Carbon sequestration CO2 multi-layer injection-production collaborative balance system and method

Abstract

The invention discloses a carbon sequestration CO2 multi-layer injection and production collaborative balance system and method.The carbon sequestration CO2 multi-layer injection and production collaborative balance system comprises a multi-layer injection mechanism, a collaborative extraction mechanism and a regulation and control mechanism, the multi-layer injection mechanism comprises an injection well, an injection allocation device and a two-way packer, the injection well vertically penetrates through 2-4 target reservoirs, and the injection allocation device vertically penetrates through the two-way packer; each target reservoir in the injection well is correspondingly provided with an injection allocation device and a two-way packer, each injection allocation device comprises a pressure sensor, a flow controller and a communication module, the collaborative extraction mechanism comprises a plurality of water production wells, the water production wells are arranged on the periphery of the injection well, and the two-way packers are arranged on the periphery of the injection well. Each water production well corresponds to one target reservoir, an adjustable water pumping screen pipe, a pressure feedback valve and a flow metering device are correspondingly arranged in each water production well, the regulation and control mechanism comprises a controller and an optical fiber monitoring device, and the controller is electrically connected with the optical fiber monitoring device, the pressure sensor, the flow metering device and the pressure feedback valve. The carbon sequestration CO2 multi-layer injection-production collaborative balance system provided by the invention has the advantages of high safety and high efficiency.

Description

Technical Field

[0001] This invention relates to the field of carbon dioxide geological storage technology, and in particular to a multi-layer injection-production coordinated balance system and method for carbon sequestration of CO2. Background Technology

[0002] With carbon capture, utilization, and storage (CCUS) technology becoming a key support for achieving the "dual carbon" goal, CO2 geological storage technology (especially saline aquifer storage) has become a key development direction in the industry due to its wide reservoir distribution and large storage potential. However, there are still many shortcomings in practical applications. The precision of injection pressure control is insufficient. Existing stratified injection technologies mostly rely on preset pressure threshold control, which can easily lead to overpressure or underpressure in some strata. Especially in multi-layered heterogeneous reservoirs, the pressure difference between strata is large, which significantly increases geological and engineering risks. The coordination between extraction and injection is poor. Although some technologies are equipped with saline water production wells, the stratum correspondence between the production well and the injection well is unclear, making it impossible to accurately release the pore space of the target layer. In some cases, excessive water extraction may even cause pressure imbalance in adjacent strata. Summary of the Invention

[0003] This invention aims to at least partially solve one of the technical problems in related technologies. To this end, embodiments of this invention propose a multi-layer CO2 injection-production coordinated balancing system, which has the advantages of high safety and high efficiency.

[0004] According to an embodiment of the present invention, a multi-layer injection-production coordinated balancing system for carbon sequestration CO2 includes a multi-layer injection mechanism, a coordinated extraction mechanism, and a control mechanism. The multi-layer injection mechanism includes an injection well, an injector, and a bidirectional packer. The injection well vertically penetrates 2-4 target reservoirs. Each target reservoir in the injection well is equipped with an injector and a bidirectional packer. The injector includes a pressure sensor, a flow controller, and a communication module. The coordinated extraction mechanism includes multiple water wells arranged around the injection wells. Each water well corresponds to one target reservoir. Each water well is equipped with an adjustable pumping screen, a pressure feedback valve, and a flow metering device. The control mechanism includes a controller and a fiber optic monitoring device. The controller is electrically connected to the fiber optic monitoring device, the pressure sensor, the flow metering device, and the pressure feedback valve.

[0005] The carbon sequestration CO2 multilayer injection-production coordinated balancing system according to embodiments of the present invention has the advantages of high safety and high efficiency. The application has the following advantages: injection, extraction, monitoring, and control are coordinated, and pressure balance is achieved through real-time adjustments based on pressure data.

[0006] In some embodiments, the injection well comprises, from bottom to top, a ball seat, multiple sets of injectors and bidirectional packers arranged corresponding to the target reservoir, a pressure control switch, a hydraulic anchor, and a centralizer. The ball seat is used to seal the bottom of the injection well, the pressure control switch is used to control the opening and closing of the CO2 injection channel, the hydraulic anchor is used to limit the axial position of the tubing string in the injection well, and the centralizer is used to ensure the verticality of the tubing string.

[0007] In some embodiments, the optical fiber monitoring device includes an optical signal transmitter, a sensing optical fiber, and a signal receiver. The two ends of the sensing optical fiber are connected to the optical signal transmitter and the signal receiver, respectively. The sensing optical fiber is buried in the interlayer around the injection well and the water production well to monitor the displacement of the interlayer. The sensing optical fiber is vertically deployed around the wellbore of the injection well, corresponding to each target reservoir layer, to monitor the pressure distribution.

[0008] In some embodiments, the water well contains, from bottom to top, a ball seat, multiple sets of pumping screens and bidirectional packers arranged corresponding to the target reservoir, a pressure control valve, a hydraulic anchor, and a centralizer. The ball seat is used to seal the bottom of the water well, the pumping screens are used to pump saline water, the pressure control valve is used to control the opening and closing of the pumping screens, the hydraulic anchor is used to limit the position of the bidirectional packers and the injector, and the centralizer is used to ensure the verticality of the tubing string.

[0009] The carbon sequestration CO2 multilayer injection-production coordinated balancing method according to embodiments of the present invention includes the following steps: Based on the geological data from the geological exploration, select 2-4 target reservoirs with a depth exceeding the predetermined depth. Arrange one injection well and 2-4 water production wells in the target reservoirs. The injection well is perforated and injected at the corresponding depth of each target reservoir, and the water production wells are perforated and extracted to produce saline water at the corresponding depth of each target reservoir. The saline water production rate is determined by calculating the pressure range for injection-production balance control based on the permeability of each target reservoir and the distance between injection and production wells, thereby deriving the saline water production rate Q1. min and Q1 max ; Calculate the effective storage capacity M for each layer, M = ×A×H×φ×(1- )×E, where Let A be the density of supercritical CO2, H be the storage area, H be the layer thickness, and φ be the porosity. Where E is the bound water saturation level, and E is the sequestration factor. Injection is initiated, and CO2 is injected into each layer according to the injection volume allocation coefficient. The water sampling mechanism is activated, and water sampling is performed synchronously. The control mechanism adjusts the injection and sampling parameters, wherein the injection volume allocation coefficient K is... i Based on reservoir porosity and permeability calculations, K i=φ i ×k i / ∑(φ j ×k j ), K i Let Q be the percentage of the injection volume in the i-th layer, k be the permeability, and Q2 be the saline water production volume = α × Q. 注 The water sampling matching coefficient is α, Q1 min ≤Q2≤Q1 max ; The extracted brackish water is desalinated and recycled, and the treated fresh water and recycled salts are reused and utilized as resources, respectively. When the injection volume of one of the target reservoirs reaches the effective storage volume or the pressure of the target reservoir exceeds the safety threshold, the injection channel of that target reservoir is closed, and injection and production continue in other target reservoirs. After all target reservoirs have been injected, the system is shut down, and reservoir pressure and interlayer stability are continuously monitored for a certain period of time.

[0010] In some embodiments, the water production wells are uniformly distributed around the injection wells. For high-permeability reservoirs, k ≥ 1 mD; for medium-permeability reservoirs, 0.1 mD ≤ k < 1 mD; and for low-permeability reservoirs, k < 0.1 mD. As the reservoir permeability decreases, the distance between the water production wells and the injection wells gradually increases.

[0011] In some embodiments, the amount of saline water produced Q1 min =k×A×(P s -P 采低 ) / (μ×L); Saltwater production Q1 max =k×A×(P p -P 采低 ) / (μ×L), P s =0.85×P f The formation fracture pressure is P f Lower limit of water intake pressure P 采低 =P p ×0.8; P s The injection pressure safety threshold is given, k is the target reservoir permeability, and A is the perforation area of ​​the water production well. P 采低 The lower limit of the water production pressure is given by μ, the viscosity of the saline water is given by L, and the distance between the injection well and the production well is given by P. p P represents the original pore pressure. f This refers to the formation fracturing pressure.

[0012] In some embodiments, α is taken as 0.3-0.6 and is dynamically adjusted according to the reservoir porosity compressibility.

[0013] In some embodiments, the pressure gradient between the injection well and the production well is ≤0.002 MPa / m.

[0014] In some embodiments, when switching between layers, when closing the injection channel of the overpressured target reservoir, the CO2 supply to the target reservoir is first cut off by the pressure control switch, and then the flow valve of the injector is closed. At the same time, the corresponding water production well is kept running for a certain period of time to avoid pressure fluctuations affecting other layers. Attached Figure Description

[0015] Figure 1 This is a schematic diagram of the structure of the carbon sequestration CO2 multilayer injection-production coordinated balance system according to an embodiment of the present invention.

[0016] Reference numerals: 1. Ball seat; 2. Injector; 3. Two-way packer; 4. Pressure control switch; 5. Hydraulic anchor; 6. Centralizer; 7. Pumping screen; 8. Pressure control valve; 9. Injection well; 10. Water intake well. Detailed Implementation

[0017] Embodiments of the present invention are described in detail below, examples of which are illustrated in the accompanying drawings. The embodiments described below with reference to the accompanying drawings are exemplary and intended to explain the present invention, and should not be construed as limiting the present invention.

[0018] According to an embodiment of the present invention, the carbon sequestration CO2 multi-layer injection-production coordinated balancing system includes a multi-layer injection mechanism, a coordinated extraction mechanism, and a control mechanism. The multi-layer injection mechanism includes an injection well, an injector 2, and a bidirectional packer 3. The injection well vertically penetrates 2-4 target reservoirs. Each target reservoir in the injection well is equipped with an injector 2 and a bidirectional packer 3. The injector 2 includes a pressure sensor, a flow controller, and a communication module. The coordinated extraction mechanism includes multiple water wells arranged around the injection wells. Each water well corresponds to a target reservoir. Each water well is equipped with an adjustable pumping screen 7, a pressure feedback valve, and a flow metering device. The control mechanism includes a controller and a fiber optic monitoring device. The controller is electrically connected to the fiber optic monitoring device, the pressure sensor, the flow metering device, and the pressure feedback valve.

[0019] The multi-layer injection mechanism achieves precise, layered CO2 injection through the injector 2 and the bidirectional packer 3. The injector 2 uses a pressure sensor to monitor the pressure within the target reservoir in real time, and the flow controller uses an electric regulating valve to adjust the CO2 distribution. The communication module enables communication between devices, transmitting data to the controller of the control mechanism, allowing for flexible adjustment and preventing the intrusion of high-permeability layers while low-permeability layers remain idle. The bidirectional packer 3 enhances interlayer isolation by simultaneously squeezing and sealing in both radial and axial directions, ensuring a tight seal and reducing interlayer leakage.

[0020] The coordinated extraction mechanism controls the water extraction rate through the adjustable pumping screen 7. A pressure feedback valve monitors the pressure of the extraction formation in real time, preventing underpressure. The extraction well and injection well work together to maintain formation pressure balance. The adjustable pumping screen 7 regulates the pumping rate by adjusting the screen opening. An electric adjusting ring can be placed inside the screen to change the screen aperture opening. Filter yarn is wrapped around the outside of the screen to reduce the impact of sand production from the formation.

[0021] The control agency uses fiber optic detection devices to detect reservoir pressure and displacement. The controller adjusts injection and production parameters based on the acquired data, resulting in a fast response speed and improved injection-production matching. The fiber optic monitoring device has a large coverage area, which improves the monitoring effect.

[0022] The carbon sequestration CO2 multilayer injection-production coordinated balancing system according to embodiments of the present invention has the advantages of high safety and high efficiency.

[0023] In some embodiments, the injection well consists of, from bottom to top, a ball seat 1, multiple sets of injectors 2 and bidirectional packers 3 arranged corresponding to the target reservoir, a pressure control switch 4, a hydraulic anchor 5, and a centralizer 6. The ball seat 1 is used to seal the bottom of the injection well, the pressure control switch 4 is used to control the opening and closing of the CO2 injection channel, the hydraulic anchor 5 is used to limit the axial position of the tubing string in the injection well, and the centralizer 6 is used to ensure the verticality of the tubing string.

[0024] Specifically, the inner diameter of the ball seat 1 matches the injection well. The ball seat 1 is sealed by inserting a sealing ball, and the sealing gasket expands to complete the seal after pressure buildup at the wellhead. A bidirectional packer 3 is arranged at both the upper and lower ends of each injector 2. A pressure control switch 4 and a bidirectional packer 3 are located between two adjacent injectors 2. The bidirectional packer 3 and the injector 2 work together to reduce inter-layer flow. The pressure control switch 4 is remotely controlled by a controller. When the optical monitoring device detects that the inter-layer displacement exceeds a set value (which can be 0.3mm-3mm / day, for example, 0.5mm / day), the pressure control switch 4 can be remotely forced open to achieve emergency pressure relief. A hydraulic anchor 5 is arranged at the top. The hydraulic anchor 5 has multiple anchoring claws that embed into the inner wall of the casing of the injection well, reducing axial displacement of the tubing string and preventing misalignment between the injector 2 and the reservoir, which would reduce injection efficiency. In some embodiments, the fiber optic monitoring device includes an optical signal transmitter, a sensing fiber, and a signal receiver. The two ends of the sensing fiber are connected to the optical signal transmitter and the signal receiver, respectively. The sensing fiber is buried in the interlayer around the injection well and the water production well to monitor the displacement of the interlayer. The sensing fiber is vertically deployed around the wellbore of the injection well to monitor the pressure distribution of each target reservoir layer.

[0025] Specifically, the optical signal transmitter emits an optical signal, continuously injecting a stable laser beam into the sensing fiber. The signal receiver captures the intensity and phase changes of the scattered light signal in real time, converts the optical signal into an electrical signal, and transmits it to the controller. The sensing fiber can be corrosion-resistant silica fiber, possessing good mechanical flexibility. Centered on the injection well, the sensing fiber is buried in a ring along the depth direction of the interlayer (5-20m below the top of the interlayer) within a 3-5km radius around the injection and water intake wells (i.e., the maximum radius of influence covering CO2 diffusion). Each well corresponds to 1-2 independent fibers, with a fiber spacing of 50-100m, forming a ring monitoring network. When CO2 migrates through the interlayer or the interlayer is displaced by pressure, it causes a slight deformation in the sensing fiber, resulting in a change in the phase of the Rayleigh scattered light. By calculating the phase difference, the amount of interlayer displacement can be deduced. When deployed vertically, the optical fiber can be fixed to the outer wall of the tubing inside the injection well. The fibers are spaced apart to allow for expansion and contraction, preventing breakage due to thermal expansion and contraction. A pressure-sensitive membrane can be wrapped around the fiber at the target reservoir location; the deformation of this membrane under pressure increases the fiber's deformation, facilitating monitoring. Reservoir pressure changes are transmitted to the optical fiber through the well casing. The pressure sensor in injector 2 monitors local pressure, while the optical fiber monitors the overall pressure distribution. Cross-validation can pinpoint the location of anomalies. When interlayer flow reduces the pressure difference between two layers, the optical fiber detects the pressure difference changes in the flow channel. By comparing this with the flow rate changes in injector 2, the failure location can be pinpointed.

[0026] In some embodiments, the water well contains, from bottom to top, a ball seat 1, multiple sets of pumping screens 7 arranged corresponding to the target reservoir, a bidirectional packer 3, a pressure control valve 8, a hydraulic anchor 5, and a centralizer 6. The ball seat 1 is used to seal the bottom of the water well, the pumping screens 7 are used to pump saline water, the pressure control valve 8 is used to control the opening and closing of the pumping screens 7, the hydraulic anchor 5 is used to limit the position of the bidirectional packer 3 and the injector 2, and the centralizer 6 is used to ensure the verticality of the tubing string.

[0027] Specifically, the ball seat 1 achieves bottom sealing through a sealing ball, preventing backflow of saline water from the bottom of the well. The pumping screen pipe 7 is wrapped with polyetheretherketone (PEEK) filter yarn and has a built-in electric adjusting ring. The bidirectional packer 3 allows for independent pumping from each layer, reducing leakage. Pressure control valves 8 are arranged for each pumping screen pipe 7. The pressure control valves 8 are set with opening and closing pressures. When the pressure of the water-producing layer is higher than the opening pressure, the diaphragm pushes the valve core to open, and saline water is pumped normally; when the pressure is lower than the closing pressure, the diaphragm drives the valve core to close, preventing sand production due to excessively low formation pressure. Furthermore, when the fiber optic monitoring system detects that the displacement of the water-producing layer exceeds a set value, such as an example of 0.3 mm / day, the valve can be remotely forcibly closed, triggering emergency protection. The hydraulic anchor 5 is used to achieve axial positioning of the tubing string inside the water-producing well, reducing axial displacement and preventing misalignment between the pumping screen pipe 7 and the target layer.

[0028] The carbon sequestration CO2 multilayer injection-production coordinated balancing method according to embodiments of the present invention includes the following steps: Based on geological data from geological exploration, select 2-4 target reservoirs at depths exceeding a predetermined depth. For each target reservoir, deploy one injection well and 2-4 production wells. The injection well will be perforated at its corresponding depth within each target reservoir to inject water, while the production wells will be perforated at their corresponding depths to produce saline water. The target reservoirs must also meet certain reservoir properties, such as a thickness greater than or equal to 5m and an interlayer thickness greater than 20m. The injection well will penetrate vertically into the target reservoir, and the production wells will be arranged around the injection well to ensure that the pumping screen 7 effectively covers the CO2 diffusion range. The predetermined depth can exceed 800m.

[0029] To determine the saline water production rate, the pressure range for injection-production balance control is calculated based on the permeability of each target reservoir and the distance between injection and production wells, thus yielding the saline water production rate Q1. min and Q1 max In fact, if Q1 min and Q1 max If the former value is greater than the latter, the well spacing needs to be adjusted or the injection pressure safety threshold needs to be lowered.

[0030] Calculate the effective storage capacity M for each layer, M = ×A×H×φ×(1- )×E, where Let A be the density of supercritical CO2, H be the storage area, H be the layer thickness, and φ be the porosity. E represents the saturation of bound water, and E is the sequestration coefficient. The sequestration area is determined according to the radius of influence of the intake well. The sequestration coefficient is directly related to the effectiveness of the pumping screen 7 in releasing pore space during water intake.

[0031] Injection begins; CO2 is injected into each layer according to the injection volume allocation coefficient. The water sampling mechanism is activated for synchronous water sampling. The control mechanism adjusts the injection and sampling parameters. The injection volume allocation coefficient K... i Based on reservoir porosity and permeability calculations, K i =φ i ×k i / ∑(φ j ×k j ), K i Let Q be the percentage of the injection volume in the i-th layer, k be the permeability, and Q2 be the saline water production volume = α × Q. 注 The water sampling matching coefficient is α, Q1 min ≤Q2≤Q1 max During the injection process, the bidirectional packer 3 of the injection well is pressurized and set, the centralizer 6 opens to ensure the tubing is centered, the injector 2 adjusts the injection rate, and injection and water production are started simultaneously. The fiber optic detection device collects data.

[0032] The extracted brackish water is desalinated and recycled, and the treated fresh water and recycled salts are reused and utilized as resources, respectively. When the injection volume of one of the target reservoirs reaches the effective storage volume or the pressure of the target reservoir exceeds the safety threshold, the injection channel of that target reservoir is closed, and injection and production continue in other target reservoirs. After injection into all target reservoirs, the system was shut down, and reservoir pressure and interlayer stability were continuously monitored for a certain period. The fiber optic monitoring device continued to operate for 12 months to monitor the interlayer and ensure reservoir stability.

[0033] In some embodiments, the water production wells are evenly distributed around the injection wells. For high-permeability reservoirs, k ≥ 1 mD; for medium-permeability reservoirs, 0.1 mD ≤ k < 1 mD; and for low-permeability reservoirs, k < 0.1 mD. As the reservoir permeability decreases, the distance between the water production wells and the injection wells gradually increases.

[0034] Specifically, for high-permeability reservoirs (k≥1mD), the distance between production wells and injection wells is 0.1-0.5km; For medium-permeability reservoirs (0.1mD≤k<1mD), the distance between production wells and injection wells is 0.5-1.5km; For low-permeability reservoirs (k < 0.1 mD), the distance between production wells and injection wells is 1.5-5 km. Production wells are distributed around the injection wells, and can be arranged in a ring or square pattern. The distance between production and injection wells is adjusted according to the reservoir permeability. In high-permeability reservoirs, CO2 diffuses quickly, easily causing a sudden increase in local pressure. It is necessary to shorten the distance to accelerate water production. If the distance is too large, CO2 tends to accumulate around the injection wells. With a short distance, the pumping screen 7 of the production well can adopt a small opening and high-frequency adjustment method to adapt to the pressure fluctuations caused by the rapid diffusion of carbon dioxide. The opening pressure of the pressure control valve 8 can be appropriately increased to reduce frequent start-stop. For medium-permeability reservoirs, it is necessary to balance water production efficiency and well network costs to avoid excessive costs due to too many wells. The opening of the pumping screen 7 can be 40%-60%. In low-permeability reservoirs, CO2 diffuses slowly and easily forms pressure dead zones. It is necessary to expand the distance to cover the diffusion range. If the distance is too short, the production wells cannot effectively cover the diffusion range, resulting in long-term low pressure in some areas. The pumping screen 7 is set to an opening of 50%-80% to release pore space through high-flow water intake, thus aiding CO2 diffusion. When there are permeability differences in the target reservoir, a mixed layout can be adopted to achieve segmented pressure relief and ensure uniform pressure.

[0035] In some embodiments, the amount of saline water produced Q1 min =k×A×(P s -P 采低 ) / (μ×L); Saltwater production Q1 max =k×A×(P p -P采低 ) / (μ×L), P s =0.85×P f The formation fracture pressure is P f Lower limit of water intake pressure P 采低 =P p ×0.8; k is the target reservoir permeability, A is the perforation area of ​​the production well, and P s To determine the safe injection pressure threshold, P 采低 The lower limit of the water production pressure is given by μ, the viscosity of the saline water is given by L, and the distance between the injection well and the production well is given by P. p P represents the original pore pressure. f This refers to the formation fracturing pressure.

[0036] Specifically, the amount of saline water produced is Q1. min The minimum necessary production rate is calculated to avoid overpressure; the saline water production rate is Q1. max The maximum safe extraction volume is calculated to avoid sand production.

[0037] Example 1: High-permeability layer, k=8mD, L=2km, Pp=18MPa, Pf=24MPa, A=0.02m 2 μ = 0.8 mPa•s. P s =0.85×P f =0.85×24=20.4MPa. P 采低 =0.8×P p =0.8×18=14.4MPa; Q1 min =2.16m 3 / h, Q1 max =1.296m 3 The actual water extraction volume Q2 falls between 1.296 and 2.16 m³ / h. 3 The / h range is matched to actual needs.

[0038] In Example 2, the infiltration layer had k=3mD, L=5km, Pp=20MPa, Pf=26MPa, and A=0.025m. 2 μ = 0.9 mPa•s. P s =0.85×P f =0.85×26=22.1MPa. P 采低 =0.8×P p =0.8×20=16MPa; Q1 min =0.366m 3 / h, Q1 max =0.24m 3The actual water extraction rate Q2 falls between 0.366 and 0.24 m³ / h. 3 The / h range is matched to actual needs.

[0039] Example 3: Low-permeability layer, k=0.5mD, L=8km, Pp=22MPa, Pf=28MPa, A=0.03m 2 μ = 1.0 mPa•s. P s =0.85×P f =0.85×28=23.8MPa. P 采低 =0.8×P p =0.8×22=17.6MPa; Q1 min =0.042m 3 / h, Q1 max =0.03m 3 / h, at this time Q1 min Greater than Q1 max Adjustments to the spacing L and the number of wells are necessary. For example, shortening the spacing L between injection wells and production wells requires careful consideration to avoid interference between production wells due to excessively short L. Increasing the number of production wells can disperse water production and better match actual needs. If there are permeability differences in the target reservoir, production wells should be treated in tiers, such as the upper layer corresponding to the high-permeability section and the lower layer corresponding to the medium-permeability section, with separate calculations for each to avoid inconsistencies.

[0040] In some embodiments, α is taken as 0.3-0.6 and is dynamically adjusted according to the reservoir porosity compressibility.

[0041] Specifically, reservoirs are categorized into highly compressible, moderately compressible, and low-compressible reservoirs. The α value can be 0.5-0.6 for highly compressible reservoirs, 0.4-0.5 for moderately compressible reservoirs, and 0.3-0.4 for low-compressible reservoirs. Flexible α values ​​allow for more precise control, improving the storage efficiency of highly compressible reservoirs and ensuring pressure stability in low-compressible reservoirs. In the initial injection and production phase, when the injected volume is less than 30% of the effective stored volume, the reservoir porosity is primarily in its original state, and α is set to the lower limit to avoid excessive initial water production. In the middle phase (30% effective stored volume ≤ injected volume ≤ 70% effective stored volume), the demand for CO2 filling the pores increases, and α is set to the upper limit (e.g., 0.6 for highly compressible reservoirs) to accelerate pore release. In the later stages of injection and production (injection volume > 70% of effective storage volume): the pores are close to saturation, α drops back to the median value (0.55 for highly compressible reservoirs), and the pressure is maintained stable until injection is completed.

[0042] In some embodiments, during the injection process, the intra-layer pressure difference must be maintained at ≤2MPa, and the pressure gradient between the injection well and the production well must be ≤0.002MPa / m.

[0043] Specifically, the pressure difference within the reservoir should be less than the target range to avoid CO2 crossflow and local overpressure. The pressure difference within the reservoir refers to the pressure difference between any two points within the same target reservoir. If the pressure difference within the reservoir is too large, a crossflow channel will be formed in the area with a large pressure gradient. Carbon dioxide in the high-permeability layer can easily flow rapidly to the low-pressure area along the channel. The low-permeability layer will produce micro-cracks due to excessively high local pressure approaching the fracturing pressure.

[0044] The pressure gradient is the ratio of the difference between the pressure around the injection well and the pressure around the production well to the distance between the injection well and the production well. The migration speed of carbon dioxide in the formation is positively correlated with the pressure gradient. When the pressure gradient is large, the intermediate pores cannot be fully filled, the pressure fluctuation is transmitted too quickly, and the production well responds relatively slowly, causing local overpressure.

[0045] In some embodiments, when switching between layers, when closing the injection channel of the overpressured target reservoir, the CO2 supply to the target reservoir is first cut off by the pressure control switch 4, and then the flow valve of the injector 2 is closed. At the same time, the corresponding water production well is kept running for a certain period of time to avoid pressure fluctuations affecting other layers.

[0046] Specifically, the determination of pressure overpressure requires dual verification using both the fiber optic monitoring device and the pressure sensor of the injector 2 to confirm that the pressure in the target reservoir has exceeded the safety threshold P for a certain period of time. s Furthermore, if adjusting the water intake pressure fails to bring it back below the safe threshold, it is determined that the injection channel of the target storage formation needs to be closed. The storage volume is then used for auxiliary verification to check if the injection volume of this formation is close to the effective storage volume M. If the storage volume is also close to saturation, the necessity of closure is further confirmed to avoid misjudging the switching timing due to short-term pressure fluctuations.

[0047] Maintaining the operation of the water intake well can release residual pressure. If the residual pressure is released too quickly, it can easily cause fluctuations in the pressure difference within the layer. Therefore, the opening of the pumping screen 7 can be reduced to slow down the depressurization rate.

[0048] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," "outer," "clockwise," "counterclockwise," "axial," "radial," and "circumferential" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and are not intended to indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0049] 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.

[0050] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between them; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components, unless otherwise explicitly limited. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0051] In this invention, unless otherwise explicitly specified and limited, "above" or "below" the second feature can mean that the first feature is in direct contact with the second feature, or that the first feature is in indirect contact with the second feature through an intermediate medium. Furthermore, "above," "over," and "on top" of the second feature can mean that the first feature is directly above or diagonally above the second feature, or simply that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature can mean that the first feature is directly below or diagonally below the second feature, or simply that the first feature is at a lower horizontal level than the second feature.

[0052] In this invention, the terms "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., refer to a specific feature, structure, material, or characteristic described in connection with that embodiment or example, which is included in at least one embodiment or example of the 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.

[0053] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Any changes, modifications, substitutions and variations made to the above embodiments by those skilled in the art are within the protection scope of the present invention.

Claims

1. A carbon sequestration CO2 multilayer injection-production synergic balancing system, characterized by, The application relates to a CO2 injection and extraction system for deep saline aquifer, which comprises the following parts: a multi-layer injection mechanism, which comprises injection wells, injection distributors and double-direction packers, the injection wells vertically penetrate through 2-4 target reservoirs, one injection distributor and one double-direction packer are arranged in the injection well corresponding to each target reservoir, the injection distributor comprises a pressure sensor, a flow controller and a communication module; a cooperative extraction mechanism, which comprises a plurality of water extraction wells, the water extraction wells are arranged around the injection wells, each water extraction well corresponds to one target reservoir, and an adjustable water extraction screen pipe, a pressure feedback valve and a flow metering device are arranged in each water extraction well; a control mechanism, which comprises a controller and an optical fiber monitoring device, the controller is electrically connected with the optical fiber monitoring device, the pressure sensor, the flow metering device and the pressure feedback valve.

2. The carbon-sequestering CO2 multizone injection-production co-balanced system according to claim 1, characterized in that, The injection well comprises, from bottom to top, a ball seat, a plurality of injection distributors and double-direction packers arranged corresponding to target reservoirs, a pressure control switch, a hydraulic anchor and a centralizer, the ball seat is used for closing the bottom of the injection well, the pressure control switch is used for controlling the opening and closing of the CO2 injection channel, the hydraulic anchor is used for limiting the axial position of the pipe column in the injection well, and the centralizer is used for ensuring the verticality of the pipe column.

3. The carbon-sequestering CO2 multizone injection-production co-balanced system according to claim 1, wherein, The optical fiber monitoring device comprises an optical signal transmitter, a sensing optical fiber and a signal receiver, the two ends of the sensing optical fiber are connected with the optical signal transmitter and the signal receiver respectively, the sensing optical fiber is buried around the injection well and the water extraction well to monitor the displacement of the interlayer, and the sensing optical fiber is vertically arranged around the wellbore of the injection well to monitor the pressure distribution corresponding to each target reservoir.

4. The carbon-sequestering CO2 multizone injection-production co-balanced system according to claim 1, wherein, The water extraction well comprises, from bottom to top, a ball seat, a plurality of water extraction screen pipes and double-direction packers arranged corresponding to target reservoirs, a pressure control valve, a hydraulic anchor and a centralizer, the ball seat is used for closing the bottom of the water extraction well, the water extraction screen pipe is used for extracting salt water, the pressure control valve is used for controlling the opening and closing of the water extraction screen pipe, the hydraulic anchor is used for limiting the position of the double-direction packer and the injection distributor, and the centralizer is used for ensuring the verticality of the pipe column.

5. A carbon sequestration CO2 multilayer injection-production synergic balancing method, characterized in that, The application further discloses a method for using the CO2 injection and extraction system for deep saline aquifer, which comprises the following steps: selecting 2-4 target reservoirs with a depth exceeding a predetermined depth according to geological data obtained through geological exploration, arranging one injection well and 2-4 water extraction wells for the target reservoirs, perforating and injecting in each target reservoir at the corresponding depth of the injection well, and perforating and extracting salt water in each target reservoir at the corresponding depth of the water extraction well; Determine the amount of salt water produced, according to the permeability of each target reservoir, the distance between injection wells and water wells to calculate the pressure range of injection-production balance control, and then the amount of salt water produced Q1 min and Q1 max ; Calculate the effective storage capacity M for each layer, M = ×A×H×φ×(1- )×E, where Let A be the density of supercritical CO2, H be the storage area, H be the layer thickness, and φ be the porosity. Where E is the bound water saturation level, and E is the sequestration factor. Start injection, inject CO2 into each layer according to injection amount distribution coefficient, start water production mechanism, simultaneously produce water, adjust injection and production parameters by adjusting mechanism, the injection amount distribution coefficient K i Based on reservoir porosity and permeability calculation, K i =φ i ×k i / ∑(φ j ×k j ), K i is the injection amount proportion of the i layer, k is the permeability, the salt water production Q2=α×Q 注 , the water production matching coefficient is α, Q1 min ≤Q2≤Q1 max ; recovering the extracted salt water through desalination treatment, and recycling the treated fresh water and resource utilization of the recovered salt; when the injection amount of one target reservoir reaches an effective storage amount or the pressure of the target reservoir exceeds a safety threshold, the injection channel of the target reservoir is closed, and the injection and extraction of other target reservoirs are continued; after the injection of all target reservoirs is completed, the system is closed, and the reservoir pressure and the stability of the interlayer are monitored for a certain period of time.

6. The carbon sequestration CO2 multilayer injection production co-balanced method according to claim 5, characterized in that, The water extraction wells are uniformly distributed around the injection well, for high-permeability reservoirs k>=1 mD, for medium-permeability reservoirs 0.1 mD<=k<1 mD, and for low-permeability reservoirs k<0.1 mD, the spacing between the water extraction well and the injection well gradually increases with the decrease of the permeability of the reservoir.

7. The carbon sequestration CO2 multilayer injection production co-balanced method according to claim 5, characterized in that, Q1 = k x A x (P min = k x A x (P s -P 采低 ) / (μ x L); Q1 = k x A x (P max = k x A x (P p -P 采低 ) / (μ x L), P s = 0.85 x P f , the formation fracture pressure is P f , the lower limit of the water production pressure P 采低 = P p x 0.8; k is the target reservoir permeability, A is the water production well perforation area, P s is the injection pressure safety threshold, P 采低 is the water production pressure lower limit, μ is the salt water viscosity, L is the injection well to water production well spacing, P p is the original pore pressure, P f is the formation fracture pressure.

8. The carbon sequestration CO2 multilayer injection production co-balanced method according to claim 5, characterized in that, α=0.3-0.6, dynamically adjusted according to reservoir porosity compression.

9. The carbon sequestration CO2 multilayer injection production co-balanced method according to claim 5, characterized in that, The pressure gradient between injection well and water production well is less than or equal to 0.002 MPa / m.

10. The carbon-sequestering CO2 multilayer injection-production co-balanced method according to claim 5, characterized by, When switching between layers, the injection channel of the target reservoir with overpressure is closed, the CO2 supply of the target reservoir is cut off through the pressure control switch, the flow valve of the injection distributor is closed, and the corresponding water production well is maintained for a certain period of time to avoid the influence of pressure fluctuation on other layers.

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