Carbon-filtering gas production system and method

Abstract

The invention discloses a carbon-filtering gas production system and method, and belongs to the technical field of oil-gas field development engineering. The system comprises a first shaft extending to a shallow salt water layer gas cap, a second shaft communicated with a deep natural gas reservoir with high CO2 content, and a fluid control assembly arranged in the second shaft. The fluid control assembly comprises a control valve unit, mixed gas of a deep gas reservoir can be guided to the salt water layer, CO2 is dissolved and sealed in the salt water layer through driving of the natural formation pressure difference, and meanwhile CH4 is migrated and gathered to the gas cap and collected by the first shaft. According to the system and the method, deep gas is introduced into a salt water layer, in-situ storage is realized by utilizing the high solubility of the deep gas to CO2, CH4 is enriched at a gas cap, a high CO2 natural gas reservoir which is difficult to economically exploit traditionally is converted into a pure CH4 product, permanent geological storage of CO2 is synchronously completed, value jump from marginal resources to clean energy and carbon sink is realized, and the system and the method have the advantages of low energy consumption and low cost. And remarkable economic benefits and negative carbon environmental protection values are achieved.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of oil and gas field development engineering, and particularly relates to a carbon filtering gas production system and method. BACKGROUND

[0002] Natural gas, as a relatively clean fossil energy, its efficient development and low-carbon utilization has become the focus of the industry. However, the development of natural gas reservoirs and the treatment of carbon dioxide (CO2) still face multiple technical bottlenecks and challenges, which are as follows:

[0003] 1. In the deep high-CO2 natural gas reservoirs (buried depth usually ≥2000m) widely distributed in the world, there are a large number of "marginal gas reservoirs" or "stranded resources" due to the high CO2 content (volume fraction ≥30%). In order to realize commercial development of such gas reservoirs, large-scale ground decarburization facilities (such as amine absorption, membrane separation process, etc.) must be built, and the investment and operation cost accounts for 30%-50% of the total cost of gas reservoir development, which significantly reduces the development income space. More importantly, if the removed CO2 lacks a suitable utilization or storage approach, direct emission will face strict environmental protection regulation constraints and high carbon tax cost, which not only causes carbon resource waste, but also offsets the low-carbon advantage of natural gas, forming a dilemma of "development loss, non-development waste of resources";

[0004] 2. There are salt water layers associated with natural gas reservoirs in many shallow geological structures (buried depth is mostly <2000m). Such salt water layers have high salinity water as the main medium, with little associated natural gas, and the distribution is scattered and the reserves are low, which does not have economic value for independent exploitation, and has been regarded as "non-target reservoir" for a long time. It is worth noting that the salt water layer has a stable pore-fracture structure, and its distribution is widespread and well sealed, and the solubility of CO2 in salt water is much higher than that of CH4, which is an internationally recognized ideal CO2 storage medium. At present, carbon capture, utilization and storage (CCUS) has become a key technical path to cope with global climate change, among which, the injection of CO2 captured from industrial production or energy consumption processes into deep salt water layer for permanent storage is a mainstream technical direction recognized by the industry and has broad application prospects. However, the core bottleneck in the large-scale promotion of this technical route is that the cost of CO2 from capture, high-pressure compression to long-distance transportation is high, which significantly restricts its economic feasibility and commercialization landing process.

[0005] To solve the above-mentioned carbon sequestration and energy development synergy problem, the existing technology represented by CO2-EOR (carbon dioxide enhanced oil recovery) as a representative of "CO2 injection into oil and gas reservoirs" scheme, although attempts to combine carbon utilization and energy production to benefit carbon sequestration costs, but still has significant limitations: on the one hand, it needs to drill special injection wells, which form an independent system with the original production well network, resulting in complex system configuration and increased operation and maintenance difficulty; on the other hand, it has strict requirements for CO2 gas source, which needs to be equipped with a special stable gas source and ensure the purity, further increasing the comprehensive cost of well network deployment, equipment investment and gas source treatment, and the overall economic efficiency is poor, which makes it difficult to achieve efficient synergy of carbon emission reduction and energy development.

[0006] Therefore, the present application is proposed. SUMMARY

[0007] In view of the above problems existing in the prior art, the present application proposes a carbon filtering gas recovery system and method, which aims to solve at least one of the above problems.

[0008] In order to achieve the above technical purpose, the present application adopts the following technical scheme:

[0009] A carbon filtering gas recovery system, which is deployed in a geological structure containing a shallow saline layer and a deep high-CO2 natural gas reservoir, the system comprising:

[0010] A first wellbore extending at least partially into the saline layer and being in fluid communication with the gas cap space of the saline layer;

[0011] A second wellbore extending through the saline layer and being in fluid communication with the high-CO2 natural gas reservoir through its bottom end;

[0012] A fluid control assembly disposed in the second wellbore, comprising a control valve unit configured to have a first position, a second position and a plurality of operating positions between the first position and the second position; when in the first position, the control valve unit allows the fluid of the high-CO2 natural gas reservoir to be directed to the saline layer, when in the second position, the fluid of the high-CO2 natural gas reservoir is prevented from entering the saline layer and the fluid of the high-CO2 natural gas reservoir is allowed to be produced from the wellhead of the second wellbore; and wherein the flow of the fluid of the high-CO2 natural gas reservoir directed to the saline layer can be adjusted by changing the operating position of the control valve unit;

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

[0014] The use method of the carbon filtering gas recovery system.

[0015] Compared with the prior art, the technical scheme in the application has the following advantages:

[0016] 1. The application creatively couples the "high CO2 natural gas reservoir" and the "shallow saline aquifer", which are traditionally independent or considered as burdens, in function. Through the in-situ separation and storage technology downhole, the expensive and energy-consuming surface decarburization facilities (such as amine absorption tower) and the CO2 compression and transportation links are completely eliminated, the development cost of high CO2 natural gas is greatly reduced, and a large amount of "idle resources" is converted into economically valuable recoverable reserves;

[0017] 2. In the early and middle stages of production, the system directly uses the natural formation pressure difference between the deep gas reservoir and the shallow saline aquifer as the only driving force to realize the whole process of CO2 injection and CH4 purification; this not only completely avoids the energy consumption and investment of external injection equipment (such as compressor set), but also realizes the efficient and gradient utilization of natural energy through accurate control of downhole flow, and the overall energy efficiency of the system is very high;

[0018] 3. The control valve unit used in the application integrates multiple working modes, which can be flexibly switched between "injection well" and "production well" without changing the downhole hardware configuration, greatly simplifying the well structure, reducing the operation complexity and cost, and also having the flow regulation function;

[0019] 4. By directly dissolving and storing CO2 in the saline aquifer downhole, production and storage are realized, and significant negative carbon emissions are achieved during the whole production process. The application provides a new technical paradigm for green development of oil and gas fields, and has great environmental and social benefits. BRIEF DESCRIPTION OF DRAWINGS

[0020] Figure 1 The principle diagram of carbon filtration gas recovery of the application is shown;

[0021] Figure 2 The distribution diagram of the wells shown in the top view is shown; Figure 1

[0022] Figure 3 The local structure diagram of the second wellbore at the position of the saline aquifer shown in is shown; Figure 1

[0023] Figure 4 The principle structure diagram of the control valve unit shown in is shown; Figure 3

[0024] Figure 5 The structure diagram of the control valve unit at the second position shown in is shown; Figure 4

[0025] ​​​​Wherein, 1 - first wellbore, 2 - second wellbore, 3 - third wellbore, 4 - wellhead shut-in 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 - blocking head, 13 - inlet, 14 - through hole, 15 - blocking sleeve, 16 - outlet, 17 - cable, 18 - motor, 19 - screen hole. DETAILED DESCRIPTION

[0026] The specific embodiments of the present application are described in further detail below in conjunction with the accompanying drawings and examples. The following examples are used to illustrate the present application but are not intended to limit the scope of the present application.

[0027] As shown in the drawings, Figures 1 to 5 The present application provides a carbon filter gas recovery system, which is deployed in a geological formation comprising a shallow saline aquifer and a deep high-CO2 gas reservoir, the system comprising:

[0028] a first wellbore 1 extending at least partially into the saline aquifer and being fluidly conductive with a gas cap space of the saline aquifer;

[0029] a second wellbore 2 extending through the saline aquifer and being fluidly connected with the high-CO2 gas reservoir through a bottom end thereof;

[0030] a fluid control assembly 5 disposed within the second wellbore 2, comprising a control valve unit 9 configured to have a first position, a second position and a plurality of operating positions between the first position and the second position; at the first position, the control valve unit 9 allows fluid of the high-CO2 gas reservoir to be directed to the saline aquifer, at the second position, the fluid of the high-CO2 gas reservoir is prevented from entering the saline aquifer and is allowed to be produced from a wellhead of the second wellbore 2; and wherein the flow rate of the fluid of the high-CO2 gas reservoir being directed to the saline aquifer can be adjusted by changing the operating position of the control valve unit 9;

[0031] a wellhead shut-in valve unit 4 installed at the wellhead of the second wellbore 2 and configured to selectively shut in or open a fluid path being produced from the wellhead of the second wellbore 2.

[0032] It should be noted that in the prior art, there are widely distributed deep high-CO2-content natural gas reservoirs containing a large amount of CO2. In order to achieve commercial development, large-scale ground decarburization facilities must be built for such gas reservoirs with high CO2 concentration, resulting in high project investment and operation cost. At the same time, if the CO2 separated from natural gas is directly discharged into the atmosphere, it will face serious environmental problems. Through the above system, the natural gas mixed gas containing CO2 of the deep high-CO2-content natural gas reservoir can be directly or controllably guided to the saline aquifer underground. In this process, the CO2 in the mixed gas is dissolved in the saline aquifer in situ due to its high solubility in the saline water, realizing permanent geological storage of CO2; this process does not need to bring CO2 to the ground, thereby completely eliminating the expensive ground capture and compression link; in addition, compared with CO2, the solubility of CH4 in saline water is extremely low. Under the driving of the gas flow, CH4 will pass through the saline aquifer and spontaneously migrate and collect in the gas cap space above the aquifer, thereby realizing 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 aquifer as the driving force to realize spontaneous migration of the fluid, without or with very little need for external energy input to drive the injection process.

[0033] In order to better achieve the purpose of the present application, the fluid control assembly 5 further comprises an inner pipe 6, a first packer 7 and a second packer 8, the inner pipe 6 is arranged in the second wellbore 2, a control valve unit 9 is arranged at the bottom of the inner pipe 6, a hole (for example, formed by perforation) leading to the saline aquifer is arranged on the second wellbore 2, and the first packer 7 and the second packer 8 are respectively located on the upper and lower sides of the hole. Further, the control valve unit 9 comprises a shell, an adjusting cavity is formed in the shell, a plurality of rows of sieve holes 19 are arranged on the shell and located below the second packer 8 to allow the mixed fluid from the deep high-CO2-content natural gas reservoir to enter the adjusting cavity, and a flow guide channel is further arranged on the control valve unit 9, the flow guide channel is communicated with the adjusting cavity through an inlet 13 thereof and communicated with the hole through an outlet 16 thereof. Through such arrangement, the mixed fluid of the deep high-CO2-content natural gas reservoir and the saline aquifer establish a flow channel.

[0034] In order to achieve the purpose of the present application, the adjusting cavity is provided with a blocking sleeve 15, the top end of the blocking sleeve 15 is closed, and the top end of the blocking sleeve 15 further extends upward to form a blocking head 12, the blocking head 12 is opposite to the inlet 13 of the flow guide channel in the vertical direction, and the blocking head 12 can block the inlet 13 in the second position. Further, the blocking sleeve 15 can move in the vertical direction to configure the control valve unit 9 in the first position, the second position and a plurality of operation positions between the first position and the second position. When the blocking sleeve 15 moves in the vertical direction, the blocking sleeve 15 can form a shielding for part of the multiple rows of sieve holes 19, so as to change the flow area, so as to affect the flow of the mixed fluid of the deep high CO2 natural gas reservoir into the adjusting cavity and further into the saline layer.

[0035] In a preferred embodiment, the bottom of the adjusting cavity is provided with a motor 18, a threaded segment (essentially forming a lead screw) is formed on the output shaft, i.e. the rotating shaft 11 of the motor 18, the threaded segment is connected with the lifting plate 10 through threaded connection, and the blocking sleeve 15 is arranged on the lifting plate 10. In this scheme, the motor 18 drives the rotation of the lead screw, and then converts into the linear motion of the lifting plate 10 and the blocking sleeve 15.

[0036] In order to achieve the purpose of the present application, among the multiple rows of sieve holes 19, a separation ring (not shown in the figure) is arranged between the adjacent two rows of sieve holes 19 on one side of the adjusting cavity. In this way, during the linear motion of the lifting plate 10, the separation ring can be sealed and isolated with the outer wall of the blocking sleeve 15. In this way, the sieve holes 19 that have been shielded by the blocking sleeve 15 cannot be communicated with the adjusting cavity, so that the accurate flow area can be obtained through the motor. It should be noted that, since it is linear motion, only the initial position needs to be determined, and then the rotation number of the lead screw and other parameters can be determined to determine the blocking position of the blocking sleeve 15, so as to determine the flow area.

[0037] In a further preferred embodiment, the motor 18 is connected with a power system on the ground through a cable 17. The cable 17 is preferably a composite cable, which contains a power line core for providing power for the motor 18, and also integrates a communication line core for transmitting data signals. Through the communication link, the ground can receive and process data from the downhole sensor (such as position feedback, pressure and temperature sensors) in real time, and send accurate motion instructions to the motor 18, so as to form a closed-loop intelligent control system, and realize fine and automatic management of the whole 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, located on the same circumference with the first wellbore 1 as the center, it can also be arranged in a non-uniform, asymmetric distribution mode according to the actual geological structure and the need of reservoir heterogeneity. Further, a plurality of auxiliary equipment are arranged between the third wellbore 3 and the second wellbore 2, such as a gas-liquid separator, a pressure booster and the like. It should be noted that the core role of the third wellbore 3 is to serve as an enhancement and protection measure. Specifically, when the natural energy of the deep high-CO2 natural gas reservoir is sufficient, the fluid of the deep high-CO2 natural gas reservoir can be directly guided into the saline aquifer through the fluid control assembly of the second wellbore 2; when it is monitored that the energy of the deep high-CO2 natural gas reservoir decays over time, resulting in that the injection flow rate through the second wellbore 2 is insufficient to maintain the optimal CO2 storage and CH4 purification rate, then the third wellbore 3 is used. In this case, the natural gas of the deep high-CO2 natural gas reservoir is produced through the wellhead of the second wellbore 2, separated by the gas-liquid separator, pressurized by the pressure booster, and then injected from the third wellbore 3. Since the third wellbore 3 is at a predetermined distance from the second wellbore 2, this not only increases the total injection area, but also ensures that the system can continue to operate stably at a predetermined, optimal injection rate.

[0042] In order to better achieve the purpose of the present application, the natural gas exploitation system is equipped with a distributed downhole pressure monitoring system. Specifically, the first wellbore 1 is provided with a first pressure sensor at the gas cap position of the saline aquifer, which is used to monitor the formation pressure of the gas cap space in real time. This pressure value is a key parameter for evaluating the CH4 enrichment degree and regulating the gas production rate of the first wellbore 1. The second wellbore 2 is provided with a second pressure sensor and a third pressure sensor on the upper and lower sides of the second packer 8, respectively. The second pressure sensor is located above the second packer 8 (i.e. on the injection side of the saline aquifer), which is used to monitor the pressure of the saline aquifer near the injection point in real time. The third pressure sensor is located below the packer 8 (i.e. on the deep gas reservoir side), which is used to directly monitor the formation pressure of the deep high-CO2 natural gas reservoir to evaluate the natural driving energy of the gas reservoir. The core value of this pressure monitoring system is to achieve precise control and safety warning through collaborative analysis of data, and its main functions are as follows: 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, by means of the matching 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 state diagnosis and optimization: combined with the data of 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, so as to optimize the injection and production strategies.

[0043] It should be understood that the present application also relates to a carbon-removing gas production method, which is realized by means of the above-mentioned exploitation system, and comprises 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, and the control valve unit 9 in the second wellbore 2 is in the second position at this time, i.e., in a position to prevent the fluid of the high-CO2-content natural gas reservoir from entering the saline aquifer), the gas cap space (which can be a small amount of original natural gas reservoir or a reserved space) at the upper part of the shallow saline aquifer is exploited, and natural gas is produced. In this process, the formation pressure of the gas cap space is continuously monitored (for example, through the first pressure sensor), and when the pressure drops to a preset threshold value and the brine begins to be produced at the wellhead of the first wellbore 1 (for example, the brine production flow rate reaches 0.5 m 3 / h or other), it indicates that the recoverable energy of the gas cap space has been exhausted, and continued exploitation will result in a sharp rise in water production and poor economic benefits. At this time, the gas cap pressure is recorded as P1, and the exploitation rate of the first wellbore 1 is immediately stopped (for example, the first wellbore 1 is closed or the exploitation rate is reduced), and the integrated storage and purification operation of the next stage is officially started;

[0046] Step S2: Integrated storage and purification stage

[0047] When the wellhead shut-in valve unit 4 of the second wellbore 2 is in the closed state, the fluid control assembly in the second wellbore 2 is 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-content natural gas reservoir is used to drive and inject the mixed gas of CH4 and CO2 into the shallow saline aquifer. In this process, the mixed gas from the deep high-CO2-content natural gas reservoir undergoes "natural filtration" in the saline aquifer, CO2 is dissolved in the brine to achieve storage; CH4 is separated due to low solubility and migrates upward under the action of buoyancy, and finally collects and supplements the gas cap space near the first wellbore 1. When the gas cap (saline aquifer gas cap, monitored at the first wellbore 1) pressure reaches a predetermined value, an additional pressure value is added to P1 (determined according to the actual production), and then the first wellbore 1 is opened, and the high-purity CH4 gas collected after purification by the saline aquifer is produced through the first wellbore 1;

[0048] Step S3, Dynamic monitoring and optimization control

[0049] In the production process, the data of the first, second, and third pressure sensors are monitored in real time, and the driving pressure difference between the deep high-CO2-content natural gas reservoir and the saline aquifer is calculated, i.e., the actual effective pressure difference of the driving fluid injection is calculated through the readings of the second pressure sensor (deep gas reservoir pressure) and the third pressure sensor (saline aquifer injection point pressure). Based on the driving pressure difference, the following optimization control strategies can be dynamically executed through the matching intelligent control system:

[0050] Injection flow rate regulation: The operating position of the fluid control assembly (i.e. the opening of the control valve unit 9) is dynamically adjusted to maintain the driving pressure difference within a preset safe and efficient window (e.g. 5-20 MPa), so as to accurately control the injection flow rate. When the driving pressure difference approaches or exceeds the upper limit, it indicates that the driving pressure difference is too large. At this time, the fluid will pass through the control valve unit 9 at a very high speed, which may cause serious high-speed erosion and equipment wear on the one hand, and may cause a large temperature drop due to throttling, resulting in freezing or hydrate formation in the wellbore on the other hand. When the driving pressure difference approaches or is lower than the lower limit of 5 MPa, it indicates that the deep natural driving energy is insufficient. At this time, the opening of the fluid control assembly should be reduced to moderately reduce the injection point pressure (P 注 ) and passively increase the driving pressure difference (ΔP) to maintain the necessary injection power.

[0051] In addition, the pressure at the gas cap should also be monitored in real time by the first pressure sensor during this process to ensure that it is always greater than P1, for example, greater than P1+1 MPa. The gas production rate of the first wellbore and the composition of the output (such as CH4 purity, CO2 content, and water content) should also be continuously analyzed in real time during this process. When the CH4 purity in the output gas is stable or increasing, the gas production rate of the first wellbore should be maintained or moderately increased to efficiently recover the purified natural gas. When the CO2 content in the output gas abnormally increases, it indicates that CO2 may have escaped, and the injection rate of the second wellbore should be immediately reduced, and the injection flow field should be optimized (such as enabling the third wellbore) to ensure the purification effect.

[0052] Step S4: When the opening of the fluid control assembly is reduced to a certain value, i.e. the closure head 12 is close to the inlet 13 to a certain distance, the driving pressure difference between the deep high-CO2 natural gas reservoir and the saltwater layer is reduced to the lower limit value (e.g. 5 MPa) of the preset safe and efficient window. At this time, the inlet 13 is closed by the closure head 12 driven by the motor 18, and then the wellhead shut-off valve unit 4 is opened to produce high-CO2 natural gas from the wellhead of the second wellbore 2. The gas is subjected to gas-liquid separation, pressure boosting, and other operations to meet the injection standard, and then injected into the saltwater layer through the third wellbore 3. It should be noted that although separation is also performed during this process, it only involves gas-liquid separation, which is much easier and significantly less costly than the separation of carbon dioxide and methane.

[0053] The above describes only the preferred specific embodiments of the present application, but the protection scope of the present application is not limited thereto. Any person skilled in the art can make equivalent substitutions or changes within the technical scope disclosed by the present application and according to the technical solutions and inventive concepts of the present application, which should be covered within the protection scope of the present application.

Claims

1. A carbon filter gas recovery system, said system deployed in a geological formation comprising a shallow saline aquifer and a deep high CO2 containing natural gas reservoir, characterized in that, The system comprises: a first wellbore (1) extending at least partially into a saline aquifer and being in fluid communication with a gas cap space of the saline aquifer; a second wellbore (2) extending through the saline aquifer and being in fluid communication with the high CO2-content natural gas reservoir through a bottom end thereof; a fluid control assembly (5) disposed in the second wellbore (2) and comprising a control valve unit (9) configured to have a first position, a second position and a plurality of operating positions between the first position and the second position; in the first position, the control valve unit (9) allows fluid of the high CO2-content natural gas reservoir to be directed to the saline aquifer, in the second position, the fluid of the high CO2-content natural gas reservoir is prevented from entering the saline aquifer and is allowed to be produced from a wellhead of the second wellbore (2); and wherein the flow rate of the fluid of the high CO2-content natural gas reservoir directed to the saline aquifer can be adjusted by changing the operating position of the control valve unit (9); a wellhead shut-in valve unit (4) installed at the wellhead of the second wellbore (2) and configured to selectively shut in or open a fluid path produced from the wellhead of the second wellbore (2).

2. A filter gas recovery system as claimed in claim 1, wherein, The fluid control assembly (5) further comprises an inner tube (6), a first packer (7) and a second packer (8), the inner tube (6) is disposed in the second wellbore (2), the control valve unit (9) is disposed at a bottom of the inner tube (6), the second wellbore (2) is provided with a borehole opening to the saline aquifer, and the first packer (7) and the second packer (8) are respectively located on the upper and lower sides of the borehole opening.

3. A filter gas recovery system as claimed in claim 2, wherein, The control valve unit (9) comprises a housing, an adjusting cavity is formed in the housing, a plurality of rows of screens (19) are provided on the housing and located below the second packer (8) to allow mixed fluid from the deep high CO2-content natural gas reservoir to enter the adjusting cavity, and a flow guide channel is further provided on the control valve unit (9) and in communication with the adjusting cavity through an inlet (13) thereof and with the borehole opening through an outlet (16) thereof.

4. A filter gas recovery system as claimed in claim 3, wherein, A blocking sleeve (15) is provided in the adjusting cavity, a top end of the blocking sleeve (15) is closed, and the top end of the blocking sleeve (15) further extends upward to form a blocking head (12), the blocking head (12) is opposite to the inlet (13) of the flow guide channel in the vertical direction, and the blocking head (12) can block the inlet (13) in the second position.

5. A filter gas recovery system as claimed in claim 4, wherein, When the blocking head (12) blocks the inlet (13), at least one row of screens (19) is not blocked by the blocking sleeve (15), and at least one through hole (14) is further provided in the top of the adjusting cavity and in communication with the inner tube (6), the through hole (14) is always in communication with the adjusting cavity.

6. A carbon filter gas extraction system as claimed in any one of claims 1 to 5 wherein, The natural gas production system further comprises a third wellbore (3) in communication with the second wellbore (2), the third wellbore (3) extends from the ground to the saline aquifer, and a borehole opening is formed on a completion string of the third wellbore (3) corresponding to a section of the saline aquifer.

7. A filter gas recovery system as claimed in claim 6, wherein, The borehole opening on the second wellbore (2) is formed towards a side away from the first wellbore (1).

8. A method of carbon filtration gas recovery, by means of a carbon filtration gas recovery system according to any one of claims 1 to 7, characterized in that, The method comprises: introducing fluid of a deep high-CO2-content natural gas reservoir into a shallow saline aquifer, and producing natural gas from the shallow saline aquifer.

9. A method of filtering carbon dioxide gas according to claim 8, wherein The method comprises the following steps: Step S1, initial production stage The first wellbore (1) is opened, the gas cap space in the upper part of the shallow saline aquifer is produced, and natural gas is produced until the pressure at the gas cap is reduced to a preset threshold and salt water begins to be produced at the wellhead of the first wellbore (1); Step S2: integrated storage and purification stage When the wellhead shut-in valve unit (4) of the second wellbore (2) is in the closed state, the fluid control assembly in the second wellbore (2) is switched to the injection mode, the high pressure of the deep high-CO2-content natural gas reservoir is used to drive and inject the mixed gas from the deep high-CO2-content natural gas reservoir into the shallow saline aquifer; when the gas cap pressure reaches a predetermined value, the first wellbore (1) is opened, and the high-purity natural gas collected after purification by the saline aquifer is produced through the first wellbore (1); Step S3, dynamic monitoring and optimal control During production, real-time monitoring of pressure data is performed, the driving pressure difference between the deep high-CO2-content natural gas reservoir and the saline aquifer is calculated, and 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 output, an intelligent control system is used to dynamically execute an optimal control strategy.

10. A method of filtering carbon dioxide gas according to claim 9, wherein Further comprising step S4, that is, The inlet (13) is blocked by the motor (18) driving the blocking head (12), and then the wellhead shut-in valve unit (4) is opened, the natural gas with high CO2 content is produced from the wellhead of the second wellbore (2), and after ground gas-liquid separation and pressure boosting treatment, it is injected into the saline aquifer through the third wellbore (3).

Images