A layered injection-production optimization control system and method for deep underground thermal energy storage

Abstract

The application discloses a kind of deep underground thermal energy storage and use layered injection-production optimization control system and method, specifically related to underground thermal energy storage and utilization technical field, system includes multi-source heat access module, heat conversion module, underground thermal reservoir well group, layered injection-production module, heat transport monitoring module, boundary pressure regulating module, storage and use collaborative control module and heat energy utilization module;Layered injection-production module includes multiple injection-production intervals, packer and controllable valve, for selective injection or selective production to different reservoir intervals.Heat transport monitoring module is used to obtain the temperature response, pressure response, conductivity change and tracer response of each injection-production interval, and determine the thermal front position, heat transport speed and predicted arrival time of each injection-production interval;Storage and use collaborative control module is used to determine the thermal breakthrough risk index of each injection-production interval according to the thermal front position, heat transport speed, predicted arrival time, pressure response and tracer response.

Description

Technical Field

[0001] This invention belongs to the field of underground thermal energy storage and utilization technology, specifically relating to a layered injection and extraction optimization control system and method for deep underground thermal energy storage and utilization. Background Technology

[0002] Existing open-cell geothermal reservoir systems typically inject heated fluid into the underground reservoir through injection wells and extract the high-temperature fluid during the heat utilization phase through production wells to achieve underground thermal storage and heat recovery. To improve reservoir utilization, some systems also employ techniques such as stratified injection and production, monitoring wells, reinjection wells, or pressure regulation using auxiliary wells to enhance the operational stability of the geothermal reservoir system.

[0003] However, deep underground reservoirs are typically highly heterogeneous, with significant differences in permeability, fracture connectivity, water absorption capacity, and pressure response at different depths. During thermal storage, injected heat preferentially enters high-permeability layers or dominant fracture channels, causing the thermal front to advance significantly faster in some reservoir segments than in others. This results in abnormal heat surges along dominant channels. When the thermal front advances rapidly towards the production well, premature thermal front breakthrough can occur, leading to underutilization of the target reservoir volume and reduced heat recovery efficiency and long-term operational stability.

[0004] Furthermore, existing underground thermal reservoir control methods mostly rely on temperature, pressure, or flow thresholds as the basis for adjustment. When the temperature of the monitoring well rises, the temperature of the production well changes, or the reservoir pressure becomes abnormal, operations such as reducing flow, closing sections, or switching layers are then implemented. This control method is typically a reactive response, making it difficult to predict the heat migration trends of each reservoir section before an early thermal front breakthrough occurs, and also difficult to dynamically redistribute the injection or production flow based on the thermal inrush risk of different reservoir sections. Summary of the Invention

[0005] The purpose of this invention is to provide a layered injection-production optimization control system and method for deep underground thermal energy storage to solve the above-mentioned problems.

[0006] To achieve the above objectives, the present invention provides the following technical solution: a deep underground thermal energy storage and utilization layered injection and production optimization control system, comprising a multi-source heat access module, a heat conversion module, an underground thermal energy storage well group, a layered injection and production module, a heat migration monitoring module, a boundary pressure regulation module, a storage and utilization coordinated control module, and a thermal energy utilization module.

[0007] The multi-source heat access module is used to receive at least one type of energy from surplus wind power, surplus photovoltaic power, off-peak electricity, and industrial waste heat. The heat conversion module is used to convert the energy into heat for the injected fluid. The underground thermal reservoir well group includes a thermal reservoir injection well, a thermal reservoir production well, a cryogenic reinjection well, a monitoring well, and a boundary pressure regulating well. The stratified injection-production module includes multiple injection-production sections disposed within the thermal reservoir injection well and / or thermal reservoir production well, packers disposed between adjacent injection-production sections, and controllable valves corresponding to each injection-production section.

[0008] The heat transport monitoring module is used to acquire the temperature response, pressure response, conductivity changes, and tracer response of each injection-production section. The storage-use coordinated control module includes a thermal front prediction unit, a thermal inrush risk assessment unit, and a flow redistribution unit.

[0009] The thermal front prediction unit is used to determine the thermal front location, heat transport velocity, and predicted arrival time of the thermal front for each injection-production segment based on the temperature response of each segment. The thermal inrush risk assessment unit is used to determine the thermal inrush risk index for each injection-production segment based on the heat transport velocity, predicted arrival time of the thermal front, pressure response, and tracer response. The flow redistribution unit is used to reduce the opening of the controllable valve corresponding to a certain injection-production segment when the thermal inrush risk index of that segment exceeds a preset risk threshold, or when the predicted arrival time of the thermal front of that segment is less than a preset safety time, and to distribute the reduced injection flow and / or production flow to other injection-production segments with lower thermal inrush risk indices and pressure responses that meet preset conditions.

[0010] The control method includes the following steps: First, the temperature response, pressure response, conductivity change, and tracer response of each injection-production segment corresponding to the reservoir segment are obtained. The temperature response is used to characterize the thermal propulsion state within each reservoir segment, the pressure response is used to characterize the injection-production pressure change and fluid connectivity state of each reservoir segment, and the conductivity change and tracer response are used to assist in determining the connectivity and fluid migration velocity between different reservoir segments.

[0011] Second, the location of the thermal front is determined based on the temperature response of each injection-production segment, and the heat transport velocity is determined based on the change in the thermal front location at adjacent time points. The thermal front location X of the i-th injection-production segment is... i (t) can satisfy: In the formula, T i (x,t) represents the temperature of the i-th injection-sampling segment at location x and time t, where T is the temperature of the i-th injection-sampling segment. 0,i Let T be the initial temperature of the reservoir segment corresponding to the i-th injection-production segment. injThe injection fluid temperature is η, which is the thermal front determination coefficient. The value of η ranges from 0.3 to 0.7. Preferably, η is 0.5. When it is necessary to identify the thermal front advancement trend in advance, η is 0.3 to 0.5. When it is necessary to reduce misjudgments caused by temperature fluctuations, η is 0.5 to 0.7.

[0012] The heat transport velocity v of the i-th injection-production segment is determined based on the change in the position of the thermal front at adjacent time points. i (t), satisfying: In the formula, Δt is the time interval between two adjacent monitoring sessions.

[0013] Third, based on the location of the thermal front, the heat migration rate, and the location of the corresponding production well or boundary monitoring well in each injection-production segment, the predicted arrival time of the thermal front in each injection-production segment is determined. The predicted arrival time τ of the thermal front in the i-th injection-production segment is... i (t) can satisfy: In the formula, L i X is the distance from the thermal front location of the i-th injection-production interval to the production well or boundary monitoring well of the thermal reservoir. i (t) represents the thermal leading edge position of the i-th injection-sampling segment at time t, v i (t) represents the heat transfer velocity of the i-th injection-production segment at time t, v min This is the preset minimum heat transfer rate.

[0014] Fourth, based on the heat migration velocity, predicted arrival time of the thermal front, pressure response, and tracer response of each injection-production segment, a thermal inrush risk index is determined for each segment. This thermal inrush risk index characterizes the risk of a thermal inrush in the dominant channel or premature breakthrough of the thermal front in the corresponding injection-production segment. It can be determined based on the temperature change rate, heat migration velocity, tracer response time, pressure response amplitude, and predicted arrival time of the thermal front. The predicted arrival time of the thermal front is determined based on the remaining migration distance between the current position of the thermal front and the target position, as well as the heat migration velocity. A smaller remaining migration distance and a larger heat migration velocity result in a shorter predicted arrival time of the thermal front.

[0015] Fifth, when the thermal surge risk index of a certain injection-production segment exceeds the preset risk threshold, or when the predicted arrival time of the thermal front of the injection-production segment is less than the preset safe time, the opening degree of the controllable valve corresponding to the injection-production segment is reduced to reduce the injection flow rate and / or production flow rate of the injection-production segment.

[0016] Sixth, the reduced injection and / or production flow rates are redistributed to other injection-production segments where the thermal surge risk index is below a preset low-risk threshold, the pressure response is within a preset pressure range, and the predicted arrival time of the thermal front is greater than a preset safe time. Preferably, the flow rate ΔQ allocated to the j-th injection-production segment is...j satisfy: ,in, Reduced flow rate for high-risk injection-production segments To allocate the flow rate to the j-th injection-production segment, R j G is the normalized thermal surge risk index for the j-th injection-production segment. j Let be the pressure bearing capacity coefficient of the j-th injection-production segment, and S be the set of injection-production segments that can withstand the flow rate.

[0017] Seventh, when there is a risk of heat leakage from the boundary of the target geothermal reservoir, the pressure gradient at the boundary of the target geothermal reservoir is adjusted through boundary pressure regulating wells to limit the migration of heat to the outside of the target geothermal reservoir. The risk of heat leakage can be determined based on the temperature rise rate of the boundary monitoring well, the direction of heat migration, and the distance from the thermal front to the boundary of the target geothermal reservoir.

[0018] The technical effects and advantages of this invention are as follows: by determining the location of the thermal front, the heat transport velocity, and the predicted arrival time of the thermal front of each injection-production segment based on the temperature response, pressure response, conductivity change, and tracer response of each injection-production segment, and further determining the thermal inrush risk index of each injection-production segment.

[0019] When the thermal surge risk index of a certain injection-production segment exceeds a preset risk threshold, or when the predicted arrival time of the thermal front of the injection-production segment is less than a preset safe time, this invention reduces the opening of the controllable valve corresponding to the injection-production segment to reduce the injection flow rate and / or production flow rate of the injection-production segment, and redistributes the reduced flow rate to other injection-production segments with lower thermal surge risk, pressure response within a preset pressure range, and longer predicted arrival time of the thermal front, thereby achieving predictive suppression of the risk of premature thermal front breakthrough.

[0020] Meanwhile, when there is a risk of heat leakage at the boundary of the target geothermal reservoir, the present invention adjusts the pressure gradient at the boundary of the target geothermal reservoir by using boundary pressure regulating wells to limit the migration of heat to the outside of the target geothermal reservoir, thereby improving the controllability and long-term operational stability of the underground geothermal reservoir. Attached Figure Description

[0021] Figure 1 This is a schematic diagram of the overall structure of a layered injection-production optimization control system for deep underground thermal energy storage based on thermal front prediction, according to the present invention.

[0022] Figure 2 This is a schematic diagram of the plan layout of the underground thermal reservoir well group and the target thermal reservoir area of ​​the present invention.

[0023] Figure 3 This is a schematic diagram of the wellbore structure of the layered injection-production well of the present invention.

[0024] Figure 4This is a flowchart illustrating the hierarchical injection-production optimization control method based on thermal front prediction of the present invention.

[0025] In the diagram: 1. Multi-source heat access module; 101. Wind power surplus energy interface; 102. Photovoltaic surplus energy interface; 103. Off-peak electricity interface; 104. Industrial waste heat interface; 2. Heat conversion module; 201. Electric heater; 202. Heat pump; 203. Industrial waste heat exchanger; 204. Mixing device; 3. Underground thermal storage well group; 301. Thermal storage injection well; 302. Thermal storage production well; 303. Low temperature reinjection well; 304. Monitoring well; 305. Boundary pressure regulating well; 4. Layered injection... 401. Injection-Production Section; 402. Packer; 403. Controllable Valve; 5. Heat Migration Monitoring Module; 6. Boundary Pressure Regulation Module; 7. Storage and Utilization Coordinated Control Module; 701. Thermal Front Prediction Unit; 702. Thermal Inrush Risk Assessment Unit; 703. Flow Redistribution Unit; 704. Boundary Pressure Regulation Linkage Unit; 8. Thermal Energy Utilization Module; 801. User Terminal Heat Exchanger; 802. User Terminal; 9. Deep Thermal Reservoir; 10. Target Thermal Reservoir Area; 11. Heat Migration Boundary. Detailed Implementation

[0026] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. 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 are within the scope of protection of the present invention.

[0027] This invention provides, for example Figures 1-4 The above describes a layered injection-production optimization control system and method for deep underground thermal energy storage, such as... Figure 1 As shown, the present invention provides a layered injection and production optimization control system for deep underground thermal energy storage based on thermal front prediction, including a multi-source heat access module 1, a heat conversion module 2, an underground thermal storage well group 3, a layered injection and production module 4, a heat migration monitoring module 5, a boundary pressure regulation module 6, a storage and utilization coordinated control module 7, and a thermal energy utilization module 8.

[0028] The multi-source heat access module 1 is used to receive at least one type of energy from wind power surplus, photovoltaic surplus, off-peak electricity, and industrial waste heat. The multi-source heat access module 1 may include at least one type of wind power surplus interface 101, photovoltaic surplus interface 102, off-peak electricity interface 103, and industrial waste heat interface 104.

[0029] The heat conversion module 2 is connected to the multi-source heat access module 1 and is used to convert the surplus wind power, surplus photovoltaic power, or off-peak electricity into heat energy, and transfer the industrial waste heat to the injection fluid, so that the injection fluid reaches the preset heat storage injection temperature. The heat conversion module 2 may include at least one of the following: an electric heater 201, a heat pump 202, an industrial waste heat exchanger 203, and a temperature mixing device 204.

[0030] like Figure 1 and Figure 2 As shown, the underground thermal reservoir well group 3 includes a thermal reservoir injection well 301, a thermal reservoir production well 302, a cryogenic reinjection well 303, a monitoring well 304, and a boundary pressure regulating well 305. The thermal reservoir injection well 301 is used to inject high-temperature fluid into the deep thermal reservoir 9 during the thermal storage stage; the thermal reservoir production well 302 is used to extract high-temperature fluid from the target thermal reservoir area 10 during the thermal extraction stage; the cryogenic reinjection well 303 is used to receive cryogenic return water after heat exchange in the thermal energy utilization module 8, specifically by using the 801 user terminal heat exchanger in the thermal energy utilization module 8 for heat exchange, and reinjecting the cryogenic return water back to the reservoir area far from the target thermal reservoir area 10 or located downstream of the target thermal reservoir area 10.

[0031] Monitoring well 304 is used to collect temperature, pressure, conductivity, and tracer response data within and at the boundary of the target geothermal reservoir 10. Monitoring well 304 may include an intermediate monitoring well located between the reservoir injection well 301 and the reservoir production well 302, and a boundary monitoring well located at the boundary of the target geothermal reservoir 10. Temperature sensors, pressure sensors, conductivity sensors, and / or tracer detectors may be installed within monitoring well 304.

[0032] The boundary pressure regulating well 305 is set outside or near the boundary of the target thermal reservoir 10. It is used to adjust the pressure distribution at the boundary of the target thermal reservoir 10 by injection, production or shutdown, so as to change the direction of heat migration or restrict the migration of heat to the outside of the target thermal reservoir 10.

[0033] like Figure 3 As shown, the stratified injection-production module 4 includes multiple injection-production sections 401 disposed within the thermal reservoir injection well 301 and / or the thermal reservoir production well 302, packers 402 disposed between adjacent injection-production sections 401, and controllable valves 403 corresponding to each injection-production section 401. The multiple injection-production sections 401 are spaced apart along the well depth direction and correspond to reservoir sections at different depths. The packers 402 are used for hydraulic isolation of adjacent reservoir sections, and the controllable valves 403 are used to independently adjust the injection flow rate and / or production flow rate of the corresponding injection-production section 401.

[0034] The injection-production section 401 can be connected to the corresponding reservoir section through at least one of the following methods: screen pipe, perforation, open hole completion, or fracturing. For porous aquifers, the injection-production section 401 can be a screen pipe completion section; for cased cemented thermal reservoirs, the injection-production section 401 can be a perforated completion section; for fractured thermal reservoirs, the injection-production section 401 can be an open hole completion section or a fracturing connection section.

[0035] The heat migration monitoring module 5 is used to acquire the temperature response, pressure response, conductivity change, and tracer response of each injection-production segment 401 corresponding to the reservoir segment. Among them, the temperature response is used to characterize the propagation state of heat within the corresponding reservoir segment; the pressure response is used to characterize the injection-production pressure change and fluid connectivity state of the corresponding reservoir segment; and the conductivity change and tracer response are used to help determine the connectivity and fluid migration velocity between different reservoir segments.

[0036] The storage and utilization coordinated control module 7 is connected to the heat conversion module 2, the stratified injection and production module 4, the heat migration monitoring module 5, the boundary pressure regulation module 6, and the thermal energy utilization module 8, respectively. The storage and utilization coordinated control module 7 includes a thermal front prediction unit 701, a thermal inrush risk assessment unit 702, a flow redistribution unit 703, and a boundary pressure regulation linkage unit 704.

[0037] The thermal front prediction unit 701 is used to determine the location, heat migration velocity, and predicted arrival time of the thermal front in each injection-production segment 401 based on the temperature response of each segment. The thermal inrush risk assessment unit 702 is used to determine the thermal inrush risk index of each injection-production segment based on the heat migration velocity, predicted arrival time of the thermal front, pressure response, and tracer response. The flow redistribution unit 703 is used to reduce the opening of the controllable valve 403 corresponding to a certain injection-production segment when there is a risk of premature thermal front breakthrough in that segment, and to distribute the reduced injection flow and / or production flow to other low-risk injection-production segments. The boundary pressure regulation linkage unit 704 is used to control the boundary pressure regulating well 305 to perform injection, production, or shutdown operations when there is a risk of heat escape at the boundary of the target thermal reservoir 10.

[0038] Example of thermal front prediction: In this embodiment, the thermal front prediction unit 701 determines the thermal front position based on the temperature response of each injection-production segment 401. For the i-th injection-production segment, its thermal front position X i (t) can be determined according to the following formula: ; In the formula, X i (t) represents the position of the thermal front of the i-th injection-production segment at time t; T i (x,t) represents the temperature of the i-th injection-production segment at location x and time t; T 0,i T represents the initial temperature of the reservoir segment corresponding to the i-th injection-production segment;inj η is the injection fluid temperature; η is the thermal front determination coefficient, which can be set according to reservoir properties, injection temperature and monitoring accuracy, preferably 0.3 to 0.7.

[0039] Determine the location X of the thermal front. i After (t), the thermal front prediction unit 701 determines the heat transport velocity v of the i-th injection-production segment based on the changes in the thermal front position at adjacent times. i (t), which satisfies: ; In the formula, Δt is the time interval between two adjacent monitoring sessions.

[0040] The thermal leading edge prediction unit 701 further predicts the thermal leading edge position X based on the thermal leading edge position X. i (t), heat transport velocity v i (t) and the location of the corresponding thermal reservoir production well 302 or boundary monitoring well are used to determine the predicted arrival time τ of the thermal front of the i-th injection-production interval. i (t), which satisfies: ; In the formula, L i v is the distance from the thermal front location of the i-th injection-production interval to the thermal reservoir production well 302 or the boundary monitoring well; min This is a preset minimum heat transfer rate to avoid distortion of prediction results when the heat transfer rate is too low or zero.

[0041] When τ i The smaller (t) is, the closer the thermal front of the injection-production section is to the thermal reservoir production well 302 or the boundary monitoring well, and the higher the risk of premature thermal front breakthrough or boundary escape in the injection-production section.

[0042] Example of thermal surge risk assessment: The thermal inrush risk assessment unit 702 is used to determine the thermal inrush risk index for each injection-production segment based on the temperature change rate, heat transport velocity, tracer response time, pressure response amplitude, and predicted arrival time of the thermal front. The thermal inrush risk index characterizes the degree of risk of thermal inrush in the dominant channel or premature breakthrough of the thermal front in the corresponding injection-production segment.

[0043] In a preferred embodiment, the thermal inrush risk index R of the i-th injection-production segment i It can be determined according to the following formula: ; In the formula, The normalized rate of temperature change This represents the normalized heat transport velocity. These are the normalized tracer response parameters. These are the normalized pressure response parameters. The normalized thermal front prediction arrival time parameters are w1, w2, w3, w4 and w5, which are weighting coefficients and satisfy: w1+w2+w3+w4+w5=1.

[0044] The greater the rate of temperature change, the faster the temperature response of the corresponding reservoir segment. The larger the value, the greater the heat transport velocity, indicating a faster thermal front advance. The larger the value, the shorter the tracer response time, indicating stronger connectivity of the corresponding reservoir segment. The larger the value, the smaller the pressure response amplitude under the same injection or production flow rate, indicating that the corresponding reservoir section is more likely to have high-permeability channels or dominant fractures. The larger the value, the shorter the predicted arrival time of the thermal front. The larger.

[0045] Therefore, the thermal surge risk index R i The larger the value, the higher the risk of abnormal thermal advance and premature breakthrough of the thermal front in the corresponding injection-production segment.

[0046] In another implementation, the thermal surge risk index R i Alternatively, instead of using the weighted summation method described above, the method can be determined through table lookup, hierarchical scoring, fuzzy evaluation, or machine learning regression model. As long as the thermal inrush risk of each injection-production segment is evaluated based on temperature response, pressure response, tracer response, and predicted arrival time of the thermal front, it can be used in the control process of this invention.

[0047] Hierarchical traffic redistribution example: The flow redistribution unit 703 is used to predict the arrival time τ based on the thermal inrush risk index Ri and the thermal front. i (t) Differentiated control of controllable valves 403 in each injection and production layer 401.

[0048] When the thermal inrush risk index R of a certain injection-production section i Exceeding the preset risk threshold R th Or the predicted arrival time τ of the thermal front of the injection-production section. i (t) is less than the preset safety time τ safe At that time, the storage and utilization collaborative control module 7 determines that there is a risk of abnormal heat advance or premature breakthrough of the thermal front in the injection and production section, and reduces the opening of the controllable valve 403 corresponding to the injection and production section to reduce the injection flow rate and / or production flow rate of the injection and production section.

[0049] Preferably, the higher the thermal surge risk index Ri, or the higher the predicted arrival time τ of the thermal front. iThe shorter the (t) value, the greater the reduction in the opening degree of the controllable valve 403. This method can suppress the rapid propagation of heat in high-permeability layers or dominant fracture channels.

[0050] After reducing the flow rate in high-risk injection-production segments, the flow rate redistribution unit 703 allocates the reduced flow rate to other injection-production segments that can handle the flow rate. The set S of injection-production segments that can handle the flow rate includes: injection-production segments whose thermal surge risk index is lower than a preset low-risk threshold, whose pressure response is within a preset pressure range, and whose predicted thermal front arrival time is greater than a preset safe time.

[0051] In a preferred embodiment, the flow rate ΔQ allocated to the j-th injection-production segment is... j satisfy: ; In the formula, Reduced flow rate for high-risk injection-production segments To allocate the flow rate to the j-th injection-production segment, R j G is the normalized thermal surge risk index for the j-th injection-production segment. j Let be the pressure bearing capacity coefficient of the j-th injection-production segment, and S be the set of injection-production segments that can withstand the flow rate.

[0052] Pressure bearing capacity factor G j It can be determined according to the following formula: ; In the formula, P j Let P be the pressure of the reservoir section corresponding to the j-th injection-production section. max To preset the upper pressure limit, P min This is the preset lower pressure limit. G j The larger the value, the greater the pressure safety margin of the injection-production segment, and the more suitable it is to accept the flow transferred from high-risk injection-production segments.

[0053] In this way, the present invention does not only perform a shutdown operation on high-risk injection-production sections, but also distributes the reduced flow rate of high-risk injection-production sections to other injection-production sections with lower thermal inrush risk and higher pressure bearing capacity, thereby improving the uniformity of heat distribution within the target thermal reservoir 10 and reducing the risk of premature breakthrough of the thermal front into the thermal reservoir production well 302.

[0054] Example of boundary voltage regulation linkage: The boundary pressure regulating linkage unit 704 is used to control the boundary pressure regulating module 6 to adjust the pressure gradient at the boundary of the target thermal reservoir 10 through the boundary pressure regulating well 305 when there is a risk of heat leakage at the boundary of the target thermal reservoir 10.

[0055] The risk of heat escape can be determined based on the temperature rise rate of the boundary monitoring well, the direction of heat migration, and the distance from the thermal front to the boundary of the target thermal reservoir 10. Specifically, when the temperature rise rate of the boundary monitoring well exceeds a preset temperature rise rate threshold, or when the direction of heat migration points to the outside of the target thermal reservoir 10, the boundary pressure regulating linkage unit 704 controls the boundary pressure regulating well 305 to perform injection, production, or shutdown operations to change the pressure gradient at the boundary of the target thermal reservoir 10, so that the thermal front or heat migration boundary 11 remains within the target thermal reservoir 10.

[0056] In one implementation, when heat migrates along the natural groundwater flow towards the outer side of the target geothermal reservoir 10, the boundary pressure regulating well 305 located downstream of the heat escape direction can be controlled to produce heat, thereby changing the local pressure field; alternatively, the boundary pressure regulating well 305 located outside the target geothermal reservoir 10 can be controlled to inject heat, thereby forming a pressure gradient that inhibits heat escape. The specific operating state of the boundary pressure regulating well 305 can be determined based on the temperature and pressure responses of the boundary monitoring wells and the boundary position of the target geothermal reservoir 10.

[0057] Control process example: like Figure 4 As shown, the hierarchical injection-mapping optimization control method based on thermal front prediction of the present invention may include the following steps: (1) Obtain the availability status of multi-source heat, user-end heat load demand, underground heat storage status and reservoir pressure status.

[0058] (2) Obtain the temperature response, pressure response, conductivity change and tracer response of the corresponding reservoir segment for each injection and production segment.

[0059] (3) Determine the position of the thermal front based on the temperature response of each injection and production layer, and determine the heat transport rate based on the change of the thermal front position at adjacent times.

[0060] (4) Determine the predicted arrival time of the thermal front in each injection-production section based on the location of the thermal front, the heat migration rate, and the location of the corresponding thermal reservoir production well or boundary monitoring well.

[0061] (5) Determine the thermal inrush risk index for each injection-production segment based on the heat transport rate, predicted arrival time of the thermal front, pressure response, and tracer response.

[0062] (6) Determine whether there is a high-risk injection-production segment where the thermal surge risk index exceeds the preset risk threshold or the predicted arrival time of the thermal front is less than the preset safe time; if so, proceed to step (7); if not, maintain the current stratified injection-production status or make routine adjustments according to the thermal storage demand, thermal extraction demand and pressure balance demand.

[0063] (7) Reduce the opening of the controllable valve 403 corresponding to the high-risk injection-production segment to reduce the injection flow rate and / or production flow rate of the injection-production segment.

[0064] (8) Allocate the reduced flow rate to other injection and production layers with lower thermal surge risk, pressure response within the preset pressure range, and predicted thermal front arrival time greater than the preset safety time.

[0065] (9) Determine whether there is a risk of heat leakage at the boundary of the target thermal reservoir 10; if so, adjust the pressure gradient at the boundary of the target thermal reservoir 10 through the boundary pressure regulating well 305; if not, continue to perform thermal front prediction and stratified injection and production optimization control.

[0066] (10) Switch between heat storage mode, heat extraction mode, pressure balance mode and boundary pressure regulation mode according to the user's heat load demand, underground heat storage status and multi-source heat availability status.

[0067] Example of thermal storage mode: In the thermal storage mode, when the available heat from multiple sources is greater than the real-time heat load demand of the user and the underground thermal storage status is lower than the preset thermal storage upper limit, the storage and utilization coordination control module 7 controls the heat conversion module 2 to heat the injected fluid to the preset thermal storage injection temperature, and injects it into the deep thermal storage layer 9 in layers through the thermal storage injection well 301.

[0068] During the stratified injection process, the heat migration monitoring module 5 continuously acquires the temperature response, pressure response, conductivity changes, and tracer response of the corresponding reservoir segment in each injection-production segment 401. The reservoir-use collaborative control module 7 determines the thermal front location, heat migration rate, predicted arrival time of the thermal front, and thermal inrush risk index of each injection-production segment based on the above monitoring data.

[0069] When the thermal inrush risk index of a certain injection-production segment exceeds the preset risk threshold, or when the predicted arrival time of the thermal front of the injection-production segment is less than the preset safe time, the storage and utilization collaborative control module 7 reduces the opening of the controllable valve 403 corresponding to the injection-production segment, reduces the injection flow of the injection-production segment, and allocates the reduced injection flow to other injection-production segments with lower thermal inrush risk, pressure response within the preset pressure range, and predicted arrival time of the thermal front greater than the preset safe time.

[0070] By using the above control methods, the heat concentration in high-permeability layers or dominant fracture channels can be reduced, allowing the injected heat to spread more evenly within the target thermal reservoir 10 and improving the volume utilization rate of the target thermal reservoir 10.

[0071] Example of heat collection mode: In the heat extraction mode, when the user's heat load demand is greater than the real-time availability of multi-source heat and the underground heat storage status is higher than the preset lower limit of heat extraction, the heat storage production well 302 extracts high-temperature fluid from the target heat storage area 10 layers, and after supplying heat to the user end 802 through the heat energy utilization module 8, the cooled return water is reinjected into the deep heat storage layer 9 through the low temperature reinjection well 303.

[0072] During the stratified production process, the storage and utilization coordinated control module 7 adjusts the opening degree of the controllable valves 403 corresponding to each injection and production segment of the thermal reservoir production well 302 based on the production temperature, production flow rate, pressure response, and thermal inrush risk index of each injection and production segment. For injection and production segments with stable production temperature, pressure response within the preset range, and low thermal inrush risk, the production flow rate can be increased; for injection and production segments with rapid production temperature drop, abnormal pressure response, or thermal front prediction arrival time less than the preset safe time, the production flow rate can be reduced or the corresponding controllable valve 403 can be temporarily closed.

[0073] By adopting the above methods, the excessive extraction of fluid from a certain advantageous channel segment in the thermal reservoir production well 302 can be avoided, the risk of premature breakthrough of the thermal front or cold end reinjection interference can be reduced, and the stability of the thermal extraction process can be improved.

[0074] Pressure balancing example: In pressure balance mode, the storage and utilization collaborative control module 7 acquires the pressure parameters of the thermal reservoir injection well 301, thermal reservoir production well 302, low temperature reinjection well 303, boundary pressure regulating well 305, and the corresponding reservoir sections of each injection and production section.

[0075] When the pressure in the deep thermal reservoir 9 exceeds the preset upper pressure limit, the reservoir-use coordination control module 7 reduces the total injection rate of the thermal reservoir injection well 301, or increases the production rate of the thermal reservoir production well 302 or the boundary pressure regulating well 305. When the pressure in the deep thermal reservoir 9 falls below the preset lower pressure limit, the reservoir-use coordination control module 7 reduces the production rate, or increases the injection rate of the cryogenic reinjection well 303 or the boundary pressure regulating well 305, so that the pressure in the deep thermal reservoir 9 remains within the preset pressure range.

[0076] Pressure balance control can be executed simultaneously with thermal front prediction control. When a certain injection-production segment has a low risk of thermal inrush but its pressure is close to the preset pressure limit, the flow redistribution unit 703 restricts the continued allocation of flow to that injection-production segment; when a certain injection-production segment has a low risk of thermal inrush and a large pressure safety margin, that injection-production segment is given priority as the target segment for receiving flow.

[0077] Example execution process: In an exemplary operation, the thermal reservoir injection well 301 includes a first injection-production section, a second injection-production section, and a third injection-production section. The heat migration monitoring module 5 detects that the temperature change rate of the first injection-production section is large, the tracer response time is short, and the predicted arrival time of the thermal front is less than a preset safe time. Based on this, the reservoir-utilization coordinated control module 7 determines that the thermal inrush risk index of the first injection-production section is higher than a preset risk threshold.

[0078] Subsequently, the flow redistribution unit 703 reduces the opening of the controllable valve 403 corresponding to the first injection-production stage, thereby reducing the injection flow rate of the first injection-production stage. Simultaneously, the storage-use coordinated control module 7 determines that the thermal inrush risk index of the second and third injection-production stages is below the preset low-risk threshold, and that the pressure response is within the preset pressure range. Therefore, it distributes the reduced injection flow rate of the first injection-production stage to the second and third injection-production stages according to the pressure bearing capacity coefficient and the risk index.

[0079] After the above adjustments, the heat propagation rate in the first injection-production section is reduced, the heat expansion in the second and third injection-production sections is enhanced, and the heat distribution in the target thermal reservoir 10 is more uniform, thereby reducing the risk of premature breakthrough of the thermal front into the thermal reservoir production well 302.

[0080] In the above embodiments, the thresholds, weighting coefficients, decision coefficients, preset pressure ranges, and safety times can be set or modified based on the reservoir properties, well spacing, injection-production regime, user heat load requirements, and historical operating data of the target thermal reservoir 10. Those skilled in the art can adjust the specific parameters according to actual engineering conditions.

[0081] Finally, it should be noted that the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A control method for a layered injection-production optimization control system for deep underground thermal energy storage, characterized in that: include: A multi-source heat access module is used to receive at least one type of energy from wind power surplus energy, photovoltaic surplus energy, off-peak electricity, and industrial waste heat. A heat conversion module is used to convert the energy into heat for the injected fluid; The underground thermal reservoir well group includes thermal reservoir injection wells, thermal reservoir production wells, cryogenic reinjection wells, monitoring wells, and boundary pressure regulating wells; The stratified injection and production module includes multiple injection and production sections installed in the thermal reservoir injection well and / or thermal reservoir production well, packers installed between adjacent injection and production sections, and controllable valves corresponding to each injection and production section; The heat transport monitoring module is used to acquire the temperature response, pressure response, conductivity changes, and tracer response of each injection and production layer. The storage and utilization coordinated control module includes a thermal front prediction unit, a thermal inrush risk assessment unit, and a flow redistribution unit; The boundary pressure regulating module is used to regulate the pressure gradient at the boundary of the target thermal reservoir by means of a boundary pressure regulating well when there is a risk of heat overflow at the boundary of the target thermal reservoir. The specific steps of this method are as follows: S1, obtain the temperature response, pressure response, conductivity change and tracer response of the corresponding reservoir segment for each injection and production segment; S2, determine the position of the thermal front based on the temperature response of each injection and production section, and determine the heat transport rate based on the change of the thermal front position at adjacent times; S3. Based on the location of the thermal front, the heat migration rate, and the location of the corresponding thermal reservoir production well or boundary monitoring well in each injection-production section, determine the predicted arrival time of the thermal front in each injection-production section. S4. Based on the heat transport rate, predicted arrival time of the thermal front, pressure response, and tracer response of each injection-production segment, determine the thermal inrush risk index of each injection-production segment. S5. When the thermal inrush risk index of a certain injection-production segment exceeds the preset risk threshold, or the predicted arrival time of the thermal front of the injection-production segment is less than the preset safe time, the opening of the controllable valve corresponding to the injection-production segment is reduced to reduce the injection flow rate and / or production flow rate of the injection-production segment. S6, the reduced injection flow and / or production flow will be redistributed to other injection and production segments where the thermal surge risk index is lower than the preset low-risk threshold, the pressure response is within the preset pressure range, and the predicted arrival time of the thermal front is greater than the preset safe time. S7. When there is a risk of heat leakage at the boundary of the target geothermal reservoir, the pressure gradient at the boundary of the target geothermal reservoir is adjusted by the boundary pressure regulating well to limit the migration of heat to the outside of the target geothermal reservoir.

2. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: The thermal front prediction unit is used to determine the thermal front location, heat migration velocity, and predicted arrival time of each injection-production segment based on the temperature response of each injection-production segment. The thermal inrush risk assessment unit is used to determine the thermal inrush risk index of each injection-production segment based on the heat transport rate, predicted arrival time of the thermal front, pressure response, and tracer response of each injection-production segment. The flow redistribution unit is used to reduce the opening of the controllable valve corresponding to a certain injection-production segment when the thermal inrush risk index of a certain injection-production segment exceeds a preset risk threshold, or when the predicted arrival time of the thermal front of the injection-production segment is less than a preset safety time, and to distribute the reduced injection flow and / or production flow to other injection-production segments with lower thermal inrush risk index and pressure response that meet preset conditions.

3. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 2, characterized in that: The monitoring wells include intermediate monitoring wells located between the geothermal reservoir injection well and the geothermal reservoir production well, and boundary monitoring wells located at the boundary of the target geothermal reservoir area; the monitoring wells are equipped with temperature sensors, pressure sensors, conductivity sensors and / or tracer detectors.

4. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 3, characterized in that: The injection-production sections are spaced apart along the well depth direction, and adjacent injection-production sections are hydraulically isolated by packers; the injection-production sections are connected to the corresponding reservoir sections by at least one of the following methods: screen pipe, perforation, open hole completion, or fracturing; the controllable valve is used to independently adjust the injection flow rate and / or production flow rate of the corresponding injection-production section.

5. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: The temperature response in S1 is used to characterize the thermal propulsion state within each reservoir segment, the pressure response is used to characterize the injection-production pressure changes and fluid connectivity state within each reservoir segment, and the conductivity changes and tracer response are used to assist in determining the connectivity and fluid migration velocity between different reservoir segments.

6. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: The calculation formula in S2 is: Assume the location of the thermal front of the i-th injection-production segment is X. i( t); X i (t) satisfies the following formula: In the formula, T i (x,t) represents the temperature of the i-th injection-sampling segment at location x and time t, where T is the temperature of the i-th injection-sampling segment. 0,i Let T be the initial temperature of the reservoir segment corresponding to the i-th injection-production segment. inj The temperature of the injected fluid is η, and the thermal front determination coefficient is η, which ranges from 0.3 to 0.

7. The heat transport velocity v of the i-th injection-production segment is determined based on the change in the position of the thermal front at adjacent time points. i (t), satisfying: In the formula, Δt is the time interval between two adjacent monitoring sessions.

7. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: The formula for calculating the predicted arrival time of the thermal front of each injection-production segment in S3 is as follows: The predicted arrival time τ of the thermal front of the i-th injection-production segment i (t) satisfies: In the formula, L i X is the distance from the thermal front location of the i-th injection-production interval to the production well or boundary monitoring well of the thermal reservoir. i (t) represents the thermal leading edge position of the i-th injection-sampling segment at time t, v i (t) represents the heat transfer velocity of the i-th injection-production segment at time t, v min This is the preset minimum heat transfer rate.

8. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: In S4, the thermal inrush risk index of each injection-production segment is determined based on the temperature change rate, heat transport velocity, tracer response time, pressure response amplitude, and predicted arrival time of the thermal front.

9. The control method for a layered injection-production optimization control system for deep underground thermal energy storage according to claim 1, characterized in that: The flow rate ΔQ allocated to the j-th injection-production segment in S6 j satisfy: ,in, Reduced flow rate for high-risk injection-production segments To allocate the flow rate to the j-th injection-production segment, R j G is the normalized thermal surge risk index for the j-th injection-production segment. j Let be the pressure bearing capacity coefficient of the j-th injection-production segment, and S be the set of injection-production segments that can withstand the flow rate.

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