461 results about "Injection well" patented technology

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.

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

The application discloses an intelligent identification method for dominant seepage channels based on big data, which comprises the following steps: collecting static geological data, dynamic development data and dynamic monitoring data of an oil reservoir and performing data processing; performing data quality analysis on the processed data and establishing a sample database; performing inter-well connectivity analysis and inter-well pressure response analysis in a plane according to the sample database, and identifying dominant channels in the plane; performing interlayer production and absorption law research in a vertical direction according to the sample database, predicting interlayer liquid production and absorption ratios and water cut, and identifying dominant interlayer positions in the vertical direction; and comprehensively identifying dominant seepage channels between each layer of a production well and an injection well based on the identified dominant channels in the plane and the dominant interlayer positions in the vertical direction.

The invention provides a carbon dioxide injection well perforation parameter optimization method and device and electronic equipment, and the method comprises the steps: carrying out the standardization processing of geological and logging data, and constructing a multi-dimensional data set comprising lithology, porosity, permeability, crack parameters and a ground stress field; a three-dimensional digital twinborn model is constructed based on the data set, and reservoir heterogeneity and fracture network distribution are restored; on the basis of the digital twinborn model, performing multi-physics field coupling simulation including carbon dioxide migration simulation, shaft stress distribution simulation and long-term corrosion prediction; based on a multi-objective optimization algorithm, with the effective wave and volume of the carbon dioxide, the integrity coefficient of the shaft and the anti-channeling safety coefficient as objectives, an optimal perforation parameter combination is screened; and outputting a visual report including perforation parameters, simulation results and risk assessment. Digital twinning, multi-physics field simulation and multi-objective optimization are deeply fused, and a set of complete, accurate and efficient perforation parameter optimization solution from data to decision is formed.

The invention discloses an active treatment method for multi-source residual coal gas of a waste mine, which comprises the following steps: firstly, hydraulic fracturing pressure relief permeability improvement and overlying strata separation layer grouting reinforcement are cooperated, the hydraulic fracturing pressure relief permeability improvement establishes a netted fracture network in a coal body to realize permeability improvement, and the overlying strata separation layer grouting reinforcement compacts goaf gangue through grouting and reinforces an overlying strata to form a continuous bearing consolidation body; and therefore, a pressure relief and permeability increasing-strengthening and reinforcing integrated structure is formed, a stable structure and a penetrating seepage network are provided for subsequent displacement and gas extraction, and the subsequent gas extraction efficiency is guaranteed. Then low-temperature liquid CO2 is injected into the coal seam through the injection well, gas displacement and desorption are conducted on gas adsorbed in the coal seam under the action of phase change and competitive adsorption, expansion and development are conducted on fractures to enable permeability to be secondarily enhanced, and meanwhile part of CO2 obtained after displacement is retained and sealed in a coal body and a goaf; on the premise that the gas extraction concentration and efficiency are effectively improved, CO2 can be stored, and the dual effects of resource utilization and carbon storage are achieved.

Various examples are provided related to airlift pumping of downhole geothermal fluids. In one example, an airlift system includes a compressor; a gas sparger head in a wellbore of a geothermal well, and a pressure head recycle assembly. The sparger head produces artificial lift of the geothermal fluids by injecting a gas resulting in a difference in density downhole. The entrained gas can be extracted by the pressure head recycle assembly, compressed, and reinjected downhole. The geothermal fluid at the well head can be used in direct use applications or in a thermodynamic cycle to make shaft power. The gas sparger head can include a venturi shaped passage extending through the gas sparger head and a bubble orifice including gas orifices radially spaced about a narrow portion of the venturi shaped passage. The gas orifices can have a corresponding resonant chamber through which the gas (e.g., air) is provided.

The invention relates to the technical field of soil and groundwater pollution remediation, in particular to a polluted groundwater source controlling and breaking system suitable for limited space of an industrial accumulation area, which comprises a main well, a gas stripping circulating unit and a groundwater circulating unit. A blocking device composed of a packing rubber structure and a driving device is arranged in the main well, the packing rubber structure is driven by the driving device to move and intermittently inject air to expand, and an air flow channel which is dynamically opened and closed is formed between the inner wall of the main well and the unsaturated area. The vacuum pump device builds negative pressure on the upper portion of the main well, so that purified clean gas enters an unsaturated area in an intermittent pulse mode through the peripheral injection well, and soil gas is induced to flow in an oscillating mode under cooperation of the dynamic gas flow channel. Groundwater extracted by the centrifugal pump is purified by the gas stripping area and the underground activated carbon filtering device and then is discharged into the top of the unsaturated area through the drainage device in an intermittent wave mode, the system is suitable for pollution treatment in the limited space of the industrial accumulation area, and targeted source control and long-acting reduction are achieved.

The conveying and injecting system comprises a main pipeline, a cooling device and a supercharging device, the main pipeline is used for receiving supercritical carbon dioxide from a carbon dioxide capturing device, and the other end of the main pipeline is connected with an inlet of the cooling device; the cooling device is used for cooling the supercritical carbon dioxide to a preset temperature, so that the supercritical carbon dioxide is converted into dense-phase carbon dioxide, an outlet of the cooling device is connected with an inlet of the pressurizing device, an outlet of the pressurizing device is used for being connected with an injection well, and the pressurizing device is used for pressurizing the dense-phase carbon dioxide to a preset pressure. According to the conveying and injecting system, carbon dioxide is conveyed to the vicinity of a sealing place in a supercritical phase state in a long distance in the main pipeline and then conveyed to the injecting well after being cooled and pressurized, and the pressure of supercritical carbon dioxide is smaller than that of dense-phase carbon dioxide, so that the risk that the main pipeline is broken can be reduced; and the stability and safety of carbon dioxide conveying are improved.

The invention discloses a quantitative calculation method for analyzing injection-production dynamic response by using time sequence interference. The quantitative calculation method comprises the following steps: S1, acquiring time sequence data of output and water injection rate; s2, taking the change of the water injection rate as an intervention event, and establishing a virtual interference variable; s3, taking the oil well output as a target variable and substituting the target variable and the virtual interference variable in the S2 into an SARMAX time sequence model for fitting; s4, judging the significance degree of the model by using the residual error of the model, and if the residual error is a random time sequence, ending; if the residual sequence of the model is non-white noise, going to S5; s5, determining autoregression and moving average orders by using an ARMA (p, q) model; s6, substituting order information into the model in the S3 for re-fitting; and S7, repeating the steps S3-S6 until the model is significant. The method can quantitatively evaluate the influence degree of the injection well on the output. Quantifiable data are provided for evaluation of production and injection dynamic influences in oil reservoir dynamic management, reasonable injection and production adjustment countermeasures are formulated accordingly, oil reservoir production dynamic management is guided, and the oilfield exploitation effect is guaranteed.

A system for implementing and optimizing the storage potential of subterranean carbon mineralization can include a fluid injection well subsystem having an injection wellbore, a pumping system, and a fluid injection completion system disposed at an injection range along the injection wellbore, where the fluid injection completion system is configured to control an injection rate of pressurized fluid from the injection range into an active storage zone within a subterranean rock formation. The system can also include a fluid production well subsystem having a production wellbore and a fluid production completion system disposed at a production range along the production wellbore, where the fluid production completion system is configured to control an inflow rate of production fluid from the active storage zone into the production range of the production wellbore. The system can further include a monitoring subsystem configured to monitor carbon mineralization in the active storage zone.

The invention discloses a coal bed gas exploitation and separation utilization method based on SCCO2 assistance, and belongs to the technical field of coal bed gas development. Supercritical carbon dioxide is prepared through a high-pressure reaction kettle and stored in a supercritical carbon dioxide storage and collection tank, meanwhile, nitrogen mixed with graphene is introduced, and CO2 / CH4 adsorption selectivity is enhanced by means of the characteristic that the specific surface area of graphene is large. A variable-frequency sound wave diffuser is matched to excite coal seam micro cracks through low-frequency sound waves, and supercritical carbon dioxide and nitrogen mixed gas is injected into a coal seam injection well. In the injection process, the sound wave diffuser synchronously radiates high-frequency sound waves to improve the displacement efficiency, then the gas enters the gas separation tower integrated with the molecular sieve membrane, and the produced gas is divided into upper methane, middle carbon dioxide and other bottom miscellaneous gas. Methane is pressurized by an air compressor and then stored in a methane storage tank, carbon dioxide is purified and pressurized and then recycled for coalbed methane exploitation, and offensive gas is cooled and stored after generating power by a steam turbine. And efficient mining, separation and multi-path utilization of the coal bed gas are realized.

The invention provides a carbon dioxide multi-layer integration injection dynamic regulation and control method and device, and relates to the field of carbon dioxide geological sequestration, and the method comprises the steps: determining the optimal layer number and layer spacing distance of multi-layer integration injection based on obtained geological parameters, and obtaining a plurality of injection layers; according to the geological parameters and the length of the gas injection well, an interlayer allowable pressure difference is calculated in combination with a seepage mechanical formula, and spatial distribution parameters of all injection layers are determined; determining an inlet angle of an injection port corresponding to each injection layer; analyzing the porosity change rate between the injection layers and the coupling influence coefficient of the stress field change; and dynamically adjusting the opening degree of the injection port of each layer by adopting a model predictive control algorithm, and determining a delayed injection strategy according to a configured formation permeability grading standard. According to the method, the injection flow uniformity and the sealing efficiency can be improved, the interlayer fluid channeling risk is reduced, and accurate dynamic regulation and control of multi-layer unified injection are achieved.

The invention provides an adsorption pressure return type blowout control method, which comprises the following steps: intervening when well control abnormity occurs at the beginning (such as overflow precursor), compounding a methane adsorbent and a conventional drilling fluid additive to prepare high-density composite well control fluid, and injecting the high-density composite well control fluid into a shaft by a special device at a position 100-200m below a wellhead according to preset displacement and pressure parameters. According to the method, bubbles in a shaft are adsorbed through an adsorbent, the slippage speed and the gas phase volume fraction are reduced, and the synergistic effect of static pressure constraint and active adsorption is achieved. Therefore, back pressure fluctuation can be stabilized in the early stage of gas cut, gas column expansion and pressure rising are limited, the risk of pressure leakage and secondary eruption is reduced, the purpose of preventing or restraining blowout is achieved, and the gas cut blowout prevention device is suitable for complex working conditions such as fractured stratums, deep water, high temperature and high pressure and narrow-density windows.

The application provides a kind of low permeability long fracture fracturing well group CO2 drive critical injection parameter evaluation method, comprising: carrying out CO2 injection well group reservoir characteristics fine description;Carrying out CO2 injection well group geomechanics parameter description;Establish low permeability long fracture fracturing well group CO2 drive reservoir matrix-fracture coupling numerical simulation model;Carrying out long fracture fracturing well group CO2 drive numerical simulation, evaluating reservoir pressure change;Carrying out long fracture fracturing well group CO2 drive disturbance stress field change evaluation;Carrying out long fracture fracturing well group CO2 drive fracture propagation determination, evaluating gas channeling and CO2 leakage risk, determining critical injection parameter limit.The low permeability long fracture fracturing well group CO2 drive critical injection parameter evaluation method combines the dynamic change evaluation CO2 drive critical injection parameter of low permeability long fracture fracturing well characteristics and reservoir physical parameter, and has important significance for improving CO2 drive development effect and realizing CO2 drive reservoir scientific management.

This invention discloses a test site and method for evaluating the geological storage capacity of carbon dioxide. The test site includes a brine pool and a brine layer and caprock structure located within the pool. The caprock structure is vertically positioned below the brine layer, and a brine reservoir structure is located below it. The brine reservoir structure is connected to a brine storage tank via a simulated extraction well pipe. The brine storage tank is connected to the brine layer via a simulated injection well pipe. Carbon dioxide is injected into the brine reservoir structure via a simulated gas injection well pipe. Pressure sensors installed on the inner wall of the brine pool monitor the pressure within the brine layer and the brine reservoir structure. The carbon dioxide injection rate, brine extraction rate, and brine injection rate are adjusted based on the monitored pressure to achieve pressure balance between the brine layer and the brine reservoir structure. This invention provides a test site for evaluating the geological storage capacity of carbon dioxide under actual site conditions.

The application discloses a coal drilling type coal underground gasification furnace, a gasification furnace construction method and a coal seam gasification method. A gas outlet well is connected with a gas injection well through a horizontal section at the top of a coal seam to form a U-shaped gasification furnace structure. The coal seam is excavated at the joint of the gas injection well, so that the coal seam collapses, stress is redistributed, the cavity is enlarged, the coal seam below the pocket section of the gas injection well is ignited, the coal seam is positively advanced, and the effective synthesis gas is discharged to the ground through the gas outlet well. The application can well develop and utilize tectonic coal, and has the advantages of environmental protection, safety and good economic benefits.

The invention discloses a flow regulation and control method, device and system for a separate injection well based on a PID (Proportion Integration Differentiation) algorithm. The method comprises the steps that whether a water injection well has a water injection layer of a reinforcing layer is judged; if yes, a water nozzle motor controller of the water injection well is informed to regulate and control the water nozzle opening degree of the reinforcing layer to the maximum; the water injection layer of which the type is not the reinforcing layer is used as a target layer regulated and controlled by a PID algorithm; if the target layer of which the actual flow does not meet the target flow exists, traversing each target layer in sequence according to a set sequence, and if the current actual flow of the currently traversed target layer does not meet the target flow, determining a water nozzle regulation and control strategy through a PID algorithm, and notifying a water nozzle motor controller to execute corresponding operation; and obtaining the current actual flow of each target layer until the target layer of which the actual flow does not meet the target flow does not exist. The method can automatically and synchronously adjust the opening degrees of the water nozzles of different layer sections, control the water injection rate of each layer section and optimize the water injection efficiency.

The invention discloses an oil shale in-situ conversion and carbon sequestration method by injecting high-temperature carbon dioxide and cooperating with sodium capsules, and belongs to the technical field of fossil energy in-situ exploitation and carbon sequestration. The method comprises the following steps: firstly, determining a target development area and formulating a corresponding development strategy; then, the oil shale reservoir is subjected to fracturing transformation; then, the oil shale reservoir is heated, supercritical carbon dioxide is injected, and displacement recovery is conducted; then, sodium capsule suspension fluid is injected into the oil shale reservoir, and solid-phase geological storage is achieved; and finally, after oil and gas exploitation reaches the economic limit, all the injection wells and the production wells are closed, and final geological storage is completed. According to the method, the carbon dioxide geological sequestration technology and the oil shale in-situ conversion process are deeply fused, the oil shale recovery efficiency is remarkably improved, the geological sequestration of the carbon dioxide is synchronously achieved, and the method has important significance in the fields of carbon emission reduction and fossil energy in-situ exploitation.

The present disclosure relates to a geothermal carbon capture system, comprising; a primary liquid circuit circulating liquid into a geothermal well and returning heated liquid from a well head of the geothermal well, the primary liquid circuit passing through a condenser; a turbine driven by the heated liquid to power a compressor configured to draw in and compresses ambient air to feed a first compressed air supply and a second compressed air supply, wherein the first compressed air supply is directed to a separator to extract carbon dioxide therefrom; and the second compressed air supply drives a pump to force the carbon dioxide extracted from the separator towards a reinjection well for reinjection into geology surrounding the reinjection well.

The present application relates to oil and gas field development technology, disclose a kind of heavy oil reservoir hot water drive limit well spacing determination method. Including the following steps: S1, the starting pressure gradient corresponding to different temperature is obtained by percolation experiment test;S2, according to the starting pressure gradient corresponding to different temperature, determine the inflection point temperature of starting pressure gradient curve;S3, based on the inflection point temperature of pressure gradient curve, the percolation area between injection well and production well is divided;S4, based on the percolation area divided, the percolation resistance R of darcy percolation area between injection well and production well is calculated d ;S5, based on R d The pressure drop ΔP of darcy percolation area between injection well and production well is calculated d ;S6, based on ΔP d The length l of non-darcy percolation area between injection well and production well is calculated nd ;S7, based on l nd Determine the limit well spacing L of heavy oil reservoir hot water drive. The determination method can guide the formulation of heavy oil reservoir hot water drive development plan, improve development effect.

The invention relates to a low-permeability reservoir CO2 drive gas channeling channel identification method which comprises the following steps: S1, collecting geological data and production dynamic data of a target block well group, and calculating a gas channeling channel discrimination index; s2, calculating the weight of each gas channeling channel discrimination index; s3, calculating an onrush coefficient and correcting a boundary; s4, calculating a membership degree, and standardizing each gas channeling channel discrimination index according to the membership degree to meet the condition that the numerical value is between 0 and 1; s5, static and dynamic index comprehensive discrimination coefficients of the injection wells and the production wells are calculated; s6, calculating comprehensive weights of static and dynamic indexes of each injection well and each production well; s7, calculating a total discrimination coefficient; and S8, determining a three-level classification standard of the gas channeling channel, and judging the development direction of the gas channeling channel. The method solves the problem that an existing gas channeling channel identification method is low in accuracy of gas channeling channel identification due to the fact that the existing gas channeling channel identification method lacks research on a low-permeability conglomerate oil reservoir and does not fully utilize dynamic and static data.

The invention discloses a coal-uranium collaborative mining circulation supply mining system and an application method, and particularly relates to the technical field of coal-uranium mining and a geological institution.The geological institution comprises a surface layer, a uranium layer, a coal seam and underground runoff, the surface layer is located above the uranium layer, the uranium layer is located above the coal seam, and the underground runoff is located above the coal seam. The underground runoff is located between the surface layer and the uranium layer; and the ground mining mechanism comprises an injection well, an extraction well, a leaching solution preparation tank, a uranium comprehensive treatment bin, a liquid injection pump, a liquid extraction pump, a liquid injection pipe and a liquid extraction pipe. According to the method, partition isolation and staged collaborative proceeding of uranium mine in-situ leaching mining and coal mining are achieved by planning the barrier infiltration reduction mechanism, the overall recovery efficiency of uranium and coal resources is improved, the pollution risk of uranium-containing leachate discharge to the environment is reduced, underground water resources are fully recycled, and the method has the advantages of being environmentally friendly, efficient and safe.

The present disclosure relates to a method and a flow control device for in-situ recovery ('ISR') of metals from an orebody. The method comprises drilling at least one vertical parent well into a formation comprising the orebody, and subsequently, drilling a plurality of lateral wells for performing a blasting operation to create a fractured rock silo within the formation. Next, an ISR drilling operation is carried out within the fractured rock silo by drilling further wells, including injection and production wells. Carrying out an ISR process, where casing strings comprising the flow control device is run into the injection and production wells, where the casing strings within injection wells are for injecting a fluid into each ISR well to dissolve the metal therein, and subsequently collecting a pregnant solution, comprising the dissolved metal, from the orebody via the production well and the casing strings therein.

This invention relates to the field of injection and production monitoring technology, and particularly to a method for real-time tracking and control of injection and production dynamics. The method includes: controlling the injection well to perform limited-amplitude micro-disturbance injection according to a coded sequence in each preset tracking cycle, generating an injection reference signal; simultaneously acquiring the response signal of the production well, constructing and analyzing the injection and production disturbance response curve based on both, generating a connectivity consistency value and a response difference value characterizing the connectivity state between wells, and constructing an injection and production dynamic fingerprint map based on their temporal changes; dividing the fingerprint map into a stable sub-map and a fluctuating sub-map, identifying abnormal categories such as enhanced crossflow or limited injection / supply when fluctuations persist; automatically determining the target control combination and generating a graded control strategy accordingly; updating the fingerprint map after executing the strategy, with the disappearance of fluctuations and the return of the characterization value to a stable range as the control completion indicator, otherwise iterative optimization. This invention achieves active monitoring, intelligent diagnosis, and closed-loop control of injection and production dynamics, improving the accuracy and timeliness of oilfield management.

The invention discloses an underground supercritical carbon dioxide mass flow testing device and a testing method. The device comprises a measuring short section and a flow collecting short section, the measuring short section comprises a volume flow meter, a temperature sensor, a pressure sensor, a flow plate and a magnetic positioning module, and a density prediction model is preset on the flow plate; and the flow plate is used for predicting a density value by using a density prediction model based on the obtained temperature value and pressure value, and converting the mass flow rate of the overflowing carbon dioxide according to the density value and the obtained volume flow rate. The device can monitor a plurality of injection parameters such as mass and flow of carbon dioxide injection in different underground intervals in real time, and provides an on-line testing means for the mass and flow regulation and control of the carbon dioxide flooding injection well intervals in an oil field.

The application discloses a method for determining the deblocking time of the near-well zone of a polymer injection well. The method comprises the following steps: S1, injecting a polymer solution into the polymer injection well; S2, measuring the injection pressure, and obtaining a relationship curve between the injection amount and the injection pressure according to the injection amount and the injection pressure of the polymer solution; and S3, determining the deblocking time according to the relationship curve: when the injection pressure is stable and then obviously decreases without a relieving trend, the deblocking time of the polymer injection well is determined. Based on the research on the solution percolation of a polymer flooding system in the near-well zone, the dynamic adsorption law of the polymer on the surface of rock minerals is determined, the dynamic adsorption has a process from quantity change to quality change, and the inflection point of the quality change is related to the formation of the near-well zone blockage, so the discrimination of the inflection point constitutes the selection of the deblocking measure time, and the application is formed.

This disclosure describes methods and systems for CO2 injection well placement in a target area. The method involves identifying input data associated with the target area, the input data including at least one of core samples or well logs from the target area; generating, based on the input data, a structural depth grid of the target area; generating, based on the structural depth grid, a slope map of the target area; generating, based on the slope map of the target area, a flow direction map for the target area; determining, based on the flow direction map, a fluid flow accumulation and a fluid flow length in the target area; and based on the fluid flow accumulation and the fluid flow length in the target area, selecting at least one position for drilling at least one CO2 injection well in the target area.