An injection scheme for saline aquifer carbon dioxide sequestration, preferred method and apparatus

Abstract

The application discloses an injection scheme optimization method and device for saline aquifer carbon dioxide storage, wherein a plurality of wells are arranged in the device, and a plurality of pressure sensors and CO2 concentration sensors are arranged around each well. In each injection scheme, different well numbers are selected, and injection work is carried out at different injection rates; the pressure increment and CO2 plume change in the device are monitored by the pressure sensors and the CO2 concentration sensors, data are recorded, and a relationship curve between the pressure propagation radius and the CO2 plume radius and the injection time is obtained; according to a relationship formula of the CO2 injection rate and the bottom hole pressure increment, the maximum injection time is calculated in combination with the limit pressure increment, the maximum CO2 storage amount under each scheme is obtained, the values in each scheme are compared, and the maximum value is selected; the well number n and the injection rate corresponding to the maximum value are the optimal injection scheme under the premise of guaranteeing the reservoir stability.

Description

TECHNICAL FIELD

[0001] The application relates to a carbon dioxide storage technology field, in particular to an injection scheme optimization method and device for carbon dioxide storage in a saline aquifer. BACKGROUND

[0002] With the development of industry and the change of people's lifestyle, the rapid growth of CO2 emission has become a prominent problem in current social development. Vigorously developing carbon capture, utilization and storage technology (CCUS) is one of the main measures to reduce carbon dioxide emissions. CO2 geological storage is a technology that permanently stores CO2 in a supercritical state in underground storage bodies, and its storage mechanism mainly includes geological structure storage, dissolution storage, residual gas storage and mineralization storage, etc. The storage places mainly include depleted oil and gas reservoirs, non-mining value coal seams, saline aquifers and deep sea, etc. Among them, the saline aquifer has great storage potential, accounting for about 98% of the total geological storage capacity, and is the most promising place in the CO2 geological storage project. China has great CO2 storage potential in saline aquifers, with a CO2 storage capacity of about 2420 Gt, which is mainly distributed in the Tarim Basin, Songliao Basin, Bohai Bay Basin and Pearl River Mouth Basin, etc.

[0003] According to the CO2 storage mechanism of the saline aquifer, it is considered that the CO2 storage potential of the saline aquifer is composed of three storage mechanisms, namely, geological structure storage, residual gas storage and dissolution storage. First, in the process of CO2 injection into the saline aquifer, CO2 is distributed in the upper region of the reservoir due to its lower density than that of the saline water, and is captured and stored under the vertical and lateral blocking conditions of the geological structure, which is the geological structure storage. With the injection work, CO2 displaces the brine in the flow direction, but when the injection stops, the fluid flows in the reverse direction due to the density difference between CO2 and brine, so CO2 migrates upward and brine flows downward. The wetting phase (brine) enters the pore through the non-wetting phase (CO2), and in this process, part of the CO2 is wrapped in the brine and is captured and stored, which is the residual gas storage. In the following centuries, CO2 near the gas-water contact surface is continuously dissolved in the saline water, which is the dissolution storage. The total storage capacity of the saline aquifer is equal to the sum of the storage capacities of the geological structure storage, the residual gas storage and the dissolution storage.

[0004] However, in the existing calculation of CO2 storage capacity, only the storage capacity generated by various storage mechanisms is considered. In the CO2 storage process, the mechanical properties of the reservoir and the plume condition of CO2 also have a great influence on the CO2 storage effect, so the calculation result may have a large error. At the same time, this technology does not consider the stress condition of the reservoir and the stability of the stratum during the CO2 storage process, which may cause problems such as too large injection speed, stratum rupture, CO2 leakage and storage failure. SUMMARY

[0005] In the existing CO2 storage amount calculation technology, only the CO2 storage mechanism is considered, and the reservoir rock mechanics and the CO2 plume condition are ignored, so that problems such as reservoir rock rupture and CO2 leakage may occur during the gas injection process. The application provides an injection scheme optimization device and method for CO2 storage in saline aquifers considering reservoir stability.

[0006] The injection scheme optimization method for CO2 storage in saline aquifers considering reservoir stability provided by the application has the following steps:

[0007] S1, calculating the limit pressure increment of the reservoir rock M ;

[0008] The limit pressure increment of the reservoir rock M is the smaller value between the limit tensile pressure increment and the limit shear pressure increment .

[0009] The limit tensile pressure increment is calculated according to the following formula:

[0010]

[0011] In the formula: is the limit pressure increment of tensile failure, MPa; is the minimum principal stress, MPa; is the initial pressure, MPa; is the tensile strength;

[0012] The limit shear pressure increment is calculated according to the following formula:

[0013]

[0014]

[0015]

[0016] In the formula: is the limit shear stress, MPa; is the maximum principal stress, MPa; is the internal friction angle of the rock; and C is the internal cohesion of the rock.

[0017] S2, installing an injection scheme optimization experimental device, the experimental device has a reservoir simulation box body in which a plurality of wells are arranged, and a plurality of pressure sensors and a plurality of CO2 concentration sensors are uniformly arranged from top to bottom around each well to monitor the pressure increment and CO2 concentration change in the device.

[0018] S3. After the experimental setup is installed, conduct gas injection experiments: In each gas injection scheme, select different numbers of wells and different injection rates. Perform gas injection; monitor T at different times in real time using pressure sensors and CO2 concentration sensors. i The pressure increment and CO2 concentration changes in various parts of the reservoir simulation tank were recorded.

[0019] S4. Obtain the time T at different times based on the recorded data. i Pressure propagation distance R i and CO2 plume radius r i ; with pressure propagation distance R i The vertical axis represents the gas injection time T. i Plot the pressure propagation distance R on the x-axis. i With gas injection time T i Regression curve of the relationship; with CO2 plume radius r i The vertical axis represents the gas injection time T. i Plot the CO2 plume radius r on the x-axis. i With gas injection time T i The regression curve shows the relationship between the reservoir pressure propagation radius and time at different gas injection rates. Function of CO2 plume radius at the upper reservoir as a function of time and the time-varying function of the CO2 plume radius at the lower end of the reservoir. .

[0020] S5. Calculate the maximum CO2 sequestration capacity. The method is as follows:

[0021] When there is only one injection well, the relationship between the CO2 injection rate of that well and the bottom hole pressure increment ∆P is as follows:

[0022]

[0023]

[0024] In the formula: This represents the bottomhole pressure increment of the gas injection well, in MPa. The specified injection rate; m 3 / d; B is the reservoir thickness, m; b is the CO2 distribution thickness, m; Let be the radius of the injection well, in meters. Let m be the radius of the CO2 plume at the upper end of the reservoir as a function of time. Let be the radius of the CO2 plume at the lower end of the reservoir as a function of time, in meters. The reservoir pressure propagation radius is a function of time, in meters (m); t is the gas injection time, in seconds (d). Vertical average mobility; Formation water mobility; CO2 mobility;

[0025] The ultimate pressure increment ∆P calculated in step S1 M Substitute into the formula above The maximum injection time T when the ultimate pressure increment is reached is calculated. M Then, the maximum CO2 sequestration capacity under this condition was calculated. :

[0026]

[0027] When multiple gas injection wells are operating simultaneously, the bottom pressure increment of a single gas injection well is:

[0028]

[0029] In the formula: The bottom pressure increment of a gas injection well under the action of multiple wells, in MPa;

[0030] The distance from a given gas injection well to other gas injection wells, in meters (m).

[0031] The ultimate pressure increment ∆P calculated in step S1 M Substitute into the formula above The maximum injection time T when the ultimate pressure increment is reached is calculated. M Then, the maximum CO2 sequestration capacity under this condition was calculated. :

[0032]

[0033] Determination and optimization of S6 and CO2 sequestration potential:

[0034] Following the steps described above, different gas injection rates were calculated for different numbers of gas injection wells within the reservoir. Maximum CO2 sequestration capacity By comparing the various options Choose the largest value. value, the maximum The corresponding well number n and injection rate This refers to the optimal gas injection scheme under the premise of ensuring reservoir stability.

[0035] The structure of the experimental device used in step S2 of the method comprises a CO2 storage tank, a formation water storage tank, a reservoir simulation box, a data acquisition system and a waste liquid collection tank; the CO2 storage tank and the formation water storage tank are connected with the reservoir simulation box, for injecting CO2 and formation water into the reservoir simulation box; the reservoir simulation box is provided with a liquid outlet at the bottom, and the liquid outlet is connected with the waste liquid collection tank.

[0036] The reservoir simulation box is uniformly provided with a plurality of wells, and a plurality of pressure sensors and a plurality of CO2 concentration sensors are uniformly arranged from top to bottom around each well; the reservoir simulation box is filled with reservoir rock samples with the same composition as the actual target reservoir rock composition; the reservoir simulation box is provided with a formation water injection port and a CO2 injection port at the top; and the data acquisition system is connected with the pressure sensors and the CO2 concentration sensors simultaneously. The pipeline connecting the CO2 storage tank and the reservoir simulation box is provided with a valve, a high-pressure pump and a pressure gauge, forming a gas injection system; the pipeline connecting the formation water storage tank and the reservoir simulation box is provided with a valve, a high-pressure pump and a pressure gauge, forming a formation water injection system.

[0037] Preferably, in step S3, the steps of the gas injection experiment are as follows:

[0038] S31, simulating the original state of the formation: injecting formation water into the reservoir simulation box, and stopping water injection when the pressure in the reservoir simulation box reaches and stabilizes at the original formation pressure P0;

[0039] S32, selecting one well in the middle of the reservoir simulation box as a gas injection well, and injecting CO2 into the reservoir simulation box at a specified injection rate Q1 under the premise that the pressure increment ΔP does not exceed the limit pressure increment

[0040] ΔP M , and real-time monitoring the pressure increment and the CO2 concentration change of each part of the reservoir simulation box at different times T i , and recording the data; after the experiment is completed, discharging the mixed fluid in the reservoir simulation box to the waste liquid treatment tank;

[0041] S33, changing the injection rate to Q2, Q3, Q4... Q n , and repeating step S32;

[0042] S34, changing the gas injection scheme, selecting different well numbers as gas injection wells, and performing experiments according to the operations of steps S32 and S33.

[0043] Compared with the prior art, the present application has the following advantages:

[0044] The present invention provides an optimal gas injection scheme for CO2 sequestration in saline aquifers considering reservoir stability. Based on the theoretical calculation of the ultimate pressure increment of the reservoir rock, and combined with a specific experimental setup, the maximum CO2 sequestration rate under each scheme is determined. The calculation results of each scheme are then compared to obtain the final maximum CO2 sequestration rate, corresponding to the number of wells n and the injection rate. This means that the optimal gas injection scheme is determined under the premise of ensuring reservoir stability. The method of this invention overcomes the problems that existing methods for calculating CO2 sequestration capacity only consider the CO2 sequestration mechanism and ignore the mechanical properties of reservoir rocks and the CO2 plume conditions, which may lead to problems such as reservoir rock fracturing and CO2 leakage during the gas injection process.

[0045] Other advantages, objectives and features of the present invention will become apparent in part from the following description, and in part from those skilled in the art through study and practice of the invention. Attached Figure Description

[0046] Figure 1 A schematic diagram of the experimental apparatus of the present invention.

[0047] Figure 2 Schematic diagram of gas injection well installation in reservoir simulation box.

[0048] Figure 3 Top view of the distribution of gas injection wells in the reservoir simulation box.

[0049] Figure 4 A schematic diagram showing the installation of pressure sensors and multiple CO2 concentration sensors in the reservoir simulation tank.

[0050] Figure 5 Schematic diagram of CO2 plume.

[0051] Figure 6 The radius f(t) of the CO2 plume at the top of the reservoir under different injection rates. x Regression curve of relationship with injection time.

[0052] Figure 7 The radius f(t) of the CO2 plume at the bottom of the reservoir under different injection rates. y Regression curve of relationship with injection time.

[0053] Figure 8 Regression curves showing the relationship between reservoir pressure propagation radius g(t) and injection time at different injection rates. Detailed Implementation

[0054] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0055] likeFigures 1-4 As shown, the experimental apparatus used in the preferred method for CO2 sequestration in saline aquifers considering reservoir stability according to the present invention includes a CO2 storage tank 1, a formation water storage tank 2, a reservoir simulation chamber 3, a data acquisition system 4, and a waste liquid collection tank 5. Both the CO2 storage tank 1 and the formation water storage tank 2 are connected to the reservoir simulation chamber 3 for injecting CO2 and formation water into it. An outlet is located at the bottom of the reservoir simulation chamber 3, connected to the waste liquid collection tank 5. A valve 15 is installed on the connecting pipeline between the waste liquid collection tank 5 and the reservoir simulation chamber 3. The waste liquid collection tank 5 is used to recover the waste liquid generated in the simulation chamber after the experiment.

[0056] The reservoir simulation chamber 5 contains several wells 6 evenly spaced, with multiple pressure sensors 7 and multiple CO2 concentration sensors 8 evenly arranged around each well 6 from top to bottom. In one embodiment, 37 wells are evenly spaced within the reservoir simulation chamber, with 6 pressure sensors and 6 CO2 concentration sensors evenly arranged around each well from top to bottom. The composition of the reservoir rock sample filling the reservoir simulation chamber 5 is the same as that of the actual target reservoir rock. A formation water injection port and a CO2 injection port are provided at the top of the reservoir simulation chamber, which are used to connect the formation water storage tank 2 and the CO2 gas storage tank 1, respectively. The data acquisition system 4 is connected to both the pressure sensors 7 and the CO2 concentration sensors 8. A valve 9, a high-pressure pump 10, and a pressure gauge 11 are installed on the pipeline connecting the CO2 gas storage tank 1 and the reservoir simulation chamber 3 to form a gas injection system; a valve 12, a high-pressure pump 13, and a pressure gauge 14 are installed on the pipeline connecting the formation water storage tank 2 and the reservoir simulation chamber 3 to form a formation water injection system.

[0057] The method for calculating CO2 sequestration potential using the above-described apparatus and method includes the following steps:

[0058] (1) Calculate the maximum pressure increment of the reservoir: Rock failure mainly involves two types: tensile failure and shear failure. Therefore, the ultimate pressure increment ∆P of the reservoir rock is... M This is the smaller of the increments of ultimate tensile pressure and ultimate shear pressure. The mechanical parameters of the reservoir rock can be obtained through rock mechanics experiments: maximum principal stress (…). Minimum principal stress ( ),tensile strength( ), rock cohesion ( ), the normal stress on the rock ( ), rock internal friction angle ( This allows for the calculation of the ultimate pressure increment ∆P of the reservoir rock. M .

[0059] When the pore pressure is greater than the sum of the minimum principal stress and the tensile strength of the rock, the rock will be stretched along the plane perpendicular to the minimum principal stress. Limit tensile pressure increment The calculation formula is as follows:

[0060]

[0061] In the formula: Limit pressure increment of tensile failure, MPa; Minimum principal stress, MPa; Initial pressure, MPa; Tensile strength;

[0062] The shear failure of the rock is mainly based on the Mohr-Coulomb criterion. When the shear stress exceeds the sum of the cohesion and friction of the rock, the rock will be sheared, as follows:

[0063]

[0064] In the formula: Shear stress, MPa; Cohesion of rock, MPa; Normal stress of rock, MPa; Internal friction angle of rock, °.

[0065] When the rock failure occurs along the angle of 45° with the maximum principal stress, the limit shear pressure increment of shear failure The calculation formula is as follows:

[0066]

[0067]

[0068]

[0069] In the formula: Limit shear stress, MPa; Maximum principal stress, MPa; Internal friction angle of rock; C is the cohesion of rock.

[0070] (2) Install the experimental device and check the air tightness of the device:

[0071] Reservoir rock sample preparation method: in order to ensure that the artificial model and the actual saline layer reservoir have similar properties, the stone powder component of the pressed artificial core sample must be consistent with the target reservoir rock component, and the mesh number of the used stone powder is determined by the porosity and permeability of the macroscopic physical model. The screened stone powder is uniformly mixed with the curing agent, and the mixed material is placed in the simulation box of the model system according to the order of the sublayer. At the same time, the gas injection well is set during the placement process, and a pressure sensor and a CO2 concentration sensor are pre-embedded at the designed position for subsequent pressure increment and CO2 plume monitoring after the placement of each layer of stone powder is completed. The distribution is shown in Figure 4 Finally, the stone powder mixture in the mold is pressed into a shape after drying, and the preparation of the artificial rock sample is completed.

[0072] Prepare the formation water sample, and the salinity measurement standard shall comply with the standard "JY / T 020-1996". The formation water sample and the CO2 sample are respectively placed in the water storage tank and the gas storage tank.

[0073] (3) Gas injection experiment

[0074] First step, simulate the original state of the formation: open the valve 12, use the pressure pump 13 to inject the formation water from the water storage tank 2 into the simulation box 3, when the pressure in the simulation box 3 reaches and stabilizes at the original pressure P0 of the formation, close the pressure pump 13 and the valve 12, and stop the water injection work.

[0075] Second step, select one well in the middle of the simulation box 3 as the gas injection well, open the valve 9 and the pressure pump 10, and inject CO2 from the gas storage tank 1 into the simulation box 3 at a specified injection rate Q1 under the premise that the pressure increment ΔP does not exceed the limit pressure increment ΔP M , use the pressure sensor 7 and the CO2 concentration sensor 8 to monitor the pressure propagation distance R i and the CO2 plume radius r i in the simulation box 3 at different times Ti in real time, and record the data; after the experiment is completed, open the valve 15 to discharge the mixed fluid in the simulation box 3 to the waste liquid treatment tank 5.

[0076] Third step, change the injection rate to Q2, Q3, Q4…Q n , repeat the second step;

[0077] Fourth step, change the injection scheme, select different well numbers as the gas injection well, and perform the experiment according to the operation of the second and third steps.

[0078] (4) Through the recorded data, the pressure propagation distance R i and the CO2 plume radius r i and the time T i are established to obtain the regression curve of different injection rates Downward pressure propagation distance R i and CO2 plume radius r i as a function of time T i g(t) and f(t). Figure 5 is a CO2 plume schematic. In one embodiment, the resulting CO2 plume radius f(t) at the top of the reservoir as a function of injection time for different injection rates x is shown in Figure 6 . The CO2 plume radius f(t) at the bottom of the reservoir as a function of injection time for different injection rates y is shown in Figure 7 . The pressure propagation radius g(t) as a function of injection time for different injection rates Figure 8 .

[0079] (5) Calculation of CO2 storage potential:

[0080] From the superposition principle, the maximum pressure increase during injection always occurs at the bottom of the injection well. Therefore, under the assumption of no fractures and traps, in an open boundary reservoir, the precise relationship between the single well CO2 injection rate and the pressure increase at the bottom of the injection well, ∆P, for long injection times is as follows:

[0081]

[0082]

[0083] Further, when multiple injection wells are operating simultaneously, assuming that the CO2 plumes do not interfere with each other, the pressure increase at the bottom of an injection well is:

[0084]

[0085] When the reservoir boundary is closed, the above formula is modified as follows:

[0086]

[0087]

[0088] where: is the pressure derivative, m 2 / d; is the reservoir radius, m; K is the reservoir permeability, mD; is the reservoir porosity; is the fluid viscosity, mPa∙s; is the overall compressibility, MPa -1 .

[0089] The limit pressure increase ∆P calculated in the first step isM Substitute the formula above into Or , calculate the maximum injection time T when the limit pressure increment is reached M , and then calculate the maximum CO2 storage under this condition :

[0090]

[0091] According to the above method, the maximum CO2 storage under different injection schemes can be calculated .

[0092] By comparing the size of the value of each scheme , the maximum value is selected , the well number n and the injection rate corresponding to the maximum value are the optimal injection scheme under the premise of ensuring reservoir stability.

[0093] The above is only a preferred embodiment of the present application, and does not limit the present application in any form. Although the present application has been disclosed as above with a preferred embodiment, it is not intended to limit the present application. Any person skilled in the art can make some changes or modifications to the above disclosed technical content without departing from the scope of the technical solution of the present application, and any simple modification, equivalent change and modification of the above embodiment according to the technical essence of the present application are still within the scope of the technical solution of the present application.

Claims

1. A preferred method for gas injection scheme for carbon dioxide sequestration in saline aquifers, characterized in that, The steps are as follows: S1. Calculate the ultimate pressure increment of the reservoir rock. P M ; S2. Install the experimental device. The reservoir simulation box of the experimental device has several wells arranged in it. Around each well, multiple pressure sensors and multiple CO2 concentration sensors are evenly arranged from top to bottom to monitor the pressure increment and CO2 concentration change in the device. S3. After the experimental setup is installed, conduct a gas injection experiment: In each gas injection scheme, select a different number of wells from several wells as injection wells, and inject gas at different rates. Perform gas injection; monitor T at different times in real time using pressure sensors and CO2 concentration sensors. i Below, the pressure increment and CO2 concentration changes in various parts of the reservoir simulation tank were recorded; S4. Obtain the time T at different times based on the recorded data. i Pressure propagation distance R i and CO2 plume radius r i ; respectively determine the pressure propagation distance R i With gas injection time T i Regression curve of CO2 plume radius r i With gas injection time T i The regression curve shows the relationship between the reservoir pressure propagation radius and time at different gas injection rates. Function of CO2 plume radius at the upper reservoir as a function of time and the time-varying function of the CO2 plume radius at the lower end of the reservoir. ; S5. Calculate the maximum CO2 sequestration capacity. The method is as follows: When there is only one injection well, the CO2 injection rate of that well is related to the bottomhole pressure increment. The relationship for P is as follows: In the formula: This represents the bottom hole pressure increment of the gas injection well, in MPa. The specified injection rate; m 3 / d; B is the reservoir thickness, m; b is the CO2 distribution thickness, m; Let be the radius of the gas injection well, in meters. Let m be the radius of the CO2 plume at the upper end of the reservoir as a function of time. Let be the radius of the CO2 plume at the lower end of the reservoir as a function of time, in meters. Let m be the reservoir pressure propagation radius as a function of time. t represents the gas injection time, d; Vertical average mobility; Formation water mobility; CO2 mobility; The ultimate pressure increment calculated in step S1 P M Substitute into the formula above The maximum injection time T when the ultimate pressure increment is reached is calculated. M Then, the maximum CO2 sequestration capacity under this condition was calculated. : When multiple gas injection wells are operating simultaneously, the bottom pressure increment of a single gas injection well is: In the formula: The bottom pressure increment of a gas injection well under the action of multiple wells, in MPa; The distance from a given gas injection well to other gas injection wells, in meters (m). The ultimate pressure increment calculated in step S1 P M Substitute into the formula above The maximum injection time T when the ultimate pressure increment is reached is calculated. M Then, the maximum CO2 sequestration capacity under this condition was calculated. : Determination and optimization of S6 and CO2 sequestration potential: Following the steps described above, different gas injection rates were calculated for different numbers of gas injection wells within the reservoir. Maximum CO2 sequestration capacity By comparing the various options Choose the largest value. value, the maximum The corresponding well number n and injection rate This refers to the optimal gas injection scheme under the premise of ensuring reservoir stability.

2. The preferred method for gas injection scheme of carbon dioxide sequestration in saline aquifers as described in claim 1, characterized in that, In step S1, the ultimate pressure increment of the reservoir rock P M Increment of ultimate tensile pressure and ultimate shear pressure increment The smaller of the two; Ultimate tensile pressure increment The calculation formula is as follows: In the formula: The ultimate pressure increment at tensile failure, in MPa; The minimum principal stress is MPa; Initial pressure, MPa; Tensile strength; Ultimate shear pressure increment The calculation formula is as follows: In the formula: The ultimate shear stress is given in MPa. The maximum principal stress is expressed in MPa. θ is the internal friction angle of the rock; C is the cohesion of the rock.

3. The preferred method for gas injection scheme of carbon dioxide sequestration in saline aquifers as described in claim 1, characterized in that, In step S2, the experimental setup includes a CO2 storage tank, a formation water storage tank, a reservoir simulation chamber, a data acquisition system, and a waste collection tank. Both the CO2 storage tank and the formation water storage tank are connected to the reservoir simulation chamber for injecting CO2 and formation water into it. An outlet is located at the bottom of the reservoir simulation chamber and connected to the waste collection tank. Several wells are evenly arranged within the reservoir simulation chamber, and multiple pressure sensors and multiple CO2 concentration sensors are evenly distributed around each well from top to bottom. The composition of the reservoir rock sample filling the simulation chamber is the same as that of the actual target reservoir rock. A formation water injection port and a CO2 injection port are located at the top of the simulation chamber. The data acquisition system is simultaneously connected to the pressure sensors and the CO2 concentration sensors.

4. The preferred method for gas injection scheme of carbon dioxide sequestration in saline aquifers as described in claim 3, characterized in that, In the experimental setup, valves, high-pressure pumps, and pressure gauges are installed on the pipeline connecting the CO2 storage tank and the reservoir simulation box to form a gas injection system; valves, high-pressure pumps, and pressure gauges are also installed on the pipeline connecting the formation water storage tank and the reservoir simulation box to form a formation water injection system.

5. The preferred method for gas injection scheme of carbon dioxide sequestration in saline aquifers as described in claim 4, characterized in that, In step S3, the steps for conducting the gas injection experiment are as follows: S31. Simulate the original state of the formation: Inject formation water into the reservoir simulation box. When the pressure inside the reservoir simulation box reaches and stabilizes at the initial formation pressure P0, stop the water injection. S32. Select one well in the middle of the reservoir simulation box as a gas injection well, and increase the pressure... P does not exceed the ultimate pressure increment. P M Under the premise of a specified injection rate Q1, CO2 is injected into the reservoir simulation chamber, and the pressure sensor and CO2 concentration sensor monitor the temperature at different times T in real time. i The pressure increment and CO2 concentration changes in various parts of the reservoir simulation tank were recorded. After the experiment, the mixed fluid in the reservoir simulation tank was discharged to the waste liquid treatment tank. S33. Change the injection rate to Q2, Q3, Q4...Q respectively. n Repeat step S32; S34. Change the gas injection scheme, select different numbers of wells as gas injection wells, and conduct experiments according to the operations in steps S32 and S33.

6. The preferred method for gas injection scheme of carbon dioxide sequestration in saline aquifers as described in claim 5, characterized in that, In step S4, the pressure propagation distance R is used as the reference. i The vertical axis represents the gas injection time T. i Plot the pressure propagation distance R on the x-axis. i With gas injection time T i Relationship regression curve; with CO2 plume radius r i The vertical axis represents the gas injection time T. i Plot the CO2 plume radius r on the x-axis. i With gas injection time T i The relationship regression curve.

7. An experimental apparatus used in a preferred method for gas injection scheme of carbon dioxide sequestration in a saline aquifer as described in claim 1, characterized in that, It includes a CO2 storage tank, a formation water storage tank, a reservoir simulation box, a data acquisition system, and a waste liquid collection box; the CO2 storage tank and the formation water storage tank are both connected to the reservoir simulation box and are used to inject CO2 and formation water into the reservoir simulation box; the bottom of the reservoir simulation box is provided with a liquid outlet, which is connected to the waste liquid collection box; The reservoir simulation box contains several wells evenly arranged, and around each well, multiple pressure sensors and multiple CO2 concentration sensors are evenly arranged from top to bottom. The composition of the reservoir rock sample in the reservoir simulation box is the same as that of the actual target reservoir rock. A formation water injection port and a CO2 injection port are set at the top of the reservoir simulation box. The data acquisition system is connected to both the pressure sensors and the CO2 concentration sensors. Valves, high-pressure pumps, and pressure gauges are installed on the pipeline connecting the CO2 storage tank and the CO2 injection port to form a gas injection system; valves, high-pressure pumps, and pressure gauges are installed on the pipeline connecting the formation water storage tank and the formation water injection port to form a formation water injection system.

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