Device and method for evaluating wellbore tightness under in-situ conditions of carbon dioxide geological storage

Abstract

The application discloses a kind of carbon dioxide geological storage in situ condition wellbore sealing evaluation device and method, including corrosion wellbore test module, carbon dioxide displacement module, gas channeling simulation module, wellbore temperature and pressure control module and formation temperature and pressure control module, corrosion wellbore test module includes wellbore combination and test shell, wellbore combination is worn in test shell, and the top end between wellbore combination and the top end of test shell and the bottom end between wellbore combination and the bottom end of test shell form closed cavity, the top end of test shell is equipped with gas flowmeter, and test shell is sequentially provided with confining pressure bin and heating bin along the radial direction away from wellbore combination, the lithology-temperature-pressure-carbonic acid environment in the carbon dioxide geological storage process can be simulated by the application, the sealing capacity under the in situ service condition of evaluation wellbore is realized, to play the purpose of optimizing cement slurry formulation, optimizing casing material, reducing carbon dioxide leakage risk.

Description

Technical Field

[0001] This invention relates to the field of carbon dioxide geological storage technology, and in particular to a device and method for evaluating wellbore sealing performance under in-situ conditions for carbon dioxide geological storage. Background Technology

[0002] Global climate change is a severe challenge facing humanity. Since the Industrial Revolution, greenhouse gas concentrations have risen dramatically, making the exploration of reliable emission reduction methods a key research focus. Geological carbon dioxide sequestration (GC-CSD) is a fallback technology for emission reduction, involving the injection of captured carbon dioxide into deep formations through wells to achieve permanent emission reduction. Suitable sites for GC-CSD generally contain numerous completed wells, some of which penetrate both the GC reservoir and the overlying caprock, and are widely recognized as high-risk locations for GC leakage.

[0003] After carbon dioxide is injected into the formation, it dissolves in pore water, forming a corrosive fluid rich in carbonic acid. This carbonic acid undergoes complex corrosive degradation reactions with cement and casing, altering the physicochemical properties of the materials and significantly impacting wellbore sealing performance. Carbon dioxide escape due to wellbore barrier seal failure poses multiple threats: environmentally, every 10,000 tons of carbon dioxide leakage will offset the carbon sequestration of approximately 1 million trees; engineering-wise, wellbore repair and disposal will significantly increase economic costs; and safety-wise, sudden carbon dioxide vaporization will directly threaten human lives. Therefore, evaluating the wellbore sealing capacity and its evolution within the storage site is crucial during carbon dioxide geological storage. However, existing research equipment and methods often simplify the in-situ service conditions of the wellbore, resulting in inaccurate simulations. For example, the fluid medium used in the experiment is pure carbon dioxide, but pure carbon dioxide is not corrosive, so it cannot accurately simulate the corrosive environment downhole. Another example is that a CT scanning system is used to analyze parameters such as porosity and permeability of the wellbore assembly every 5 hours to determine the sealing condition of the wellbore cemented surface. This method can only determine whether the cemented surface is damaged, but it cannot obtain the leakage pressure and leakage degree when the cemented surface is damaged and leaks, and cannot study the evolution law of wellbore sealing performance.

[0004] Therefore, there is an urgent need for a new wellbore sealing performance evaluation device and method under in-situ conditions of carbon dioxide geological sealing to solve the above-mentioned technical problems. Summary of the Invention

[0005] The present invention aims to solve the above-mentioned technical problems, namely, to solve the problem that existing research devices and methods often simplify the in-situ service conditions of wellbore, resulting in inaccurate simulation and affecting the accurate evaluation of wellbore sealing performance.

[0006] To this end, in a first aspect, the present invention provides a device for evaluating the sealing performance of a wellbore assembly under in-situ conditions of carbon dioxide geological storage, comprising a corrosion wellbore testing module, a carbon dioxide displacement module, a gas channeling simulation module, a wellbore temperature and pressure control module, and a formation temperature and pressure control module. The corrosion wellbore testing module includes a wellbore assembly, a gas flow meter, and a testing housing. The wellbore assembly is disposed within the testing housing. Closed cavities are formed between the top end of the wellbore assembly and the top end of the testing housing, and between the bottom end of the wellbore assembly and the bottom end of the testing housing. A gas flow meter is installed at the top end of the testing housing for measuring... Gas flows from the closed cavity at the bottom through the wellbore assembly and then exits through the closed cavity at the top. Inside the test housing, a confining pressure chamber and a heating chamber are arranged sequentially along the radial direction away from the wellbore assembly. The carbon dioxide displacement module is configured to introduce a carbonic acid solution of carbon dioxide and formation water into the wellbore assembly. The wellbore temperature and pressure control module is configured to control the temperature and pressure inside the wellbore assembly. The formation temperature and pressure control module is configured to control the temperature of the heating chamber and the pressure inside the confining pressure chamber. The gas flow simulation module is configured to inject the required gas from the bottom of the wellbore assembly into the interior of the wellbore assembly.

[0007] In a specific embodiment of the wellbore sealing performance evaluation device under the above-mentioned in-situ carbon dioxide geological storage conditions, the wellbore assembly sealing performance evaluation device under the in-situ carbon dioxide geological storage conditions further includes a control wellbore test module and a formation water displacement module. The control wellbore test module has the same structure as the corrosion wellbore test module. The formation water displacement module introduces formation water into the wellbore assembly in the control wellbore test module. The wellbore temperature and pressure control module is used to control the temperature and pressure inside the wellbore assembly in the control wellbore test module. The formation temperature and pressure control module is used to control the temperature of the heating chamber and the pressure inside the confining chamber in the control wellbore test module. The gas flow simulation module is used to inject the required gas from the bottom of the wellbore assembly in the control wellbore test module into the interior of the wellbore assembly.

[0008] In a specific embodiment of the wellbore sealing performance evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the test shell includes an insulating shell, a confining pressure shell, and a rubber sleeve. Both the insulating shell and the confining pressure shell are hollow cylindrical structures. The insulating shell is fitted over the outside of the confining pressure shell, and a heating chamber is formed between the two. The confining pressure shell is fitted over the outside of the rubber sleeve, and a confining pressure chamber is formed between the two. The wellbore assembly passes through the inside of the rubber sleeve and fits against it. A first sealing component is installed at the top of the confining pressure shell, and a second sealing component is installed at its bottom. The confining pressure shell achieves a seal with both the wellbore assembly and the rubber sleeve through the first sealing component and the second sealing component. A gas flow meter is installed on the first sealing component.

[0009] In a specific embodiment of the wellbore sealing evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the wellbore assembly includes surrounding rock, a cement sheath, and a casing. The surrounding rock is located inside the rubber sleeve and adheres to it. The casing passes through the surrounding rock. The surrounding rock and the casing are connected by injecting cement grout, and the cement grout between the surrounding rock and the casing forms the cement sheath. The top end of the casing passes through a first sealing component, and the bottom end of the casing passes through a second sealing component. A sealing plug is installed at the top end of the casing. A displacement chamber is provided on the inner wall of the rubber sleeve, and a displacement injection hole is provided on the outer wall of the insulation shell. The displacement injection hole extends radially along the insulation shell and the confining shell to communicate with the displacement chamber. The carbon dioxide displacement module injects carbonic acid solution into the displacement chamber through the displacement injection hole in the corrosion wellbore test module, and the formation water displacement module injects formation water into the displacement chamber through the displacement injection hole in the control wellbore test module.

[0010] In the specific implementation of the wellbore sealing evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the first sealing component and the second sealing component have the same structure. The first sealing component includes a sealing compensation ring and a sealing flange. The sealing compensation ring is installed at the top of the confining pressure shell and fits against the top surface of the surrounding rock. The sealing flange is sleeved on the casing and connected to the sealing compensation ring. Sealing rings are provided between the sealing compensation ring and the surrounding rock, between the sealing ring and the sealing flange, and between the sealing flange and the casing. The sealing flange is provided with a through hole, and the gas flow meter is installed in the through hole. The through hole in the second sealing component is used to connect to the gas channeling simulation module.

[0011] In a specific embodiment of the wellbore sealing evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the carbon dioxide displacement module includes a first storage tank, a first delivery pump, and a mixing vessel. The first storage tank stores carbon dioxide and introduces carbon dioxide into the mixing vessel through the first delivery pump. The mixing vessel is equipped with a first pressure gauge and a magnetic stirrer. The outlet of the mixing vessel is connected to a first pipeline, and the first pipeline is connected to the displacement injection port in the corrosion wellbore testing module.

[0012] In a specific embodiment of the wellbore sealing evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the gas channeling simulation module includes a gas cylinder, a second delivery pump, and a second pipeline. The outlet of the gas cylinder is connected to one end of the second pipeline. The second pipeline is equipped with a second delivery pump, a second pressure gauge, and a flow meter. The other end of the second pipeline is connected to the through holes on the second sealing components in the corrosion wellbore test module and the control wellbore test module, respectively, to deliver gas into the wellbore assembly.

[0013] In a specific embodiment of the wellbore sealing evaluation device under the above-mentioned in-situ conditions of carbon dioxide geological storage, the wellbore temperature and pressure control module includes a first controller, a wellbore temperature control unit, and a wellbore pressure control unit. The wellbore temperature control unit includes an electric heating rod and a first temperature sensor connected to the first controller. An electric heating rod and a first temperature sensor are installed inside the casing of both the corrosion wellbore test module and the control wellbore test module. The wellbore pressure control unit includes a first storage tank, a third delivery pump, and a third pipeline. The outlet of the first storage tank is connected to one end of the third pipeline. The third delivery pump is installed on the third pipeline. The other end of the third pipeline is connected to the bottom end of the casing in both the corrosion wellbore test module and the control wellbore test module. A third pressure gauge is installed on the third pipeline. And / or

[0014] The formation temperature and pressure control module includes a second controller, a formation temperature control unit, and a formation pressure control unit. The formation temperature control unit includes an annular electric heating element and a second temperature sensor connected to the second controller. The annular electric heating element and the second temperature sensor are installed in the heating chambers of both the corrosion wellbore test module and the control wellbore test module. The formation pressure control unit includes a second liquid storage tank, a fourth delivery pump, and a fourth pipeline. The outlet of the second liquid storage tank is connected to one end of the fourth pipeline. The fourth delivery pump is installed on the fourth pipeline. The other end of the fourth pipeline is connected to the confining pressure chambers in both the corrosion wellbore test module and the control wellbore test module. A fourth pressure gauge is installed on the fourth pipeline.

[0015] In a second aspect, the present invention also provides a method for evaluating the sealing performance of a wellbore under in-situ conditions of carbon dioxide geological storage as described in the first aspect, comprising the following steps:

[0016] Activate the wellbore temperature and pressure control module and the formation temperature and pressure control module to control the temperature and pressure of the corresponding wellbore assembly in the corrosion wellbore test module and the control wellbore test module to be maintained at the set temperature and pressure value of the wellbore assembly and the formation temperature and pressure to be maintained at the set temperature and pressure value of the formation.

[0017] Without installing a gas flow meter and without the first sealing assembly sealing the top of the wellbore assembly and the second sealing assembly sealing the bottom of the wellbore assembly, the carbon dioxide displacement module and the formation water displacement module are turned on to deliver the corresponding displacement liquids into the corrosion wellbore test module and the control wellbore test module, respectively.

[0018] When the displacement fluid in the corrosion wellbore test module seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the carbon dioxide displacement module is turned off when the preset corrosion time is reached. When the displacement fluid in the control wellbore test module seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the formation water displacement module is turned off when the preset corrosion time is reached. Then, gas flow meters are installed, and the first and second sealing components are fully installed and sealed with the corresponding wellbore assembly.

[0019] With the gas flow simulation module connected to the bottom of the wellbore assembly, the gas flow simulation module continuously injects gas into the wellbore assembly in both the corrosion wellbore test module and the control wellbore test module and starts timing. During the injection process, the injection time, the pressure value of the injected gas, and the gas flow rate of the gas flow meter are recorded in real time. If the pressure value drops and the gas flow meter in the corrosion wellbore test module shows a gas flow rate, it is determined that the wellbore assembly in the corrosion wellbore test module has leaked. When the leak reaches the preset leakage time, the gas flow simulation module is turned off and the timing is stopped.

[0020] The degree of leakage is determined based on the recorded injection time, pressure value recorded during the injection process, and gas flow rate.

[0021] In a specific embodiment of the method for evaluating the sealing performance of a wellbore assembly under the aforementioned in-situ conditions of carbon dioxide geological storage, the method further includes:

[0022] After determining that a leak has occurred in the corrosion well casing test module, the internal pressure of the well casing assembly in the corrosion well casing test module is depressurized. After depressurization, the module is left to stand and the gas flow simulation module is activated every second preset time. During the activation process, the gas flow rate and injection time of the gas flow meter are recorded in real time. The sealing self-healing performance of the well casing assembly is determined based on the recorded gas flow rate and injection time each time.

[0023] Compared with the prior art, the beneficial effects of the present invention are:

[0024] 1. This invention uses a mixing vessel to dissolve carbon dioxide into a solution to form a carbonic acid solution, providing a carbonic acid environment for simulation. The formation temperature and pressure control module heats the heating chamber and provides confining pressure to the confining chamber respectively, which can flexibly simulate the formation conditions for carbon dioxide sequestration. By simulating the lithology-temperature-pressure-carbonic acid environment during the carbon dioxide geological sequestration process, it can evaluate the sealing capacity of the wellbore under in-situ service conditions, thereby optimizing the cement slurry formula, selecting the casing material, and reducing the risk of carbon dioxide leakage.

[0025] 2. The present invention has the advantages of setting an annular heating element in the heating chamber and adjusting the confining pressure value by injecting liquid in the confining pressure chamber. It has the advantages of a large adjustment range and flexible adjustment, and is applicable to a wider range of applications.

[0026] 3. This invention determines the leakage rate by measuring the gas flow rate increase of a gas flow meter and determines the leakage pressure by recording pressure changes in a gas crossflow simulation module. By using values ​​such as leakage pressure and leakage rate, not only can the wellbore sealing performance be evaluated, but the wellbore's self-healing properties and self-healing capabilities can also be detected. This enables simulation research on the evolution law of wellbore sealing performance, which helps to evaluate and strengthen wellbore sealing performance and reduce the risk of carbon dioxide leakage. Attached Figure Description

[0027] The preferred embodiments of the present invention are described below with reference to the accompanying drawings, in which:

[0028] Figure 1 This is a schematic diagram of the overall structure of the wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage provided by the present invention.

[0029] Figure 2 This is a schematic diagram of the corrosion wellbore testing module;

[0030] Figure 3 yes Figure 1 A schematic diagram of the carbon dioxide displacement module in the middle;

[0031] Figure 4 yes Figure 1 Schematic diagram of the structure of the mid-formation water displacement module;

[0032] Figure 5 yes Figure 1 Schematic diagram of the structure of the pressure control unit in the middle wellbore;

[0033] Figure 6 yes Figure 1 Schematic diagram of the structure of the mid-formation pressure control unit;

[0034] Figure 7 yes Figure 1 A schematic diagram of the gas channeling simulation module;

[0035] Figure 8a This is the test result corresponding to step S5 of the corrosion wellbore test module;

[0036] Figure 8b This is the test result of the self-healing property of the corrosion wellbore testing module.

[0037] List of reference numerals in the attached diagram:

[0038] 1. Carbon dioxide displacement module; 1.1 First storage tank; 1.2 First delivery pump; 1.3 First pressure gauge; 1.4 Magnetic stirrer; 1.5 Mixing vessel; 1.6 First valve; 2. Corrosion wellbore testing module; 2.1 Sealing compensation ring; 2.2 Sealing ring; 2.3 Through hole; 2.4 Sealing plug; 2.5 Heating rod; 2.6 Sealing flange; 2.7 Insulation shell; 2.8 Heating chamber; 2.9 Confining pressure shell; 2.10 Confining pressure chamber; 2.11 Rubber sleeve; 2.12 Surrounding rock; 2.13 Cement sheath; 2.14 Casing; 2.15 Confining pressure injection hole; 2.16 Casing injection hole; 2.17 Slug baffle; 2.18 Displacement injection hole; 2.19 Displacement chamber; 3. Gas flow meter; 4. Wellbore temperature control unit; 5. Formation temperature... 6. Formation water displacement module; 6.1 Fifth delivery pump; 6.2 Fifth pressure gauge; 6.3 Fifth valve; 6.4 Third storage tank; 7. Gas channeling simulation module; 7.1 Gas cylinder; 7.2 Second delivery pump; 7.3 Second pressure gauge; 7.4 Flow meter; 7.5 Second pipeline; 7.6 Second valve; 7.7 First branch pipeline; 8. Control wellbore test module; 9. Wellbore pressure control unit; 9.1 First storage tank; 9.2 Third pressure gauge; 9.3 Third valve; 9.4 Second branch pipeline; 9.5 Third delivery pump; 10. Formation pressure control unit; 10.1 Fourth delivery pump; 10.2 Fourth pressure gauge; 10.3 Fourth valve; 10.4 Fourth pipeline; 10.5 Second storage tank; 10.6 Third branch pipeline. Detailed Implementation

[0039] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of this invention. All other embodiments obtained by those skilled in the art based on the embodiments of this invention without creative effort are within the scope of protection of this invention.

[0040] In the description of this invention, it should be noted that the terms "upper," "lower," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing the invention and for simplifying the description, and do not indicate or imply that the system or component referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on the invention. Furthermore, the use of terms such as "first" and "second" to define components is merely for the convenience of distinguishing the aforementioned components. Unless otherwise stated, these terms have no special meaning and should not be construed as indicating or implying relative importance.

[0041] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "installation," "setting," and "connection" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0042] This invention relates to the field of carbon dioxide geological storage technology, and in particular to a device and method for evaluating the sealing performance of wellbore under in-situ conditions for carbon dioxide geological storage. The aim is to address the problem that existing research devices and methods often simplify the in-situ service conditions of the wellbore, resulting in inaccurate simulations and affecting the accurate evaluation of wellbore sealing performance. To this end, the invention provides a device for evaluating the sealing performance of wellbore under in-situ conditions for carbon dioxide geological storage, comprising a corrosion wellbore testing module, a carbon dioxide displacement module, a gas channeling simulation module, a wellbore temperature and pressure control module, and a formation temperature and pressure control module. The corrosion wellbore testing module includes a wellbore assembly, a gas flow meter, and a test shell. The wellbore assembly is inserted into the test shell, and closed cavities are formed between the top of the wellbore assembly and the top of the test shell, as well as between the bottom of the wellbore assembly and the bottom of the test shell. A gas flow meter is installed at the top of the test shell to measure the gas discharged from the closed cavity at the bottom, passing through the closed cavity at the top and bottom of the wellbore assembly. Inside the test shell, a confining pressure chamber and a heating chamber are sequentially arranged along a radial direction away from the wellbore assembly. The carbon dioxide displacement module is configured to introduce carbon dioxide into the wellbore assembly... The wellbore temperature and pressure control module is configured to control the temperature and pressure within the wellbore assembly, while the formation temperature and pressure control module is configured to control the temperature of the heating chamber and the pressure within the confining chamber. The gas flow simulation module is configured to inject the required gas from the bottom of the wellbore assembly into the interior of the wellbore assembly. This invention uses a mixing vessel to dissolve carbon dioxide into the solution to form a carbonic acid solution, providing a carbonic acid environment for simulation. The formation temperature and pressure control module heats the heating chamber and provides confining pressure to the confining chamber respectively, which can flexibly simulate the formation conditions for carbon dioxide sequestration. By simulating the lithology-temperature-pressure-carbonic acid environment during the carbon dioxide geological sequestration process, the sealing capability of the wellbore assembly under in-situ service conditions can be evaluated, thereby achieving the purpose of selecting the casing material, optimizing the cement slurry formula, and reducing the risk of carbon dioxide leakage.

[0043] The following is a detailed description of the wellbore sealing performance evaluation device and method under in-situ conditions for carbon dioxide geological storage provided in this invention, with reference to the accompanying drawings.

[0044] See Figure 1This invention provides a wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage, comprising a corrosion wellbore testing module 2, a carbon dioxide displacement module 1, a gas channeling simulation module 7, a wellbore temperature and pressure control module, and a formation temperature and pressure control module. The corrosion wellbore testing module 2 includes a wellbore assembly, a gas flow meter 3, and a test housing. The wellbore assembly is housed within the test housing. Closed cavities are formed between the top of the wellbore assembly and the top of the test housing, and between the bottom of the wellbore assembly and the bottom of the test housing. The gas flow meter 3 is installed at the top of the test housing to measure the flow rate of gas passing through the closed cavity at the bottom of the wellbore. The gas discharged from the wellbore assembly and the closed cavity at the top is tested. Inside the test shell, along the radial direction away from the wellbore assembly, there are a confining pressure chamber 2.10 and a heating chamber 2.8. The carbon dioxide displacement module 1 is configured to introduce a carbonic acid solution of carbon dioxide and formation water into the wellbore assembly. The wellbore temperature and pressure control module is configured to control the temperature and pressure inside the wellbore assembly. The formation temperature and pressure control module is configured to control the temperature of the heating chamber 2.8 and the pressure inside the confining pressure chamber 2.10. The gas flow simulation module 7 is configured to inject the required gas from the bottom of the wellbore assembly into the interior of the wellbore assembly.

[0045] In the above embodiments, the heating chamber 2.8 and the confining pressure chamber 2.10 are controlled by the formation temperature and pressure control module to adjust the temperature and confining pressure values, simulating various temperature and pressure conditions around the wellbore assembly. The gas flow meter 3 measures the gas flux discharged from the closed cavity, enabling real-time detection of leaks in the wellbore assembly. Simultaneously, by measuring the gas flux and the delivery pressure value in the gas flow simulation module 7, leakage pressure and leakage degree information can be obtained. This allows for simulation research on the evolution of the wellbore assembly's sealing performance, facilitating improvements to the wellbore assembly's sealing and reducing the risk of carbon dioxide leakage.

[0046] In one embodiment, see Figure 1 The wellbore sealing evaluation device under in-situ conditions for carbon dioxide geological storage also includes a control wellbore test module and a formation water displacement module 6. The control wellbore test module has the same structure as the corrosion wellbore test module. The formation water displacement module 6 introduces formation water into the wellbore assembly in the control wellbore test module. The wellbore temperature and pressure control module is used to control the temperature and pressure inside the wellbore assembly in the control wellbore test module. The formation temperature and pressure control module is used to control the temperature of the heating chamber 2.8 and the pressure inside the confining chamber 2.10 in the control wellbore test module. The gas flow simulation module 7 is used to inject the required gas from the bottom of the wellbore assembly in the control wellbore test module into the interior of the wellbore assembly.

[0047] In the simulation experiment, the control wellbore test module and the corrosion wellbore test module were conducted simultaneously. All data during the simulation process could be compared, which helps to better understand the corrosive effect of carbonic acid solution on the wellbore assembly and to make a more accurate evaluation of the sealing performance of the wellbore assembly.

[0048] In the above embodiments, see Figure 1-2 Preferably, the test housing includes an insulation housing 2.7, a confining pressure housing 2.9, and a rubber sleeve 2.11. Both the insulation housing 2.7 and the confining pressure housing 2.9 are hollow cylindrical structures. The top and bottom surfaces of the insulation housing 2.7 are flush with the corresponding top and bottom surfaces of the confining pressure housing 2.9. The insulation housing 2.7 is fitted over the outside of the confining pressure housing 2.9, forming a heating chamber 2.8 between them. The confining pressure housing 2.9 is fitted over the outside of the rubber sleeve 2.11, forming a confining pressure chamber 2.10 between them. The well shaft assembly passes through and fits against the inner side of the rubber sleeve 2.11. A first sealing component is installed at the top of the confining pressure housing 2.9, and a second sealing component is installed at its bottom. The confining pressure housing 2.9 achieves a seal between itself and both the well shaft assembly and the rubber sleeve 2.11 through the first and second sealing components. A gas flow meter 3 is installed on the first sealing component.

[0049] Specifically, a heating chamber 2.8 is formed between the inner wall of the insulating outer shell 2.7 and the outer wall of the confining outer shell 2.9. The top of the confining outer shell 2.9 has a first opening, and the bottom of the confining outer shell 2.9 has a second opening. The diameters of the first and second openings are the same and both smaller than the inner diameter of the confining outer shell 2.9. A rubber sleeve 2.11 is located inside the confining outer shell 2.9 and forms a confining chamber 2.10 between itself and the inner wall of the confining outer shell 2.9. A first sealing component is installed in the first opening, and a second sealing component is installed in the second opening. The rubber sleeve 2.11 is confined within the confining outer shell 2.9 and sealed by the combined action of the first and second sealing components. The rubber sleeve 2.11 has temperature, pressure, and corrosion resistance properties, for example, it is made of fluororubber. The rubber sleeve 2.11 is used to isolate the fluid within the confining chamber 2.10 and indirectly transmit the confining load provided by the confining chamber 2.10.

[0050] In the above embodiments, see Figure 2Preferably, the wellbore assembly includes surrounding rock 2.12, a cement sheath 2.13, and a casing 2.14. The surrounding rock is located inside and adheres to the casing 2.11. The casing 2.14 passes through the surrounding rock. The surrounding rock and the casing 2.14 are connected by injecting cement grout. The cement grout between the surrounding rock and the casing 2.14 forms a cement sheath 2.13. The top end of the casing 2.14 passes through a first sealing assembly, and the bottom end of the casing 2.14 passes through a second sealing assembly. A sealing plug 2.4 is installed at the top end of the casing 2.14, and a casing injection hole 2.16 is provided at the bottom end of the casing 2.14 to facilitate... Pressure is applied to the casing 2.14 to simulate the internal pressure conditions of the wellbore assembly. A displacement chamber 2.19 is located on the inner wall of the rubber sleeve 2.11, and a displacement injection port 2.18 is located on the outer wall of the insulation shell 2.7. The displacement injection port 2.18 extends radially along the insulation shell 2.7 and the confining shell 2.9 to communicate with the displacement chamber 2.19. The carbon dioxide displacement module 1 injects carbonic acid solution into the displacement chamber 2.19 through the displacement injection port 2.18 in the corrosion wellbore test module. The formation water displacement module 6 injects formation water into the displacement chamber 2.19 through the displacement injection port 2.18 in the control wellbore test module. The surrounding rock is used to simulate the surrounding formation, and the lithology can be adjusted according to experimental requirements.

[0051] In one embodiment, see Figure 2 The first sealing assembly and the second sealing assembly have the same structure. The first sealing assembly includes a sealing compensation ring 2.1 and a sealing flange 2.6. The sealing compensation ring 2.1 is installed on the top of the confining pressure shell 2.9 and fits against the top surface of the surrounding rock. The sealing flange 2.6 is sleeved on the casing 2.14 and connected to the sealing compensation ring 2.1. Sealing rings 2.2 are provided between the sealing compensation ring 2.1 and the surrounding rock, and between the sealing flange 2.6 and the casing 2.14, to provide a sealing function. The sealing flange 2.6 is provided with a through hole 2.3, and the gas flow meter 3 is installed in the through hole 2.3. The through hole 2.3 in the second sealing assembly is used to connect to the gas channeling simulation module 7.

[0052] Specifically, the sealing compensation ring 2.1 in the first sealing assembly is detachably installed in the first opening, and the sealing compensation ring 2.1 in the second sealing assembly is detachably installed in the second opening. The sealing compensation ring 2.1 serves to compensate for the length of the surrounding rock and to provide a seal.

[0053] In this application, as Figure 2As shown, before cement grout injection, a slurry diaphragm 2.17 is placed on top of the sealing flange 2.6 in the second sealing assembly. The slurry diaphragm 2.17 is located inside the sealing compensation ring 2.1, with its top surface flush with the top surface of the sealing compensation ring 2.1. This ensures that the bottom surface of the cement ring 2.13 is flush with the bottom surface of the surrounding rock. After the cement ring 2.13 is formed, the slurry diaphragm 2.17 can be removed from the inside of the sealing compensation ring 2.1 by disassembling the sealing flange 2.6. The slurry diaphragm 2.17 is used during the setting stage of the cement ring 2.13 to prevent cement grout from flowing into the vent and causing blockage.

[0054] In one embodiment, see Figure 3 The carbon dioxide displacement module 1 includes a first storage tank 1.1, a first delivery pump 1.2, and a mixing vessel 1.5. The first storage tank 1.1 stores carbon dioxide. The outlet of the first storage tank 1.1 is connected to the mixing vessel 1.5 via a carbon dioxide delivery pipeline. The first delivery pump 1.2 is installed on the carbon dioxide delivery pipeline, and carbon dioxide is introduced into the mixing vessel 1.5 through the first delivery pump 1.2. The mixing vessel 1.5 is equipped with a first pressure gauge 1.3 and a magnetic stirrer 1.4. The outlet of the mixing vessel 1.5 is connected to a first pipeline, which is connected to the displacement injection port 2.18 in the corrosion wellbore testing module. A first valve 1.6 is installed on the first pipeline.

[0055] In one embodiment, see Figure 7 The gas channeling simulation module 7 includes a gas cylinder 7.1, a second delivery pump 7.2, and a second pipeline 7.5. The outlet of the gas cylinder 7.1 is connected to one end of the second pipeline 7.5. The second pipeline 7.5 is equipped with the second delivery pump 7.2, a second pressure gauge 7.3, and a flow meter 7.4. The other end of the second pipeline 7.5 is connected to the through-hole 2.3 on the second sealing assembly in the corrosion wellbore test module and the control wellbore test module, respectively, to deliver gas into the wellbore assembly. The second delivery pump 7.2 is a constant-speed, constant-pressure pump. For example, the gas flow rate is 5 mL / s.

[0056] Specifically, the other end of the second pipe 7.5 is connected to the corresponding through hole 2.3 through two first branch pipes 7.7, and a second valve 7.6 is installed on each of the two first branch pipes 7.7. The second valve 7.6 is a three-way valve.

[0057] In one embodiment, see Figure 1 and Figure 5The wellbore temperature and pressure control module includes a first controller, a wellbore temperature control unit 4, and a wellbore pressure control unit 9. The wellbore temperature control unit 4 includes an electric heating rod 2.5 and a first temperature sensor connected to the first controller. An electric heating rod 2.5 and a first temperature sensor are installed inside the casing 2.14 in both the corrosion wellbore test module and the control wellbore test module. The wellbore pressure control unit 9 includes a first liquid storage tank 9.1, a third delivery pump 9.5, and a third pipeline. The outlet of the first liquid storage tank 9.1 is connected to one end of the third pipeline. The third delivery pump 9.5 is installed on the third pipeline. The other end of the third pipeline is connected to the bottom end of the casing 2.14 in both the corrosion wellbore test module and the control wellbore test module. A third pressure gauge 9.2 is installed on the third pipeline. Both the third pressure gauge 9.2 and the third delivery pump 9.5 are connected to the first controller.

[0058] Specifically, the other end of the third pipe is connected to the bottom end of the casing 2.14 via two second branch pipes 9.4, and a third valve 9.3 is installed on the second branch pipes 9.4. The end of the second branch pipe away from the first storage tank is connected to the casing injection port 2.16.

[0059] In one embodiment, see Figure 1 and Figure 6 The formation temperature and pressure control module includes a second controller, a formation temperature control unit 5, and a formation pressure control unit 10. The formation temperature control unit 5 includes an annular electric heating element and a second temperature sensor connected to the second controller. The heating chamber 2.8 in both the corrosion wellbore test module and the control wellbore test module is equipped with an annular electric heating element and a second temperature sensor. The formation pressure control unit 10 includes a second liquid storage tank 10.5, a fourth delivery pump 10.1, and a fourth pipeline 10.4. The outlet of the second liquid storage tank 10.5 is connected to one end of the fourth pipeline 10.4. The fourth delivery pump 10.1 is installed on the fourth pipeline 10.4. The other end of the fourth pipeline 10.4 is connected to the confining pressure chamber 2.10 in both the corrosion wellbore test module and the control wellbore test module. A fourth pressure gauge 10.2 is installed on the fourth pipeline 10.4. Both the fourth pressure gauge 10.2 and the fourth delivery pump 10.1 are connected to the second controller.

[0060] Specifically, the other end of the fourth pipe 10.4 is connected to two third branch pipes 10.6, each third branch pipe 10.6 being connected to a confining pressure chamber 2.10. A fourth valve 10.3 is installed on the third branch pipe 10.6. The bottom end of the confining pressure shell 2.9 is provided with a confining pressure injection hole 2.15, which communicates with the confining pressure chamber 2.10. The third branch pipe 10.6 is connected to the confining pressure injection hole 2.15.

[0061] In the above embodiments, see Figure 4The formation water displacement module 6 includes a fifth pipeline, a fifth delivery pump 6.1, and a third storage tank 6.4. The third storage tank 6.4 stores formation water, which is fresh water. The outlet of the third storage tank 6.4 is connected to the fifth pipeline, and the other end of the fifth pipeline is connected to the displacement injection port 2.18 in the wellbore testing module. A fifth pressure gauge 6.2 and a fifth valve 6.3 are installed on the fifth pipeline.

[0062] In another embodiment, the present invention also provides a method for evaluating the sealing performance of a wellbore assembly under in-situ conditions of carbon dioxide geological storage using the sealing performance evaluation device described in any of the above embodiments, comprising the following steps:

[0063] S1, activate the wellbore temperature and pressure control module and the formation temperature and pressure control module to control the temperature and pressure of the corresponding wellbore assembly in the corrosion wellbore test module 2 and the control wellbore test module 8 to be maintained at the set temperature and pressure value of the wellbore assembly and the formation temperature and pressure to be maintained at the set temperature and pressure value of the formation.

[0064] S2, without the gas flow meter 3 installed and without the first sealing component sealing the top of the wellbore assembly and the second sealing component sealing the bottom of the wellbore assembly, the carbon dioxide displacement module 1 and the formation water displacement module 6 are turned on to deliver the corresponding displacement liquid into the corrosion wellbore test module 2 and the control wellbore test module 8 respectively.

[0065] S3, when the displacement fluid in the corrosion wellbore test module 2 seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the carbon dioxide displacement module 1 is turned off when the corrosion preset time is reached. When the displacement fluid in the control wellbore test module 8 seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the formation water displacement module 6 is turned off when the corrosion preset time is reached. Then, the gas flow meter 3 is installed respectively, and the first sealing component and the second sealing component are fully installed and sealed with the corresponding wellbore assembly.

[0066] S4, with the gas flow simulation module 7 connected to the bottom of the wellbore assembly, control the gas flow simulation module 7 to continuously inject gas into the wellbore assembly in the corrosion wellbore test module 2 and the control wellbore test module 8 and start timing. During the injection process, record the injection time, the pressure value of the injected gas and the gas flow rate of the gas flow meter 3 in real time. If the pressure value drops and the gas flow meter 3 in the corrosion wellbore test module 2 shows a gas flow, it is determined that the wellbore assembly in the corrosion wellbore test module 2 has leaked. When the leak reaches the preset leakage time, shut down the gas flow simulation module 7 and stop timing.

[0067] S5. Determine the degree of leakage based on the recorded injection time, pressure value recorded during the injection process, and gas flow rate.

[0068] The specific steps for fabricating the wellbore assembly in this application are as follows: First, open the first sealing assembly (i.e., remove the corresponding sealing flange 2.6 and sealing compensation ring 2.1 from the confining pressure shell 2.9), place the pre-prepared surrounding rock, and then install the sealing compensation ring 2.1, without temporarily installing the sealing flange 2.6. In this step, the lithology of the surrounding rock can be adjusted according to geological data or experimental requirements. Then, open the sealing flange 2.6 in the second sealing assembly, place the slurry baffle 2.17, and reinstall the sealing flange 2.6. Next, inject the pre-prepared cement slurry between the surrounding rock and the casing 2.14. In this step, the cement slurry formula can be adjusted according to experimental requirements. During the setting of the cement ring 2.13, activate the wellbore temperature and pressure control module and the formation temperature and pressure control module to execute step S1.

[0069] In the above embodiment, the specific control steps of the wellbore temperature and pressure control module in step S1 are as follows: The first controller controls the electric heating rod 2.5 to start heating; the first temperature sensor detects the temperature inside the wellbore assembly; the first controller controls the start and stop of the electric heating rod 2.5 based on the temperature information detected by the first temperature sensor, thereby adjusting the temperature inside the wellbore assembly. Liquid is injected into the casing 2.14 by the third delivery pump 9.5 to adjust the pressure inside the wellbore assembly; the third pressure gauge 9.2 detects the pressure of the liquid in the third pipeline and feeds it back to the first controller; the controller controls the start and stop of the third delivery pump 9.5 based on the pressure information, thereby adjusting the pressure inside the wellbore assembly. The set temperature and pressure values ​​for the wellbore assembly include the set temperature value and the set pressure value. During pressure adjustment, the third valve 9.3 is open during liquid injection; after the pressure reaches the set pressure value for the wellbore assembly, the third delivery pump 9.5 is closed while the third valve 9.3 is closed.

[0070] The specific control steps of the formation temperature and pressure control module in step S1 are as follows: The annular electric heating element is activated for heating. The second temperature sensor transmits the detected temperature information to the second controller. The second controller controls the start and stop of the annular electric heating element based on the temperature information, thereby regulating the temperature inside the heating chamber 2.8. The fourth delivery pump 10.1 is activated to inject liquid into the confining pressure chamber 2.10. The fourth pressure gauge 10.2 detects the pressure value in real time and transmits it to the second controller. The second controller controls the opening and closing of the fourth delivery pump 10.1 based on the pressure value. Simultaneously, the fourth valve 10.3 closes when the fourth delivery pump 10.1 closes. The set formation temperature and pressure values ​​include the set formation temperature value and the set formation pressure value.

[0071] The wellbore temperature and pressure control module and the formation temperature and pressure control module can control the corrosion wellbore test module and the control wellbore test module to be at the same wellbore assembly set temperature and pressure value and the formation set temperature and pressure value, ensuring data consistency.

[0072] Furthermore, the set temperature and pressure values ​​for the wellbore assembly and the formation are set to specific values ​​according to experimental requirements. Therefore, this application does not impose specific limitations on these values, and they can be flexibly selected according to experimental requirements. For example, the set temperature and pressure values ​​for the wellbore assembly are 15 MPa and 50°C, and the set temperature and pressure values ​​for the formation are 20 MPa and 60°C.

[0073] Under the temperature and pressure conditions designed for the experiment, the cement sheath 2.13 is cured for more than five days, and after the surrounding rock, cement sheath 2.13 and casing 2.14 are bonded and stabilized, the sealing flange 2.6 in the second sealing assembly is opened, the slurry baffle 2.17 is removed, and the sealing flange 2.6 is not installed temporarily. Under these conditions, step S2 is performed.

[0074] The specific steps of step S2 are as follows: The first delivery pump 1.2 is turned on to deliver carbon dioxide from the first storage tank 1.1 to the mixing vessel 1.5. The magnetic stirrer 1.4 in the mixing vessel 1.5 stirs the solution in the mixing vessel 1.5 to fully mix it and form a carbonic acid solution. This solution is then injected into the displacement chamber 2.19 through the displacement injection port 2.18, slowly seeping into the wellbore assembly. During the displacement process, the first valve 1.6 is in the open state. After the displacement is completed, the first valve 1.6, the first delivery pump 1.2, and the magnetic stirrer 1.4 are all in the closed state. The pressure value during the displacement process is 5 MPa.

[0075] In step S3, during the displacement process, observe the top and bottom of the wellbore assembly. When the displacing fluid seeps out from the top and bottom of the wellbore assembly, it indicates that the displacing fluid has begun to contact the wellbore assembly on a large scale and undergo a corrosion reaction. The preset corrosion time is flexibly set according to the actual experimental conditions. For example, the preset corrosion time is five days (to ensure that the wellbore assembly and the displacing fluid can fully contact each other). After the carbon dioxide displacement module 1 is turned off, install the corresponding first and second sealing components, and then install the gas flow meter 3 on the sealing flange 2.6. Similarly, after the formation water displacement module 6 is turned off, install the corresponding first and second sealing components, and then install the gas flow meter 3 on the sealing flange 2.6. After all is completed, connect the first branch pipe 7.7 in the gas channeling simulation module 7 to the corresponding through hole 2.3 to facilitate subsequent operations.

[0076] In step S4, if the gas flow meter 3 in the corrosion wellbore test module 2 does not show any gas flow, it indicates that the wellbore assembly is not leaking. By recording the time when leakage begins in the control wellbore test module 8 and the time when leakage begins in the corrosion wellbore test module 2, the corrosive effect of the carbonic acid solution on the wellbore assembly can be analyzed through time comparison, which is beneficial for changing the sealing performance by adjusting the wellbore assembly. The second delivery pump 7.2 and the second valve 7.6 are closed to shut down the gas channeling simulation module 7.

[0077] In step S5, by acquiring the gas flux and pressure value during the leakage process within a set time period, the degree of leakage and leakage pressure information can be determined, thereby realizing the simulation study of the evolution law of the sealing performance of the wellbore assembly.

[0078] In one embodiment, the method further includes:

[0079] After determining that a leak has occurred in the corrosion wellbore test module 2 (i.e. after executing step S5), the internal pressure of the wellbore assembly in the corrosion wellbore test module 2 is depressurized. After the depressurization is completed, the assembly is left to stand and the gas flow simulation module 7 is turned on once every second preset time. During the turning-on process, the gas flow rate and injection time of the gas flow meter 3 are recorded in real time. The sealing self-healing performance of the wellbore assembly is judged based on the gas flow rate and injection time recorded each time.

[0080] In the above embodiment, the other port of the second valve 7.6 corresponding to the corrosion wellbore test module 2 is opened to release pressure. After the pressure is released, the corrosion wellbore test module 2 is left to stand. The gas flow simulation module 7 is turned on once every second preset time. For example, the second preset time is five days. The second delivery pump 7.2 injects gas into the wellbore assembly at a rate of 5 mL / s. The gas flow rate and injection time are recorded. Based on these data, it is analyzed whether the wellbore assembly has sealing and self-healing properties.

[0081] After the experiment, the pressure is released, the first sealing component and the second sealing component are disassembled, and the wellbore assembly is taken out for cleaning or replacement with other wellbore assemblies.

[0082] Figure 8a and 8b The experimental results are for the corrosion wellbore testing module 2. Figure 8a The test results correspond to step S5. Figure 8b The results of the self-healing test were analyzed as follows:

[0083] Depend on Figure 8aIt can be seen that after the second delivery pump 7.2 is turned on, the gas pressure recorded by the second pressure gauge 7.3 continues to increase, reaching a peak of 5.15 MPa at about 1300s, and then drops sharply. The reading of the gas flow meter 3 also rises rapidly and stabilizes at 4.9 mL / s, indicating that the well assembly is leaking. The maximum sealing pressure difference of the well assembly is 5.15 MPa.

[0084] Depend on Figure 8b It can be seen that the gas flow meter 3 reading was stable at 4.9 mL / s during the first test. After that, the test was conducted every five days. It can be seen that the gas flow rate decreased significantly, and the well assembly showed a certain degree of self-healing under the experimental conditions.

[0085] This invention determines the leakage rate by measuring the gas flow rate increase of a gas flow meter and determines the leakage pressure by recording pressure changes in a gas crossflow simulation module. The leakage pressure and leakage rate, among other values, not only evaluate the sealing performance of the wellbore assembly but also detect its self-healing properties and capabilities. This enables simulation research on the evolution of the wellbore assembly's sealing performance, which helps to improve the sealing performance of the wellbore assembly and reduce the risk of carbon dioxide leakage.

[0086] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the protection scope of the technical solutions of the embodiments of the present invention.

Claims

1. A wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage, characterized in that, The system includes a corrosion wellbore testing module, a carbon dioxide displacement module, a gas flow simulation module, a wellbore temperature and pressure control module, and a formation temperature and pressure control module. The corrosion wellbore testing module comprises a wellbore assembly, a gas flow meter, and a test housing. The wellbore assembly is housed within the test housing. Closed cavities are formed between the top and bottom ends of the wellbore assembly and the test housing, respectively. A gas flow meter is installed at the top of the test housing to measure the gas discharged from the closed cavity at the bottom, passing through the wellbore assembly and the closed cavity at the top. A confining pressure chamber and a heating chamber are sequentially arranged radially away from the wellbore assembly inside the test housing. The carbon dioxide displacement module is configured to introduce a carbonic acid solution (a mixture of carbon dioxide and formation water) into the wellbore assembly. The wellbore temperature and pressure control module is configured to control the temperature and pressure within the wellbore assembly. The formation temperature and pressure control module is configured to control the temperature of the heating chamber and the pressure within the confining pressure chamber. The gas flow simulation module is configured to inject the required gas from the bottom of the wellbore assembly into the wellbore assembly. The in-situ wellbore sealing evaluation device under the conditions of carbon dioxide geological storage also includes a control wellbore test module and a formation water displacement module. The control wellbore test module has the same structure as the corrosion wellbore test module. The formation water displacement module injects formation water into the displacement chamber through the displacement injection hole in the control wellbore test module. The wellbore temperature and pressure control module is used to control the temperature and pressure inside the wellbore assembly in the control wellbore test module. The formation temperature and pressure control module is used to control the temperature of the heating chamber and the pressure inside the confining chamber in the control wellbore test module. The gas flow simulation module is used to inject the required gas from the bottom of the wellbore assembly of the control wellbore test module into the interior of the wellbore assembly.

2. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 1, characterized in that, The test housing includes an insulation housing, a confining pressure housing, and a rubber sleeve. Both the insulation housing and the confining pressure housing are hollow cylindrical structures. The insulation housing is fitted over the outside of the confining pressure housing, forming a heating chamber between them. The confining pressure housing is fitted over the outside of the rubber sleeve, forming a confining pressure chamber between them. The well casing assembly passes through the inside of the rubber sleeve and fits against it. A first sealing component is installed at the top of the confining pressure housing, and a second sealing component is installed at its bottom. The confining pressure housing achieves a seal with both the well casing assembly and the rubber sleeve through the first and second sealing components. A gas flow meter is installed on the first sealing component.

3. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 2, characterized in that, The wellbore assembly includes surrounding rock, a cement sheath, and a casing. The surrounding rock is located inside and adheres to the casing. The casing passes through the surrounding rock. The surrounding rock and the casing are connected by injecting cement grout, and the cement grout between the surrounding rock and the casing forms the cement sheath. The top end of the casing passes through a first sealing component, and the bottom end of the casing passes through a second sealing component. A sealing plug is installed at the top end of the casing. A displacement chamber is provided on the inner wall of the casing. A displacement injection hole is provided on the outer wall of the insulation shell. The displacement injection hole extends radially along the insulation shell and the confining shell to communicate with the displacement chamber. The carbon dioxide displacement module injects carbonic acid solution into the displacement chamber through the displacement injection hole in the corrosion wellbore testing module.

4. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 3, characterized in that, The first sealing assembly and the second sealing assembly have the same structure. The first sealing assembly includes a sealing compensation ring and a sealing flange. The sealing compensation ring is installed at the top of the confining pressure shell and fits against the top surface of the surrounding rock. The sealing flange is sleeved on the casing and connected to the sealing compensation ring. Sealing rings are provided between the sealing compensation ring and the surrounding rock, between the sealing ring and the sealing flange, and between the sealing flange and the casing. The sealing flange has a through hole, and the gas flow meter is installed in the through hole. The through hole in the second sealing assembly is used to connect to the gas flow simulation module.

5. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 1, characterized in that, The carbon dioxide displacement module includes a first storage tank, a first delivery pump, and a mixing vessel. The first storage tank stores carbon dioxide and the first delivery pump introduces carbon dioxide into the mixing vessel. The mixing vessel is equipped with a first pressure gauge and a magnetic stirrer. The outlet of the mixing vessel is connected to a first pipe, and the first pipe is connected to the displacement injection port in the corrosion wellbore testing module.

6. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 1, characterized in that, The gas flow simulation module includes a gas cylinder, a second delivery pump, and a second pipeline. The outlet of the gas cylinder is connected to one end of the second pipeline. The second pipeline is equipped with a second delivery pump, a second pressure gauge, and a flow meter. The other end of the second pipeline is connected to the through holes on the second sealing components in the corrosion wellbore test module and the control wellbore test module, respectively, to deliver gas into the wellbore assembly.

7. The wellbore sealing performance evaluation device under in-situ conditions for carbon dioxide geological storage according to claim 1, characterized in that, The wellbore temperature and pressure control module includes a first controller, a wellbore temperature control unit, and a wellbore pressure control unit. The wellbore temperature control unit includes an electric heating rod and a first temperature sensor connected to the first controller. An electric heating rod and a first temperature sensor are installed inside the casing of both the corrosion wellbore testing module and the control wellbore testing module. The wellbore pressure control unit includes a first storage tank, a third delivery pump, and a third pipeline. The outlet of the first storage tank is connected to one end of the third pipeline. The third delivery pump is installed on the third pipeline. The other end of the third pipeline is connected to the bottom end of the casing in both the corrosion wellbore testing module and the control wellbore testing module. A third pressure gauge is installed on the third pipeline. And / or The formation temperature and pressure control module includes a second controller, a formation temperature control unit, and a formation pressure control unit. The formation temperature control unit includes an annular electric heating element and a second temperature sensor connected to the second controller. The annular electric heating element and the second temperature sensor are installed in the heating chambers of both the corrosion wellbore test module and the control wellbore test module. The formation pressure control unit includes a second liquid storage tank, a fourth delivery pump, and a fourth pipeline. The outlet of the second liquid storage tank is connected to one end of the fourth pipeline. The fourth delivery pump is installed on the fourth pipeline. The other end of the fourth pipeline is connected to the confining pressure chambers in both the corrosion wellbore test module and the control wellbore test module. A fourth pressure gauge is installed on the fourth pipeline.

8. A method for evaluating the sealing performance of a wellbore under in-situ conditions of carbon dioxide geological storage as described in any one of claims 6-7, characterized in that, Includes the following steps: Activate the wellbore temperature and pressure control module and the formation temperature and pressure control module to control the temperature and pressure of the corresponding wellbore assembly in the corrosion wellbore test module and the control wellbore test module to be maintained at the set temperature and pressure value of the wellbore assembly and the formation temperature and pressure to be maintained at the set temperature and pressure value of the formation. Without installing a gas flow meter and without the first sealing assembly sealing the top of the wellbore assembly and the second sealing assembly sealing the bottom of the wellbore assembly, the carbon dioxide displacement module and the formation water displacement module are turned on to deliver the corresponding displacement liquids into the corrosion wellbore test module and the control wellbore test module, respectively. When the displacement fluid in the corrosion wellbore test module seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the carbon dioxide displacement module is turned off when the preset corrosion time is reached. When the displacement fluid in the control wellbore test module seeps out from the top and bottom of the corresponding wellbore assembly, the timing starts, and the formation water displacement module is turned off when the preset corrosion time is reached. Then, gas flow meters are installed, and the first and second sealing components are fully installed and sealed with the corresponding wellbore assembly. With the gas flow simulation module connected to the bottom of the wellbore assembly, the gas flow simulation module continuously injects gas into the wellbore assembly in both the corrosion wellbore test module and the control wellbore test module and starts timing. During the injection process, the injection time, the pressure value of the injected gas, and the gas flow rate of the gas flow meter are recorded in real time. If the pressure value drops and the gas flow meter in the corrosion wellbore test module shows a gas flow rate, it is determined that the wellbore assembly in the corrosion wellbore test module has leaked. When the leak reaches the preset leakage time, the gas flow simulation module is turned off and the timing is stopped. The degree of leakage is determined based on the recorded injection time, pressure value recorded during the injection process, and gas flow rate.

9. The method for evaluating the sealing performance of a wellbore under in-situ conditions of carbon dioxide geological storage according to claim 8, characterized in that, The method further includes: After determining that a leak has occurred in the corrosion well casing test module, the internal pressure of the well casing assembly in the corrosion well casing test module is depressurized. After depressurization, the module is left to stand and the gas flow simulation module is activated every second preset time. During the activation process, the gas flow rate and injection time of the gas flow meter are recorded in real time. The sealing self-healing performance of the well casing assembly is determined based on the recorded gas flow rate and injection time each time.

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