175 results about "Reservoir pressure" patented technology

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 reservoir numerical simulation, and discloses a polymer flooding reservoir rapid simulation optimization method considering sedimentary facies constraints, which comprises the following steps: identifying sedimentary facies boundaries according to distribution characteristics of sedimentary facies, and establishing a connected network model considering the sedimentary facies constraints on the basis of the sedimentary facies boundaries, well positions and various sedimentary facies attributes; carrying out one-dimensional grid division on the connected network model, converting the connected network model into a grid connection format of a universal simulator, and solving the connected network model by adopting the universal simulator to obtain pressure and saturation solutions; establishing an automatic historical fitting mathematical model based on sedimentary facies and oil reservoir constraint conditions; the economic net present value is used as an index, the water injection rate, the liquid production rate and the polymer injection rate of each well are used as optimization variables, the differential evolution algorithm is used, the total polymer injection amount and the oil reservoir pressure are restrained, and an oil reservoir injection and production optimization mathematical model is established. According to the method, the oil reservoir is optimized by comprehensively considering the characteristics of the oil reservoir after water flooding is converted into polymer flooding, so that rapid decision-making of the oil field and guidance of oil field construction are realized.

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.

The invention relates to the technical field of oil production engineering, in particular to a fracturing process for a tight oil horizontal well, which comprises the following steps: acquiring geological data information; determining a rock stratum state according to the pore reference value of the to-be-constructed area and the tight oil enrichment degree, and determining a target stratum setting mode according to the rock stratum state; perforation is conducted on the toe end of the horizontal well, and fracturing operation is conducted on all target layers after perforation of the toe end of the horizontal well is completed; the injection amount of CO2 fracturing fluid is determined according to the length of the reference oil-containing sandstone, and the content of a thickening agent is determined according to the reservoir pressure; if the fracture density is smaller than the preset fracture density, it is determined that the fracturing fluid adjusting mode of the rear target layer is an optimization mode determined according to the gravel particle size difference degree or adjustment is conducted according to the injection pressure of CO2 fracturing fluid according to the gravel state of the proppant; after the CO2 fracturing fluid is injected into the whole well section, the well closing time is determined according to the comprehensive reference value; and drilling and removing the bridge plug. The fracturing effect can be improved, and the exploitation efficiency of the tight oil horizontal well is improved.

The invention provides a shale gas reservoir pressure fracture network expansion numerical simulation method, which comprises the following steps of: performing multi-layer coring scanning on a shale gas reservoir, and constructing a three-dimensional digital core model; constructing digital core flow numerical simulation by adopting a lattice Boltzmann method to obtain flow physical parameters; constructing digital rock core strain simulation by adopting a finite element method to obtain rock mechanical parameters; establishing a shale gas reservoir complex fracture network expansion mathematical model by considering a fluid-solid coupling effect, and constructing a numerical solution algorithm by combining a finite element method and a finite volume method; constructing a quantitative characterization method for the shape of the fracture network after pressing, and evaluating the size and complexity of the transformed fracture network; the method fills the gap of fracturing simulation technology research, and has the characteristics of high calculation precision, short calculation period and low cost.

A method for estimating a volume of a reservoir to be filled from a station for distributing a pressurized fluid including injecting a flow of pressurized fluid into the reservoir, determining a pressure variation in the reservoir, the pressure variation being determined with respect to an initial pressure, determining an amount of the fluid flow injected into the reservoir, and estimating the volume of the reservoir to be filled, on the basis of the amount of the fluid flow injected into the reservoir and on the basis of the pressure variation in the reservoir after the injection of the fluid flow. Wherein the volume of the reservoir to be filled is also estimated on the basis of an injection temperature, and on the basis of a temperature variation in the reservoir after the injection of the fluid flow.

The layered water distributor comprises multiple stages of layered water distributors which correspond to water injection layers and are connected between two adjacent oil pipes, packers are arranged between the outer portions of the oil pipes at the upper end and the lower end of each stage of layered water distributor and a sleeve in a sealed mode, and the top end of the oil pipe at the uppermost end is communicated with a ground water injection pipeline. A water injection regulating valve and a flow meter are arranged on the ground water injection pipeline, and the water injection regulating valve and the flow meter are in common electric signal connection with a ground layering controller. The underground layered water injection rate is metered by the ground layered controller and linked with the layered water distributor of the underground target interval, layered alternate pulsating water injection is carried out, interlayer interference factors are overcome, and layered accurate water injection is achieved; additional fluid channeling, gravity fluid channeling and capillary force fluid channeling generated by pulsation type unstable water injection solve the problem of invalid water injection of dominant channels. Oil reservoir pressure field changes generated by layered pulsating water injection expand the water injection sweep efficiency, and the water injection recovery efficiency is greatly improved.

The invention belongs to the technical field of gas reservoir numerical simulation, and relates to a physical property time-varying characterization method and system for a loose sandstone gas reservoir, and the method comprises the following steps: determining physical property time-varying sensitive parameters of the loose sandstone gas reservoir; constructing a permeability-gas reservoir pressure equation according to the reservoir physical property time-varying sensitive parameters; and based on the permeability-gas reservoir pressure equation, constructing a reservoir physical property time-varying model of the loose sandstone gas reservoir. The system comprises a determination module, a first building module and a second building module. By applying the physical property time-varying characterization method for the loose sandstone gas reservoir, the historical fitting precision can be improved, the residual gas distribution rule can be accurately known, and the gas reservoir recovery ratio can be accurately predicted, so that the accuracy of development prediction 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.

Determining three-dimensional (3D) minimum horizontal stress magnitude from mechanical properties, rock strength properties, reservoir pressure, vertical stress, a fracture density index distributed across a 3D geological grid, and formation testing data from formation tests such as a formation integrity test (FIT), a leak off test (LOT), an extended leak off test (XLOT), and a diagnostic fracture injection test. The 3D minimum horizontal stress magnitude may be used to determine sweet spots for hydraulic fracturing operations.

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 discloses a carbon dioxide geological sequestration quantity evaluation method considering the influence of sealing performance of a cover layer. The method comprises the following steps: acquiring a structural plane and a thickness distribution map of the cover layer by utilizing a three-dimensional geological model; obtaining the change rule of the cap layer breakthrough pressure along with the depth; the hydraulic fracturing pressure of the cover rock is obtained, and a cover rock damage envelope line and the cover rock breakthrough pressure are drawn; and finally determining and obtaining the maximum allowable reservoir pressure based on the cap stratum breakthrough pressure, the reservoir and the cap stratum fracture pressure. The maximum reservoir pressure after maximum permissible carbon dioxide injection of reservoirs in different regions is utilized to obtain a regional saline water layer carbon dioxide limit sequestration amount distribution map, the limit sequestration potential of the regions is determined, and the problem that an existing carbon dioxide geological sequestration amount evaluation method does not consider the influence of the sealing performance of a cover layer is solved. The method breaks through the basic theory that the current reservoir pressure cannot exceed the overburden breakthrough pressure, provides a new thought for carbon dioxide geological storage potential evaluation, and is suitable for large-scale carbon dioxide geological utilization and 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.

The invention relates to a heterogeneous reservoir pressure prediction method based on multi-modal data and knowledge hybrid driving. The method comprises the following steps that a heterogeneous reservoir permeability field and pressure field multi-modal data set is established; establishing a deep neural network model for knowledge guidance, and training the deep neural network model based on the multi-modal data set; and inputting the acquired permeability field and spatio-temporal information into the trained deep neural network model to obtain the predicted oil reservoir pressure. According to the method, the requirement of a traditional deep learning method for the high-cost training data volume is remarkably reduced, the algorithm performance and prediction precision are improved, and the method has important significance for intelligent development of an oil field and improvement of the recovery ratio.

The invention discloses a condensate gas adsorption and desorption capability testing method, which comprises the following steps: screening reservoir rock broken samples, loading the samples into a sample cylinder, injecting methane to make the gas pressure of the sample cylinder higher than the condensate gas dew point pressure, injecting mixed gas into a reference cylinder to reach the set pressure, communicating the sample cylinder with the reference cylinder to prepare condensate gas, and testing the adsorption and desorption capability of the condensate gas. Then injecting condensate gas, increasing the pressure to reservoir pressure from a set pressure gradient, measuring the adsorption amount of the rock to the condensate gas at different pressure points above the dew point pressure, and then reducing the pressure in a gradient manner to measure the desorption amount of the rock to the condensate gas at different pressure points. Based on the constant mass expansion experiment result of the condensate gas, the measurement error of the reverse condensate oil volume on the gas desorption amount is eliminated, and the adsorption / desorption capacity of the rock sample on the condensate gas is evaluated. According to the scheme, the adsorption / desorption amount of the condensate gas can be accurately measured, and reserve calculation and efficient development of the condensate gas reservoir are facilitated.

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.

The invention discloses a method and device for determining the position of a reservoir fluid channeling channel and a storage medium, and belongs to the technical field of oil and gas exploitation and carbon sequestration. The method comprises the steps that in the process of injecting preset gas into a target reservoir, it is determined that a channeling channel exists in the target reservoir; performing grid division on the region where the target reservoir is located to obtain a plurality of reservoir grid regions; acquiring a first reservoir gas flow rate and a first reservoir pressure value corresponding to the current time step of each reservoir grid region, and a second reservoir gas flow rate and a second reservoir pressure value corresponding to the previous time step of each reservoir grid region; and according to the first reservoir gas flow rate, the first reservoir pressure value, the second reservoir gas flow rate and the second reservoir pressure value, determining a target reservoir grid region covered by the channeling channel in the plurality of reservoir grid regions so as to obtain the position of the channeling channel in the target reservoir, according to the invention, the position of the channeling channel in the target reservoir can be accurately determined.

The invention discloses an anhydrous fracturing in-situ low-permeability reservoir pressure-driving-seepage integrated test device and method.The device comprises a triaxial pressure chamber system, a fracturing system and a seepage system, the fracturing system comprises a liquid nitrogen storage tank, a self-pressurization liquid nitrogen tank and a pressurization device, the self-pressurization liquid nitrogen tank is connected with the liquid nitrogen storage tank through an injection pipe, and the pressurization device is connected with the fracturing system; a port of the injection pipe extends to the inner bottom of the liquid nitrogen storage tank; the interior of the liquid nitrogen storage tank is connected with a supercharging device and is connected with a fracturing liquid inlet of the triaxial pressure chamber system through a corresponding control valve, and the fracturing liquid inlet is connected with a fracturing pipe in the triaxial pressure chamber system; and a bottom outlet of the liquid nitrogen storage tank is connected with a fracturing liquid inlet of the triaxial pressure chamber system through a corresponding control valve and a preheater. According to the invention, liquid nitrogen is used as a low-temperature fluid, and a coal body sample is fractured with large displacement and high pressure, so that a coal rock fracture process and a monitoring process in a liquid nitrogen fracturing process and a seepage process under an in-situ condition are really simulated under a low-temperature condition.

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.