in-production capacity prediction model established in S102 using the comprehensive fracture propagation model, stress sensitivity, and capillary force absorption effect are as follows: S1021. Perform crack propagation modeling; The perforation erosion evolution mechanism is introduced. By calculating the local energy loss generated by fracturing fluid during high-speed flow through the perforation, the throttling effect of the perforation section on fluid flow is characterized, and the multi-fracture flow rate of fracturing fluid is adaptively allocated to determine the flow rate between different hydraulic fractures. Assuming the flow distribution is the same across all fractures, the PKN model is used to solve for the net fracture pressure. The expression is as follows: ； In the formula, ,in It is the elastic modulus; The viscosity of the fracturing fluid; This refers to the total pumped fracturing fluid flow rate; The filtration loss coefficient; The height of the crack; Poisson's ratio; For time; Pi; Based on crack interaction, the intensity of stress interference between cracks decreases as the crack spacing increases. The coefficient of induced stress attenuation with distance is calculated. The expression is as follows: ； In the formula, The spacing between the perforation clusters; The reservoir thickness; Calculate the crack-induced stress value The expression is as follows: ； In the formula, This is a correction factor for the position of the perforation cluster, representing the position of the outermost perforation cluster within the segment. c =0.5, other perforation cluster locations c =1; based on The fractures extend simultaneously. The dynamic distribution of fracturing fluid flow into each fracture is solved based on the corresponding conditions. Ignoring wellbore friction within the fracturing section, assuming equal fluid pressure at each perforation cluster, and that the sum of fracturing fluid flow rates into each fracture equals the total pumped fracturing fluid flow, constraints are set, expressed as follows: ； ； ； In the formula, This refers to the total pumped fracturing fluid flow rate; For the first Fracturing fluid flow rate pumped into the cluster perforation hole; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Fluid pressure at the crack opening; The fluid pressure at the opening of the first crack; The fluid pressure at the opening of the second crack; For the first Cluster aperture frictional resistance voltage drop; For the first Induced stress in cluster cracks; Minimum horizontal ground stress; Based on the relationship between frictional pressure drop and perforation orifice parameters, calculate the first... The expression for the flow rate of fracturing fluid pumped into the perforation hole is as follows: ； In the formula, , where represents the coefficient of friction of the orifice. This refers to the density of the fracturing fluid. The number of perforations per cluster; The diameter of the perforation hole; For flow coefficient; Calculate the length of each cluster of cracks based on the PKN model. and width The expression is as follows: ； ； S1022. Based on the closed well model and according to the effect of carbon dioxide on rock dissolution, porosity enhancement, and permeability improvement, the change in permeability over time is expressed as follows: The change in porosity over time is expressed as: ; Calculate gas production during post-compression extraction and aqueous phase yield The expression is as follows: ； ； In the formula, This is the unit conversion factor; For the first The permeability of the main fracture; For the first The relative permeability of the gas phase in the crack; For the first The width of the main crack; For the first The average crack pressure of the crack; For the first The bottom hole flowing pressure corresponding to the fracture; This refers to the viscosity of the gas phase. This is the gas phase volume coefficient; For the first The equivalent supply radius of the crack; Where is the wellbore radius; For the first The skin coefficient of the crack; For the first The relative permeability of the water phase in the crack; The viscosity of water; This is the volume coefficient of water; Full-process gas-water two-phase flow: The equation for gas-phase seepage in the main fracture is as follows: ； In the formula, For local coordinate systems; The relative permeability of the gas phase in the main fracture; The gas-phase source term of the main fracture; The gas phase flow term between the main fracture and the matrix; The main crack mesh volume; Main crack porosity; The main fracture gas phase saturation; The absolute permeability of the main crack; The main crack pressure; The volume of the main crack; The equation for water phase seepage in the main fracture is as follows: ； In the formula, The relative permeability of the water phase in the main fracture; The water-phase source term of the main fissure; The water phase flow term between the main fracture and the matrix; The water phase saturation of the main fracture; The equation for gas-phase seepage in microcracks is as follows: ； In the formula, For gradient / divergence operators, it represents the spatial derivative in three-dimensional space; The relative permeability of the gas phase in the microcracks; The gas phase pressure in the microcracks; This refers to the gas-phase flow term between the microcracks and the main crack; For microcrack mesh volume; Microcrack porosity; The gas phase saturation of the microcracks; This represents the absolute permeability of the microcracks; when no main cracks are embedded in the microcrack network mesh. Select 0, otherwise select 1; For shape factor; This represents the absolute permeability of the matrix. The relative permeability of the matrix gas phase; The matrix gas phase pressure; The equation for water phase seepage in microcracks is as follows: ； In the formula, The relative permeability of the water phase in the microcracks; The water phase pressure in the microcracks; This refers to the water phase flow term between the micro-fractures and the main fractures; The water phase saturation in the microcracks; The initial absolute permeability of the matrix; The relative permeability of the aqueous phase in the matrix; The pressure of the aqueous phase in the matrix; The water phase pressure in the microcracks; The equation for gas phase flow in the matrix is ​​as follows: ； In the formula, This represents the gas phase saturation in the matrix. This refers to the density of the shale matrix. For the Langmuir volume; For Langmuir pressure; The equation for the aqueous phase flow in the matrix is ​​as follows: In the formula, for regions in the matrix system with microcrack networks... Select 1 if the value is 1, otherwise select 0.

5. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 4, characterized in that, The specific details of setting the initial conditions for the three stages of fracturing, well shut-in, and production, as well as the closed outer boundary and production inner boundary conditions in S103 are as follows: Set the initial fracturing conditions: The pressure distribution is defined by the following expression: ； Initial pressure distribution in the main fracture; The initial gas phase pressure distribution in the microcrack network; This represents the initial gas phase pressure distribution within the matrix. Pressure distribution in the main fracture; The gas phase pressure distribution in the microcrack network; This represents the gas phase pressure distribution within the matrix. The water saturation distribution is defined by the following expression: ； Initial water saturation distribution in the main fracture; The initial water saturation distribution in the microcracks; This represents the initial water saturation distribution in the matrix; Water saturation distribution in the main cracks; The distribution of water saturation in microcracks; This represents the distribution of water saturation in the matrix. The well-shutdown process uses the pressure and saturation distribution at the end of fracturing as initial conditions, while the production process uses the calculation results at the end of well-shutdown as initial conditions. The outer boundary is set as a closed boundary, ignoring flow exchange and pressure transmission at the boundary. The expression is as follows: ； In the formula, This is the outer boundary of the reservoir; This represents the normal flux of the aqueous phase of the matrix. This represents the normal flux of the matrix gas phase. Matrix component / energy normal flux; The boundary within the production process is set using the following expression: ； In the formula, The pressure of the main fracture at the wellbore; This refers to the pressure of the substrate at the wellbore. Bottom hole flowing pressure; These are the coordinates of the wellbore location.

6. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 5, characterized in that, The specific details of S2 are as follows: Based on geological feature data and construction data, the integrated production capacity prediction model of fracturing-shutdown-production constructed in S1 was verified. Reservoir physical parameters and construction parameters were input into the model for simulation calculation, and the calculation results were compared and analyzed with actual on-site production data. By historical fitting and correction of the model parameters, the simulation results were made consistent with the actual production dynamics, thus completing the rationality verification of the model.

7. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 6, characterized in that, The specific details of S3 are as follows: A larger injection rate results in higher near-wellbore pressure, causing the boosting medium to occupy the pore throat space and reducing water entry into the pores, thus preventing water lock damage. Based on the effect of capillary tension at the gas-liquid interface, the capillary pressure difference that CO2 needs to overcome to enter the micro-pore throat is calculated, as shown in the following expression: ； In the formula, The interfacial tension of carbon dioxide; Contact angle; The radius of the throat; Overcoming capillary force constraints allows CO2 to enter the throat of the micropores, achieving a occlusion effect and reducing water lock damage.

8. The CO2 energy storage fracturing parameter optimization method based on the integrated fracturing and extraction model according to claim 7, characterized in that, The specific details of S4 are as follows: A parameter optimization index function is constructed to evaluate the effectiveness of CO2 energy storage fracturing, thereby evaluating and optimizing the economic benefits of fracturing schemes. The objective function is Net Present Value (NPV), and its expression is as follows: ； In the formula, Net present value; To increase cumulative gas production; The price of natural gas; Cost of CO2 injection; For CO2 injection volume; the expression means that the newly added cumulative gas production volume = cumulative gas production volume with CO2 injection - cumulative gas production volume without CO2 injection. Engineering parameters were collected, and the integrated fracturing-well shut-in-production capacity prediction model was called to perform simulation calculations to obtain the corresponding post-fracturing production. With the maximum net present value as the objective, the construction parameters and CO2 injection volume in the CO2 energy storage fracturing process were selected as optimization variables to determine the optimal injection volume.

Images