354 results about "Water saturation" patented technology

A porous media grouting test system and method taking temperature effects into consideration. The system comprises a porous media formation simulation model (1), a grouting system (2), a water level adjustment system, a formation temperature control system and a data analysis system, wherein the porous media formation simulation model (1) is used for simulating a porous media formation; the water level adjustment system and the formation temperature control system are used for simulating the conditions of different water saturation levels and different water temperatures and ground temperatures; and the data analysis system is used for comparing different time-series data collected by sensors such as a temperature sensor and a pressure sensor with data such as temperature data and pressure data that is obtained by means of coupled solving of a heat transfer equation and a momentum equation, so as to verify and analyze a grouting diffusion path. Free simulation of different water saturation levels is realized by means of a water level adjustment system, and simulation of different ground temperatures is realized by means of a formation temperature control system, thereby realizing the research on grouting diffusion under different water levels and different water temperatures and ground temperatures.

The invention relates to the technical field of rock sample oil-water saturation determination based on a nuclear magnetic technology, and provides a shale sample oil-water saturation intelligent determination method based on a two-dimensional nuclear magnetic technology, and the method comprises the following steps: collecting volumes, echo signals and signal-to-noise ratios of a preset number of rock samples; marking a target rock sample and a comparison rock sample, and determining a volume influence comprehensive interference degree and a noise amplification coefficient of a target echo signal; obtaining a denoised target echo signal according to the target echo signal, the volume of the rock sample corresponding to the target echo signal and the noise amplification coefficient of the echo signal; according to experiments of rock sample two-dimensional nuclear magnetic oil-water distribution, pore attributes and the like, a two-dimensional nuclear magnetic T1-T2 map is divided into an invalid pore area and an effective pore area of a rock sample corresponding to the two-dimensional nuclear magnetic T1-T2 map and an oil-water distribution area of the effective pore area, a fluid close to reservoir oil-water distribution is adopted to recover a two-dimensional nuclear magnetic spectrum of the rock sample, and the oil-water content corresponding to a nuclear magnetic signal is extracted; and obtaining a rock sample oil-water saturation determination result based on the nuclear magnetic technology.

The invention discloses a low-permeability gas reservoir productivity prediction method, a storage medium and a low-permeability gas reservoir productivity prediction device, and belongs to the technical field of low-permeability gas reservoir development. Based on the gas-water two-phase motion equation, establishing a gas phase productivity equation considering the high-speed non-darcy effect, the starting pressure gradient and the stress sensitive effect; establishing a water yield calculation formula considering the starting pressure gradient and the stress sensitive effect; the water-phase relative permeability is expressed on the basis of the relation between the gas-water relative permeability ratio and the water saturation; using a gas-water relative permeability model to express the gas-phase relative permeability considering the active degree of the water body; and substituting the gas phase relative permeability into the gas phase productivity equation. According to the method, the influence of the water body active degree, the starting pressure gradient and the stress sensitive effect on the productivity of the gas reservoir is considered, the multi-factor coupled productivity prediction model including formation water invasion is established, the technical problem that the productivity of the low-permeability gas reservoir is difficult to accurately predict through a traditional method is solved, and the development efficiency and economic benefits of the low-permeability gas reservoir are effectively improved.

The invention discloses a shale hydrocarbon expulsion efficiency evaluation method, device, equipment and medium, and relates to the technical field of shale gas exploration and developing.The shale hydrocarbon expulsion efficiency evaluation method includes the steps that hydrocarbon generation quantity charts of shale under different total organic carbon TOC grades are constructed; testing the water saturation of the core sample of the shale to obtain the water saturation rate of the core sample; carrying out oil washing treatment on the rock core sample, and carrying out porosity test to obtain rock porosity and rock apparent density; obtaining a crude oil sample of a production layer where the core sample is located, and performing a crude oil physical property experiment to obtain crude oil density; when key parameters such as water saturation rate, rock porosity, rock apparent density, crude oil density and shale hydrocarbon generation quantity charts under different total organic carbon TOC grades of a core sample and key parameters of hydrocarbon release and migration in a hydrocarbon expulsion process are measured, a dynamic measurement process is adopted, and the dynamic measurement process can realize dynamic simulation of a hydrocarbon migration path; and finally, accurate evaluation of the shale hydrocarbon expulsion efficiency is realized.

The invention discloses a hydrate-containing porous medium resistivity model construction method considering hydrate heterogeneous distribution, and the method comprises the following steps: 1) manufacturing a rock core according to the rock composition of a target hydrate reservoir, and scanning the pore throat structure of the rock core through CT; 2) generating a hydrate in the core, and scanning the occurrence state of the hydrate through CT (Computed Tomography); 3) establishing a digital core model based on CT scanning data, and applying an electrostatic field; 4) changing hydrate saturation parameters in the model, and calculating the resistivity of the model through numerical simulation; 5) calculating the critical water saturation of the hydrate; and (6) fitting by taking the critical water saturation as a boundary to obtain a resistivity segmentation calculation model. According to the method, a hydrate-containing porous medium resistivity model is established based on a real rock core size, and an electric field simulation means is utilized to calculate a hydrate-containing porous medium resistivity value. In combination with CT scanning data, an undetermined coefficient of a porous medium resistivity calculation formula in a hydrate thermal decomposition experiment is obtained through electric field simulation, and a basis is provided for hydrate reservoir electric heating development.

The invention discloses a method for evaluating the crude oil utilization rate during shale oil in-situ heating modification exploitation, and is applied to the field of oil development. The method comprises the following steps: (1) constructing a three-dimensional grid model of shale oil reservoirs between two horizontal wells, and determining parameters such as initial temperature, initial fluid pressure, initial porosity, initial oil saturation, initial gas saturation, initial water saturation and initial dissolved gas volume of three-dimensional grid units of each reservoir; (2) determining the pressure of each reservoir three-dimensional grid unit when the fluid pressure is balanced according to the shale oil layer section bottom hole pressure and the reservoir displacement pressure gradient; (3) according to the characteristics of a temperature field, a pressure field and the like of the in-situ heating shale oil reservoir, obtaining three-dimensional grid unit temperature and instantaneous fluid pressure parameters of each reservoir, and determining porosity and fluid saturation at each time point; and (4) according to the instantaneous fluid pressure and the balanced fluid pressure of the three-dimensional grid unit of each reservoir, determining the oil, gas and water production quantity and the production rate of the grid unit of each reservoir in combination with the oil, gas and water saturation.

The invention relates to the technical field of water flooding gas reservoirs, in particular to a rock core displacement fluid saturation testing method and a testing device thereof.The method comprises the steps that S1, the original formation pressure and temperature of a gas reservoir are obtained; s2, obtaining a rock core, and testing physical property data of the rock core; then carrying out nuclear magnetic testing on the rock core; s3, saturating the rock core with formation water, and then carrying out nuclear magnetic testing; s4, carrying out gas drive water seepage test on the rock core according to the data in the S1, and obtaining the drive water quantity; s5, performing nuclear magnetic test on the depleted rock core; s6, obtaining the irreducible water saturation of the depleted rock core according to the nuclear magnetic test results of the steps S2, S3 and S5; s7, the total irreducible water saturation of the rock core is obtained according to the rock core physical property data, the displacement water amount and the irreducible water saturation of the rock core after exhaustion; the device comprises a drying oven, a first container, a second container, a core holder, a confining pressure pump, a displacement pump, a back pressure assembly, a receiving container and an electronic balance. The accuracy of fluid saturation determination can be improved.

The invention provides a tight sandstone gas reservoir formation water division method based on mercury intrusion and online nuclear magnetic resonance, and relates to the field of gas reservoir formation water production, and the method specifically comprises the following steps: obtaining a tight sandstone core standard rock sample; cutting the rock core into two sections, and performing a high-pressure mercury injection experiment on the first section of the rock core; and scanning the nuclear magnetic resonance signal T2 spectrum curve of the rock core in the completely saturated water state and the area of the nuclear magnetic resonance T2 spectrum curve. And carrying out gas drive and nuclear magnetic scanning experiments. And sequentially increasing the displacement pressure differences to obtain a nuclear magnetic resonance correction curve under different displacement pressure differences. And drawing a water saturation and displacement pressure difference relation curve, and defining the critical pressure difference of different types of formation water production according to the curve form and the slope change rule. And processing the data to obtain the formation water production rule of the tight sandstone gas reservoir in different states. According to the technical scheme, the problem that in the prior art, the critical output pressure difference and the dynamic output rule of various types of formation water in different pore diameter ranges cannot be quantitatively represented is solved.

The invention discloses a well logging water saturation calculation method and device, equipment and a medium, and relates to the technical field of oil and gas field exploration and development geological research, and the method comprises the steps: preprocessing a well logging curve of a crack and pore composite compact sandstone reservoir, and calculating the parameter information of a crack according to the processed curve; correcting the deep lateral resistivity value in the processed curve to obtain a corrected resistivity value; calculating a target exchange coefficient and a resistance increase rate of the rock core; determining a logging cementation index according to the parameter information of the fracture and the target exchange coefficient, dividing reservoir types, and fitting the core water saturation and the resistance increase rate of different reservoir types to obtain fitting results; obtaining a logging saturation index and a logging lithologic coefficient according to an Archie formula and a fitting result, and determining the logging water saturation based on the corrected resistivity value, the logging cementation index, the logging saturation index and the logging lithologic coefficient. And the logging water saturation can be accurately calculated.

Method and systems are provided that characterize a geological formation, which involve collecting or obtaining electrical signal data that results from interaction of electrical signals with the formation. The electrical signal data is processed to determine data characterizing relative permittivity and conductivity of the formation. The data characterizing relative permittivity and conductivity of the formation are used as inputs to models to determine data characterizing water saturation of the formation, particularly useful in formation evaluation and reservoir saturation dynamic monitoring in fresh water and mixed salinity environments.

The invention provides a method and system for determining gas-water distribution of a tight sandstone gas reservoir, and the method comprises the steps: building a multi-factor hierarchical control mode of the gas-water distribution of the tight sandstone gas reservoir, and embedding control factors step by step in the modeling process of bound water and movable water based on the multi-factor hierarchical control mode of the gas-water distribution, and a total water saturation model is established by taking a bound water and movable water merging model as spatial constraint, so that quantitative characterization of gas-water distribution under multi-factor control is realized.

The present application relates to new systems and methods of quantifying hydrocarbon saturation using measured acoustic logs. The methods and systems herein can accurately quantify the water saturation and hydrocarbon percentage in a low resistivity low contrast shaly sand reservoir where previous methods would indicate the reservoir was wet. In an embodiment, the disclosed system utilizes acoustic logging equipment or tools and techniques to transmit and / or record acoustic signals. Acoustic logging equipment operates by generating acoustic signals and detecting the acoustic signals after the acoustic signals pass through one or more geologic formations.

The invention provides a deep water gravity flow gas field reservoir water saturation earthquake prediction method based on TDCN-TransNet. The method comprises the following specific steps: a TDCN-TransNet network architecture comprises an input processing layer, a dual TWT position code, a TDCN module, a Transformer encoder layer and an output layer; mapping the features to a hidden dimension in an input processing layer through linear full connection; a dynamic Gaussian convolution kernel and a CBAM attention mechanism are embedded in the TDCN, and modeling of a nonlinear relation between an elastic parameter and saturation is enhanced through multi-scale time sequence feature extraction; tCBlock is integrated on a Transform encoder layer, and long-distance sequence dependence is captured by using attention pooling and an SE channel excitation mechanism; a TWT position code is introduced between the TDCN and the Transform, and sequence position information is enhanced; constructing a combined loss function of a mean square error and L2 regularization; finally, training and reasoning are conducted based on the model, and high-precision water saturation prediction is achieved. The method provided by the invention has high generalization and accuracy, and shows excellent prediction performance in a complex geological environment of a deepwater gravity flow reservoir.

The invention belongs to the technical field of oil and gas development, and discloses a formation water comprehensive compression coefficient measuring method and system.The method comprises the steps that a fracture network distribution rule and pore structure parameters are extracted; preparing a micro-fluidic chip; preparing formation water fluid containing dissolved gas, and injecting the formation water fluid into the micro-fluidic chip; carrying out a formation water failure development experiment under a reservoir in-situ condition, and recording gas-water saturation and pressure change in the micro-fluidic chip; quantifying the variation of the volume of the precipitated bubbles along with the pressure drop, and calculating a first compression coefficient contributed by the dissolved gas part and a second compression coefficient contributed by the formation water body part; and superposing the two coefficients to obtain the formation water comprehensive isothermal compression coefficient. According to the method, the formation water gassing expansion process can be monitored in real time, the formation water comprehensive isothermal compressibility coefficient can be more accurately calculated in combination with gas-water saturation and pressure change, and the problem that fluid seepage and fluid characteristics of the fractured low-porosity sandstone gas reservoir cannot be fully reflected is solved. The system has the same advantages as the method.

The invention discloses a soil solidification effect detection and analysis system and method, and relates to the field of soil solidification effect detection.The soil solidification effect detection and analysis method comprises the steps that based on the sedimentation characteristics of a solidification material, soil is divided into a bottom sedimentation sudden change zone, a middle sedimentation gradual change zone and a top sedimentation stable zone in the depth direction, and the minimum operation thickness of a sampling tool serves as the reference layer thickness; dividing non-equidistant sampling layers according to different multiples in each settlement zone to intercept columnar soil samples; performing an initial dynamic load test on the original soil sample, then performing circulating saturated water drying treatment on the same soil sample, and applying the completely same dynamic load mode again; a water circulation effect in a natural environment is simulated by performing vacuum water saturation and constant-temperature drying circulation treatment on a soil sample for multiple times and combining a dynamic load test after water damage. Through non-equal-interval stratified sampling and multi-round dry-wet cycle testing, stratified dynamic and high-precision quantitative evaluation of the water damage resistance of soil solidification is achieved.

The invention discloses a laboratory adsorption gas calculation method based on isothermal adsorption-nuclear magnetic resonance combined measurement, and relates to the technical field of exploration geophysics. According to the invention, on the basis of isothermal adsorption-nuclear magnetic resonance combined measurement experiment, 23MHz nuclear magnetic resonance experiment is utilized; nuclear magnetic signal conversion of bound water-adsorbed state methane is carried out through nuclear magnetic resonance T2 spectrums of coal rocks with different water saturations and T2 spectrums measured through a coal rock isothermal adsorption-nuclear magnetic resonance combined measurement experiment to obtain the hydrogen content of the adsorbed state methane, then the amount of substance of the adsorbed state methane is obtained, and finally the volume of the adsorbed state methane is obtained. The method comprises the following steps: firstly, measuring and determining the content of bound water in the coal rock by adopting a 25mm sample tube and the current minimum nuclear magnetism callback interval, then carrying out bound water-adsorbed gas nuclear magnetism signal conversion on the sample tube used in an isothermal adsorption-nuclear magnetism combined measurement experiment to obtain the hydrogen content of the adsorbed gas, further obtaining the amount of substance of the adsorbed gas, and finally obtaining the volume of the adsorbed gas.

The invention belongs to the technical field of oil and gas reservoir engineering and multiphase seepage dynamic monitoring, relates to a characterization method of seepage behaviors of multiphase fluid in a porous medium, and particularly provides a dynamic construction method of a multiphase displacement capillary pressure-saturation relationship based on nuclear magnetic resonance. Comprising the following steps: S1, acquiring a low-field nuclear magnetic resonance relaxation spectrum of a porous medium in a gas-water two-phase displacement process; s2, determining two-phase fluid interfacial tension, a wetting contact angle and a rock surface relaxation rate; s3, determining the dynamic cut-off relaxation time of the displacement stage; s4, calculating equivalent capillary pressure; the residual water saturation is calculated, and the equivalent capillary pressure is the capillary pressure corresponding to the current displacement stage and is used for constructing a capillary pressure-saturation curve. According to the method, the capillary pressure change in the porous medium can be obtained only through spectral analysis without a centrifugal or mercury injection experiment.

The invention discloses a method, a device and equipment for identifying the flooding level of a to-be-developed drilling well and a medium. The method comprises the following steps: determining typical water flooded layers, and determining resistivity thresholds between the water flooded layers; rock-electricity parameters and formation water resistivity corresponding to the to-be-developed drilling well are determined; determining a porosity parameter corresponding to the to-be-developed drilling well, and determining a critical change curve between the critical water saturation of the to-be-developed drilling well under different water flooded layers and the porosity parameter based on a resistivity threshold value, a rock electricity parameter, the formation water resistivity and the porosity parameter; and on the basis of the porosity parameter, the rock electricity parameter, the formation water resistivity, the conventional logging curve and the critical change curve corresponding to the to-be-developed drilling well, determining a flooding level identification result corresponding to the to-be-developed drilling well. According to the invention, accurate identification of the to-be-developed well flooding level can be realized, the flexibility and accuracy of well flooding level identification are greatly improved, and the identification efficiency is improved.

The invention relates to the technical field of coal reservoir development, in particular to a well-seismic data collaborative inversion and reservoir prediction method based on a rock physical model. The method comprises the following steps: acquiring well logging data and seismic data of a target reservoir, preprocessing the data, and ensuring the matching consistency of the data in time and depth; a dynamic rock physical model is constructed, reservoir heterogeneity parameters are introduced into the model, and the heterogeneity parameters are represented through rock core experiments or reservoir physical property analysis and used for describing the dynamic relation between the porosity, the permeability and the water saturation and the elastic parameters; on the basis of the dynamic rock physical model, well logging constraint and seismic reflection information in a well are jointly optimized by adopting an adaptive collaborative inversion algorithm to obtain three-dimensional distribution of longitudinal wave velocity, transverse wave velocity and density; by introducing a dynamic rock physical model, an adaptive collaborative inversion algorithm and a multi-scale convolutional neural network and combining well-seismic data joint processing, the prediction precision and resolution of reservoir physical properties can be improved.

The invention discloses a downhole reservoir oil-gas phase state fluid property identification method, device and equipment and a medium, and relates to the field of oil well exploration, the method comprises the following steps: collecting related data of cable formation test during pumping operation, and forming a data set; constructing a cable formation test three-dimensional seepage numerical simulation model, and discretizing and solving a mass conservation equation in the model to obtain a pressure distribution field and a water saturation distribution field; establishing a probe suction port fluid hydrocarbon content calculation model according to the pressure distribution field, the water saturation distribution field and probe node fluid spherical flow characteristics; utilizing the data set and a probe suction port fluid hydrocarbon content calculation model to simulate and calculate a hydrocarbon content curve of oil and gas classification of the same type of stratums, and constructing a clustering chart; and comparing the hydrocarbon phase breakthrough time of the actual formation test operation of the same type of to-be-processed formations with the clustering chart, and identifying the fluid properties of the to-be-processed formations. According to the invention, the fluid property of the stratum to be processed can be identified conveniently and accurately.

The invention discloses a shale gas exploration method, device, equipment and medium, and relates to the technical field of shale gas exploration and development, and the shale gas exploration method comprises the following steps: obtaining respective mass fractions of long quartz minerals, clay minerals and carbonate minerals of a shale reservoir in each well section of a current well, determining the maximum difference degree index, the local onrush characteristic index and the relative change amplitude index of the corresponding mineral content of the shale reservoir in each well section based on each mass fraction, and constructing a comprehensive heterogeneity index representing the shale reservoir in each well section; the porosity, the water saturation and the total gas content of the shale reservoir in each well section are obtained, so that the initial sweet spot grade of each well section is divided; performing grade correction on the initial dessert grade of the corresponding well section according to each comprehensive heterogeneity index to obtain a target dessert grade corresponding to each well section after correction; and determining a well track optimization scheme and a fracturing design scheme based on the target dessert grade so as to carry out corresponding shale gas exploration operation. And accurate shale gas exploration is realized.

A method for acquiring the storage potential of a saline aquifer. The method comprises: acquiring the area of a research zone, the density of carbon dioxide under a stratum pressure, the thickness of an oil reservoir, the porosity of the oil reservoir, the irreducible water saturation of the oil reservoir, a reservoir fluid volume coefficient, a carbon dioxide storage efficiency factor, and stratum data; on the basis of the stratum data, determining estimated storage areas; on the basis of the area of the research zone and the estimated storage areas, determining a target storage area; and on the basis of said values, calculating a storage potential value of a saline aquifer in a target region. Further disclosed are an apparatus (400) for acquiring the storage potential of a saline aquifer, and an electronic device (500), a storage medium, a computer program product and a computer program.

The invention discloses an attenuation rock physical quantity plate construction method, electronic equipment, a storage medium and a device. The method comprises the following steps: acquiring rock physical parameters of a tight sandstone reservoir rock sample under different confining pressures and water saturation based on a variable fluid rock physical experiment, analyzing the sensitive degree of each rock physical parameter to a fluid based on a fluid indication factor, and further determining a sensitive parameter with high sensitive degree to the fluid, and establishing a dual-dual pore medium model, obtaining a change relationship between each sensitive parameter and the rock reservoir characteristic parameter based on the dual-dual pore medium model, and constructing an attenuation rock physical quantity plate based on each sensitive parameter and the corresponding change relationship. According to the method, the attenuation rock physical quantity plate for introducing attenuation characteristic fluid identification is constructed, the porosity and saturation of the tight sandstone reservoir can be accurately predicted aiming at the condition that the tight sandstone reservoir simultaneously contains a pore structure and fluid heterogeneity, and a theoretical support is provided for fine prediction of the gas-bearing property of the tight sandstone reservoir.

The invention provides a residual oil saturation prediction method based on a percolation mechanism constraint agent model, and relates to the technical field of oil reservoir development, and the method specifically comprises the following steps: generating a water saturation field data set for an oil-water two-phase system by using an oil reservoir numerical simulator, and dividing the water saturation field data set into a training set and a test set; constructing an end-to-end proxy model based on the three-dimensional convolutional neural network and Informer; under the constraint of a seepage mechanism, training the end-to-end proxy model by using the training set; and inputting the test set into the trained end-to-end agent model to obtain a water saturation field prediction result, and drawing an image to represent remaining oil saturation distribution. According to the technical scheme, the problems of high model calculation complexity and low prediction accuracy in the prior art are solved.

The invention provides a method and a device for measuring oil-water seepage capacity and comprehensive flow capacity of a sandstone reservoir, and relates to the technical field of petroleum and natural gas development, and the method comprises the following steps: measuring basic parameters of a core model, and obtaining an oil-water relative permeability curve; respectively carrying out CT scanning to obtain a reference CT value, saturating the rock core with water, and then carrying out CT scanning; utilizing oil-displacing water to establish a bound water state and performing CT (Computed Tomography) scanning; injecting water into the rock core for displacement, and performing CT scanning at different injection rate nodes to obtain a real-time image; and calculating oil-water saturation distribution at each position according to the CT image, carrying out grid division on the rock core, reading a corresponding relative permeability value for each grid, and calculating the phase permeability and the comprehensive flow capacity of each grid. According to the method, the macroscopic relative permeability curve and the microcosmic saturation field are subjected to data fusion, quantitative partition evaluation of the flow capacity of different areas of the heterogeneous reservoir is achieved, and the evolution rule of the flow capacity of the reservoir along with the development process can be dynamically tracked.

The invention discloses a method, a system, equipment and a medium for detecting an oil-water two-phase relative permeability curve, and belongs to the technical field of oil-gas field development technologies. The detection method of the oil-water two-phase relative permeability curve comprises the following steps: washing oil and drying a rock core sample, vacuumizing the rock core sample, and injecting formation water into the rock core sample, so that the rock core sample reaches a saturated water state; injecting crude oil into the core sample at a preset oil reservoir temperature to enable the core sample to reach a saturated oil state; performing water-displacing oil operation on the rock core sample at a preset flow rate, and scanning the rock core sample at a plurality of scanning nodes by using a CT (Computed Tomography) scanning device; oil saturation and water saturation are calculated according to an actually measured rock core CT value, and parameter fitting is performed on the Corey model according to the oil saturation and the water saturation to obtain an oil-water two-phase relative permeability curve. The method can accurately detect the oil-water two-phase relative permeability curve of the rock core.

The invention discloses a method and a device for determining a gas reservoir water plugging and pore plugging radius boundary based on a capillary tube bundle, and the method is characterized in that the method comprises the following steps: collecting physical property data of a tight gas reservoir, and obtaining a capillary tube bundle pore diameter sample set; according to the capillary tube bundle pore diameter sample set, single-tube gas-water two-phase flow is calculated one by one; accumulating the single-tube gas-water two-phase flow to obtain the total flow of a capillary tube bundle under different water saturations, and obtaining a simulated water-gas ratio according to the total flow of the capillary tube bundle; according to the simulated water-gas ratio, obtaining a global optimal solution of the maximum permissible plugging pore radius; and obtaining a field recommendation scheme according to the global optimal solution of the maximum allowable plugging radius. According to the method, the critical plugging aperture under different reservoir conditions can be accurately identified, and the gas production capacity and the water control effect are effectively considered.

The invention discloses a carbonate rock water saturation modeling method and device based on pore structure classification, and belongs to the technical field of rock physics and well logging interpretation. Carrying out matched conventional pore permeability, rock electricity, casting body slice, nuclear magnetic resonance and constant-speed mercury injection experiments on the reservoir core; dividing pore structures into four types according to core casting body sheet characteristics, nuclear magnetic resonance T2 spectrum distribution characteristics and capillary pressure curve forms; the actual water saturation of the reservoir rock core is obtained according to the nuclear magnetic resonance experiment in the rock core saturation and centrifugal state; respectively fitting rock electrical parameters for the four pore structure types; and calculating the water saturation of the whole well section in combination with an Archie formula. According to the method, the relation between the carbonate rock pore structure and the rock electrical parameters is fully excavated, the problem that the non-Archie phenomenon of the heterogeneous carbonate rock reservoir is serious is solved, and the calculation precision of the water saturation is greatly improved.

The application provides a dense reservoir fluid identification method based on physical data double driving, comprising: performing abnormal value correction and fluid category direct marking on conventional logging data to obtain labeled logging data; performing signal self-adaptive time-frequency conversion on the labeled logging data, and calculating porosity, permeability and water saturation to output physical prior feature channels; inputting two-dimensional multi-channel time-frequency spectrum and the physical prior feature channels into a pre-constructed MDSC-TAM neural network model to extract hidden logging signal frequency domain spectrum series structure and global sedimentary rule to obtain a dense reservoir fluid identification result; and performing physical perception constraint and decision output on the fusion feature representation to obtain a fluid type and confidence. The application solves the data scarcity and model black box bottleneck, improves the engineering practicability of the algorithm, and realizes high-precision identification of the dense reservoir fluid and enhanced physical interpretability.

The application discloses a kind of well bottom reservoir oil and gas phase state fluid property identification method, device, equipment and medium, it is related to oil well exploration field, the method includes: collecting the relevant data of wireline formation testing in pumping operation, form data set;Construct wireline formation testing three-dimensional seepage numerical simulation model, the mass conservation equation in it is dispersed and solved, obtain pressure distribution field and water saturation distribution field;According to pressure distribution field, water saturation distribution field and probe node fluid spherical flow characteristics, establish probe suction fluid hydrocarbon content calculation model;Using data set and probe suction fluid hydrocarbon content calculation model, simulate and calculate the hydrocarbon content curve of the same type strata oil and gas classification, construct cluster chart;The hydrocarbon phase breakthrough time of actual formation testing operation of the same type strata to be processed is compared with cluster chart, and the fluid property of the strata to be processed is identified.The application can conveniently and accurately identify the fluid property of the strata to be processed.