A carbon filter gas recovery system and method

Abstract

The application discloses a kind of filter carbon gas recovery system and method, belong to oil and gas field development engineering technical field.Its system includes the first wellbore extending to shallow brine layer gas cap, the second wellbore being communicated with deep high CO2 natural gas reservoir and the fluid control assembly being arranged in the second wellbore.The fluid control assembly includes control valve unit, can guide the mixed gas of deep gas reservoir to brine layer, using natural formation differential pressure drive, make CO2 dissolve and be sealed in brine layer, while CH4 migration converges to gas cap and is recovered by the first wellbore.The system and method by introducing deep gas into brine layer, realize in situ storage using its high solubility to CO2, while CH4 is enriched in gas cap, convert high CO2 natural gas reservoir which is traditionally difficult to economically exploit into pure CH4 product, and simultaneously complete permanent geological storage of CO2, realize the value leap from marginal resources to clean energy and carbon sink, have remarkable economic benefit and negative carbon environmental protection value.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development engineering technology, specifically relating to a carbon-filtering gas extraction system and method. Background Technology

[0002] As a relatively clean fossil fuel, the efficient development and low-carbon utilization of natural gas have become a focus of the industry. However, the development of natural gas reservoirs and the treatment of carbon dioxide (CO2) still face multiple technological bottlenecks and challenges, specifically as follows:

[0003] 1. Globally widespread deep natural gas reservoirs with high CO2 content (typically ≥2000m deep) contain a large number of "marginal reservoirs" or "shelved resources" with poor economic viability due to excessively high CO2 content (≥30% by volume). Commercial development of these reservoirs requires large-scale surface decarbonization facilities (such as amine absorption and membrane separation processes), with investment and operating costs accounting for 30%–50% of the total development cost, significantly reducing profitability. More importantly, if the removed CO2 lacks suitable utilization or storage pathways, direct emission will face stringent environmental regulations and high carbon tax costs, resulting in carbon resource waste and negating the low-carbon advantages of natural gas, creating a dilemma of "development leading to losses, and no development leading to resource waste."

[0004] 2. Many shallow geological structures contain saline water layers (mostly less than 2000m deep) associated with natural gas reservoirs. These saline water layers are primarily composed of highly saline water, with very little associated natural gas. Furthermore, the natural gas is scattered and has low reserves, lacking economic value for independent extraction, and has long been considered "non-target reservoirs." It is worth noting that saline water layers possess a stable pore-fracture structure, are widely distributed and well-sealed, and have a much higher solubility for CO2 than CH4, making them an internationally recognized ideal medium for CO2 sequestration. Currently, carbon dioxide capture, utilization, and storage (CCUS) has become a key technological pathway for addressing global climate change. Among these, permanently storing CO2 emitted during industrial production or energy consumption in deep saline water layers is a mainstream technology recognized by the industry and has broad application prospects. However, the core bottleneck facing the large-scale promotion of this technology lies in the high cost of the entire CO2 chain, from capture and high-pressure compression to long-distance transportation, significantly restricting its economic feasibility and commercialization.

[0005] To address the aforementioned challenges in synergistic development of carbon sequestration and energy, existing technologies, such as CO2-EOR (carbon dioxide enhanced oil recovery) and "CO2 injection into oil and gas reservoirs," attempt to offset carbon sequestration costs by combining carbon utilization with increased energy production. However, these technologies still have significant limitations: Firstly, they require the drilling of dedicated injection wells, forming an independent system from the existing production well network, leading to complex system configuration and increased maintenance difficulties. Secondly, they have strict requirements for CO2 gas sources, necessitating a dedicated, stable gas source with guaranteed purity, further increasing the overall costs of well network deployment, equipment investment, and gas source treatment. Consequently, their overall economic efficiency is poor, making it difficult to achieve efficient synergy between carbon emission reduction and energy development.

[0006] In view of this, the present invention is proposed. Summary of the Invention

[0007] In view of the above-mentioned problems in the existing technology, the present invention proposes a carbon-filtered gas collection system and method, with the aim of solving at least one of the above problems.

[0008] To achieve the above technical objectives, the present invention adopts the following technical solution:

[0009] A carbon-filtering gas production system is deployed in a geological structure containing shallow saline aquifers and deep high-CO2 natural gas reservoirs, the system comprising:

[0010] The first wellbore extends at least partially into the saline aquifer and is in communication with the gas cap space of the saline aquifer for fluid flow.

[0011] The second wellbore extends through the saline layer and is in fluid communication with the high CO2 natural gas reservoir through its bottom end;

[0012] A fluid control assembly, disposed within the second wellbore, includes a control valve unit configured to have a first position, a second position, and multiple operating positions between the first and second positions. In the first position, the control valve unit allows fluid from the high-CO2-content natural gas reservoir to be directed to a saline water layer; in the second position, the fluid from the high-CO2-content natural gas reservoir is prevented from entering the saline water layer and is allowed to be extracted from the wellhead of the second wellbore. Furthermore, the flow rate of fluid from the high-CO2-content natural gas reservoir directed to the saline water layer can be adjusted by changing the operating position of the control valve unit.

[0013] The wellhead shut-off valve unit, installed at the wellhead of the second wellbore, is configured to selectively shut off or open the fluid path produced from the wellhead of the second wellbore.

[0014] Instructions for using the carbon filter gas extraction system.

[0015] Compared with the prior art, the technical solution of the present invention has the following advantages:

[0016] 1. This invention creatively couples the traditionally independent or burdensome geological units of "high CO2 natural gas reservoirs" and "shallow saline aquifers." Through downhole in-situ separation and storage technology, it completely eliminates the need for expensive and energy-intensive surface decarbonization facilities (such as amine absorption towers) and CO2 compression and transportation, significantly reducing the development cost of high CO2 natural gas and transforming a large amount of "dormant resources" into economically valuable recoverable reserves.

[0017] 2. In the early and middle stages of production, the system directly utilizes the natural formation pressure difference between the deep gas reservoir and the shallow saline water layer as the sole driving force to realize the entire process of CO2 injection and CH4 purification. This not only completely avoids the energy consumption and investment of external injection equipment (such as compressor units), but also achieves efficient and cascaded utilization of natural energy through precise control of downhole flow rate, resulting in extremely high overall system energy efficiency.

[0018] 3. The control valve unit used in this invention integrates multiple working modes. It can flexibly switch between the roles of "injection well" and "production well" without changing the downhole hardware configuration, which greatly simplifies the well structure, reduces the complexity and cost of operation, and also has the function of flow regulation.

[0019] 4. By directly dissolving and storing CO2 in the saline aquifer downhole, production is simultaneously achieved and storage is realized, resulting in significant negative carbon emissions throughout the extraction process. This provides a completely new technological paradigm for the green development of oil and gas fields, with substantial environmental and social benefits. Attached Figure Description

[0020] Figure 1 This is a schematic diagram illustrating the principle of carbon filtration gas extraction according to the present invention.

[0021] Figure 2 From a top-down perspective Figure 1 A schematic diagram showing the distribution of each well;

[0022] Figure 3 for Figure 1 A partial structural diagram of the second wellbore at the location of the saline layer is shown.

[0023] Figure 4 for Figure 3 The schematic diagram of the control valve unit shown is a schematic representation of its underlying structure.

[0024] Figure 5 for Figure 4 The diagram shows the structure of the control valve unit in the second position.

[0025] Wherein, 1-first wellbore, 2-second wellbore, 3-third wellbore, 4-wellhead shut-off valve unit, 5-fluid control assembly, 6-inner tube, 7-first packer, 8-second packer, 9-control valve unit, 10-lifting plate, 11-rotating shaft, 12-plug head, 13-inlet, 14-through hole, 15-plug sleeve, 16-outlet, 17-cable, 18-motor, 19-screen hole. Detailed Implementation

[0026] The specific embodiments of the present invention will be described in further detail below with reference to the accompanying drawings and examples. The following examples are for illustrative purposes only and are not intended to limit the scope of the invention.

[0027] like Figures 1 to 5 As shown, this invention provides a carbon-filtering gas production system, which is deployed in a geological structure containing shallow saline aquifers and deep high-CO2 natural gas reservoirs. The system includes:

[0028] The first wellbore 1 extends at least partially into the saline aquifer and is capable of communicating with the gas cap space of the saline aquifer fluid.

[0029] The second wellbore 2 extends through the saline layer and is in fluid communication with the high CO2 natural gas reservoir through its bottom end;

[0030] A fluid control assembly 5, disposed within the second wellbore 2, includes a control valve unit 9 configured to have a first position, a second position, and multiple operating positions between the first and second positions. At the first position, the control valve unit 9 allows fluid from the high-CO2-content natural gas reservoir to be guided to the saline water layer; at the second position, the fluid from the high-CO2-content natural gas reservoir is prevented from entering the saline water layer, and the fluid from the high-CO2-content natural gas reservoir is allowed to be extracted from the wellhead of the second wellbore 2. Furthermore, the flow rate of the fluid from the high-CO2-content natural gas reservoir guided to the saline water layer can be adjusted by changing the operating position of the control valve unit 9.

[0031] Wellhead shut-off valve unit 4, installed at the wellhead of the second wellbore 2, is configured to selectively shut off or open the fluid path extracted from the wellhead of the second wellbore 2.

[0032] It should be noted that existing technologies widely include deep, high-CO2 natural gas reservoirs. Due to their high CO2 concentration, commercial development of these reservoirs requires large-scale surface decarbonization facilities, resulting in high investment and operating costs. Furthermore, direct release of CO2 separated from natural gas into the atmosphere poses serious environmental problems. This invention, through the aforementioned system, enables the direct or controlled downhole guidance of CO2-containing natural gas mixtures from deep, high-CO2 natural gas reservoirs to saline water layers. During this process, the CO2 in the mixture dissolves in situ in the saline water layer due to its high solubility, achieving permanent geological sequestration of CO2. This process eliminates the need to extract CO2 to the surface, thus completely avoiding expensive surface capture and compression processes. Moreover, compared to CO2, CH4 has extremely low solubility in saline water. Driven by airflow, CH4 will pass through the saline layer and spontaneously migrate and collect in the gas cap space above the layer, thus achieving natural filtration and purification of the gas. In addition, the system directly utilizes the natural formation pressure difference between the deep gas reservoir and the shallow saline layer as the driving force to achieve spontaneous fluid migration, requiring little or no external energy input to drive the injection process.

[0033] To better achieve the objectives of this invention, the fluid control assembly 5 further includes an inner tube 6, a first packer 7, and a second packer 8. The inner tube 6 is disposed within the second wellbore 2, and the control valve unit 9 is disposed at the bottom of the inner tube 6. The second wellbore 2 is provided with orifices (e.g., formed through perforations) leading to the saline water layer. The first packer 7 and the second packer 8 are located on the upper and lower sides of the orifices, respectively. Further, the control valve unit 9 includes a housing with a regulating chamber formed within it. The housing is provided with multiple rows of perforations 19, located below the second packer 8 to allow mixed fluid from a deep, high-CO2 natural gas reservoir to enter the regulating chamber. The control valve unit 9 is also provided with a flow channel, which communicates with the regulating chamber through its inlet 13 and with the orifices through its outlet 16. Through this arrangement, a flow channel is established between the mixed fluid from the deep, high-CO2 natural gas reservoir and the saline water layer.

[0034] To better achieve the objectives of this invention, a sealing sleeve 15 is provided inside the regulating chamber. The top of the sealing sleeve 15 is closed, and a sealing head 12 extends upward from the top of the sealing sleeve 15. The sealing head 12 is vertically opposite to the inlet 13 of the guide channel. In the second position, the sealing head 12 can block the inlet 13. Furthermore, the sealing sleeve 15 can move vertically to configure the control valve unit 9 in a first position, a second position, and multiple operating positions between the first and second positions. When the sealing sleeve 15 moves vertically, it can block some of the sieve holes 19 in the multiple rows of sieve holes 19, thereby changing the flow area to affect the flow rate of the mixed fluid from the deep high CO2 natural gas reservoir entering the regulating chamber and further entering the saline water layer.

[0035] In a preferred embodiment, a motor 18 is disposed at the bottom of the adjusting cavity. A threaded section (essentially forming a lead screw) is formed on the output shaft, i.e., the rotating shaft 11 of the motor 18. The threaded section is connected to a lifting plate 10 via a threaded engagement, and a sealing sleeve 15 is disposed on the lifting plate 10. In this scheme, the motor 18 drives the lead screw to rotate, which is then converted into linear motion between the lifting plate 10 and the sealing sleeve 15.

[0036] To better achieve the objectives of this invention, an isolation ring (not shown in the figure) is provided between adjacent rows of screen holes 19 on one side of the regulating cavity. This allows the isolation ring to seal against the outer wall of the sealing sleeve 15 during the linear movement of the lifting plate 10. Consequently, the screen holes 19 blocked by the sealing sleeve 15 cannot communicate with the regulating cavity, allowing for accurate flow area determination via the motor. It should be noted that, due to the linear motion, only the initial position needs to be determined, and the sealing position of the sealing sleeve 15 can be determined using parameters such as the number of rotations of the lead screw, thus enabling the determination of the flow area.

[0037] In a further preferred embodiment, the motor 18 is connected to a power system located on the ground via a cable 17. The cable 17 is preferably a composite cable, comprising both a power core that provides power to the motor 18 and a communication core for transmitting data signals. Through this communication link, the ground can receive and process data from downhole sensors (such as position feedback, pressure, and temperature sensors) in real time and send precise motion commands to the motor 18, thus forming a closed-loop intelligent control system that enables refined and automated management of the entire injection process.

[0038] To better achieve the objectives of this invention, when the plugging head 12 is placed at the inlet 13, at least one row of screen holes 19 is not blocked by the plugging sleeve 15. Furthermore, the top of the regulating chamber is provided with at least one through hole 14 communicating with the inner tube 6, and the through hole 14 is always in communication with the regulating chamber. With this arrangement, even after the flow channel is blocked, the fluid from the deep high-CO2 natural gas reservoir can still enter the regulating chamber through the screen holes 19, and further pass through the through hole 14, before being extracted from the wellhead of the second wellbore 2.

[0039] To better achieve the purpose of this invention, a vertical slide rail or groove (not shown in the figure) is provided inside the adjustment cavity to cooperate with the lifting plate 10. This ensures that when the rotating shaft 11 rotates, the lifting plate 10 does not rotate, but only undergoes linear movement in the vertical direction, ensuring the smoothness of its movement in the vertical direction.

[0040] To better achieve the objectives of this invention, the perforations on the second wellbore 2 are formed in a direction away from the first wellbore 1, for example, through directional perforations. The purpose of this arrangement is that when the mixed gas from the deep high-pressure gas reservoir is ejected from the perforations of the second wellbore 2, the directional perforations prevent the fluid from flowing directly and at high speed toward the first wellbore 1. This allows the fluid to diffuse more gently in all directions after entering the saline layer, significantly increasing the fluid's transport path and total hydraulic residence time in the saline layer's porous medium. This allows CO2 to dissolve more thoroughly in the saline water, rather than rapidly escaping as free bubbles, thereby greatly improving the CO2 capture efficiency and storage safety in the saline layer. Meanwhile, CH4, with its extremely low solubility, can be separated more effectively from the gas-water mixture and, driven by buoyancy, migrate upwards through the wellbore, ultimately accumulating in the gas cap space of the first wellbore 1 with higher CH4 purity.

[0041] To better achieve the objectives of this invention, the carbon-filtered gas production system further includes a third wellbore 3 connected to the second wellbore 2. The third wellbore 3 extends from the ground to the saline aquifer, and the section of its completion string corresponding to the saline aquifer also has perforations on the side away from the first wellbore 1 (see [reference]). Figure 2 (The perforation direction is shown). Furthermore, the third wellbore 3 is arranged around the first wellbore 1 and maintains a predetermined spatial distance from the second wellbore 2. The second wellbore 2 and the third wellbore 3 can be arranged as follows: Figure 2As shown, the wells are located on the same circumference centered on the first wellbore 1. Alternatively, they can be arranged in a non-uniform, asymmetrical distribution pattern depending on the actual geological structure and reservoir heterogeneity. Furthermore, several auxiliary devices are installed between the third wellbore 3 and the second wellbore 2, such as gas-liquid separators and boosters. It should be noted that the core function of the third wellbore 3 is as an enhancement and safeguard measure. Specifically, when the natural energy of the deep high-CO2 natural gas reservoir is sufficient, the fluid from the deep high-CO2 natural gas reservoir can be preferentially guided directly into the saline water layer through the fluid control components of the second wellbore 2. However, when it is detected that the energy of the deep high-CO2 natural gas reservoir decays over time, resulting in insufficient injection flow through the second wellbore 2 to maintain the optimal CO2 sequestration and CH4 purification rate, the third wellbore 3 is activated. In this case, natural gas from deep high CO2 natural gas reservoirs is produced through the wellhead of the second wellbore 2, separated by a gas-liquid separator, pressurized by a booster, and then injected through the third wellbore 3. Since the third wellbore 3 is a predetermined distance away from the second wellbore 2, this not only increases the total injection area, but also ensures that the system can operate continuously and stably at a preset, optimal injection rate.

[0042] To better achieve the objectives of this invention, the natural gas extraction system is equipped with a distributed downhole pressure monitoring system. Specifically, a first pressure sensor is installed at the gas cap location of the saline layer in the first wellbore 1 to monitor the formation pressure in the gas cap space in real time. This pressure value is a key parameter for assessing the CH4 enrichment level and regulating the gas production rate of the first wellbore 1. A second pressure sensor and a third pressure sensor are respectively installed on the upper and lower sides of the second packer 8 in the second wellbore 2. The second pressure sensor is located above the second packer 8 (i.e., the saline layer injection side) to monitor the saline layer pressure near the injection point in real time. The third pressure sensor is located below the packer 8 (i.e., the deep gas reservoir side) to directly monitor the formation pressure of the deep high CO2 natural gas reservoir to assess the natural driving energy of the gas reservoir. The core value of this pressure monitoring system lies in achieving precise control and safety early warning through collaborative data analysis. Its main functions are: 1. Real-time driving pressure difference monitoring: By calculating the difference between the readings of the second and third pressure sensors, the actual effective pressure difference of the driving fluid injection can be obtained. Therefore, with the help of the supporting intelligent control system, the opening of the injection control valve unit 9 can be dynamically adjusted according to this pressure difference to ensure that the injection process always operates within the optimal and safe pressure difference window. 2. System status diagnosis and optimization: By combining the data from the first pressure sensor (gas cap pressure) and the third pressure sensor (injection point pressure), the migration and enrichment efficiency of CH4 in the saline aquifer can be analyzed, thereby synergistically optimizing the injection and production strategies.

[0043] It should be understood that the present invention also relates to a carbon-filtering gas extraction method, which is implemented by means of the above-mentioned extraction system, and includes the following steps:

[0044] Step S1, Initial Production Stage

[0045] The first wellbore 1 is opened (the second wellbore 2 and the third wellbore 3 are both closed; the control valve unit 9 in the second wellbore 2 is in the second position, i.e., in a position that prevents fluid from the high CO2-content natural gas reservoir from entering the saline layer), and the gas cap space above the shallow saline layer (which can be the original small-scale natural gas reservoir or a reserved space) is exploited to produce natural gas. During this process, the formation pressure in the gas cap space is continuously monitored (e.g., through a first pressure sensor). When the pressure drops to a preset threshold and saline water begins to be produced at the wellhead of the first wellbore 1 (e.g., the saline water flow rate reaches 0.5 m³ / h), natural gas is produced. 3 When the pressure reaches / h or other values, it indicates that the recoverable energy of the gas cap space is nearly exhausted. Continued mining will lead to a sharp increase in water production and a decline in economic benefits. At this time, record the gas cap pressure as P1 and immediately stop the mining rate of the first wellbore 1 (e.g., close the first wellbore 1 or reduce the mining rate), and officially start the next stage of integrated storage and purification operation.

[0046] Step S2: Integrated Sealing and Purification Stage

[0047] With the wellhead shut-off valve unit 4 of the second wellbore 2 in the closed state, the fluid control components inside the second wellbore 2 are switched to the injection mode (i.e., the first position or other corresponding operating position, not the second position). At this time, the high pressure of the deep high CO2 natural gas reservoir is used to drive and inject the mixed gas of CH4 and CO2 into the shallow saline water layer. During this process, the mixed gas from the deep high CO2 natural gas reservoir undergoes "natural filtration" in the saline water layer. A large amount of CO2 dissolves in the saline water and is sealed; CH4, due to its low solubility, separates out and moves upward under the action of buoyancy, eventually gathering and replenishing the gas cap space near the first wellbore 1. When the pressure of the gas cap (saline water layer gas cap, monitored at the first wellbore 1) reaches a predetermined value, an additional pressure value is added on top of P1 (the specific value is determined according to the on-site production), and then the first wellbore 1 is opened to extract the high-purity CH4 gas that has been purified and gathered from the saline water layer through the first wellbore 1.

[0048] Step S3: Dynamic Monitoring and Optimization Control

[0049] During production, data from the first, second, and third pressure sensors are monitored in real time to calculate the driving pressure difference between the deep, high-CO2 natural gas reservoir and the saline water layer. Specifically, the actual effective pressure difference for driving fluid injection is calculated using the readings from the second pressure sensor (deep reservoir pressure) and the third pressure sensor (saline water layer injection point pressure). Based on this driving pressure difference, the following optimized control strategies can be dynamically executed through a supporting intelligent control system:

[0050] Injection flow rate control: The core objective is to maintain the driving pressure differential within a preset safe and efficient window (e.g., 5MPa to 20MPa). The operating position of the fluid control component (i.e., the opening of the control valve unit 9) is dynamically adjusted to precisely control the injection flow rate. When the driving pressure differential approaches or exceeds the upper limit, it indicates that the driving pressure differential is too large. At this time, the fluid will pass through the control valve unit 9 at extremely high speeds. On the one hand, this may cause severe high-speed erosion and equipment wear; on the other hand, the throttling effect here may cause a significant drop in temperature, leading to downhole icing or hydrate formation and blockage. When the driving pressure differential approaches or falls below the lower limit of 5MPa, it indicates insufficient deep natural driving energy. At this time, the opening of the fluid control component should be reduced to moderately reduce the injection point pressure (P) by increasing the throttling. 注 This passively increases the driving pressure difference (ΔP) to maintain the necessary injection power.

[0051] Furthermore, during this process, the pressure at the gas cap should be monitored in real time using the first pressure sensor to ensure that its pressure value is always greater than P1, for example, greater than P1+1MPa. Simultaneously, the gas production rate of the first wellbore and the composition of the produced gas (such as CH4 purity, CO2 content, and water content) should be continuously analyzed in real time. When the CH4 purity in the produced gas is detected to be stable or increasing, the gas production rate of the first wellbore should be maintained or appropriately increased to efficiently recover the purified natural gas. When an abnormal increase in the CO2 content in the produced gas is detected, indicating that CO2 may be leaking, the injection rate of the second wellbore should be immediately reduced, and the injection flow field optimized (e.g., by activating the third wellbore) to ensure the purification effect.

[0052] Step S4: When the opening of the fluid control component is reduced to a certain value, i.e., when the plugging head 12 approaches the inlet 13 to a certain distance, the driving pressure difference between the deep high-CO2 natural gas reservoir and the saline water layer decreases to the lower limit of the preset safe and efficient window (e.g., 5 MPa). At this time, the plugging head 12 is driven by the motor 18 to plug the inlet 13, and then the wellhead shut-off valve unit 4 is opened to extract high-CO2 natural gas from the wellhead of the second wellbore 2. Through gas-liquid separation, pressurization, and other operations, it is made to meet the injection standard, and then injected into the saline water layer through the third wellbore 3. It should be noted that although separation is also performed in this process, it only involves gas-liquid separation, which is much easier and significantly lower in cost than the separation of natural gas such as carbon dioxide and methane.

[0053] The above description is only a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any equivalent substitutions or modifications made by those skilled in the art within the scope of the technology disclosed in the present invention, based on the technical solution and inventive concept of the present invention, should be covered within the scope of protection of the present invention.

Claims

1. A carbon-filtering gas production system, said system being deployed in a geological structure containing shallow saline aquifers and deep high-CO2 natural gas reservoirs, characterized in that, The system includes: The first wellbore (1) extends at least partially into the saline aquifer and is in communication with the gas cap space of the saline aquifer. The second wellbore (2) extends through the saline layer and is in fluid communication with the high CO2 natural gas reservoir through its bottom end; A fluid control assembly (5), disposed within the second wellbore (2), includes a control valve unit (9) configured to have a first position, a second position, and multiple operating positions between the first and second positions; at the first position, the control valve unit (9) allows fluid from the high CO2-content natural gas reservoir to be guided to the saline water layer; at the second position, the fluid from the high CO2-content natural gas reservoir is prevented from entering the saline water layer and is allowed to be extracted from the wellhead of the second wellbore (2); and wherein the flow rate of fluid from the high CO2-content natural gas reservoir being guided to the saline water layer can be adjusted by changing the operating position of the control valve unit (9); The wellhead shut-off valve unit (4), installed at the wellhead of the second wellbore (2), is configured to selectively shut off or open the fluid path extracted from the wellhead of the second wellbore (2); The fluid control assembly (5) also includes an inner tube (6), a first packer (7) and a second packer (8). The inner tube (6) is located inside the second wellbore (2), and the control valve unit (9) is located at the bottom of the inner tube (6). The second wellbore (2) is provided with an orifice that leads to the saline layer. The first packer (7) and the second packer (8) are located on the upper and lower sides of the orifice, respectively. The control valve unit (9) includes a housing, an adjustment chamber is formed inside the housing, and multiple rows of screen holes (19) are provided on the housing. The multiple rows of screen holes (19) are located below the second packer (8) to allow mixed fluid from a deep high CO2 natural gas reservoir to enter the adjustment chamber. The control valve unit (9) is also provided with a flow guide channel, which communicates with the adjustment chamber through its inlet (13) and with the orifices through its outlet (16). The regulating cavity is provided with a sealing sleeve (15), the top of the sealing sleeve (15) is closed, and the top of the sealing sleeve (15) extends upward to form a sealing head (12). The sealing head (12) is opposite to the inlet (13) of the guide channel in the vertical direction. In the second position, the sealing head (12) can block the inlet (13). When the plugging head (12) is plugged at the inlet (13), at least one row of sieve holes (19) is not blocked by the plugging sleeve (15), and the top of the regulating cavity is provided with at least one through hole (14) that connects to the inner tube (6), and the through hole (14) is always in communication with the regulating cavity.

2. The carbon-filtering gas extraction system as described in claim 1, characterized in that, The natural gas extraction system also includes a third wellbore (3) connected to the second wellbore (2), the third wellbore (3) extending from the ground to the saline layer, and the completion string having perforations in the section corresponding to the saline layer.

3. The carbon-filtering gas extraction system as described in claim 2, characterized in that, The holes on the second wellbore (2) are formed facing away from the first wellbore (1).

4. A carbon-filtering gas extraction method, implemented by means of a carbon-filtering gas extraction system according to any one of claims 1 to 3, characterized in that, The method includes: introducing fluid from a deep, high-CO2 natural gas reservoir into a shallow saline aquifer, and extracting natural gas from the shallow saline aquifer.

5. The carbon-filtering gas extraction method as described in claim 4, characterized in that, The process includes the following steps: Step S1, Initial Production Stage Open the first wellbore (1) to mine the gas cap space above the shallow saline layer and produce natural gas until the pressure at the gas cap drops to a preset threshold and saline water begins to be produced at the wellhead of the first wellbore (1). Step S2: Integrated Sealing and Purification Stage With the wellhead shut-off valve unit (4) of the second wellbore (2) in the closed state, the fluid control component in the second wellbore (2) is switched to the injection mode. Using the high pressure of the deep high CO2 natural gas reservoir, the mixed gas from the deep high CO2 natural gas reservoir is driven and injected into the shallow saline water layer. When the gas cap pressure reaches the predetermined value, the first wellbore (1) is opened, and the high-purity natural gas collected after purification by the saline water layer is extracted through the first wellbore (1). Step S3: Dynamic Monitoring and Optimization Control During the production process, pressure data is monitored in real time, and the driving pressure difference between the deep high CO2 natural gas reservoir and the saline water layer is calculated. Based on the driving pressure difference, the pressure at the gas cap, the gas production rate of the first wellbore and the composition of the produced products, the optimized control strategy is dynamically executed through the supporting intelligent control system.

6. The carbon-filtering gas extraction method as described in claim 5, characterized in that, It also includes step S4, that is, the inlet (13) is sealed by the plugging head (12) driven by the motor (18), and then the wellhead shut-off valve unit (4) is opened to extract high CO2 natural gas from the wellhead of the second well (2), and after surface gas-liquid separation and pressurization, it is injected into the saline layer through the third well (3).

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