A method and system for optimizing CO2 gas channeling prevention and well control construction parameters.

Abstract

This invention discloses a method and system for optimizing CO2 gas channeling prevention and well control construction parameters. The method includes the following steps: S1: Obtaining the basic parameters of the target well; S2: Establishing a CO2 temperature and pressure calculation model within the wellbore and a CO2 temperature, pressure, and concentration calculation model within a high-permeability channel; S3: Based on the CO2 temperature and pressure calculation model within the wellbore, outputting temperature and pressure data at different locations within the wellbore at different construction times; S4: Based on the CO2 temperature, pressure, and concentration calculation model within the high-permeability channel, outputting temperature, pressure, and concentration data at different locations within the high-permeability channel at different construction times; S5: Conducting static immersion experiments and dynamic displacement experiments with CO2-rock-well control fluid; S6: Based on the experimental results, conducting a comprehensive evaluation of the well control effect and obtaining the optimal combination; S7: Back-calculating the CO2 temperature, pressure, and concentration calculation model within the high-permeability channel; S8: Back-calculating the CO2 temperature and pressure calculation model within the wellbore and outputting the optimal construction parameters at the wellhead. This invention can more accurately optimize CO2 gas channeling prevention and well control construction parameters.

Description

Technical Field

[0001] This invention relates to the field of fracturing and mining technology, and in particular to a method and system for optimizing well control parameters to prevent CO2 gas channeling. Background Technology

[0002] After CO2 well control, CO2 displacement, and CO2 wellbore flushing operations are completed, a certain amount of CO2 may remain in the wellbore and near-wellbore formation, or a movable gas phase may form. For wells in CO2-containing or high-gas-content environments where gas invasion occurs, well control operations need to establish and maintain stable bottom hole pressure within the well control safety pressure window, while suppressing pressure instability and gas return risks caused by gas surging along the dominant channel. In existing technologies, various wellbore temperature-pressure coupling calculation methods based on continuity equations, momentum equations, and energy conservation equations have been proposed to address issues such as CO2 flow and heat transfer processes in the wellbore, and prediction of wellbore temperature and pressure distribution, as well as temperature-pressure calculation models for CO2 injection or runoff conditions. These methods can reflect the coupling effect of CO2 properties with temperature and pressure changes to a certain extent, but their research objects usually focus on the wellbore flow process under conditions such as injection, fracturing, or drilling, which differs from the "pumping-shutdown-circulation replacement" whole-process control objective required for well control scenarios.

[0003] In well control operations aimed at preventing CO2 gas channeling, the kill fluid is typically injected into the well via tubing or casing. Changes in fluid temperature, pressure, and phase within the wellbore directly affect the bottomhole pressure build-up process; therefore, wellbore flow calculations are a crucial foundation for designing well control operation parameters. However, for wells with CO2 gas intrusion, wells after CO2 operations, or wells with dominant seepage paths, the effectiveness of well control operations does not solely depend on the injection process within the wellbore. During well control operations and after pump shutdown and well shut-in, CO2 near the bottom of the well, in the wellbore section, and in the near-wellbore formation may redistribute and preferentially migrate along high-permeability channels, microfractures, channeling channels, or other dominant seepage paths, continuously interacting with the rock and kill fluid. This can affect pressure transmission stability, bottomhole pressure maintenance effectiveness, and the risk of gas channeling.

[0004] While existing methods can reflect the coupling effect of CO2 properties with temperature and pressure changes to some extent, their research usually focuses on the flow process within the wellbore. It is difficult to consider the correlation between the wellbore and the state evolution within the near-well high-permeability channels and dominant channels. It is also difficult to map the calculation results with indoor experimental conditions or field evaluation indicators. Therefore, it is difficult to quantify the contribution of different construction parameters to gas channeling risk and form parameter optimization conclusions that can directly guide field construction.

[0005] On the other hand, CO2 entering the near-wellbore formation may cause dissolution, changes in interfacial tension, changes in wettability, and alterations in pore structure and seepage characteristics. Without boundary condition setting and evaluation methods consistent with well control conditions, it is difficult to translate these effects into actionable criteria for well control pressure stability, pressure transmission efficiency, and gas channeling risk. Especially during the pump shutdown and well shut-in phases and the circulation and replacement phases, the continuous interaction and displacement breakthrough behavior between CO2, rock, and well control fluid have a significant impact on subsequent well control effectiveness and gas channeling prevention capabilities. Summary of the Invention

[0006] To address the aforementioned problems, this invention aims to provide a method and system for optimizing CO2 gas channeling prevention and well control construction parameters.

[0007] The technical solution of the present invention is as follows: On the one hand, a method for optimizing CO2 gas channeling prevention and well control construction parameters is provided, including the following steps: S1: Obtain the basic parameters of the target well, including well depth structure parameters, geological parameters, and construction parameters; S2: Based on the aforementioned basic parameters, establish a calculation model for CO2 temperature and pressure inside the wellbore and a calculation model for CO2 temperature, pressure, and concentration inside the high-permeability channel; S3: Based on the CO2 temperature and pressure calculation model inside the wellbore, input the basic parameters and output the temperature and pressure data at different locations inside the wellbore at different construction times; S4: Based on the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, input the temperature and pressure data at the bottom of the well obtained in step S3, and output the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times; S5: Based on the data obtained in step S4, conduct static soaking experiments of CO2-rock-killing fluid and dynamic displacement experiments of CO2-rock-killing fluid respectively; S6: Based on the results of the static soaking experiment of CO2-rock-kill fluid and the dynamic displacement experiment of CO2-rock-kill fluid, a comprehensive evaluation of the kill effect is conducted, and based on the evaluation results, the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration is selected. S7: Back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom-hole temperature and optimal bottom-hole pressure; S8: Back-calculate the CO2 temperature and pressure calculation model inside the wellbore, input the optimal bottom hole temperature and the optimal bottom hole pressure, and output the optimal construction parameters at the wellhead.

[0008] Preferably, in step S2, the CO2 temperature and pressure calculation model inside the wellbore includes: (1) Calculation model for frictional heat distribution coefficient (1) In the formula: The coefficient for distribution of heat generated by friction; , , These are the thermal conductivity, density, and specific heat capacity of the tubular material, respectively. , , These are the fluid's thermal conductivity, density, and specific heat capacity, respectively. (2) Mathematical model of mass conservation (2) In the formula: To control the cross-sectional area of ​​the body; To control the height of the body; To control the fluid density within the body; the horizontal bar represents the average value on the interface; the subscript i represents the spatial grid node index; The current moment; The previous moment; To control the fluid velocity within the body; subscripts i and n indicate the north interface of the control body; The average value within the time step; The unit time step; the subscripts i and s represent the south interface of the control volume; (3) Mathematical model of momentum conservation (3) In the formula: It is the acceleration due to gravity; For stress; Darcy's coefficient of friction; To control the radius of the body; (4) Mathematical model of energy conservation of a stationary control volume (4) In the formula: Specific heat capacity; To control the body temperature; subscripts i, j represent the two-dimensional mesh node indices; denoted by Boltzmann constant; subscripts i, j, S indicate the negative axial interface; subscripts i, j, N indicate the positive axial interface; subscripts i, j, F indicate the outer radial interface; subscripts i, j, B indicate the inner radial interface. The radial inner heat transfer area; The radial outer heat transfer area; (5) Mathematical model of energy conservation of flow control volume (5) In the formula: This represents the specific heat capacity at constant pressure; the subscripts i and F indicate the front interface of the control volume. To control the power of frictional heat generation within the body.

[0009] Preferably, in step S2, the CO2 temperature and pressure concentration calculation model in the high-permeability channel includes: (1) Stress equilibrium equation (6) (7) (8) In the formula: Represents the gradient operator; This is a concentration-dependent damage degradation function; This is a concentration-dependent damage degradation function; For equivalent change; The compressive strain energy density function; The coefficient of thermal expansion of a solid. Bulk modulus; For temperature change; The concentration-dependent Biot coefficient; This refers to gas phase saturation. This refers to the gas phase pressure. This indicates taking the positive part; G is the shear modulus; Indicates taking the negative part; (2) Flow equations considering capillary forces and compressibility (9) In the formula: t is time; For Biot coefficients; Porosity; The bulk modulus of the solid framework; The bulk modulus of the gas; Pore ​​pressure; For temperature; Represents the divergence operator; This refers to the relative permeability of the gas phase. This refers to the viscosity of the gas phase. The vapor pressure gradient; (3) Heat transfer equation based on small deformation theory (10) In the formula: Effective volumetric heat capacity; For fluid density; Specific heat capacity of the fluid; Darcy velocity; The coefficient of thermal expansion of the solid phase; For reference temperature; For volumetric strain; The thermal-fluid coupling coefficient; The pressure in the aqueous phase; This refers to the water phase saturation. Effective thermal conductivity; The thermal conductivity is the vapor phase conductivity. This is a concentration-dependent heat transfer attenuation function.

[0010] Preferably, step S5, which involves conducting a static soaking test of CO2-rock-kill fluid, specifically includes the following sub-steps: (1) Set the data obtained in step S4 as the experimental temperature and pressure phase concentration conditions, and set the time for the temperature and pressure phase concentration in the high permeability channel to recover to the equilibrium state after the pump is stopped as the soaking time. (2) Heat the static immersion device until its temperature reaches the experimental set temperature; (3) Calculate the partial pressure of CO2 and N2 required to achieve the target CO2 pressure and phase concentration conditions; (4) First, inject CO2 into the static soaking device to the CO2 partial pressure calculated in step (3); (5) Continue to inject N2 into the static immersion device until the experimental pressure is reached; (6) Setting the time for the heat preservation and pressure immersion test; (7) After the experiment, the core sample after the static interaction between CO2, rock and well control fluid was taken out.

[0011] Preferably, step S5, which involves conducting a dynamic displacement experiment of CO2-rock-kill fluid, specifically includes the following sub-steps: (1) The temperature after the temperature and pressure phase concentration in the high-permeability channel recovers to equilibrium after the pump stops is taken as the experimental temperature, the equilibrium pressure is taken as the inlet pressure, and the formation pressure is taken as the outlet back pressure. (2) Calculate the CO2 volume passing through a unit wall area by the total amount of CO2 pumped and the wall area of ​​the well section, and determine the CO2 partial pressure and CO2 volume that should pass through the standard core cross-sectional area; (3) Introduce the CO2 volume calculated in step (2) into the buffer tank of the dynamic displacement experiment, and continue to introduce N2 to achieve the CO2 partial pressure state calculated in step (2); (4) Use the mixed gas in the buffer tank to carry out a dynamic displacement experiment under the temperature and pressure conditions set in step (1) until no more gas is emitted from the outlet; (5) After the experiment, the core sample after the dynamic interaction between CO2, rock and well control fluid was taken out.

[0012] As a preferred option, in step S6, when conducting a comprehensive evaluation of the well control effect, the changes in pore structure, absolute permeability, water lock state, and rock surface wettability before and after CO2 action are analyzed, and the gas breakthrough time and gas holdup changes during the dynamic displacement process are analyzed.

[0013] As a preferred method, when analyzing the changes in pore structure before and after CO2 treatment, the pore structure is characterized by nuclear magnetic resonance T2 spectrum, and the changes in pore components of small pores, medium pores, large pores, and micro-wellbore sections in the core are analyzed. When analyzing the change in absolute permeability before and after CO2 treatment, the improvement rate of absolute permeability is calculated using the following formula: (11) In the formula: This represents the absolute penetration rate improvement rate. The permeability was measured after the core was dried with saturated kill fluid. Permeability measured after drying of saturated kill fluid following CO2 treatment of the core sample; When analyzing the changes in water-lock state before and after CO2 treatment, the water-lock rate is calculated using the following formula: (12) (13) (14) In the formula: To determine the water-locking rate; The water-lock damage rate before CO2 action; This represents the water-lock damage rate after CO2 action. Permeability at the bound water saturation level before CO2 action; This represents the absolute permeability of the core. Permeability at the bound water saturation level after CO2 action; When analyzing the changes in rock surface wettability before and after CO2 treatment, the degree of wettability change is calculated using the following formula: (15) In the formula: The degree of change in wettability; The contact angle before action; The contact angle after action is the wetting contact angle.

[0014] Preferably, in step S6, the preferred combination is selected based on a comprehensive evaluation index, which is calculated using the following formula: (16) In the formula: R is the comprehensive evaluation index; w1, w2, w3, and w4 are all weight coefficients, and their sum is 1; This represents the gas volume fraction in the wellbore; the subscript "max" indicates that the corresponding parameter takes the maximum value. This refers to the pressure difference between the wellbore and the formation. For CO2 concentration gradient; For gas breakthrough time; The higher the comprehensive evaluation index, the better the combined well control and gas channeling prevention effect, and the combination is selected as the preferred combination.

[0015] On the other hand, a system for optimizing CO2 gas channeling prevention and well control construction parameters is also provided, including: The parameter acquisition module is used to acquire the basic parameters of the target well, including well depth structure parameters, geological parameters, and construction parameters. The model building module is used to establish a CO2 temperature and pressure calculation model in the wellbore and a CO2 temperature, pressure and concentration calculation model in the high-permeability channel based on the basic parameters. The calculation module is used to input the basic parameters according to the CO2 temperature and pressure calculation model in the wellbore, and output the temperature and pressure data at different locations in the wellbore at different construction times; according to the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, it inputs the temperature and pressure data at the bottom of the well obtained in step S3, and outputs the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times; The comprehensive evaluation module for well control effect is used to conduct a comprehensive evaluation of the well control effect based on the results of static immersion experiments and dynamic displacement experiments of CO2-rock-well control fluid conducted using data obtained from the calculation module, and to select the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration based on the evaluation results. The back-calculation module is used to back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom-hole temperature and optimal bottom-hole pressure; it also back-calculates the CO2 temperature and pressure calculation model in the wellbore, inputs the optimal bottom-hole temperature and optimal bottom-hole pressure, and outputs the optimal wellhead construction parameters.

[0016] The beneficial effects of this invention are: 1. Existing technologies generally neglect the spatiotemporal distribution of CO2 phase state and concentration within high-permeability channels, which is crucial for gas channeling control. This invention establishes a CO2 temperature, pressure, and concentration calculation model within high-permeability channels, which can dynamically and accurately simulate the evolution of CO2 phase state and concentration at any location within the channel during the entire well control process and after pump shutdown, providing a quantitative basis for identifying the driving forces and risks of gas channeling in advantageous channels.

[0017] 2. Traditional laboratory evaluations often employ constant or idealized boundary conditions, which are inconsistent with the non-uniform temperature gradient, pressure drop, and concentration gradient during downhole well control. This invention uses the "spatiotemporally varying temperature and pressure concentration field" output by the CO2 temperature and pressure concentration calculation model within a high-permeability channel as the basis for formulating static soaking and dynamic displacement conditions. This allows the experiment to realistically reflect the differentiated environments near the wellbore section, near the channel end, and far from the channel end, significantly enhancing the guiding value of the experimental results for setting wellhead backpressure regimes, discharge grading, and pump shutdown times in the field. 3. The optimal wellhead construction parameters obtained by back-calculation in this invention can accurately control the wellhead back pressure, the injection rate of the kill pump, and the bottom hole pressure window. This allows CO2 to maintain a predictable phase and physical properties in the wellbore and near-wellbore formation, reducing density abrupt changes and fluid column fluctuations caused by phase transitions, thereby improving the accuracy of kill pressure control and shut-in stability. At the same time, static and dynamic experiments based on model output matching can identify and avoid near-wellbore damage and pressure transmission hysteresis caused by kill fluid loss, CO2 dissolution and precipitation, and pore throat blockage, reducing the risk of kill failure.

[0018] 4. This invention can "tailor-make" well control construction parameter combinations for different well conditions (such as CO2 control wells, post-displacement wells, wells with wellbore development or wells containing CO2 gas intrusion). Under the premise of meeting well control safety constraints, it optimizes the wellhead backpressure system, displacement grading strategy and CO2 content control upper limit with the goal of minimizing the gas channeling risk index. This can not only suppress CO2 upflow along wellbore sections and high-permeability channels, but also shorten the well control construction time and improve the success rate and economy of well control. Attached Figure Description

[0019] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0020] Figure 1 This is a flowchart illustrating the method of the present invention for optimizing CO2 gas channeling control well control construction parameters; Figure 2 This is a grid diagram of the area near the construction pipe column in a specific embodiment; Figure 3 and Figure 4 This is a diagram showing the changes in the pore structure of the core before and after a static immersion experiment with CO2-rock-killing fluid in a specific embodiment. Detailed Implementation

[0021] The present invention will be further described below with reference to the accompanying drawings and embodiments. It should be noted that, unless otherwise specified, the embodiments and technical features described in this application can be combined with each other. It should also be pointed out that, unless otherwise indicated, all technical and scientific terms used in this application have the same meaning as commonly understood by one of ordinary skill in the art to which this application pertains. The terms "comprising" or "including" and similar words used in this invention refer to elements or objects preceding the word that encompass the elements or objects listed following the word and their equivalents, without excluding other elements or objects.

[0022] On the one hand, such as Figure 1 As shown, the present invention provides a method for optimizing CO2 gas channeling prevention and well control construction parameters, comprising the following steps: S1: Obtain the basic parameters of the target well, including well depth structural parameters, geological parameters, and construction parameters.

[0023] S2: Based on the aforementioned basic parameters, establish a calculation model for CO2 temperature and pressure inside the wellbore and a calculation model for CO2 temperature, pressure, and concentration inside the high-permeability channel.

[0024] In one specific embodiment, the CO2 temperature and pressure calculation model inside the wellbore includes: (1) Calculation model for frictional heat distribution coefficient (1) In the formula: The coefficient for distribution of heat generated by friction; , , These are the thermal conductivity, density, and specific heat capacity of the tubular material, respectively. , , These are the fluid's thermal conductivity, density, and specific heat capacity, respectively. (2) Mathematical model of mass conservation (2) In the formula: To control the cross-sectional area of ​​the body; To control the height of the body; To control the fluid density within the body; the horizontal bar represents the average value on the interface; the subscript i represents the spatial grid node index; The current moment; The previous moment; To control the fluid velocity within the body; subscripts i and n indicate the north interface of the control body; The average value within the time step; The unit time step; the subscripts i and s represent the south interface of the control volume; (3) Mathematical model of momentum conservation (3) In the formula: It is the acceleration due to gravity; For stress; Darcy's coefficient of friction; To control the radius of the body; (4) Mathematical model of energy conservation of a stationary control volume (4) In the formula: Specific heat capacity; To control the body temperature; subscripts i, j represent the two-dimensional mesh node indices; Here, represents the Boltzmann constant; subscripts i, j, S indicate the negative axial interface (south); subscripts i, j, N indicate the positive axial interface (north); subscripts i, j, F indicate the outer radial interface (front); subscripts i, j, B indicate the inner radial interface (rear). The radial inner heat transfer area; The radial outer heat transfer area; (5) Mathematical model of energy conservation of flow control volume (5) In the formula: This represents the specific heat capacity at constant pressure; the subscripts i and F indicate the front interface of the control volume. To control the power of frictional heat generation within the body.

[0025] In the above embodiments, the following assumptions are made when establishing the CO2 temperature and pressure calculation model inside the wellbore: Assuming that the fluid mass, momentum, and energy transfer processes are symmetrically distributed along the axis of the kill string, such as Figure 2 As shown, the area near the wellbore is subdivided into the following grid areas: inside the tubing, tubing wall, annulus, casing wall, cement sheath, and reservoir rock; and it is assumed that: (1) before the well kill operation, the well kill string is filled with fluid and reaches thermal equilibrium with the formation; (2) the temperature, pressure, flow rate and density parameters at the same cross section inside the well kill string are equal; (3) the CO2 pump discharge rate and pump temperature at the wellhead of the well kill operation remain constant; (4) when the CO2 tubing is used for well kill, the annulus fluid only participates in heat transfer and does not participate in momentum and mass transfer; (5) the formation isothermal zone depth Z=Z0, and the formation temperature below the surface increases linearly; (6) frictional heat is distributed to the tubing wall and CO2 at the same time, rather than simply heating CO2.

[0026] In the above embodiments, in order to describe the distribution of frictional heat between the fluid and the pipe wall, the present invention introduces a frictional heat distribution coefficient to describe the distribution of heat to the pipe wall and the fluid. f represents the proportion of the heat generated by friction that is distributed to the CO2 fluid in the wellbore, and the remaining heat 1-f is distributed to the oil pipe wall and the annular fluid. The value of f is affected by the specific heat capacity, thermal conductivity and contact area of ​​the fluid and the pipe wall, and the value is usually 0.3-0.5.

[0027] This invention considers the frictional heat distribution coefficient, thus taking into account the distribution effect of frictional heat between CO2 fluid and the kill string during well control operations, rather than only considering the heat transfer process from the formation to CO2 in the wellbore. This allows for accurate tracking of CO2 temperature, pressure, and phase changes during well control pumping and shut-in phases, improving the accuracy of bottom hole pressure calculation and ensuring well control safety during well control.

[0028] In one specific embodiment, the CO2 temperature and pressure concentration calculation model in the high-permeability channel includes: (1) Stress equilibrium equation (6) (7) (8) In the formula: Represents the gradient operator; This is a concentration-dependent damage degradation function; This is a concentration-dependent damage degradation function; For equivalent strain ( , , There are three principal strain components (i.e., 1, 2, and 3 are indices, not powers). The compressive strain energy density function; The coefficient of thermal expansion of a solid. Bulk modulus; For temperature change; The concentration-dependent Biot coefficient; This refers to gas phase saturation. This refers to the gas phase pressure. This indicates taking the positive part; G is the shear modulus; Indicates taking the negative part; (2) Flow equations considering capillary forces and compressibility (9) In the formula: t is time; For Biot coefficients; Porosity; The bulk modulus of the solid framework; The bulk modulus of the gas; Pore ​​pressure; For temperature; Represents the divergence operator; This refers to the relative permeability of the gas phase. This refers to the viscosity of the gas phase. The vapor pressure gradient; (3) Heat transfer equation based on small deformation theory (10) In the formula: Effective volumetric heat capacity; For fluid density; Specific heat capacity of the fluid; Darcy velocity; The coefficient of thermal expansion of the solid phase; For reference temperature; For volumetric strain; The thermal-fluid coupling coefficient; The pressure in the aqueous phase; This refers to the water phase saturation. Effective thermal conductivity; The thermal conductivity is the vapor phase conductivity. This is a concentration-dependent heat transfer attenuation function.

[0029] In the above embodiments, the CO2 temperature, pressure and concentration calculation model in the high permeability channel can describe the pressure, temperature and concentration distribution of CO2 at different wellbore sections after well control construction and pump shutdown, and identify the potential path and driving force of CO2 gas channeling along the dominant channel during well control.

[0030] S3: Based on the CO2 temperature and pressure calculation model inside the wellbore, input the basic parameters and output the temperature and pressure data at different locations inside the wellbore at different construction times.

[0031] S4: Based on the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, input the temperature and pressure data at the bottom of the well obtained in step S3, and output the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times.

[0032] S5: Based on the data obtained in step S4, conduct static soaking experiments of CO2-rock-killing fluid and dynamic displacement experiments of CO2-rock-killing fluid respectively.

[0033] In a specific embodiment, conducting a static immersion experiment of CO2-rock-kill fluid includes the following sub-steps: (1) Set the data obtained in step S4 as the experimental temperature and pressure phase concentration conditions, and set the time for the temperature and pressure phase concentration in the high permeability channel to recover to the equilibrium state after the pump is stopped as the soaking time. (2) Heat the static soaking device to reach the experimental set temperature (i.e., the temperature condition in the experimental temperature-pressure phase concentration condition in step (1), i.e., the temperature data obtained in step S4). (3) Calculate the partial pressure of CO2 and the partial pressure of N2 required to achieve the target CO2 pressure and phase concentration conditions (i.e., the pressure and concentration conditions in the experimental temperature, pressure and phase concentration conditions in step (1), i.e. the pressure data and concentration data obtained in step S4); (4) First, inject CO2 into the static soaking device to the CO2 partial pressure calculated in step (3); (5) Continue to inject N2 into the static soaking device until the experimental set pressure is reached (i.e., the pressure condition in the experimental temperature-pressure phase concentration condition in step (1), i.e., the pressure data obtained in step S4). (6) Set the soaking time for the heat preservation and pressure preservation immersion experiment (i.e., the soaking time in step (1)). (7) After the experiment, the core sample after the static interaction between CO2, rock and well control fluid was taken out.

[0034] In the above embodiments, by conducting the CO2-rock-kill fluid static immersion experiment, the interaction environment between CO2 and rock and kill fluid in the wellbore section during the kill operation can be simulated.

[0035] In a specific embodiment, conducting a dynamic displacement experiment of CO2-rock-killing fluid includes the following sub-steps: (1) The temperature after the temperature and pressure phase concentration in the high-permeability channel recovers to equilibrium after the pump stops is taken as the experimental temperature, the equilibrium pressure is taken as the inlet pressure, and the formation pressure is taken as the outlet back pressure. (2) Calculate the CO2 volume passing through a unit wall area by the total amount of CO2 pumped and the wall area of ​​the well section, and determine the CO2 partial pressure and CO2 volume that should pass through the standard core cross-sectional area; (3) Introduce the CO2 volume calculated in step (2) into the buffer tank of the dynamic displacement experiment, and continue to introduce N2 to achieve the CO2 partial pressure state calculated in step (2); (4) Use the mixed gas in the buffer tank to carry out a dynamic displacement experiment under the temperature and pressure conditions set in step (1) until no more gas is emitted from the outlet; (5) After the experiment, the core sample after the dynamic interaction between CO2, rock and well control fluid was taken out.

[0036] In the above embodiments, the dynamic displacement experiment of CO2-rock-killing fluid was carried out. By recording the pressure difference change, gas and liquid production and gas breakthrough time during the experiment, the channelized migration behavior of CO2 during the well control process can be characterized.

[0037] In one specific embodiment, when conducting the CO2-rock-well-kill fluid static soaking experiment and the CO2-rock-well-kill fluid dynamic displacement experiment, the experimental temperature range is [temperature range missing]. Temperature range: 20–120℃; pressure range: 0–80 MPa.

[0038] S6: Based on the results of the static soaking experiment of CO2-rock-kill fluid and the dynamic displacement experiment of CO2-rock-kill fluid, a comprehensive evaluation of the kill effect is conducted, and based on the evaluation results, the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration is selected.

[0039] In a specific embodiment, when conducting a comprehensive evaluation of the well control effect, the changes in pore structure, absolute permeability, water lock status, and rock surface wettability before and after CO2 action are analyzed, as well as the gas breakthrough time and gas holdup changes during the dynamic displacement process.

[0040] In one specific embodiment, when analyzing the changes in pore structure before and after CO2 treatment, the pore structure is characterized by nuclear magnetic resonance T2 spectrum, and the changes in pore components of small pores, medium pores, large pores, and micro-wellbore sections in the core are analyzed. When analyzing the change in absolute permeability before and after CO2 treatment, the improvement rate of absolute permeability is calculated using the following formula: (11) In the formula: This represents the absolute penetration rate improvement rate. The permeability was measured after the core was dried with saturated kill fluid. Permeability measured after drying of saturated kill fluid following CO2 treatment of the core sample; When analyzing the changes in water-lock state before and after CO2 treatment, the water-lock rate is calculated using the following formula: (12) (13) (14) In the formula: To determine the water-locking rate; The water-lock damage rate before CO2 action; This represents the water-lock damage rate after CO2 action. Permeability at the bound water saturation level before CO2 action; This represents the absolute permeability of the core. Permeability at the bound water saturation level after CO2 action; When analyzing the changes in rock surface wettability before and after CO2 treatment, the degree of wettability change is calculated using the following formula: (15) In the formula: The degree of change in wettability; The contact angle before action; The contact angle after action is the wetting contact angle.

[0041] In one specific embodiment, the preferred combination is selected based on a comprehensive evaluation index, which is calculated using the following formula: (16) In the formula: R is the comprehensive evaluation index; w1, w2, w3, and w4 are all weight coefficients, and their sum is 1; This represents the gas volume fraction in the wellbore; the subscript "max" indicates that the corresponding parameter takes the maximum value. This refers to the pressure difference between the wellbore and the formation. For CO2 concentration gradient; For gas breakthrough time; The higher the comprehensive evaluation index, the better the combined well control and gas channeling prevention effect, and the combination is selected as the preferred combination.

[0042] In the above embodiments, the parameters required to calculate the comprehensive evaluation index are obtained through step S3 (obtaining gas phase volume fraction and pressure difference by CO2 temperature and pressure calculation model in wellbore), step S4 (obtaining CO2 concentration gradient by CO2 temperature and pressure concentration calculation model in high permeability channel), and step S6 (obtaining gas breakthrough time by dynamic displacement experiment of CO2-rock-killing fluid).

[0043] S7: Back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom hole temperature and optimal bottom hole pressure.

[0044] S8: Back-calculate the CO2 temperature and pressure calculation model inside the wellbore, input the optimal bottom hole temperature and the optimal bottom hole pressure, and output the optimal construction parameters at the wellhead.

[0045] This invention establishes a CO2 temperature and pressure calculation model within the wellbore and a CO2 temperature, pressure, and concentration calculation model within a high-permeability channel. This enables precise simulation of the spatiotemporal distribution of CO2 phases and its dissolution-precipitation behavior during well control operations. Furthermore, based on the non-uniform temperature and pressure concentration field output by the model, highly simulated static soaking and dynamic displacement experiments of CO2-rock-well control fluid are conducted. This characterizes the influence of CO2 on pore structure, permeability, wettability, and water lock release during the pump shut-in and circulation replacement stages. Indicators such as gas breakthrough time and gas holdup changes are introduced to characterize the tendency for gas channeling. Finally, under the constraint of the bottomhole pressure window (not lower than the formation pressure and lower than the fracture pressure), the optimal well control operation parameters, such as wellhead back pressure, pump injection rate, well control fluid density, viscosity, and CO2 content, are accurately solved through an inversion model. This suppresses CO2 gas channeling and improves well control safety and well control success rate. In summary, this invention enables the realization of a closed-loop optimization path of "model prediction - experimental verification - parameter inversion - field control", and obtains more accurate optimized CO2 gas channeling prevention well control construction parameters.

[0046] On the other hand, the present invention also provides a system for optimizing CO2 gas channeling prevention and well control construction parameters, comprising: The parameter acquisition module is used to acquire the basic parameters of the target well, including well depth structure parameters, geological parameters, and construction parameters. The model building module is used to establish a CO2 temperature and pressure calculation model in the wellbore and a CO2 temperature, pressure and concentration calculation model in the high-permeability channel based on the basic parameters. The calculation module is used to input the basic parameters according to the CO2 temperature and pressure calculation model in the wellbore, and output the temperature and pressure data at different locations in the wellbore at different construction times; according to the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, it inputs the temperature and pressure data at the bottom of the well obtained in step S3, and outputs the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times; The comprehensive evaluation module for well control effect is used to conduct a comprehensive evaluation of the well control effect based on the results of static immersion experiments and dynamic displacement experiments of CO2-rock-well control fluid conducted using data obtained from the calculation module, and to select the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration based on the evaluation results. The back-calculation module is used to back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom-hole temperature and optimal bottom-hole pressure; it also back-calculates the CO2 temperature and pressure calculation model in the wellbore, inputs the optimal bottom-hole temperature and optimal bottom-hole pressure, and outputs the optimal wellhead construction parameters.

[0047] In one specific embodiment, a well control operation in a tight gas reservoir that experienced gas invasion after CO2 operation was taken as the object. The method for optimizing well control operation parameters to prevent CO2 gas channeling, as described in this invention, was used to optimize the well control operation parameters and verify its effectiveness in preventing CO2 gas channeling. In this embodiment, the basic parameters for the 9th stage of well control are shown in Table 1: Table 1. Basic parameters for CO2 gas channeling prevention and well control construction in the 9th stage of a certain well.

[0048] Inputting the above basic parameters into the CO2 temperature and pressure calculation model in the wellbore shown in equations (1)-(5), the calculation results show that: under the selected well kill pump injection rate and wellhead back pressure regime, the bottom-hole CO2 pressure at the end of the well kill pump injection is 98 MPa. This bottom-hole pressure is higher than the formation pressure and lower than the formation fracture pressure, which is within the well control design's well kill safety pressure window, indicating that the bottom-hole pressure can be effectively established and the well kill standard requirements can be met under the above construction parameter conditions (it can both suppress the formation fluid backflow and not induce formation fracture and leakage risks). On the other hand, the temperature of CO2 changes from the wellhead to the bottom of the well. As the temperature gradually increases from 20°C to 55°C, combined with phase analysis, it can be determined that CO2 at the bottom of the well remains in a supercritical state. While this phase state is beneficial for reducing viscosity and improving solubility, it may also increase the risk of channelization and gas channeling due to high compressibility and low viscosity. Therefore, further optimization of well control parameters to prevent gas channeling is needed, incorporating the present invention.

[0049] The CO2 temperature-pressure concentration calculation model within a high-permeability channel employs a pre-defined single-channel structure (this channel can represent the natural fracture-wellbore connection zone, a high-permeability path formed during well control operations, or an equivalent simplified model) to simulate the behavior and risk distribution of CO2 gas channeling along the dominant channel during well control. The geometric model is 200m long and 40m wide, with a pre-defined half-fracture length of 100m. The supercritical CO2 temperature and pressure input to the model are the bottom-hole temperature and pressure output from the CO2 temperature-pressure calculation model within the wellbore. The boundary conditions consider the process of pressure, temperature, and CO2 concentration re-equilibrating within the wellbore section after pump shutdown, used to characterize the CO2 redistribution and gas channeling driving force evolution during the shut-in phase. Specific input parameters are shown in Table 2. Table 2 Input parameters for the CO2 temperature and pressure concentration calculation model in high-permeability channels

[0050] With a bottom-hole CO2 temperature of 55℃ and a formation pressure of 70MPa, the injection time was 30 minutes followed by a 20-minute pause. The simulation results are as follows: ① The pressure inside the wellbore injection port in the wellbore section gradually increased from 70MPa to 84.6MPa, and then dropped sharply after injection was stopped. After 20 minutes, the pressure dropped to about 76MPa. After the pressure at the tip of the wellbore section was transmitted, it continued to rise to 80.5MPa, and then dropped to 76MPa and stabilized after injection was stopped.

[0051] ② CO2 was continuously injected into the wellbore injection port, and the temperature remained stable at 55℃. After injection was stopped, it gradually increased to 78℃. The temperature at the fracture tip gradually decreased from 160℃ to 130℃, and then slowly decreased to 124℃ after injection was stopped (the model assumes that CO2 and the reservoir are always in thermal equilibrium).

[0052] The simulation results show that during the well control pumping stage, the pressure in the wellbore section can be effectively established and transmitted to the tip of the channel, indicating that the corresponding parameter combination is feasible for well control pressure transmission and bottom hole pressure establishment. During the pump shutdown and well shut-in stage, the pressure in the channel gradually recovers after a short period of decline and tends to be consistent with the formation pressure, indicating that there is no long-term abnormal pressure differential driving force in the wellbore section after pump shutdown, and the pressure stability during the well control process is good, providing well control conditions for suppressing the continuous upward movement of CO2 along the dominant channel.

[0053] ③ CO2 preferentially migrates along the wellbore section, mainly concentrated in the high-permeability channel, and slowly filters out into the matrix. That is, CO2 is always in a supercritical state in the wellbore section during the pumping process.

[0054] ④ Under the conditions of wellbore closure and water-dominated environment in the reservoir injection section, the CO2 concentration near the wellbore injection port can reach over 95% during the injection process, and the CO2 concentration in the dominant channel also exceeds 80%. The CO2 concentration decreases as the matrix moves further away from the fracture end. The CO2 concentration gradually decreases from the wellbore section to the surrounding area in a basically linear distribution, and the CO2 concentration drops to 0 at about 15m away from the wellbore section.

[0055] ⑤ After injection is stopped, the CO2 concentration at the wellbore injection port slowly decreases to 85%, and also slowly decreases to 70% in the high-permeability channel, eventually forming a CO2 concentration field in the reservoir, and a CO2 concentration gradient exists.

[0056] After the well is killed, the temperature, pressure and CO2 concentration inside the high-permeability channel have not yet reached complete thermodynamic equilibrium. Therefore, numerical simulations are performed on the redistribution process of temperature, pressure and concentration inside the channel after the pump is stopped at the end of the construction to evaluate the post-gas channeling effects and stability evolution characteristics.

[0057] With a bottom-hole CO2 temperature of 55℃ and a formation pressure of 70MPa, the injection time was 30 minutes followed by a 20-minute pause. The simulation results are as follows: ①During CO2 injection, the pressure inside the injection port of the wellbore section gradually increased from 70 MPa to 84.6 MPa, and the pressure at the tip of the wellbore section continued to rise to 80.5 MPa after transmission. After injection was stopped, the pressure dropped sharply. After 3 hours of injection stoppage, the pressure in the high-permeability channel dropped to about 72.5 MPa. After 8 hours of injection stoppage, the overall pressure in the high-permeability channel recovered to 71 MPa and tended to stabilize, which was close to the reservoir pressure.

[0058] ②During CO2 injection, the temperature in the high-permeability channel continuously decreases. After injection is stopped, the temperature at the injection port of the well section rises rapidly. After 3 hours of injection stoppage, the temperature at the injection port of the well section recovers from 55℃ to 115℃. After 8 hours, the overall temperature in the high-permeability channel stabilizes at around 128℃ and tends to stabilize.

[0059] Two feature point parameters from the model output were selected as experimental conditions to simulate the CO2 environment at different locations within the wellbore section. The simulation of the near end of the wellbore section was performed with a temperature of 128°C, a pressure of 71 MPa, and a CO2 concentration of 85%. The soaking time was set to 36 hours to simulate the full interaction between CO2 and the rock after the well was sealed.

[0060] The aforementioned characteristic point parameters represent the CO2 environment at three key locations during well control operations: ① the near-wellbore section (controlled by wellhead back pressure and well control pump injection rate, determining the rate of bottomhole pressure build-up); ② the wellbore section and the near end of high-permeability channels (determining whether CO2 preferentially ascends along the channels and forms early gas channeling); ③ the wellbore section and the far end of high-permeability channels (determining the intensity of CO2 dissolution, diffusion, and redistribution in the formation). Mapping this non-uniform temperature, pressure, and concentration field to laboratory experimental boundary conditions allows for verification of the model's predictive ability for the well control, pump shutdown, and well shut-in phases, and provides reliable physical property response data for parameter inversion.

[0061] Based on the calculation results of the CO2 temperature-pressure concentration calculation model within the high-permeability channel, static immersion experiments using CO2-rock-kill fluid were conducted for representative environments in two typical wellbore sections (near and far ends) of the target reservoir. The experiments employed a high-low temperature, high-pressure reactor to simulate the temperature and pressure conditions within the wellbore section. The equipment temperature control range was [range missing]. It can withstand pressure up to 80 MPa at temperatures ranging from 20°C to 120°C.

[0062] Before the experiment, the standard core sample was saturated with kill fluid and placed in the reactor, then heated to the target temperature output by the model. Based on the set CO2 molar concentration C(CO2) and total pressure P, the required CO2 partial pressure (C(CO2)×P) and N2 partial pressure (P–CO2 partial pressure) were calculated. CO2 and N2 were then slowly injected sequentially until the pressure inside the reactor stabilized at the target value. For example, to simulate the near-wellbore environment during the pump shutdown and well shut-in phase (CO2 concentration 85%, pressure 71MPa, temperature 128°C), a soaking period of 36 hours was set to reproduce the gas-liquid-rock interaction during the pump shutdown and well shut-in phase of the kill operation.

[0063] Pressure and temperature fluctuations were continuously monitored during the soaking process to ensure stability. After soaking, the rock was slowly cooled, depressurized, and the core sample was removed. The same experimental procedure was also used to simulate conditions in remote areas (e.g., CO2 concentration of 70%) to compare the differences in rock response under different concentration fields.

[0064] Experiments show that CO2 significantly affects the pore-throat structure of core samples under high temperature and high pressure (results are shown in Figure 1). Figure 3 and Figure 4 As shown in the figure, wettability and water-locking status are used to regulate the seepage path and pressure transmission behavior of the kill fluid. Prolonging the soaking time can intensify CO2-lithological interactions and induce the evolution of conductivity. When the CO2 concentration increases, its solubility, interfacial tension and other factors may trigger a competitive mechanism between water-lock release and pore blockage, thereby affecting the bottom hole pressure stability and gas channeling trend, providing an important basis for setting the shut-in time and the wellhead backpressure regime.

[0065] Further dynamic displacement experiments were conducted on CO2-rock-kill fluid to simulate the migration and breakthrough behavior of CO2 in the wellbore section and high-permeability channels during the wellbore fluid circulation injection stage. Using a high-temperature and high-pressure core displacement device (equipped with a constant flow pump, back pressure valve, pressure sensor and production metering system), continuous injection was carried out under temperature, pressure and concentration conditions consistent with the model, and the pressure difference change, gas and liquid production volume and CO2 breakthrough time were recorded.

[0066] The experiment was stopped when the produced gas composition stabilized and matched the injected composition, and the cumulative injected volume was recorded. The experiment was used to verify the coupling relationship between "well kill pump injection rate – differential pressure – breakthrough time" and to guide the formulation of well kill rate control and channelization risk avoidance strategies.

[0067] The results showed that excessively high displacement pressure differentials significantly shortened gas breakthrough time, enhanced the conductivity of dominant channels, and increased the risk of gas channeling. However, in the low pressure differential range of 1-2 MPa, dynamic backpressure control effectively delayed breakthrough time and improved wellbore pressure transmission stability. Based on this, a well control strategy of "low pressure differential – staged displacement – ​​dynamic backpressure" is recommended, with a comprehensive evaluation index R used as a basis for real-time parameter adjustment to improve well control safety and well control operation reliability. The wellhead backpressure regime and pump displacement combination determined by the method of this invention can quickly establish and stably maintain bottom hole pressure during well control operations, while significantly delaying the breakthrough time of CO2 in the wellbore section and high-permeability channels, without significant gas channeling, verifying the effectiveness of the method of this invention in preventing CO2 gas channeling in well control operations.

[0068] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for optimizing well control parameters to prevent CO2 gas channeling, characterized in that, Includes the following steps: S1: Obtain the basic parameters of the target well, including well depth structure parameters, geological parameters, and construction parameters; S2: Based on the aforementioned basic parameters, establish a calculation model for CO2 temperature and pressure inside the wellbore and a calculation model for CO2 temperature, pressure, and concentration inside the high-permeability channel; S3: Based on the CO2 temperature and pressure calculation model inside the wellbore, input the basic parameters and output the temperature and pressure data at different locations inside the wellbore at different construction times; S4: Based on the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, input the temperature and pressure data at the bottom of the well obtained in step S3, and output the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times; S5: Based on the data obtained in step S4, conduct static soaking experiments of CO2-rock-killing fluid and dynamic displacement experiments of CO2-rock-killing fluid respectively; S6: Based on the results of the static soaking experiment of CO2-rock-kill fluid and the dynamic displacement experiment of CO2-rock-kill fluid, a comprehensive evaluation of the kill effect is conducted, and based on the evaluation results, the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration is selected. S7: Back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom-hole temperature and optimal bottom-hole pressure; S8: Back-calculate the CO2 temperature and pressure calculation model inside the wellbore, input the optimal bottom hole temperature and the optimal bottom hole pressure, and output the optimal construction parameters at the wellhead.

2. The method for optimizing CO2 gas channeling prevention and well control construction parameters according to claim 1, characterized in that, In step S2, the CO2 temperature and pressure calculation model inside the wellbore includes: (1) Calculation model for frictional heat distribution coefficient （1） In the formula: The coefficient for distribution of heat generated by friction; , , These are the thermal conductivity, density, and specific heat capacity of the tubular material, respectively. , , These are the fluid's thermal conductivity, density, and specific heat capacity, respectively. (2) Mathematical model of mass conservation （2） In the formula: To control the cross-sectional area of ​​the body; To control the height of the body; To control the fluid density within the body; the horizontal bar represents the average value on the interface; the subscript i represents the spatial grid node index; The current moment; The previous moment; To control the fluid velocity within the body; subscripts i and n indicate the north interface of the control body; It is the average value within the time step; The unit time step; the subscripts i and s represent the south interface of the control volume; (3) Mathematical model of momentum conservation （3） In the formula: It is the acceleration due to gravity; For stress; Darcy's coefficient of friction; To control the radius of the body; (4) Mathematical model of energy conservation of a stationary control volume （4） In the formula: Specific heat capacity; To control the body temperature; subscripts i, j represent the two-dimensional mesh node indices; denoted by Boltzmann constant; subscripts i, j, S indicate the negative axial interface; subscripts i, j, N indicate the positive axial interface; subscripts i, j, F indicate the outer radial interface; subscripts i, j, B indicate the inner radial interface. The radial inner heat transfer area; The radial outer heat transfer area; (5) Mathematical model of energy conservation of flow control volume （5） In the formula: This represents the specific heat capacity at constant pressure; the subscripts i and F indicate the front interface of the control volume. To control the power of frictional heat generation within the body.

3. The method for optimizing CO2 gas channeling prevention and well control construction parameters according to claim 2, characterized in that, In step S2, the calculation model for CO2 temperature and pressure concentration in the high-permeability channel includes: (1) Stress equilibrium equation （6） （7） （8） In the formula: Represents the gradient operator; This is a concentration-dependent damage degradation function; This is a concentration-dependent damage degradation function; For equivalent change; The compressive strain energy density function; The coefficient of thermal expansion of a solid. Bulk modulus; For temperature change; The concentration-dependent Biot coefficient; This refers to gas phase saturation. This refers to the gas phase pressure. This indicates taking the positive part; G is the shear modulus; Indicates taking the negative part; (2) Flow equations considering capillary forces and compressibility （9） In the formula: t is time; For Biot coefficients; Porosity; The bulk modulus of the solid framework; The bulk modulus of the gas; Pore ​​pressure; For temperature; Represents the divergence operator; This refers to the relative permeability of the gas phase. This refers to the viscosity of the gas phase. The vapor pressure gradient; (3) Heat transfer equation based on small deformation theory （10） In the formula: Effective volumetric heat capacity; For fluid density; Specific heat capacity of the fluid; Darcy velocity; The coefficient of thermal expansion of the solid phase; For reference temperature; For volumetric strain; The thermal-fluid coupling coefficient; The pressure in the aqueous phase; This refers to the water phase saturation. Effective thermal conductivity; The thermal conductivity is the vapor phase conductivity. This is a concentration-dependent heat transfer attenuation function.

4. The method for optimizing CO2 gas channeling prevention and well control construction parameters according to claim 1, characterized in that, Step S5, the static soaking experiment of CO2-rock-killing fluid, specifically includes the following sub-steps: (1) Set the data obtained in step S4 as the experimental temperature and pressure phase concentration conditions, and set the time for the temperature and pressure phase concentration in the high permeability channel to recover to the equilibrium state after the pump is stopped as the soaking time. (2) Heat the static immersion device until its temperature reaches the experimental set temperature; (3) Calculate the partial pressure of CO2 and N2 required to achieve the target CO2 pressure and phase concentration conditions; (4) First, inject CO2 into the static soaking device to the CO2 partial pressure calculated in step (3); (5) Continue to inject N2 into the static immersion device until the experimental pressure is reached; (6) Setting the time for the heat preservation and pressure immersion test; (7) After the experiment, the core sample after the static interaction between CO2, rock and well control fluid was taken out.

5. The method for optimizing CO2 gas channeling prevention and well control construction parameters according to claim 1, characterized in that, Step S5, conducting the CO2-rock-kill fluid dynamic displacement experiment, specifically includes the following sub-steps: (1) The temperature after the temperature and pressure phase concentration in the high-permeability channel recovers to equilibrium after the pump stops is taken as the experimental temperature, the equilibrium pressure is taken as the inlet pressure, and the formation pressure is taken as the outlet back pressure. (2) Calculate the CO2 volume passing through a unit wall area by the total amount of CO2 pumped and the wall area of ​​the well section, and determine the CO2 partial pressure and CO2 volume that should pass through the standard core cross-sectional area; (3) Introduce the CO2 volume calculated in step (2) into the buffer tank of the dynamic displacement experiment, and continue to introduce N2 to achieve the CO2 partial pressure state calculated in step (2); (4) Use the mixed gas in the buffer tank to carry out a dynamic displacement experiment under the temperature and pressure conditions set in step (1) until no more gas is emitted from the outlet; (5) After the experiment, the core sample after the dynamic interaction between CO2, rock and well control fluid was taken out.

6. The method for optimizing CO2 gas channeling prevention well control construction parameters according to claim 1, characterized in that, In step S6, when conducting a comprehensive evaluation of the well control effect, the changes in pore structure, absolute permeability, water lock state, and rock surface wettability before and after CO2 action are analyzed, as well as the gas breakthrough time and gas holdup changes during the dynamic displacement process.

7. The method for optimizing CO2 gas channeling prevention and well control construction parameters according to claim 6, characterized in that, When analyzing the changes in pore structure before and after CO2 treatment, the pore structure was characterized by nuclear magnetic resonance T2 spectrum, and the changes in pore components in small pores, medium pores, large pores, and micro-wellbore sections of the core were analyzed. When analyzing the change in absolute permeability before and after CO2 treatment, the improvement rate of absolute permeability is calculated using the following formula: （11） In the formula: This represents the absolute penetration rate improvement rate. The permeability was measured after the core was dried with saturated kill fluid. Permeability measured after drying of saturated kill fluid following CO2 treatment of the core sample; When analyzing the changes in water-lock state before and after CO2 treatment, the water-lock rate is calculated using the following formula: （12） （13） （14） In the formula: To determine the water-locking rate; The water-lock damage rate before CO2 action; This represents the water-lock damage rate after CO2 action. Permeability at the bound water saturation level before CO2 action; This represents the absolute permeability of the core. Permeability at the bound water saturation level after CO2 action; When analyzing the changes in rock surface wettability before and after CO2 treatment, the degree of wettability change is calculated using the following formula: （15） In the formula: The degree of change in wettability; The contact angle before action; The contact angle after action is the wetting contact angle.

8. The method for optimizing CO2 gas channeling prevention well control construction parameters according to any one of claims 1-7, characterized in that, In step S6, the preferred combination is selected based on the comprehensive evaluation index, which is calculated using the following formula: （16） In the formula: R is the comprehensive evaluation index; w1, w2, w3, and w4 are all weight coefficients, and their sum is 1; This represents the gas volume fraction in the wellbore; the subscript "max" indicates that the corresponding parameter takes the maximum value. This refers to the pressure difference between the wellbore and the formation. For CO2 concentration gradient; For gas breakthrough time; The higher the comprehensive evaluation index, the better the combined well control and gas channeling prevention effect, and the combination is selected as the preferred combination.

9. A system for optimizing CO2 gas channeling prevention and well control construction parameters, characterized in that, include: The parameter acquisition module is used to acquire the basic parameters of the target well, including well depth structure parameters, geological parameters, and construction parameters. The model building module is used to establish a CO2 temperature and pressure calculation model in the wellbore and a CO2 temperature, pressure and concentration calculation model in the high-permeability channel based on the basic parameters. The calculation module is used to input the basic parameters according to the CO2 temperature and pressure calculation model in the wellbore, and output the temperature and pressure data at different locations in the wellbore at different construction times; according to the CO2 temperature, pressure and concentration calculation model in the high-permeability channel, it inputs the temperature and pressure data at the bottom of the well, and outputs the temperature, pressure and concentration data at different locations in the high-permeability channel at different construction times; The comprehensive evaluation module for well control effect is used to conduct a comprehensive evaluation of the well control effect based on the results of static immersion experiments and dynamic displacement experiments of CO2-rock-well control fluid conducted using data obtained from the calculation module, and to select the optimal combination of bottom hole temperature, bottom hole pressure and phase concentration based on the evaluation results. The back-calculation module is used to back-calculate the CO2 temperature and pressure concentration calculation model in the high-permeability channel, input the preferred combination, and output the optimal bottom-hole temperature and optimal bottom-hole pressure; it also back-calculates the CO2 temperature and pressure calculation model in the wellbore, inputs the optimal bottom-hole temperature and optimal bottom-hole pressure, and outputs the optimal wellhead construction parameters.

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