120 results about "Reservoir pressure" patented technology

The invention belongs to the technical field of shale oil horizontal well three-dimensional development, and particularly discloses a three-dimensional well pattern interference evaluation method based on dynamic oil drainage volume. The method is used for solving the problem of how to establish an accurate inter-well interference evaluation method under the conditions of high reservoir heterogeneity and complex inter-well mutual influence. Comprising the following steps: (1) constructing a multi-field coupling dynamic oil drainage volume characterization model based on reservoir pressure field evolution, fluid seepage characteristics and fracture network response, and realizing quantitative and dynamic evaluation of shale oil reservoir inter-well interference; and (2) establishing an inter-well interference degree quantitative evaluation system based on the multi-field coupling dynamic oil drainage volume characterization model, and measuring the space overlapping degree and the pressure field difference of the oil drainage volume of each well by using the inter-well interference degree quantitative evaluation system so as to provide a quantitative basis for well pattern layout and interference control. According to the method, the dynamic seepage characteristics of the shale oil reservoir and the inter-well competition relationship are tightly coupled, and the interference identification precision is improved.

Systems and methods for modeling gas desorption in a subterranean reservoir include measuring a gas sorption parameter using a crushed core sample from the subterranean reservoir; computing a gas storage capacity of the subterranean reservoir at an initial reservoir pressure based on the gas sorption parameter; generating a three-dimensional (3D) distribution of total organic carbon (TOC) in the subterranean reservoir; estimating a 3D distribution of original adsorbed gas in place of the subterranean reservoir by correlating the gas storage capacity with the 3D distribution of TOC; and predicting the amount of gas desorbed from the subterranean reservoir as the reservoir is depleted.

The invention provides a reservoir mechanical integrity evaluation method under high-frequency injection and production. The evaluation method comprises the steps that S1, rock sample compressive strength and mechanical property parameters of a reservoir under multiple confining pressures are determined; s2, determining the upper limit and the lower limit of the reservoir pressure of the energy storage reservoir in the injection-production process; s3, obtaining the critical fatigue strength of the reservoir rock sample under a plurality of confining pressures within the designed age limit; s4, determining a deviating stress-average stress plane according to the compressive strength and the critical fatigue strength of the rock sample under the plurality of confining pressures, and dividing rock failure zones on the deviating stress-average stress plane; and S5, establishing a geomechanical model to predict the stress level of the reservoir, and judging the safety of the reservoir during the cyclic injection-production period from the perspective of mechanical integrity. Safe, efficient, economical and lasting operation of the energy storage warehouse is guaranteed, and a feasible method is provided for expanding the application range of compressed air energy storage.

The invention provides a carbon dioxide geological sequestration injection strategy optimization method and device. The method comprises the steps that candidate injection curves of different forms of carbon dioxide injection rates and time change relations of a target sequestration site are obtained; each candidate injection curve represents an injection strategy; inputting the time sequence data and the reservoir state query information corresponding to each candidate injection curve into the trained agent model to obtain a prediction index corresponding to the reservoir state query information; and determining a target injection strategy corresponding to the target candidate injection curve based on the prediction index corresponding to the reservoir state query information and the target index evaluation condition. According to the method, the maximization of the sealing injection efficiency and the accumulative sealing amount is realized on the premise of ensuring the reservoir pressure safety.

The invention provides an intelligent management and control method and system for carbon dioxide sequestration, and the method comprises the steps: obtaining multi-source data, carrying out the space-time alignment processing, feature extraction processing and multi-scale hierarchical data fusion processing of the multi-source data, obtaining dynamic parameter field data, carrying out the time sequence feature extraction and spatial feature coding based on the dynamic parameter field data, and carrying out the time sequence feature extraction and spatial feature coding. Generating a spatial-temporal characteristic matrix, inputting the spatial-temporal characteristic matrix into a pre-trained short-term leakage prediction model, and outputting a high-risk area coordinate of which the leakage probability is greater than a preset value in a future first duration, obtaining reservoir pressure, cover layer stress, fault activation index and geomechanical simulation data, inputting the data into a long-term stability evaluation model obtained through pre-training, outputting gas injection adjustment amplitude and recommended dosage of a repairing agent in a second time period in the future, and determining the reservoir pressure gradient and the earth surface deformation rate based on the gas injection adjustment amplitude, the recommended dosage of the repairing agent, the reservoir pressure gradient and the earth surface deformation rate. An executable repair strategy is generated through a multi-objective optimization algorithm, and a repair instruction set is issued according to the repair strategy to execute targeted repair, so that the leakage positioning and risk area identification precision is improved, and a'prediction-decision-repair 'full-process automatic closed loop is formed.

Disclosed are methods, systems, and computer-readable medium to perform operations including: obtaining production data about the well; generating a simulated average reservoir pressure at the subsurface region that includes the well; computing a difference between an average reservoir pressure obtained from the production data and the simulated average reservoir pressure; determining, based on the computed difference, a performance deviation with reference to a particular area of the subsurface region that includes the well; comparing the performance deviation to a predetermined threshold value that represents an acceptable tolerance for variance in performance of the well; and triggering, when the performance deviation exceeds the predetermined threshold value, a particular type of automated response comprising an action that addresses the variance in performance of the well.

A method for evaluating contribution of each component to shale oil reservoir resistivity at high temperature and high pressure is applied to the field of oil exploration and development. The method comprises the following steps: (1) analyzing the volume percentage of each clay mineral, the pore water content and the mineralization degree of the shale oil reservoir pressure-maintaining closed core; (2) when the fluid pressure is greater than 23MPa, measuring the resistivity of the pressure-maintaining closed rock core at each temperature point; (3) carrying out water balance treatment on pure clay minerals, namely kaolinite, montmorillonite, illite and chlorite, and measuring the resistivity at each temperature point when the fluid pressure is greater than 23MPa; (4) when the fluid pressure is greater than 23MPa, measuring the resistivity of each temperature point of the solution consistent with the mineralization degree of the pore water; and (5) constructing a resistivity evaluation model, and evaluating the contribution of each component to the resistivity of the shale oil reservoir under the condition of high temperature pressure.

The invention provides a supercritical carbon dioxide pipeline and storage well linkage flow control method and device, and relates to the field of carbon dioxide geological storage, the method comprises the following steps: determining the pressure deviation between the reservoir pressure and the configured target pressure based on the obtained pipeline data, bottom hole pressure data and reservoir pressure data; based on the pressure deviation, the first opening degree of an injection control valve of supercritical carbon dioxide and the second opening degree of an injection control valve of a corresponding water injection opening in the water injection pipeline are determined. The pressure deviation can be accurately calculated by acquiring the pressure data of the pipeline, the well bottom and the reservoir and comprehensively considering the influence of the pipeline parameters on the pressure. Based on the deviation, the opening degrees of the carbon dioxide and water injection control valves are determined through scientific methods such as proportional control and flow and opening degree curves, and cooperative control over the carbon dioxide and the water injection control valves is achieved. According to the method, the problem that the reservoir pressure is too high or too low due to improper injection flow can be effectively avoided, the carbon dioxide leakage risk is reduced, and the sealing efficiency is improved.

The invention provides a low-permeability gas reservoir fractured gas well productivity calculation method based on multi-effect coupling. The low-permeability gas reservoir fractured gas well productivity calculation method comprises the steps that the flowing bottomhole pressure of a low-permeability gas reservoir fractured gas well is obtained based on the low-permeability gas reservoir fractured gas well; the low-permeability gas reservoir core is experimented based on the flowing bottomhole pressure of the low-permeability gas reservoir fractured gas well, and the fracture permeability of the low-permeability gas reservoir fractured gas well under the original gas reservoir pressure is obtained; based on the gas reservoir original data and the fracturing data, the fracturing fracture half length and the fracturing fracture width of the low-permeability gas reservoir fracturing gas well are calculated; calculating a stress sensitivity coefficient, a slippage effect parameter and a starting pressure gradient of the low-permeability gas reservoir fractured gas well based on the absolute permeability, the fracture permeability, the fractured fracture half length and the fractured fracture width of the low-permeability gas reservoir fractured gas well; on the basis of the stress sensitivity coefficient, the slippage effect parameter and the starting pressure gradient of the low-permeability gas reservoir fractured gas well, seepage bottom hole pressure and yield at the two ends and the two sides of a crack considering multi-effect coupling are obtained through calculation; and the total yield of the low-permeability gas reservoir fractured gas well considering multi-effect coupling is obtained based on the gas production rates at the two ends and the two sides of the crack. According to the method, the productivity of the fractured gas well of the low-permeability gas reservoir can be accurately obtained.

Systems and methods presented herein facilitate coiled tubing cleanout operations, and generally relate to estimating reservoir pressure prior to the coiled tubing cleanout operations (e.g., while the wellbore is shut-in). For example, a method includes acquiring, via one or more downhole sensors of a coiled tubing system at least partially disposed within a wellbore, downhole data of the coiled tubing system; identifying, via a processing and control system, a density profile of fluids disposed within the wellbore based at least in part on the acquired downhole data; interpreting, via the processing and control system, the density profile of the fluids disposed within the wellbore; and estimating, via the processing and control system, a reservoir pressure of a reservoir through which the wellbore extends based at least in part on the interpreted density profile of the fluids disposed within the wellbore.

The invention provides a rock mechanics dynamic analysis method, system and equipment based on numerical simulation, and relates to the technical field of rock mechanics analys.The method comprises the steps that a three-dimensional geologic model and a three-dimensional geomechanical attribute model of a target sequestration body are constructed; based on the three-dimensional geologic model, establishing an oil reservoir numerical simulation model of the CO2 injection and storage process, and simulating to obtain a reservoir pressure field and a CO2 saturation field under different time steps; carrying out dynamic rock mechanics calculation to obtain dynamic fracture pressure fields of the cover layer under different time steps; and coupling the reservoir pressure field, the CO2 saturation field and the dynamic fracture pressure field, and carrying out transverse and longitudinal leakage risk dynamic evaluation. The technical problems that in the prior art, a simplified geologic model or a coarse mesh model is generally adopted, complex geologic and mechanical characteristics cannot be accurately described, the long-term stability of the storage body cannot be accurately evaluated, and the safety and long-term stability of storage are affected are solved.

The invention relates to a hydrothermal type geothermal heat reservoir protection method and system, and provides a technical scheme of taking heat without taking water aiming at the problems of heat reservoir pressure unbalance, ground subsidence and pollution caused by traditional water taking type development. The system comprises a thermal reservoir parameter monitoring module which collects temperature, pressure and working medium states in real time; the double-path regulation and control module is divided into a first control path and a second control path; the execution module executes two types of signals through interlaced time sequences and controls the rotating speed of the circulating pump and the working medium flow. The core of the method is time domain decoupling: the pump speed is immediately reduced when the temperature exceeds a threshold value, and the flow is adjusted after the pressure abnormity is delayed for 10-30 seconds, so that the pressure and the temperature fluctuation are separated on a time axis. The delay duration is dynamically calculated to be 1.2-1.5 times of the thermal recovery period of the thermal reservoir, and self-adaptive adjustment is performed in combination with the rock heat capacity characteristic and the fracture development state.

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.

The invention relates to the field of safe exploitation of natural gas hydrates, in particular to a reservoir pressure rebound simulation device and an experimental method in sea area hydrate exploitation. According to the technical scheme, the device comprises a multi-section continuous high-pressure reaction hold-down module, a top window module, a low-temperature control module, a data acquisition module, a gas-liquid injection system, a gas-liquid recovery system and a steel cylinder set, and the multi-section continuous high-pressure reaction hold-down module is formed by connecting five sections of single hold-down devices end to end; 60 pressure and temperature monitoring sub-areas are configured in the axial direction and the tangential direction in total, a rock core can be prepared through two methods of integrated pressing and five-time sectional pressing, and a reservoir pressure rebound phenomenon simulation experiment can be carried out in situ. The problems that a traditional device can only simulate a discontinuous reservoir with fixed porosity and the internal temperature and pressure monitoring precision is low are solved, and the device has important theoretical and practical significance on reservoir stability control, mining strategy and reservoir transformation scheme optimization during hydrate mining.

The present application relates to a kind of fracturing fluid flowback period gas well productivity evaluation method, steps are as follows: obtaining gas component, and the relationship curve of pressure and gas density, gas viscosity is calculated to obtain;The ratio of water phase and gas phase relative permeability is calculated, and the relationship curve of pressure and gas phase relative permeability, water phase relative permeability is respectively interpolated to obtain;The relationship curve of pressure and pseudo pressure is obtained;Fracturing fluid flowback period water-gas ratio and bottom hole flowing pressure are calculated, and based on the relationship curve of pressure and pseudo pressure, pseudo pressure under gas reservoir pressure and bottom hole flowing pressure is respectively calculated by interpolation, and the total flow of gas and water is calculated, then the average of test point is calculated;Bottom hole flowing pressure and water-gas ratio are set, pseudo pressure under the set bottom hole flowing pressure is calculated, and combined with average, the open flow capacity of gas well is obtained.The present application establishes gas-water two-phase seepage under gas well productivity calculation mathematical model, realizes the accurate calculation of gas well productivity under gas-water two same production condition.

The invention relates to an edge-bottom water reservoir natural energy evaluation method, and belongs to the technical field of reservoir development. According to the edge-bottom water reservoir natural energy evaluation method, firstly, the rock pore compression coefficient is calculated, then the accumulated water invasion amount of the reservoir is calculated according to the geological parameters and the production and development parameters of the reservoir, and then the natural energy activity index of the reservoir is calculated. And finally, determining the natural energy activity degree of the oil reservoir according to the natural energy activity index. The edge-bottom water reservoir natural energy evaluation method is suitable for non-closed unsaturated water pressure driven reservoirs, namely the reservoirs which have connected water bodies and have the water invasion effect due to reservoir pressure drop in the exploitation process, is suitable for the reservoirs subjected to water injection development and natural energy production, and has high evaluation accuracy.

The application provides a method for improving the recovery of natural gas hydrates in permafrost regions. The method comprises the following steps: (1) discharging free gas from the target permafrost region natural gas hydrate reservoir by depressurization, so that the reservoir temperature of the target permafrost region natural gas hydrate reservoir is less than 0 DEG C and greater than or equal to -6 DEG C, and the reservoir pressure reaches 0.8-1.2 times the phase equilibrium pressure of the natural gas hydrate; (2) injecting a mixed gas of CO2 and H2 into the target permafrost region natural gas hydrate reservoir for multiple rounds of throughput sweeping; wherein, between each round of throughput sweeping, huff and puff is carried out, and the temperature of the target permafrost region natural gas hydrate reservoir is maintained at less than 0 DEG C and greater than or equal to -6 DEG C; (3) after the throughput sweeping is completed, injecting CO2 into the target permafrost region natural gas hydrate reservoir for sweeping to recover free H2 and for geological storage of CO2. The method can significantly improve the recovery of natural gas in permafrost regions, effectively ensure the stability of the reservoir, and achieve geological storage of carbon dioxide.

The invention provides a transient productivity prediction method based on a fracture-vug reservoir pressure recovery well test model, and relates to the technical field of oil and gas reservoir development. The prediction method comprises the following steps: S1, through fracture-vuggy reservoir pressure recovery well test interpretation, establishing a fracture-vuggy reservoir well test geologic model, and obtaining reservoir parameters; s2, establishing a bottom hole pressure calculation equation under a constant flow condition, and calculating bottom hole pressure by adopting a multi-stage flow superposition principle; s3, establishing a yield calculation equation under the condition of the fixed bottom hole pressure to obtain data of flow changing along with time under the fixed bottom hole flow pressure; s4, forming a productivity prediction method that both the yield and the bottom hole pressure change along with well testing, and establishing a productivity calculation equation of the yield and the pressure when both the pressure and the flow change based on a Duhanm principle to realize transient productivity calculation prediction; therefore, a new productivity prediction method suitable for the fracture-cavity type oil reservoir is formed. The long-term production pressure and yield change of the oil well can be predicted more accurately, and development and production allocation are guided.

The present invention discloses a method for predicting the recovery rate of deep coalbed methane, comprising: determining correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation, as well as average coal reservoir pressure, cumulative water production and conventional average deviation coefficient of gas under multiple production dates, calculating the actual average deviation coefficient of gas, establishing a prediction model for reservoir gas production, calculating an iterative value of a control volume according to the correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation and original gas reserves of the reservoir, returning the iterative value to an initial given value that replaces the control volume for cyclic calculation, determining a first relationship model between cumulative water production and average coal reservoir pressure, determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure according to the first relationship model, substituting the vertical axis prediction value into the prediction model established last time in the cyclic calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate, thereby achieving the purpose of improving the reliability of the prediction.

The invention provides a deep coal bed gas pressure-maintaining coring free gas and adsorption gas content testing system and method.The testing system comprises a control system, a pressure maintaining barrel, a gas-liquid separation device, a drying and condensing device and a flow meter, and the pressure maintaining barrel, the gas-liquid separation device, the drying and condensing device and the flow meter are sequentially communicated through a pipeline; and a numerical control pressure gauge and an intelligent flow valve are mounted on the pipeline between the pressure maintaining barrel and the gas-liquid separation device. Free gas and adsorbed gas reach the original state of dynamic balance through constant temperature, then the intelligent flow valve is controlled to be opened and closed through the control system, when the pressure in the pressure maintaining barrel is lower than the reservoir pressure, the intelligent flow valve is closed, after the pressure in the pressure maintaining barrel rises to the reservoir pressure, the intelligent flow valve is opened, operation is circulated, and the pressure maintaining barrel is opened. After the pressure in the pressure maintaining barrel cannot rise to the reservoir pressure, free gas measurement is ended; in the whole process, the pressure maintaining barrel is decompressed by adopting small displacement, and the gas volume is measured by the flow meter, so that the on-site accurate gas content test of the deep coal bed gas with high gas content and high free gas ratio is realized.

The invention belongs to the technical field of reservoir engineering application, and discloses a digital-analog characterization method for reservoir pressure drive seepage parameters, which comprises the following steps: S1, measuring the permeability and relative permeability of a stratum sample before pressure drive, manufacturing artificial microfractures in a reservoir, converting original stratum pore seepage into artificial fracture net seepage, and calculating the permeability of the stratum sample before pressure drive; performing a water injection experiment on the sample by adopting different displacement pressure gradients, and determining the change relation of the permeability of the reservoir sample along with the pressure and the change condition of relative permeability before and after the matrix fracture pressure is reached in the water injection experiment process; s2, calculating the limit wave and radius under the pressure-driven water injection condition; and S3, carrying out digital-analog characterization on the oil reservoir pressure-drive water injection seepage parameters. According to the method, the permeability and relative permeability parameters are adjusted in real time by using the pressure as a reference condition, and full-life-cycle seepage parameter characterization in the pressure driving process is equivalently completed.

The invention discloses a method and a device for predicting the productivity of a directional fracturing horizontal well of a complex fracture network shale gas reservoir. The method comprises the following steps: respectively establishing corresponding relations between shale gas viscosity, a compression factor, a compression coefficient and reservoir permeability and reservoir pressure; on the basis of the matrix grid model, hydraulic fractures are embedded by adopting a determined modeling method, and natural fractures are embedded by adopting a random modeling method; according to the fact that shale gas follows the Langmuir adsorption law in a matrix and follows the Darcy flow law in a crack, mass conservation equations of the matrix and the crack are established respectively; flow relations between adjacent matrix grids, between fracture grids, between matrixes and fracture grids and between crossed fracture grids are established respectively, and a matrix equation set of the horizontal well is obtained in combination with a Peaeman well equation; and solving to obtain the productivity data of the horizontal well. According to the method, reasonable productivity prediction can be carried out on the shale gas reservoir directional fracturing horizontal well under the constraint of the complex fracture network.

The invention discloses an ultrasonic enhanced water-oil displacement recovery ratio experiment system based on CT real-time imaging, and belongs to the technical field of oil and gas exploitation experiments. The system is composed of a core clamping and pressure control system, an ultrasonic excitation system, an injection and extraction system, a monitoring and data acquisition system and a data analysis and optimization system. A core holder can accurately simulate underground reservoir pressure and fluid conditions. The ultrasonic excitation system reduces the oil-water interfacial tension through the cavitation effect and micro-vibration, and improves the fluidity and release effect of oil drops; the injection and extraction system is used for accurately controlling the injection flow rate and pressure of displacement liquid to form a stable oil displacement gradient; the monitoring system dynamically captures the core internal oil-water leading edge propulsion, residual oil distribution and ultrasonic cavitation bubble evolution process, and visualization of an ultrasonic energy transfer path under the pore scale is achieved for the first time. The system can effectively research the influence of ultrasonic enhancement on the water drive recovery efficiency, and provides experimental basis and technical support for improving the oilfield development efficiency.

The invention discloses an experimental system and method for multi-field coupling simulation of a reservoir pressure exhaustion process. The system comprises a true triaxial simulation cabin, a crustal stress loading device, a pore pressure applying device, a scouring pressurization circulating device and a sand production separation device, the true triaxial simulation cabin simulates the storage state of the experimental rock core in the well wall of the stratum development well; the crustal stress loading device applies three-dimensional crustal stress to the true triaxial simulation cabin; the pore pressure applying device applies a fluid medium to the experimental rock core in the true triaxial simulation cabin; the scouring pressurizing circulating device provides pressurized scouring fluid to circularly scour the true triaxial simulation cabin; and the produced sand separation device is used for carrying out solid-liquid separation on a produced sand mixture generated after washing and collecting solid matters separated in different washing time periods. Therefore, the method is suitable for evaluating the borehole wall stability problem in the open hole section oil extraction process and researching the borehole wall collapse and chipping form caused by fluid scouring, and precise simulation of the borehole wall instability and chipping form is achieved.

This invention relates to the field of collaborative well testing technology for coal reservoirs, specifically disclosing a constant flow rate-limited pressure collaborative control method and system for coal reservoir well testing. The method includes: collecting cluster-single-well dual-dimensional parameters; constructing a regional reservoir pressure field coupling model based on the dual-dimensional parameters, wherein the regional reservoir pressure field coupling model embeds fluid-structure interaction equations and a pulverized coal critical velocity model; configuring a cluster-single-well dual-level priority dynamic allocation rule based on the dual-dimensional parameters; and configuring a cluster-level multi-objective optimization algorithm with single-well flow deviation, single-well pressure, regional pressure field uniformity, and cluster pulverized coal blockage risk as constraint indicators. This invention successfully resolves the contradiction between rapid pressure relief and prevention of pulverized coal explosions, minimizing reservoir damage and wellbore blockage risks while ensuring well control safety, and significantly improving the success rate and data quality of coalbed methane well cluster testing operations.

The invention relates to the field of oil and gas resource exploration, and discloses a fracturing design method based on shale content three-dimensional geological modeling, which comprises the following steps: determining geological characteristics of a research area, integrating earthquake, logging and core data, analyzing reservoir deposition characteristics and shale content distribution, and combining porosity and permeability to establish a correlation model of a reservoir and shale content; the method comprises the following steps: establishing a shale content three-dimensional geologic model by adopting a sequential Gaussian simulation method by taking well data as hard data and seismic inversion data as soft data through petri l software, constructing a reservoir three-dimensional geologic model according to porosity, permeability and reservoir thickness, and fitting the shale content three-dimensional geologic model and the reservoir three-dimensional geologic model through a variation function to obtain a compressible reservoir model. By combining microseismic monitoring, acoustic logging and a pressure sensor, generation and extension of the crack and reservoir pressure change can be tracked in real time, it is ensured that the crack is effectively extended according to a design path, and a real-time feedback system provides accurate data support in the crack extension process.

The invention discloses a novel intelligent oil and gas reservoir numerical simulation method based on physical mechanism driving, and relates to the cross technical field of computational fluid mechanics and deep learning. Comprising the following steps of oil and gas reservoir mathematical model establishment and grid division, SE attention mechanism feature weight distribution, learnable wavelet operator neural network multi-scale feature extraction, physical constraint scaling of output of a pressure prediction branch and a saturation prediction branch, and performing spatial discretization on the partial differential equations in the S1 by adopting a finite volume method to construct a conservation type discretization format and the like. According to the method, intelligent high-precision numerical simulation of oil and gas reservoir seepage based on a physical mechanism driven neural network is realized, a deep learning method is combined with a physical equation, adaptive extraction of multi-scale features is realized through a learnable wavelet operator, sequential progressive prediction is realized through a transfer learning strategy, and the method is more accurate and efficient. On the premise of ensuring the physical consistency, the spatio-temporal evolution law of the pressure and saturation of the oil and gas reservoir can be efficiently and accurately predicted.

The application discloses a kind of Jurassic system reservoir control bottom water invasion profile control process selection method, comprising the following steps: S1, first, the cumulative oil production of reservoir, cumulative water production, cumulative injection, geological reserves, crude oil volume coefficient, formation water volume coefficient, comprehensive compression coefficient, crude oil original volume coefficient, formation original pressure and current reservoir pressure data are collected, then the data collected is used to calculate the water invasion amount of block in past years, and curve is drawn;S2, according to the water invasion amount of block in past years and water invasion amount curve trend, select profile control process;S3, according to the profile control process selected in step S2, the well group that needs profile control of Jurassic bottom water reservoir is profile controlled.The application calculates and characterizes the bottom water invasion condition of Jurassic system reservoir, calculates the different states of bottom water reservoir water invasion, and selects different profile control processes according to the different states of bottom water reservoir water invasion, so as to realize the purpose of controlling bottom water invasion and inhibiting water content.

This invention discloses a low-cost thermally activated pressure-controlled development method and system for improving the recovery rate of shallow gas in offshore areas. It relates to the field of shallow gas development technology. The method includes: deploying horizontal heating and water injection channels at the bottom, lower part, or near the outer boundary of the shallow gas reservoir; transporting and injecting high-temperature seawater from the sea surface or near the sea surface into the bottom or lower reservoir layer; employing a slow depressurization and pressure window control method in the production well to maintain the reservoir pressure within a range higher than the gas pore connectivity disruption pressure but lower than the caprock breakthrough pressure; installing a variable-diameter sand-control production cylinder in the open-hole production section of the production well; and transporting the developed natural gas to a seabed natural gas hydrate formation shed or container, utilizing the low-temperature, high-pressure environment of the seabed to form natural gas hydrates, thereby achieving low-cost storage and transportation. This invention achieves shallow gas reservoir heating, dissolved gas desolvation, gas-water displacement, pressure control and stable production, and efficient sand control with low energy consumption, thereby improving the recovery rate and economic efficiency of shallow gas development in offshore areas.

The invention provides an experimental device and method for simulating edge-bottom water reservoir development. The experimental device comprises a sand filling model, a water injection assembly, an oil injection assembly and a plurality of simulated oil wells. The sand filling model is filled with a plurality of sand layers and interlayers, the sand layers and the interlayers are alternately distributed at intervals in the height direction, and the permeability of the interlayers is lower than that of the sand layers; the sand layer and the interlayer have the same inclination angle; the water injection assembly is arranged at the bottom of the sand-packed model and used for injecting water into the bottom of the sand-packed model so as to simulate the upward coning process of bottom water and the invasion process of edge water in the sand layer dip angle direction at the same time. The oil injection assembly is used for saturating crude oil to the sand layer to target reservoir pressure to simulate the reservoir; and the plurality of simulated oil wells are arranged in the sand layer, are distributed along the height direction of the sand-packed model and the dip angle direction of the sand layer, and are used for producing oil from the sand-packed model at set pressure. The influence of the combined action of edge water and bottom water on the edge-bottom water reservoir development effect can be simulated, so that the actual well spacing and oil production process is guided.