1192 results about "Injection well" patented technology

A method of constructing an injection well for a geothermal energy system comprising determining a fracture area of an injection well with a curved wellbore by inputting the curved wellbore path, a set of formation properties, and a fracturing operation, into a fracturing model. The curved wellbore path can promote fracture interference between fracture stresses extending from the injection wellbore. A production model can determine an economic value of the production fluids produced from at least one production well by determining a contact time for the injection fluids to traverse the formation. A design process can iterate the curved wellbore path of the injection well to produce a production fluid with an economic value above a threshold value.

A method of constructing an injection well for a geothermal energy system comprising determining a fracture area of an injection well with a curved wellbore by inputting the curved wellbore path, a set of formation properties, and a fracturing operation, into a fracturing model. The curved wellbore path can promote fracture interference between fracture stresses extending from the injection wellbore. A production model can determine an economic value of the production fluids produced from at least one production well by determining a contact time for the injection fluids to traverse the formation. A design process can iterate the curved wellbore path of the injection well to produce a production fluid with an economic value above a threshold value.

The invention provides an intelligent pressure management system, method and terminal for geological sequestration of carbon dioxide, and the system comprises the steps: collecting the pressure data of the interior and peripheral key positions of each geological reservoir in real time through a pressure monitoring subsystem, and then carrying out the data preprocessing and feature extraction through a data processing and analysis subsystem; and predicting the reservoir pressure change trend in a specific time period in the future. If the predicted reservoir pressure change trend pressure is too high, high-risk related information is transmitted to the intelligent regulation and control subsystem, and the intelligent regulation and control subsystem regulates and controls the reservoir pressure by regulating the flow of a carbon dioxide injection well and a production well or starting a pressure release device according to a preset strategy and dynamically regulates a regulation and control mode according to pressure data. Meanwhile, the communication and monitoring subsystem transmits system operation data to a remote monitoring terminal in real time, so that real-time monitoring is facilitated. Real-time, accurate and automatic regulation and control of the pressure of the geological reservoir are achieved, the stability and safety of the geological reservoir in the carbon dioxide injection process are guaranteed, the geological storage effect of the carbon dioxide is improved, and various negative effects caused by too high pressure are avoided.

The invention relates to the technical field of underground casing monitoring, and discloses an injection well immovable string casing damage rapid detection device based on efficient testing and adjusting, the injection well immovable string casing damage rapid detection device comprises a testing vehicle, a top sheave and a casing, one side in the testing vehicle is provided with a ground control system, and the other side in the testing vehicle is provided with a double-roller winch; a cable is wound on the outer side of the double-roller winch, an electromagnetic flaw detection testing instrument is installed at one end of the cable, an oil pipe is arranged in the casing pipe in a sleeved mode, a plurality of packers are sequentially installed between the outer side of the oil pipe and the inner wall of the casing pipe from top to bottom, and a plurality of water distributors are sequentially distributed in the oil pipe from top to bottom. A water injection well efficient testing and adjusting technology and an electromagnetic flaw detection technology are combined, an electromagnetic flaw detection testing instrument is tripped in through a testing vehicle, cable power supply and communication are tested, a ground control system carries out signal acquisition and processing on the electromagnetic flaw detection instrument, and rapid detection of casing damage of a water injection well immovable string is achieved.

The invention discloses an automatic measuring and adjusting method and system for flow of an intelligent separate injection well, and relates to the technical field of layered flow allocation. The method comprises the steps that the residual oil saturation of each layer in an oil reservoir is calculated based on historical and real-time data of the oil reservoir, and the initial water injection rate is distributed according to the residual oil saturation of different layers; and predicting an oil-water output ratio by using a water drive curve model according to the distributed initial water injection rate, and dynamically adjusting a water injection strategy in combination with actual production data for implementation. According to the method, the seepage rate and the pressure distribution are calculated by combining the physical constraint model and the Darcy law, so that the scientificity of regulation and control of the water injection rate of each layer is improved, and pressure balance and seepage path optimization of each layer in the oil reservoir development process are ensured; the real-time water injection strategy is optimized by dynamically predicting and adjusting the oil-water output ratio through the water drive curve model, the water injection rate is dynamically adjusted through the nonlinear prediction control model, it is ensured that the system can still operate stably in the complex dynamic environment, and the water injection efficiency and the recovery efficiency are remarkably improved.

The invention discloses an injection-production well connectivity modeling and yield prediction method and device, and relates to the technical field of oil reservoir engineering. Comprising the following steps: on the basis of preprocessed time sequence injection-production data, constructing a spatial topological graph structure according to screening conditions; constructing a yield prediction model based on the LSTM-GAT network, taking the spatial topological graph structure as the input of a graph attention mechanism, extracting the time dependence characteristics of the gas injection well and the production well by using the long short-term memory network, and extracting the spatial dependence relationship of the gas injection well and the production well by using the graph attention mechanism so as to output the predicted yield of the production well at the future moment; constructing a fitness function, and introducing a whale optimization algorithm to perform global optimization on the injection-production parameters to obtain an optimal injection-production parameter combination; and outputting the optimal injection-production parameter combination. The problems that when an existing method is used for determining the inter-well communication relation, a large amount of geological data and experiment cost are needed, the analysis process is complex, consumed time is long, and accurate optimization of injection-production parameters is difficult to achieve are solved.

A water injection regulation system for water injection well has a float limiting device (A) provided at a wellhead configured to release and capture a float; a ground water delivery device (B) having an outlet in communication with the float limiting device (A), and is configured to inject water into well through the float limiting device (A); and a plurality of downhole water distribution devices, each arranged in a target layer and outside a sidewall of a water-injection string, and configured to monitor production data of the target layer. The float is configured to receive a water distribution instruction to regulate water distribution of each downhole water distribution device, enter the water-injection string (11) with water flow, and float upwards to the wellhead after completing data collection. Each downhole water distribution device is configured to exchange the production data with the water distribution instruction carried by the float.

The invention relates to a deep coal underground gasification method which comprises the following steps: drilling a plurality of gasification wells in a land parcel, sequentially arranging the plurality of gasification wells into three rows from the edge of the land parcel, and fracturing a bottommost coal seam; the first row of gasification wells are injection wells, the second row of gasification wells are production wells, and the bottommost coal seam between the first row of gasification wells and the second row of gasification wells is gasified; when the gasification high-temperature area of the gasified coal seam is expanded to the front edge of the gas cooling area, the second gas gasification well is closed, the third gas gasification well serves as a production well, and the coal seam continues to be gasified; meanwhile, a fourth row of gasification wells are drilled; after the coal bed is gasified, the bottommost coal bed between the second row of gasification wells and the third row of gasification wells is gasified, and so on, the bottommost coal bed between all the rows of gasification wells is gasified; meanwhile, cement paste is injected into the first exhaust gasification well to fill the gasified goaf; and so on, filling the goaf between each row of gasification wells; sequentially gasifying and refilling each coal seam from bottom to top according to the method.

Disclosed herein are systems and methods of gas sequestration of carbon dioxide from a fossil-fueled hydrogen production plant. The method includes producing at least hydrogen and carbon dioxide above ground from a fossil-fueled hydrogen production plant, injecting at least a portion of the hydrogen and carbon dioxide produced from the fossil-fueled hydrogen production plant into a geological hydrogen storage unit and a geological carbon dioxide storage unit, respectively, wherein the portion of the carbon dioxide is injected concurrently with the portion of the hydrogen. The injection of the portion of carbon dioxide and hydrogen underground are performed through carbon dioxide injection well(s) and hydrogen injection well(s), respectively, wherein a hydrogen injection wellhead(s) and a carbon dioxide injection wellhead(s) are located on a multi-well pad proximate the fossil-fueled hydrogen production plant.

The invention discloses a carbon dioxide monitoring method. The method comprises the following steps: arranging a temperature sensor, a strain gauge type pressure sensor, a Ca < 2 + > concentration sensor and a tracer agent concentration sensor; a tracer agent is injected into the injection well to monitor the moving track and the leakage condition of CO2; when the formation temperature rise exceeds a threshold A, the formation pressure change exceeds a threshold B, the Ca2 + concentration exceeds a threshold C, and the tracer concentration is below a threshold D, when at least three of the conditions are achieved, or only two of the conditions are achieved, and at least one of the conditions exceeds 20-30% of the respective threshold, the tracer concentration is determined to be less than the threshold D. And if not, inputting the stratum parameters and the tracer agent characteristic data into a pre-trained machine learning model, calculating the addition amount of the additive, and injecting the additive into an injection well. The invention further claims to protect the carbon dioxide monitoring device. The performance of the tracer agent in the CO2 monitoring process can be intelligently evaluated and maintained, and the moving track and the leakage condition of CO2 are accurately monitored.

Methods and systems for geothermal energy production wherein multiple horizontal or vertical wells may be used to pass fluids through the Earth from an injector well to a producer well through induced cracks, splits, fractures, conduits, or channels in the rock. Such methods and systems may include controlling tensile-split conduits in a subterranean geothermal formation by providing an injection well, providing a production well, configuring the injection well for injection of a tensile-splitting fluid into a production zone, configuring the production well to produce a heated fluid from the production zone, applying pressure to the production well, creating a plurality of tensile-split conduits, raising or lowering the pressure in the production well, establishing fluid communication between the injection well and the production well, and producing the heated fluid to the surface.

The invention discloses an integrated intelligent management and control method and system for underground water pumping and injection based on the Internet of Things, and the method comprises the steps: carrying out the geological investigation of a target region, constructing a three-dimensional geological model, and planning the layout of a pumping and injection well group and a sensor network according to the three-dimensional geological model; deploying a monitoring network and collecting data based on the layout scheme, and fusing a three-dimensional geologic model to construct a polluted site digital twinborn body; groundwater situation data are extracted through the digital twinborn body, a pollutant migration path and a water level dynamic state are predicted by using an LSTM model, and pollution scene simulation information corrected by geologic features is output; by taking the simulation information as input and coupling geological parameters as constraints, generating a pumping and injection well group cooperative control strategy set by adopting a BLMFO double-layer multi-objective optimization algorithm; and finally, a control instruction is executed, the real-time situation is monitored in the repairing process, strategy change suggestions including the flow adjustment amplitude, the agent optimization scheme and equipment operation parameter correction are judged and pushed, the repairing efficiency is improved, and the method adapts to the complex geological environment.

Methods and systems for geothermal energy production wherein multiple horizontal or vertical wells may be used to pass fluids through the Earth from an injector well to a producer well through induced cracks, splits, fractures, conduits, or channels in the rock. Such methods and systems may include controlling tensile-split conduits in a subterranean geothermal formation by providing an injection well, providing a production well, configuring the injection well for injection of a tensile-splitting fluid into a production zone, configuring the production well to produce a heated fluid from the production zone, applying pressure to the production well, creating a plurality of tensile-split conduits, raising or lowering the pressure in the production well, establishing fluid communication between the injection well and the production well, and producing the heated fluid to the surface.

The invention relates to the technical field of oil-gas field development and geothermal energy utilization. The invention provides an underground high-temperature composite fluid heating system, which comprises a crude oil separation device, a catalysis module, a high-temperature fluid generation module, an injection well pattern module, a target reservoir and a production well, and is characterized in that the crude oil separation device is communicated with the catalysis module through a first gas inlet pipeline and a second gas inlet pipeline; a first gas outlet pipeline and a second gas outlet pipeline are communicated with a high-temperature fluid generation module, the high-temperature fluid generation module is communicated with an injection well pattern module through a third gas outlet pipeline, the injection well pattern module is communicated with a target reservoir, and the target reservoir supplies energy to the outside through a fourth gas outlet pipeline. And the production well conveys the energy-supplied gas to the heat energy recovery device through the first recovery pipeline. In this way, efficient and uniform heating of the underground reservoir is achieved, energy consumption is reduced while the energy recovery efficiency is improved, and the problems of low heat conduction efficiency and high energy consumption in deep oil gas and hot dry rock development are solved.

The invention provides a layout method and system for a carbon dioxide injection well and a pressure control well. The method comprises the steps that the reservoir thickness, porosity, permeability and formation pressure distribution data of a target reservoir are obtained; determining a deployment area according to the reservoir thickness, the porosity, the permeability and the formation pressure distribution data; based on a preset carbon dioxide injection well distance, carbon dioxide injection wells are arranged in the deployment area in an equilateral triangle grid mode; and a pressure control well is laid based on the center of the equilateral triangle grid, and the layout of the carbon dioxide injection well and the pressure control well is obtained. According to the technical scheme, the carbon dioxide injection well and the pressure control well are reasonably arranged, and the safety and economical efficiency of carbon dioxide geological sequestration are improved.

The invention belongs to the technical field of carbon dioxide capture and utilization and geological sequestration, and discloses a numerical simulation method for migration of CO2 in stratum.The method comprises the steps that an actual stratum complex geological model is constructed, and then a numerical simulation model is obtained; finely adjusting the numerical simulation model to limit fluid channeling and external substance and energy exchange, and ensuring rapid convergence of operation; the injection of CO2 in different layers is simulated, and the influence of the injection layers on the migration law is analyzed; cO2 injection at different injection speeds and temperatures is simulated to analyze the influence of the injection speeds and temperatures on the migration law; cO2 is simulated to be injected at different injection temperatures under the condition of consistent initial salt concentration, and the influence of dissolved salt on migration and dissolution rules is analyzed; the injection of CO2 at different positions of the reservoir is simulated, and the influence of the injection well position on CO2 storage is analyzed; and optimizing well position arrangement to obtain an optimal well pattern scheme. According to the method, the results of various influence factors are comprehensively analyzed, and then the migration rule of CO2 in the stratum is accurately obtained.

The invention provides a method for predicting and controlling water injection pressure rise of a water injection well, which comprises the following steps of: 1, collecting data of the water injection well according to different characteristics of each stage of water injection development of an oil reservoir; 2, according to the water injection well data, water injection well dynamic analysis is conducted; 3, establishing a water injection well water injection pressure rise prediction model according to oil reservoir factors by taking the water injection pressure as response and the factors influencing the water injection pressure rise as variables; and 4, according to the water injection well water injection pressure rise prediction model, a water injection well pressure rise control method is formulated. According to the water injection well water injection pressure rise prediction and control method, the prediction model is established, the water injection well pressure rise trend is predicted according to the model, a targeted control method is formulated, advanced early warning is achieved, effective water injection is guaranteed, and the purposes of more water injection and good water injection are achieved.

The invention discloses an oil reservoir water content prediction method based on a graph neural network and Transform, and belongs to the technical field of oil and gas field development, and the method comprises the following steps: S1, converting an oil reservoir injection-production model at each time point into a graph structure, and constructing a connection network from a water injection well to a production well; and S2, constructing a GNT proxy model in combination with the graph neural network and Transform, training the GNT proxy model, and predicting the water content of each production well. According to the constructed GNT proxy model, an oil reservoir injection-production structure is converted into graph data through a GCN module, the information transmission strength between nodes is dynamically adjusted through an edge feature enhanced message transmission mechanism, and inter-well communication features are accurately captured; and the multi-head self-attention mechanism of the Transform encoder module is combined to process the time sequence dependence, so that the long-distance time dynamic relationship is effectively modeled, and an efficient and reliable agent model is provided for the dynamic analysis of the oil reservoir.

The invention discloses a system and a method for supercritical CO2 in-situ pyrolysis of wide-depth-range oil-rich coal, an injection well, a first horizontal well, a second horizontal well and a production well are respectively arranged in shallow-layer oil-rich coal and deep-layer oil-rich coal, a temperature monitor is supplemented, supercritical CO2 is injected to realize in-situ pyrolysis of the oil-rich coal, and the in-situ pyrolysis of the oil-rich coal is realized. The pyrolysis products are subjected to grading treatment, meanwhile, different land parcels are operated in a combined mode, waste heat of the previous land parcel is used for the pyrolysis reaction of the next land parcel, CO2 is a heat carrying medium, and then part of CO2 is sealed in the previous land parcel. In the whole process, in-situ pyrolysis of the oil-rich coal seam in different burial depths and thickness ranges is achieved, heat in the pyrolysis process is fully utilized, heat waste is avoided, and the mining utilization rate of the oil-rich coal is increased through the promoting effect of supercritical CO2 on heat and mass transfer; and meanwhile, the strategic goals of CO2 emission reduction and carbon neutralization promotion are achieved.

The present disclosure describes a system and a method for generating energy from geothermal sources. The system includes an injection well and a production well extending underground into a rock formation, a first lateral section connected to the injection well and a second lateral section connected to the production well, the first and second lateral sections connected with a multilateral connector, defining a pressure-tested downhole well loop within the rock formation and in a heat transfer arrangement therewith. The downhole well loop cased in steel and cemented in place within the rock formation. The downhole well loop to receive working fluid capable of undergoing phase change between liquid and gas within the downhole well loop as a result of heat transferred from the rock formation. The system also includes a pump to circulate working fluid, a turbine system to convert the flow of working fluid into electricity, and a cooler.

The invention provides a safety risk control method for geological storage of carbon dioxide and electronic equipment. A distributed optical fiber sensing system is arranged in at least one injection well of the target sealing and storage area in the axial direction of a shaft and penetrates through a main cover layer and a reservoir; the method comprises the following steps: acquiring background data through a distributed optical fiber sensing system, and establishing a multi-parameter baseline model including a temperature field, a strain field and background noise; temperature, strain and sound wave vibration signals are collected in real time, and key features are extracted; the key features extracted in real time are compared with a preset risk feature library, the types of risk events are identified, and the identified risk events are graded according to the spatial range and intensity of the abnormal signals; and according to the type and the grade of the risk event, generating and executing a corresponding control instruction. According to the embodiment of the invention, the optical fibers are distributed in the whole area along the shaft and the target stratum, a three-dimensional monitoring network covering the sealing body is constructed, and the hysteresis quality of traditional point type measurement and periodic exploration is overcome.

The invention provides a layered water injection well injection profile testing system, electronic equipment and a storage medium, and the system comprises a plurality of visible light communication modules which are respectively installed on eccentric water distributors of all water injection layers and on water injection pipe couplings between any two water injection layers; the plurality of sensing monitoring modules are mounted on the eccentric water distributor and are used for acquiring underground monitoring data of the layered water injection well; and the upper computer terminal is used for processing the underground monitoring data based on the group strategy optimization model to obtain an optimized water injection strategy, further generating a water injection control instruction, and transmitting the water injection control instruction to the eccentric water distributors of the water injection layers through a downlink channel. According to the scheme, the LED is used for transmitting data under the dark well, the problems existing in an existing transmission mode are solved, the original water injection well layout structure is not changed through installation of the hardware module, space is saved, and more stable and reliable light transmission can be achieved.

The invention discloses a sediment type salt cavern gas storage gas-liquid interface depth prediction method. The method comprises the following steps that S1, a change curve of brine discharge flow along with time is obtained through on-site monitoring; s2, determining the mining form of the salt cavern cavity, and obtaining a change curve of the effective cross section area of the cavity brine along with the depth; s3, respectively calculating gas-liquid interface depths when the gas-liquid interface is in the gas injection well and does not enter the salt cavity, when the gas-liquid interface is in the pure brine space at the upper part of the salt cavity and does not enter sediment, and when the gas-liquid interface is in the sediment accumulation space; s4, judging whether the gas-liquid interface depth obtained through calculation in S3 meets a corresponding application interval or not, and obtaining a gas-liquid interface depth value; the gas-liquid interface depth of the pure brine space on the upper portion of the salt cavern can be detected, the gas-liquid interface depth of the sediment accumulation space can also be detected, and gas-liquid interface depth detection of the whole space of the inner cavity of the sediment type salt cavern gas storage is achieved.

The invention provides an anti-clogging method and device for a brine discharging well in the low-position brine discharging process in salt cavern sediment. A method for preventing clogging of a brine discharging well in the low-position brine discharging process in salt cavern sediment comprises the steps that S1, gas injection wells and brine discharging wells are drilled on the ground, and the gas injection wells and the brine discharging wells communicate with the top of a salt cavern and the bottom of the salt cavern sediment in a one-to-one correspondence mode; s2, gas injection is conducted on the top of the salt cavity through a gas injection well, so that brine in the salt cavity is discharged through a brine discharging well under the action of gas pressure; s3, fresh water is injected into the open hole section through a central pipe of the brine discharging well, so that salt rocks around the open hole section are corroded by the fresh water; and S4, fresh water injection through the central pipe of the brine discharging well is stopped, and brine discharging is conducted through the central pipe of the brine discharging well and the annulus.

The invention relates to the technical field of wellbore risk evaluation, in particular to a carbon dioxide flooding injection well wellbore integrity risk quantitative evaluation method, which comprises the following steps: constructing an injection well integrity evaluation hierarchical structure model; determining a weight coefficient of each risk index; respectively evaluating each risk index; and calculating a total risk grade score and determining a risk grade. Through the hierarchical model and the determination of the weight coefficient, various risk factors can be comprehensively considered, and detailed evaluation of the integrity of the shaft is realized. Acquisition of real-time data and parameter correction ensure the accuracy and timeliness of an evaluation result, in addition, the method can recognize a high-risk area in advance, early warning and timely treatment are achieved, and the problem that in the prior art, due to the fact that an integrity analysis evaluation method is large in subjectivity, the accuracy and timeliness of the evaluation result are poor is effectively solved. Therefore, the problem of low evaluation accuracy caused by the fact that the integrity risk of the shaft cannot be evaluated more objectively and quantitatively is solved.

The invention discloses a safe operation tubular column for a carbon dioxide injection well and an operation method, a tubing hanger is hung at the upper end of a casing head, a load test short section is connected below the tubing hanger, and the load test short section is sequentially provided with a sliding sleeve valve, an upper centralizer, a releasing packer, a lower centralizer, a gas injection valve, a tail short section and a screwed plug towards the lower tubular column. After the pipe column enters a well, the annulus protection fluid is positively injected for fluid replacement; a constant-pressure valve ball is put in, and the sealing performance is checked through step-by-step positive pressure; a tubing hanger is seated after pressure relief; the releasing packer is set through positive pressure, then pressure is continuously increased to break the valve seat thin-wall section of the constant-pressure valve seat, and positive injection communication of the tubular column is achieved; and then water is squeezed forwards, after the sealing performance of the packer is verified, a wellhead is installed and connected with a ground process, carbon dioxide is injected forwards, and soaking is conducted after the carbon dioxide reaches the set gas injection amount. The tubular column does not overflow in the process of descending into a well, after positive replacement, a ball is thrown to press and set a packer, a shaft is protected, dirt deposition is prevented, the risk of breakage and falling of the tubular column is completely eradicated, and the operation process is safe and controllable.

Hydrocarbon extraction may be coupled with subterranean hydrogen storage. For example, a method of hydrocarbon extraction and hydrogen storage may include: introducing carbon dioxide into a subterranean formation via one or more injection wells, the subterranean formation containing hydrocarbons and optionally water; mobilizing at least a portion of the hydrocarbons in a hydrocarbon-bearing zone of the subterranean formation with the carbon dioxide; after mobilization with the carbon dioxide, producing the hydrocarbons from the hydrocarbon-bearing zone of the subterranean formation via one or more production wells; introducing hydrogen to the subterranean formation via the one or more injection wells, the hydrogen displacing the carbon dioxide downward in the subterranean formation; storing the hydrogen in the subterranean formation above the carbon dioxide; and producing at least a portion of the hydrogen from the subterranean formation via the one or more production wells, the one or more injection wells, or any combination thereof.

The utility model discloses a well structure for injecting a suspended state repairing agent. The well structure comprises an injection well, a lower end injection pipeline and an upper end injection pipeline, wherein the lower end injection pipeline downwards penetrates into the injection well from the top of the injection well; the upper end injection pipeline is arranged on the side wall of one side of the top of the injection well; and a Y-shaped tee joint is arranged at the bottom of the lower end injection pipeline. By adopting the well structure, the migration and distribution uniformity of the suspended state repairing agent is remarkably improved, the reaction efficiency with pollutants is enhanced, meanwhile, the repairing cost is reduced, the construction period is shortened, and the repairing quality is ensured. Meanwhile, the problem that in a traditional injection method, when the repair depth exceeds the injection range or the repair medium is bed rock, it is difficult to inject suspended-state repair agents is solved.

The invention discloses a CCUS experimental device and method for carbon dioxide flooding and storage, and relates to the technical field of petroleum engineering. The device comprises a three-dimensional oil reservoir physical model, a fluid injection system, a fluid collecting and metering system, a resistivity monitoring system and a fluid migration observation system. The three-dimensional oil reservoir physical model is used for constructing a simulated stratum, and a development well pattern system is installed on the simulated stratum; the fluid injection system is connected with the injection well; the fluid collecting and metering system is connected with the production well; the resistivity monitoring system is provided with a plurality of monitoring points on the simulated stratum; the fluid migration observation system is used for observing a migration path of supercritical carbon dioxide in the three-dimensional oil reservoir physical model; and the distributed optical fiber monitoring system is arranged in the simulated stratum. According to the device and the method, oil reservoir water injection exploitation and CO2 injection oil displacement and CO2 storage stability simulation experiments in the later development period can be realized.

The invention belongs to the technical field of oil-gas field development tertiary oil recovery and unconventional oil-gas development, and discloses a low-permeability-tight oil reservoir carbon dioxide injection effective displacement distance evaluation method, which comprises the following steps: obtaining several groups of different permeability core starting pressure gradients, and obtaining a quasi-starting pressure gradient according to the starting pressure gradients; establishing a mathematical relationship between the real starting pressure gradient and the permeability and a mathematical relationship between the quasi-starting pressure gradient and the permeability; effective displacement distances of reservoirs with different permeability under different pressure gradient conditions are obtained through calculation, and an effective displacement distance and permeability relation chart is established; according to the oil field early-stage oil production well average well bottom pressure, oil production well bottom pressure is obtained, and then the pressure gradient between the gas injection well and the oil production well is obtained; and according to the actual permeability of the oil reservoir and the pressure gradient between the gas injection well and the oil producing well, the actual effective displacement distance of oil reservoir carbon dioxide flooding is obtained. According to the method, the limiting distance of fluid flowing is simply calculated by using a limiting well spacing method, the method is simple and rapid, and few basic parameters are needed.