Cooperative regulation and control method and device for carbon dioxide sequestration and residual methane displacement

Abstract

The invention provides a coordinated regulation and control method and device for carbon dioxide sequestration and residual methane displacement. According to the cooperative regulation and control method for carbon dioxide sequestration and residual methane displacement, efficient sequestration of carbon dioxide in the waste shale gas reservoir and cooperative displacement of residual methane can be achieved, the methane recovery rate is remarkably increased by 30-50%, the carbon dioxide sequestration safety is guaranteed, the sequestration efficiency can reach 85% or above, and the method is suitable for industrial production. And meanwhile, the energy consumption of the system is reduced by 20-30%.

Description

Technical Field

[0001] This invention relates to the field of synergistic regulation of carbon sequestration and methane displacement, and particularly to a method and apparatus for synergistic regulation of carbon dioxide sequestration and residual methane displacement. Background Technology

[0002] With the continued advancement of global carbon emission reduction targets, carbon dioxide geological storage technology, as an important means of achieving carbon neutrality, occupies a key position in energy transition and environmental governance. In the field of unconventional natural gas development, abandoned shale gas reservoirs, due to their natural sealing properties, known geological structures, and abundant micropore and fracture systems, have become ideal targets for the synergistic development of carbon dioxide storage and residual methane displacement. Related technologies typically construct an integrated storage and displacement technical system through the coordinated operation of carbon dioxide injection, methane extraction, and reservoir monitoring. Specifically, this system covers the entire process from carbon dioxide pretreatment, injection parameter design, displacement process control to storage stability assessment, including key aspects such as adsorption-diffusion-seepage coupling modeling, well pattern optimization, and real-time multi-parameter control.

[0003] However, existing methods for coordinating carbon dioxide sequestration and methane displacement directly employ fixed injection parameters and independent production strategies, failing to fully consider the reservoir characteristics of shale gas reservoirs, such as low permeability (0.001–0.1 mD) and high adsorption capacity (carbon dioxide adsorption capacity is 2–3 times that of methane). This may lead to low carbon dioxide sequestration efficiency, insufficient methane displacement, and even problems such as premature carbon dioxide breakthrough of production wells or reservoir pressure imbalance. Furthermore, existing technologies lack dynamic coordination and control mechanisms for the injection and production processes, making it difficult to adjust strategies according to real-time reservoir changes, thus affecting the balance between displacement efficiency and sequestration safety. Simultaneously, monitoring methods are insufficient in terms of spatial resolution and data feedback timeliness, limiting the accurate understanding of carbon dioxide migration paths and methane production distribution, thereby affecting the optimization and evaluation of the coordinating process. Summary of the Invention

[0004] The present invention aims to at least partially solve one of the technical problems in the related art.

[0005] Therefore, the first objective of this invention is to propose a method for synergistic regulation of carbon dioxide sequestration and residual methane displacement.

[0006] The second objective of this invention is to provide a method and apparatus for the synergistic regulation of carbon dioxide sequestration and residual methane displacement.

[0007] To achieve the above objectives, a first aspect of the present invention proposes a method for synergistic regulation of carbon dioxide sequestration and residual methane displacement, comprising: S1, acquiring geological parameters and residual methane content of abandoned shale gas reservoirs, and designing the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate, and methane extraction rate based on the parameters; S2, injecting pretreated high-purity carbon dioxide into the abandoned shale gas reservoir, while recovering the displaced methane through production wells, and monitoring the reservoir pressure, carbon dioxide concentration, and methane concentration distribution in real time; S3, based on monitoring data and a multiphysics coupling model of a numerical simulation platform, predicting carbon dioxide migration paths and methane production trends, and automatically adjusting the injection rate or extraction intensity when the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%.

[0008] S4. When the reservoir pressure exceeds 1.2 times the original formation pressure, pressure release measures are initiated to stabilize the reservoir pressure by increasing the methane extraction rate and ensuring the safety of carbon dioxide sequestration.

[0009] In one embodiment of the present invention, S1 includes:

[0010] S11 reservoir porosity, permeability, total organic carbon content, and residual methane content were analyzed using core experiments and well logging data. The porosity ranged from 2-10%, the permeability from 0.001-0.1 mD, and the residual methane content from 1-5 mD. 3 / t;

[0011] S12 adopts a five-point well network layout, with 3 horizontal injection wells and 5 production wells. The well spacing is 300-500m, and the horizontal section length of the injection wells is 1000-2000m. They are arranged along the main stress direction of the reservoir to maximize the contact area between carbon dioxide and the reservoir.

[0012] In one embodiment of the present invention, S2 includes:

[0013] S21 uses membrane separation to remove H2S and N2 impurities from carbon dioxide, achieving a carbon dioxide purity of over 99.7%, and uses adsorption to reduce the water content of carbon dioxide to below 30 ppm.

[0014] S22 separates the displaced methane using a gas-liquid separator, and measures the methane output using a flow meter with a measurement range of 1000-10000 m³ / h. 3 / d.

[0015] In one embodiment of the present invention, S3 includes:

[0016] S31, the numerical simulation platform uses the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide in the reservoir and the production distribution of methane.

[0017] The S32 intelligent control software automatically generates control schemes for injection flow, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

[0018] In one embodiment of the present invention, S4 includes:

[0019] S41. When the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure, the methane extraction rate should be appropriately increased by 20-30% through the production wells. S42. Continuously monitor the changes in reservoir pressure. If the pressure does not recover to less than 1.1 times the original pressure within 7 days, the production well extraction strategy should be further adjusted or auxiliary pressure release wells should be activated.

[0020] In one embodiment of the present invention, it further includes: S5, continuously monitoring reservoir temperature and strain through a distributed optical fiber sensing system with a spatial resolution of 1m, and arranging pressure sensors and concentration sensors within a 50m range around the injection well and production well to achieve high-precision dynamic monitoring of key areas of the reservoir.

[0021] To achieve the above objectives, a second aspect of the present invention provides a synergistic control device for carbon dioxide sequestration and residual methane displacement, comprising:

[0022] The geological parameter acquisition module is used to acquire the geological parameters and residual methane content of abandoned shale gas reservoirs, and to design the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate and methane extraction rate based on the parameters.

[0023] The carbon dioxide injection and methane recovery module is used to inject pre-treated high-purity carbon dioxide into the abandoned shale gas reservoir, while recovering the displaced methane through production wells, and monitoring the reservoir pressure, carbon dioxide concentration and methane concentration distribution in real time.

[0024] The migration path and mining trend prediction module is used to predict carbon dioxide migration paths and methane production trends based on monitoring data and a multiphysics coupling model of a numerical simulation platform. When the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%, the injection rate or mining intensity is automatically adjusted.

[0025] The pressure release control module is used to activate pressure release measures when the reservoir pressure exceeds 1.2 times the original formation pressure. This stabilizes the reservoir pressure by increasing the methane extraction rate, thus ensuring the safety of carbon dioxide sequestration.

[0026] The method and apparatus of this invention achieve dynamic synergistic control of efficient carbon dioxide sequestration and residual methane displacement, significantly improving sequestration efficiency to over 85% and methane recovery rate to 30-50%, while ensuring sequestration safety and system economy.

[0027] The beneficial effects of this invention are as follows:

[0028] 1. This invention utilizes the natural sealing properties of abandoned shale gas reservoirs to achieve efficient carbon dioxide sequestration. At the same time, it displaces residual methane through the competitive adsorption characteristics of carbon dioxide and methane, thereby increasing methane recovery rate by 30-50%, achieving the dual benefits of carbon emission reduction and energy recovery.

[0029] 2. The injection-production module adopts a horizontal well staggered layout and a precise control device. Combined with the real-time response mechanism of the collaborative control center, it can dynamically optimize injection and production parameters according to the reservoir, avoid premature carbon dioxide breakthrough of production wells, improve displacement efficiency, and ensure the safety of carbon dioxide storage.

[0030] 3. The reservoir monitoring module adopts a combination of distributed optical fiber and multi-point sensors to achieve comprehensive monitoring of carbon dioxide migration, methane production and reservoir pressure, providing accurate data support for dynamic regulation and improving monitoring accuracy by more than 40% compared with traditional methods.

[0031] 4. The synergistic approach, through a closed-loop design of reservoir assessment, dynamic regulation and stability assessment, is fully adapted to the low permeability and high adsorption characteristics of abandoned shale gas reservoirs. The carbon dioxide sequestration efficiency can reach more than 85%, and the energy consumption of the whole process is reduced by 20-30% compared with conventional sequestration technology.

[0032] Additional aspects and advantages of the invention will be set forth in part in the description which follows, and in part will be obvious from the description, or may be learned by practice of the invention. Attached Figure Description

[0033] The above and / or additional aspects and advantages of the present invention will become apparent and readily understood from the following description of the embodiments taken in conjunction with the accompanying drawings, wherein:

[0034] Figure 1 This is a flowchart of a method for synergistic regulation of carbon dioxide sequestration and residual methane displacement according to an embodiment of the present invention;

[0035] Figure 2 This is a structural diagram of a synergistic control device for carbon dioxide sequestration and residual methane displacement according to an embodiment of the present invention. Detailed Implementation

[0036] It should be noted that, unless otherwise specified, the embodiments and features described in the present invention can be combined with each other. The present invention will now be described in detail with reference to the accompanying drawings and embodiments.

[0037] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0038] The following describes, with reference to the accompanying drawings, a method and apparatus for synergistic regulation of carbon dioxide sequestration and residual methane displacement according to an embodiment of the present invention.

[0039] Example 1

[0040] Figure 1 This is a flowchart of a method for synergistic regulation of carbon dioxide sequestration and residual methane displacement according to an embodiment of the present invention.

[0041] like Figure 1 As shown, the synergistic regulation method of carbon dioxide sequestration and residual methane displacement includes the following steps:

[0042] S1. Obtain the geological parameters and residual methane content of abandoned shale gas reservoirs, and design the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate and methane extraction rate based on the parameters.

[0043] Specifically, this step is the initial stage of a synergistic method for carbon dioxide sequestration and residual methane displacement in abandoned shale gas reservoirs. Its core lies in systematically acquiring reservoir geological parameters and residual methane content to provide data support for the scientific setting of subsequent injection and production parameters. At the technical implementation level, this step first obtains key reservoir geological parameters, including porosity (2-10%), permeability (0.001-0.1 mD), total organic carbon content (2-10%), and residual methane content (1-5 mD), through core experiments and well logging data analysis. 3 These parameters reflect the reservoir's storage capacity, fluid transport characteristics, and adsorption potential, and are the basic inputs for carbon dioxide injection and methane displacement simulation modeling.

[0044] Furthermore, based on the above parameters, a reservoir geological model is constructed using a numerical simulation platform (such as the TOUGH2-E CO2 N module). The adsorption-diffusion-seepage equations for CO2 and methane are coupled to simulate the displacement efficiency and storage capacity under different injection pressures and rates. In some implementations, combining the original reservoir pressure (e.g., 18 MPa) and the CO2 injection pressure window (15-25 MPa), the initial injection pressure is set to 20 MPa, and the injection rate is set to 50-150 t / d, preferably 100 t / d, to balance displacement efficiency and reservoir pressure stability. Simultaneously, the methane recovery rate is set to 2000-8000 m³ / h. 3 / d, preferably 5000m 3 / d, to ensure that the displaced methane can be recovered in a timely manner and to avoid excessive reservoir pressure affecting the carbon dioxide sequestration effect.

[0045] In practical applications, this step is typically deployed in abandoned shale gas reservoirs that have undergone extraction, possess sealed caprocks, and have stable geological structures. Through precise well network layout (such as alternating horizontal and production wells with a well spacing of 300-500m), the contact area between carbon dioxide and the reservoir can be maximized, improving displacement efficiency. Its technical value lies in providing a scientific basis for the entire collaborative system, ensuring that subsequent injection and extraction processes are carried out safely and efficiently, thereby achieving the dual goals of a carbon dioxide sequestration rate ≥85% and a methane recovery rate increase of 30-50%.

[0046] Furthermore, S1 also includes:

[0047] S11 reservoir porosity, permeability, total organic carbon content, and residual methane content were analyzed using core experiments and well logging data. The porosity ranged from 2-10%, the permeability from 0.001-0.1 mD, and the residual methane content from 1-5 mD. 3 / t.

[0048] Specifically, this step is "reservoir assessment and scheme design," the core of which is to analyze the key geological parameters of abandoned shale gas reservoirs through core experiments and well logging data, including porosity, permeability, total organic carbon (TOC) content and residual methane content, thereby providing scientific basis and engineering parameter support for subsequent carbon dioxide injection and methane displacement.

[0049] S12 adopts a five-point well network layout, with 3 horizontal injection wells and 5 production wells. The well spacing is 300-500m, and the horizontal section length of the injection wells is 1000-2000m. They are arranged along the main stress direction of the reservoir to maximize the contact area between carbon dioxide and the reservoir.

[0050] S2, pretreated high-purity carbon dioxide is injected into the abandoned shale gas reservoir, while the displaced methane is recovered through production wells, and the reservoir pressure, carbon dioxide concentration and methane concentration distribution are monitored in real time.

[0051] Specifically, this step involves injecting pretreated high-purity carbon dioxide into abandoned shale gas reservoirs and recovering the displaced methane through production wells, while simultaneously monitoring the reservoir pressure, carbon dioxide concentration, and methane concentration distribution in real time. The technology is based on the competitive adsorption mechanism of carbon dioxide and methane in shale reservoirs and the seepage behavior of multiphase fluids.

[0052] In some implementations, the injected carbon dioxide undergoes pretreatment to ensure a purity ≥99.7% and a water content ≤30ppm. The carbon dioxide is pressurized to 10-30MPa using a reciprocating compressor to overcome the low permeability of shale reservoirs (typically 0.001-0.1mD) and achieve effective displacement. The injection well is designed as a horizontal well with a horizontal section length of 1000-2000m, arranged along the principal stress direction to increase the contact area between the carbon dioxide and the reservoir, enhancing displacement efficiency. The injection rate is controlled within the range of 50-150t / d, and the initial injection pressure is typically set at 15-25MPa to match the original reservoir pressure (e.g., 18MPa) and prevent premature breakthrough or reservoir failure.

[0053] Meanwhile, methane production wells and injection wells are staggered, with a well spacing of 300-500m, facilitating the recovery of residual methane displaced by carbon dioxide. Production wells are equipped with gas-liquid separators and high-precision flow meters (measuring range 1000-10000m³). 3 / d), ensuring the continuity and accuracy of methane recovery. During carbon dioxide injection, the reservoir monitoring module collects data in real time, including pressure sensors (measurement range 0-50MPa, accuracy ±0.1MPa), carbon dioxide and methane concentration sensors (measurement range 0-100%, accuracy ±0.5%), and a distributed fiber optic system (spatial resolution 1m), to monitor reservoir temperature, strain, and fluid concentration distribution.

[0054] Furthermore, the collaborative control center dynamically adjusts injection and production parameters based on monitoring data and numerical simulation results (such as the TOUGH2-E carbon dioxide N model). For example, when the carbon dioxide concentration near the injection well exceeds 80%, the system automatically reduces the injection rate; when the methane concentration in the production well is below 30%, the control software reduces the production intensity to optimize displacement efficiency and ensure storage safety.

[0055] This step plays a crucial role in the overall technical solution. By precisely controlling the injection and extraction process, it enables efficient carbon dioxide sequestration and residual methane displacement and recovery, thereby improving carbon sequestration efficiency and energy utilization, while reducing leakage risks and ensuring both environmental and economic sustainability.

[0056] Furthermore, S2 includes:

[0057] S21 uses membrane separation to remove H2S and N2 impurities from carbon dioxide, achieving a carbon dioxide purity of over 99.7%, and uses adsorption to reduce the water content of carbon dioxide to below 30 ppm.

[0058] Specifically, this step employs a combination of membrane separation and adsorption methods to deeply purify and dry carbon dioxide, meeting the high purity and low water content requirements for injection into abandoned shale gas reservoirs. In some implementations, membrane separation primarily relies on the permeability differences of gases within composite membrane materials, preferentially removing impurity gases such as H2S and N2. The selected membrane modules are typically hollow fiber membranes or flat sheet membranes, made of materials such as polyimide (PI), polyetherimide (PEI), or mixed matrix membranes (MMMs), exhibiting high selectivity and rejection rates (>99.9%) for H2S and N2. During operation, the carbon dioxide feed gas enters the membrane separation system at a pressure of 1.5-3.0 MPa. By controlling the pressure difference across the membrane (typically 0.5-1.0 MPa), small molecule gases such as H2S and N2 preferentially permeate to the low-pressure side, thereby achieving efficient removal of impurities. The purity of carbon dioxide at the membrane separation outlet can be consistently maintained above 99.7%, which meets the industry standard for carbon dioxide purity in geological storage (such as the IPCC recommendation of above 99.5%).

[0059] Furthermore, adsorption is used to reduce the water content in carbon dioxide, typically employing molecular sieves (such as 3A, 4A, or 13X types) or silica gel as adsorbents. In some implementations, the drying equipment uses a dual-tower switching adsorption system, where one tower is in the adsorption state while the other undergoes regeneration. The adsorption operating temperature is controlled at 20-40℃, and the regeneration temperature is 180-220℃. The regeneration gas can be dry nitrogen or heated carbon dioxide recirculated gas. Through this process, the water content of carbon dioxide can be reduced to below 30 ppm, meeting the strict water content requirements for shale gas reservoir injection (typically <50 ppm) to prevent hydrate formation or mineral reactions that could lead to reservoir blockage.

[0060] S22 separates the displaced methane using a gas-liquid separator, and measures the methane output using a flow meter with a measurement range of 1000-10000 m³ / h. 3 / d.

[0061] At the technical implementation level, gas-liquid separators typically employ a combination of gravity separation and cyclone separation to separate methane gas from any entrained liquid hydrocarbons or moisture. The separator is equipped with a gas-liquid interface control device to ensure a stable output of gaseous methane and prevent liquid backflow from affecting subsequent metering. The separated methane gas then enters a flow meter for measurement; the flow meter used is a high-precision gas mass flow meter with a measurement range of 1000-10000 m³ / h. 3 / d, suitable for medium to high-yield methane recovery scenarios, with a measurement accuracy typically within ±1%, meeting the requirements of GB / T2624-2006 "Flow Measurement Throttling Devices" and ISO5167 standards for gas flow measurement.

[0062] Regarding parameters, the flow meter's range selection must match the reservoir displacement capacity and the production well's capacity. For example, in this embodiment, the daily methane production is stabilized at 5000 m³ / h. 3 The flow meter's measurement range should cover a reasonable fluctuation range of the output to ensure the continuity and accuracy of data acquisition. Simultaneously, the gas-liquid separator's separation efficiency should reach over 95% to prevent liquid components from entering the flow meter and causing measurement deviations or equipment damage.

[0063] In application scenarios, this step is typically deployed at the outlet of production wells in abandoned shale gas reservoirs as an important component of the injection-production module. During carbon dioxide injection, as methane in the reservoir is gradually displaced, the methane concentration in the gas produced from the production well gradually increases. Real-time monitoring and optimized recovery of the produced gas are required through gas-liquid separation and flow metering.

[0064] S3, based on a multiphysics coupling model using monitoring data and a numerical simulation platform, predicts carbon dioxide transport pathways and methane production trends. When the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%, it automatically adjusts the injection rate or extraction intensity.

[0065] Specifically, this step involves using a multiphysics coupled model based on monitoring data and a numerical simulation platform to predict the migration path of carbon dioxide and the methane production trend in abandoned shale gas reservoirs, and automatically adjusting the injection rate or extraction intensity when a specific concentration threshold is triggered. This step is the core component for achieving coordinated control of safe carbon dioxide sequestration and efficient recovery of residual methane.

[0066] At the technical implementation level, this step establishes a multiphysics coupled model through a numerical simulation platform (such as the TOUGH2-E carbon dioxide N module) integrated by the collaborative control center, covering the adsorption-diffusion-permeation process of carbon dioxide and methane. Model inputs include reservoir geological parameters (such as porosity, permeability, and TOC content), initial injection and production conditions, and real-time monitoring data (such as pressure, carbon dioxide, and methane concentrations). By solving the multi-component multiphase flow control equations, the diffusion behavior of carbon dioxide in the reservoir and its displacement efficiency for methane are simulated, predicting the carbon dioxide migration pathway and methane production trend over the next 15 days.

[0067] At the parameter level, the system sets a carbon dioxide concentration threshold of 80% near the injection well and 5% in the production well. When the monitoring module (such as a carbon dioxide concentration sensor with an accuracy of ±0.5%) detects that the carbon dioxide concentration around the injection well exceeds this threshold, it indicates that the carbon dioxide injection rate is too high, which may lead to premature breakthrough or abnormal reservoir pressure. At this time, the intelligent control software will automatically reduce the injection rate by 20-30%. If the carbon dioxide concentration in the production well exceeds 5%, it indicates that carbon dioxide has partially broken into the production well, affecting the purity of methane recovery. The system will then adjust the extraction intensity accordingly, such as increasing the wellhead pressure of the production well or increasing the extraction rate to 6000 m³ / h. 3 / d, to accelerate methane emission and suppress carbon dioxide reflux.

[0068] At the application level, this step is suitable for abandoned shale gas reservoirs with low permeability and high adsorption. By combining real-time monitoring and dynamic simulation, the system can adaptively regulate reservoir heterogeneity, fracture development, and fluid phase changes to ensure a balance between carbon dioxide sequestration efficiency and methane recovery.

[0069] The technical advantage of this step lies in its ability to dynamically optimize injection and extraction parameters through a closed-loop feedback mechanism, effectively controlling the range of carbon dioxide migration, preventing it from breaching the production well, reducing leakage risks, and simultaneously improving methane recovery efficiency. Combined with high-precision monitoring and numerical simulation, the system response time is no more than 5 minutes, significantly enhancing the controllability and safety of the co-storage and displacement process.

[0070] Furthermore, S3 includes:

[0071] S31, the numerical simulation platform uses the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide in the reservoir and the production distribution of methane.

[0072] Specifically, in the collaborative method of the present invention, the numerical simulation platform adopts the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide and the production distribution of methane in abandoned shale gas reservoirs with high accuracy.

[0073] At the technical implementation level, the TOUGH2-E carbon dioxide N module is a numerical simulation tool based on multiphase, multicomponent, and multiphysics coupling, specifically designed to simulate the injection, migration, and storage processes of carbon dioxide in low-permeability, highly adsorbent shale reservoirs. This module constructs a competitive adsorption-diffusion-permeability coupling model between carbon dioxide and methane by solving the mass, energy, and momentum conservation equations for non-isothermal, multicomponent gases in porous media, combined with the Langmuir adsorption model and Fick's diffusion law. Specifically, the adsorption term uses nonlinear isothermal adsorption curves to consider the differences in adsorption capacity of organic matter and inorganic minerals in shale for carbon dioxide and CH4; the diffusion term uses the effective diffusion coefficient (typically around 1×10⁻⁶). -6 Up to 1×10 -7 m 2 The mass transfer behavior of gas in micropores is described within the range of / s; the seepage term is based on Darcy's law and combines reservoir permeability (0.001–0.1mD) and porosity (2–10%) parameters to simulate the flow path of gas in the fracture-matrix system.

[0074] At the parameter level, the simulation process requires inputting reservoir geological parameters (such as total organic carbon content, residual methane content, fracture network distribution, etc.), injection parameters (such as carbon dioxide injection rate of 50–150 t / d, injection pressure of 15–25 MPa), and production parameters (such as methane recovery rate of 2000–8000 m³ / d). 3 The simulation time step is typically set to 1 hour, and the spatial grid size is 10–50 m to balance computational accuracy and efficiency. Model outputs include key indicators such as carbon dioxide saturation distribution in the reservoir, pressure field evolution, methane production concentration, and recovery rate prediction.

[0075] At the application level, this simulation step is mainly used in the decision support system of the collaborative control center. By receiving data from reservoir monitoring modules (such as distributed optical fibers, pressure and concentration sensors) in real time, the model is updated every 72 hours to predict the carbon dioxide migration trend and methane production distribution for the next 15 days, thereby providing a scientific basis for the dynamic adjustment of parameters such as injection rate and production well pressure.

[0076] The S32 intelligent control software automatically generates control schemes for injection flow, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

[0077] Specifically, in some implementations, intelligent control software automatically generates control schemes for carbon dioxide injection flow rate, injection pressure, and methane production well exploitation intensity based on the displacement-storage model prediction results provided by the numerical simulation platform and real-time data such as pressure and concentration collected by the reservoir monitoring module. The response time is no more than 5 minutes, thus achieving dynamic closed-loop control of the storage and displacement processes. This step, based on a dual mechanism of real-time data-driven and numerical simulation feedback, combined with the reservoir's low permeability and high adsorption physical characteristics, ensures the safety of carbon dioxide storage and the high efficiency of methane recovery.

[0078] At the technical implementation level, the intelligent control software employs a combination of rule-based expert systems and machine learning algorithms to perform real-time analysis of reservoir dynamics. The software receives monitoring data from a distributed fiber optic sensing system (1m spatial resolution, 1 sampling time / hour) and pressure sensors (0-50MPa measurement range, ±0.1MPa accuracy) and concentration sensors (0-100% measurement range for carbon dioxide and methane, ±0.5% accuracy) located at key positions. Simultaneously, the numerical simulation platform updates the reservoir model every 72 hours, predicting carbon dioxide migration paths and methane production trends for the next 15 days. Based on these predictions and real-time data, and combined with preset control logic (e.g., a carbon dioxide exceedance threshold of >5% for methane concentration and a pressure safety threshold of 1.2 times the original formation pressure), the intelligent control software automatically generates flow rate adjustment commands (adjustment range 10-200t / d) and pressure control signals (adjustment accuracy ±0.1MPa) for injection wells, as well as production intensity adjustment schemes for production wells (adjustment range 2000-8000m). 3 / d).

[0079] In terms of parameters, the system is initially set with a carbon dioxide injection rate of 100 t / d, an injection pressure of 20 MPa, and a methane extraction rate of 5000 m³ / d. 3 / d, wellhead pressure is 5MPa. When the carbon dioxide concentration near the injection well exceeds 80%, the software will automatically reduce the injection rate by 5-10t / d; if the methane concentration in the production well is below 30%, the production intensity will be reduced by 10-20%. Furthermore, if the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure, the system will trigger a pressure release mechanism, increasing the production well production rate to 6000m 3 / d, to achieve pressure balance.

[0080] Furthermore, this step demonstrates significant technical effectiveness, with a response time controlled within 5 minutes, ensuring the real-time nature and effectiveness of the control. By dynamically adjusting injection and extraction parameters, the system can increase carbon dioxide sequestration efficiency to over 85%, methane recovery rate by 30-50%, and reduce overall energy consumption by 20-30%, achieving synergistic optimization of carbon emission reduction and energy recovery.

[0081] S4. When the reservoir pressure exceeds 1.2 times the original formation pressure, pressure release measures are initiated to stabilize the reservoir pressure by increasing the methane extraction rate and ensuring the safety of carbon dioxide sequestration.

[0082] Specifically, when the reservoir pressure exceeds 1.2 times the original formation pressure, pressure release measures are initiated. By increasing the methane extraction rate, the reservoir pressure is stabilized, ensuring the safety of carbon dioxide sequestration. This step is a key component of the synergistic control method of this invention, aiming to prevent abnormal increases in reservoir pressure from causing carbon dioxide sequestration failure or increased leakage risk through a dynamic response mechanism.

[0083] At the technical implementation level, this step relies on real-time pressure data provided by the reservoir monitoring module, with intelligent judgment and response from the collaborative control center. When the pressure sensor detects that the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure (e.g., 18 MPa) (i.e., 21.6 MPa), the control center immediately triggers the pressure release logic. At this time, the intelligent control software will automatically adjust the production parameters of the production well, adjusting the methane extraction rate from the initial set value (e.g., 5000 m³ / h) by regulating the wellhead throttle valve or the gas flow control valve after the gas-liquid separator. 3 / d) Increase to 6000-8000m 3 / d, to accelerate the discharge of residual methane, thereby reducing the reservoir pressure gradient, alleviating the migration pressure of carbon dioxide in the reservoir, and preventing it from breaking through to the overlying sealing layer or production well.

[0084] Regarding parameters, the pressure monitoring accuracy is ±0.1 MPa, and the response threshold is set at 1.2 times the original formation pressure to ensure timely and accurate control. The methane extraction rate is increased within the range of 20-60% to avoid reservoir structure disturbance or overloading of downhole equipment due to excessively rapid extraction. Meanwhile, the production well flow meter has a measurement range of 1000-10000 m³ / h. 3 / d has sufficient dynamic adjustment capabilities.

[0085] In practical applications, this step is suitable for stages of significant reservoir pressure fluctuations during carbon dioxide injection, especially when the injection rate is high or the reservoir adsorption capacity is strong. By increasing the methane extraction rate, reservoir pressure can be effectively maintained within a safe range, ensuring the long-term stability of carbon dioxide sequestration.

[0086] In terms of technical effectiveness, this measure can quickly respond to reservoir pressure anomalies, prevent carbon dioxide breaches or leaks, and ensure storage safety. Simultaneously, by enhancing methane displacement efficiency and improving residual gas recovery rates, it achieves synergistic optimization of carbon sequestration and energy recovery, demonstrating significant engineering practical value and environmental benefits.

[0087] The synergistic regulation method for carbon dioxide sequestration and residual methane displacement in this invention achieves synergistic optimization of efficient carbon dioxide sequestration and effective residual methane displacement, improves carbon sequestration safety and methane recovery rate, and balances environmental and energy benefits.

[0088] Furthermore, it also includes:

[0089] The S5 continuously monitors reservoir temperature and strain through a distributed fiber optic sensing system with a spatial resolution of 1m. Pressure and concentration sensors are deployed within a 50m radius around injection and production wells to achieve high-precision dynamic monitoring of key reservoir areas.

[0090] Example 2

[0091] The present invention proposes a synergistic regulation method for carbon dioxide sequestration and residual methane displacement, comprising the following steps:

[0092] 1) Composition of the collaborative system:

[0093] The carbon dioxide pretreatment module consists of a purification unit, a compressor unit, and a drying device. The purification unit uses membrane separation to remove impurities such as H2S and N2 from the carbon dioxide, achieving a purity of over 99.7%. The compressor unit uses a reciprocating compressor to compress the carbon dioxide to 10-30 MPa, meeting the injection pressure requirements of shale gas reservoirs. The drying device uses adsorption to reduce the water content of the carbon dioxide to below 30 ppm, preventing moisture from reacting with shale minerals and clogging the pores.

[0094] Injection-production module: includes carbon dioxide injection well, methane production well, injection pipeline, production pipeline and control device.

[0095] Carbon dioxide injection wells are designed as horizontal wells with a horizontal section length of 1000-2000m, arranged along the principal stress direction of the shale gas reservoir to increase the contact area between carbon dioxide and the reservoir. Methane production wells are staggered with injection wells, with a well spacing of 300-500m, facilitating efficient recovery of displaced methane. Flow control valves (adjustment range 10-200t / d) and pressure regulating valves (adjustment accuracy ±0.1MPa) are installed on the injection pipelines, while gas-liquid separators and flow meters (measuring range 1000-10000m³) are installed on the production pipelines. 3 / d), to achieve precise control of injection and mining parameters.

[0096] Reservoir monitoring module: includes fiber optic sensing system, pressure sensor, carbon dioxide concentration sensor and methane concentration sensor.

[0097] The fiber optic sensing system is deployed along the injection and production wells, employing distributed fiber optic technology to achieve continuous monitoring of reservoir temperature and strain with a spatial resolution of 1m. Pressure sensors (measurement range 0-50MPa, accuracy ±0.1MPa) and concentration sensors (carbon dioxide measurement range 0-100%, methane measurement range 0-100%, both with accuracy ±0.5%) are arranged at key reservoir locations and around the wellbore to monitor reservoir pressure and the distribution of carbon dioxide and methane concentrations in real time.

[0098] The collaborative control center consists of a data acquisition server, a numerical simulation platform, and intelligent control software. The data acquisition server receives data from the monitoring modules in real time, with a storage capacity of no less than 10TB. The numerical simulation platform, based on a shale gas reservoir geological model, couples the carbon dioxide-methane adsorption-diffusion-seepage equation to simulate the carbon dioxide displacement of methane and its sequestration effect. The intelligent control software automatically generates control schemes for injection flow rate, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

[0099] 2) The steps of the collaborative method are as follows:

[0100] Reservoir assessment and scheme design steps: Geological parameters of abandoned shale gas reservoirs are analyzed through core experiments and well logging data, including porosity (2-10%), permeability (0.001-0.1 mD), total organic carbon content (2-10%), and residual methane content (1-5 mD). 3 Based on the assessment results, the well network layout of injection wells and production wells was designed, and the initial carbon dioxide injection pressure (15-25 MPa), injection rate (50-150 t / d), and methane extraction rate (2000-8000 m³ / d) were determined. 3 / d).

[0101] Carbon dioxide injection and methane displacement steps: The carbon dioxide pretreatment module is activated to compress purified and dried carbon dioxide to a set pressure and inject it into the abandoned shale gas reservoir through the injection well. Carbon dioxide preferentially adsorbs onto the shale pore surface, displacing residual methane. The displaced methane is extracted through production wells and metered for recovery after gas-liquid separation. The collaborative control center monitors reservoir pressure and concentration distribution in real time. When the carbon dioxide concentration near the injection well exceeds 80%, the injection rate is appropriately reduced; when the methane concentration in the production well is below 30%, the extraction intensity is reduced.

[0102] Dynamic control steps: Based on reservoir monitoring data, the numerical simulation platform updates the displacement-storage model every 72 hours to predict the carbon dioxide migration and methane production trends for the next 15 days. If the simulation shows that carbon dioxide exceeds the production well (carbon dioxide concentration in methane > 5%), the intelligent control software automatically reduces the flow rate of the corresponding injection well by 20-30% and adjusts the wellhead pressure of the production well. If the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure, pressure release measures are initiated, and the production rate is appropriately increased through the production well.

[0103] Storage stability assessment steps: When the methane recovery rate reaches 80% or higher and the carbon dioxide injection volume meets the storage target, gradually reduce the carbon dioxide injection rate until injection stops. Continuously monitor reservoir pressure and carbon dioxide concentration distribution for 12 months to assess carbon dioxide storage stability. If the reservoir pressure decrease rate is <0.1 MPa / month and there are no signs of carbon dioxide leakage, the coordinated process is completed.

[0104] Specifically, the implementation process of the present invention is as follows:

[0105] System setup and parameter settings:

[0106] 1. Select an abandoned shale gas reservoir (porosity 5%, permeability 0.01 mD, residual methane content 3 m). 3 The system deploys 3 horizontal injection wells (1500m long horizontal section) and 5 production wells with a well spacing of 400m, forming a five-point well network.

[0107] 2. Carbon dioxide pretreatment module settings: purification unit membrane module rejection rate >99.9%, compressor unit outlet pressure 20MPa, and drying equipment outlet moisture content 25ppm.

[0108] 3. Initial parameters for the injection-extraction module: Carbon dioxide injection rate 100 t / d, injection pressure 20 MPa; Methane extraction rate 5000 m³ / d. 3 / d, wellhead pressure of production well is 5MPa.

[0109] 4. Reservoir monitoring module: Distributed optical fibers are deployed along the horizontal section of the injection well, with 3 pressure-concentration monitoring points arranged 50m around each well, and the data acquisition frequency is 1 time / hour.

[0110] 5. Collaborative Control Center: The numerical simulation platform adopts the TOUGH2-E carbon dioxide N module, and the intelligent control software sets the carbon dioxide overshoot threshold (5% carbon dioxide concentration in methane) and the pressure safety threshold (1.2 times the original formation pressure).

[0111] Implementation process of collaborative methods:

[0112] 1. Reservoir assessment and scheme design: Core experiments determined that the carbon dioxide adsorption capacity of this shale gas reservoir is 2-3 times that of methane. The injection wells were designed to be arranged along the direction of maximum principal stress, with an initial injection pressure of 20 MPa to match the original reservoir pressure (18 MPa).

[0113] 2. Carbon Dioxide Injection and Methane Displacement: After system startup, pretreated carbon dioxide is injected into the reservoir. Monitoring during the first three months showed that the methane concentration within 100m of the injection well decreased from an initial 30% to 10%, and the daily methane production from the production well stabilized at 5000 m³ / min. 3 The cumulative carbon dioxide sequestration capacity has reached 9,000 tons.

[0114] 3. Dynamic Control: In the fourth month, the carbon dioxide concentration in methane of a certain production well was monitored to rise to 6%. The coordinated control center automatically reduced the flow rate of the corresponding injection well from 100t / d to 70t / d. Three days later, the carbon dioxide concentration dropped back to 3%. In the sixth month, the pressure in the middle of the reservoir rose to 22MPa (original pressure 18MPa). The production well production rate was increased to 6000m³. 3 / d, and the pressure stabilized at 20MPa after 1 week.

[0115] 4. Storage Stability Assessment: By the 12th month, methane recovery reached 85%, and the cumulative carbon dioxide injection reached the designed storage target (5000 Ot), at which point injection ceased. Continuous monitoring for 12 months showed that the reservoir pressure slowly decreased from 20 MPa to 19.5 MPa, with no carbon dioxide leakage, indicating that storage stability met the standards.

[0116] Through the above implementation, this method achieves safe carbon dioxide sequestration while recovering 3.5 million m³ of residual methane. 3 It has significant economic and environmental benefits and is suitable for the coordinated development of various types of abandoned shale gas reservoirs.

[0117] Example 3

[0118] To achieve the above embodiments, such as Figure 2 As shown, this embodiment also provides a synergistic control device 10 for carbon dioxide sequestration and residual methane displacement, comprising:

[0119] The geological parameter acquisition module 100 is used to acquire the geological parameters and residual methane content of abandoned shale gas reservoirs, and to design the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate and methane extraction rate based on the parameters.

[0120] The carbon dioxide injection and methane recovery module 200 is used to inject pretreated high-purity carbon dioxide into the abandoned shale gas reservoir, while recovering the displaced methane through the production well, and monitoring the reservoir pressure, carbon dioxide concentration and methane concentration distribution in real time.

[0121] The migration path and mining trend prediction module 300 is used to predict carbon dioxide migration paths and methane production trends based on monitoring data and a multiphysics coupling model of a numerical simulation platform. When the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%, the injection rate or mining intensity is automatically adjusted.

[0122] The pressure release control module 400 is used to activate pressure release measures when the reservoir pressure exceeds 1.2 times the original formation pressure. This stabilizes the reservoir pressure by increasing the methane extraction rate, thus ensuring the safety of carbon dioxide sequestration.

[0123] Furthermore, the geological parameter acquisition module 100 is also used for:

[0124] Core experiments and well logging data were used to analyze the reservoir's porosity, permeability, total organic carbon content, and residual methane content. The porosity ranged from 2-10%, the permeability from 0.001-0.1 mD, and the residual methane content from 1-5 mD. 3 / t;

[0125] A five-point well network layout is adopted, with 3 horizontal injection wells and 5 production wells. The well spacing is 300-500m, and the horizontal section length of the injection wells is 1000-2000m. They are arranged along the direction of the reservoir principal stress to maximize the contact area between carbon dioxide and the reservoir.

[0126] Furthermore, the carbon dioxide injection and methane recovery module 200 is also used for:

[0127] Membrane separation is used to remove H2S and N2 impurities from carbon dioxide, achieving a carbon dioxide purity of over 99.7%, and adsorption is used to reduce the water content of carbon dioxide to below 30 ppm.

[0128] The displaced methane is separated using a gas-liquid separator, and the methane output is measured using a flow meter with a measurement range of 1000-10000 m³. 3 / d.

[0129] Furthermore, the migration path and mining trend prediction module 300 is also used for:

[0130] The numerical simulation platform uses the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide in the reservoir and the production distribution of methane.

[0131] The intelligent control software automatically generates control schemes for injection flow, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

[0132] Furthermore, the pressure relief control module 400 is also used for:

[0133] When the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure, the methane extraction rate can be appropriately increased by 20-30% through production wells;

[0134] Continuously monitor reservoir pressure changes. If the pressure does not recover to less than 1.1 times the original pressure within 7 days, further adjust the production well exploitation strategy or activate auxiliary pressure release wells.

[0135] The synergistic regulation device for carbon dioxide sequestration and residual methane displacement in this invention embodiment achieves synergistic optimization of efficient carbon dioxide sequestration and effective residual methane displacement, improves carbon sequestration safety and methane recovery rate, and balances environmental and energy benefits.

[0136] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0137] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Thus, a feature defined as "first" or "second" may explicitly or implicitly include at least one of that feature. In the description of this invention, "a plurality of" means at least two, such as two, three, etc., unless otherwise explicitly specified.

Claims

1. A method for synergistic regulation of carbon dioxide sequestration and residual methane displacement, characterized in that, include: S1. Obtain the geological parameters and residual methane content of abandoned shale gas reservoirs, and design the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate and methane extraction rate based on the parameters. S2, pretreated high-purity carbon dioxide is injected into the abandoned shale gas reservoir, while the displaced methane is recovered through the production well, and the reservoir pressure, carbon dioxide concentration and methane concentration distribution are monitored in real time. S3, based on a multi-physics coupling model of monitoring data and numerical simulation platform, predicts carbon dioxide transport paths and methane production trends. When the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%, it automatically adjusts the injection rate or extraction intensity. S4. When the reservoir pressure exceeds 1.2 times the original formation pressure, pressure release measures are initiated to stabilize the reservoir pressure by increasing the methane extraction rate and ensuring the safety of carbon dioxide sequestration.

2. The method as described in claim 1, characterized in that, S1 includes: S11 reservoir porosity, permeability, total organic carbon content, and residual methane content were analyzed using core experiments and well logging data. The porosity ranged from 2-10%, the permeability from 0.001-0.1 mD, and the residual methane content from 1-5 mD. 3 / t; S12 adopts a five-point well network layout, with 3 horizontal injection wells and 5 production wells. The well spacing is 300-500m, and the horizontal section length of the injection wells is 1000-2000m. They are arranged along the main stress direction of the reservoir to maximize the contact area between carbon dioxide and the reservoir.

3. The method as described in claim 1, characterized in that, S2 includes: S21 uses membrane separation to remove H2S and N2 impurities from carbon dioxide, achieving a carbon dioxide purity of over 99.7%, and uses adsorption to reduce the water content of carbon dioxide to below 30 ppm. S22 separates the displaced methane using a gas-liquid separator, and measures the methane output using a flow meter with a measurement range of 1000-10000 m³ / h. 3 / d.

4. The method as described in claim 1, characterized in that, The S3 includes: S31, the numerical simulation platform uses the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide in the reservoir and the production distribution of methane. The S32 intelligent control software automatically generates control schemes for injection flow, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

5. The method as described in claim 1, characterized in that, The S4 includes: S41, when the pressure in a certain area of ​​the reservoir exceeds 1.2 times the original formation pressure, the methane production rate can be appropriately increased by 20-30% through production wells; S42 continuously monitors reservoir pressure changes. If the pressure does not recover to less than 1.1 times the original pressure within 7 days, the production well exploitation strategy will be further adjusted or auxiliary pressure release wells will be activated.

6. The method as described in claim 1, characterized in that, Also includes: The S5 continuously monitors reservoir temperature and strain through a distributed fiber optic sensing system with a spatial resolution of 1m. Pressure and concentration sensors are deployed within a 50m radius around injection and production wells to achieve high-precision dynamic monitoring of key reservoir areas.

7. A synergistic control device for carbon dioxide sequestration and residual methane displacement, characterized in that, include: The geological parameter acquisition module is used to acquire the geological parameters and residual methane content of abandoned shale gas reservoirs, and to design the well network layout of injection wells and production wells, as well as the initial injection pressure, injection rate and methane extraction rate based on the parameters. The carbon dioxide injection and methane recovery module is used to inject pre-treated high-purity carbon dioxide into the abandoned shale gas reservoir, while recovering the displaced methane through production wells, and monitoring the reservoir pressure, carbon dioxide concentration and methane concentration distribution in real time. The migration path and mining trend prediction module is used to predict carbon dioxide migration paths and methane production trends based on monitoring data and a multiphysics coupling model of a numerical simulation platform. When the carbon dioxide concentration near the injection well exceeds 80% or the carbon dioxide concentration in the production well exceeds 5%, the injection rate or mining intensity is automatically adjusted. The pressure release control module is used to activate pressure release measures when the reservoir pressure exceeds 1.2 times the original formation pressure. This stabilizes the reservoir pressure by increasing the methane extraction rate, thus ensuring the safety of carbon dioxide sequestration.

8. The apparatus as claimed in claim 7, characterized in that, The geological parameter acquisition module is also used for: Core experiments and well logging data were used to analyze the reservoir's porosity, permeability, total organic carbon content, and residual methane content. The porosity ranged from 2-10%, the permeability from 0.001-0.1 mD, and the residual methane content from 1-5 mD. 3 / t; A five-point well network layout is adopted, with 3 horizontal injection wells and 5 production wells. The well spacing is 300-500m, and the horizontal section length of the injection wells is 1000-2000m. They are arranged along the direction of the reservoir principal stress to maximize the contact area between carbon dioxide and the reservoir.

9. The apparatus as claimed in claim 7, characterized in that, The carbon dioxide injection and methane recovery module is also used for: Membrane separation is used to remove H2S and N2 impurities from carbon dioxide, achieving a carbon dioxide purity of over 99.7%, and adsorption is used to reduce the water content of carbon dioxide to below 30 ppm. The displaced methane is separated using a gas-liquid separator, and the methane output is measured using a flow meter with a measurement range of 1000-10000 m³. 3 / d.

10. The apparatus as claimed in claim 7, characterized in that, The migration path and mining trend prediction module is also used for: The numerical simulation platform uses the TOUGH2-E carbon dioxide N module, which couples the adsorption-diffusion-percolation equations of carbon dioxide and methane to simulate the migration path of carbon dioxide in the reservoir and the production distribution of methane. The intelligent control software automatically generates control schemes for injection flow, pressure, and production well exploitation intensity based on simulation results and real-time monitoring data, with a response time of no more than 5 minutes.

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