166 results about "Water saturation" patented technology

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 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 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 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 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 reservoir prediction method and device, electronic equipment and a storage medium, and belongs to the technical field of seismic exploration. The method determines acoustic time difference relationship data, density relationship data, porosity relationship data and water saturation relationship data according to first logging data, then reconstructs impedance relationship data according to the relationship data, determines a seismic wavelet according to first seismic data and the first logging data, and obtains a first data volume and a second data volume based on the reconstructed impedance relationship data, the first seismic data and the seismic wavelet, and fuses middle-low frequency data in the first data volume with high frequency data in the second data volume to obtain a target data volume. The method supplements the missing high frequency data in the seismic data by the high frequency data in the logging data, can predict thin sand layers with relatively thin thickness, and thus improves the prediction effect on the thin sand layers with relatively thin thickness.

The invention relates to the technical field of near-well region reservoir development, and particularly discloses a method for evaluating the permeability of pilot production near-well region reservoirs by drilling and production working fluid invasion, which comprises the following steps: selecting shallow surface layer muddy silt sediment and fine silt of a target sea area as media, and preparing an overlying stratum core and multiple groups of parallel cores with different porosity and water saturation; putting the sample tube into a holder with a nuclear magnetic cavity, introducing methane gas to generate hydrate, and monitoring pressure and nuclear magnetic signals to obtain a hydrate reservoir core; reversely injecting cold water to test the permeability before liquid phase invasion; injecting a microbial solution and a nutritive salt solution for culture and reinforcement, testing permeability before and after reinforcement, and analyzing the influence; drilling fluid, well completion fluid, reservoir transformation working fluid, transformation working fluid carrying permeation enhancing materials and ethylene glycol mining fluid are injected under the same conditions to simulate invasion, nuclear magnetic signals are monitored, the permeability after invasion is tested, and the damage degree before and after reinforcement and the anti-invasion effect are compared.

The invention relates to a resistivity-based shale reservoir artificial fracture relative permeability testing method, which comprises the following steps of: respectively placing a plunger sample rock core, a parallel sample rock core X1, a parallel sample rock core X2 and a parallel sample rock core X3 which are subjected to resistivity testing and are filled with a propping agent into a special insulating rock core holder, and connecting the special insulating rock core holder into a rock core permeability testing device; reducing the reservoir temperature and pressure conditions of the core X3, and performing an independent measurement experiment on the core X3 by a steady-state method; drawing a relational graph of the propping agent filling crack resistance value and the water saturation: performing an experiment on the core X1 and the core X2 by a steady-state method, changing the oil-water injection ratio, and performing a re-experiment; determining the water saturation of the rock core proppant filling crack of the experimental group; calculating the relative permeability of the rock core X1 proppant filling crack; and drawing an oil-water relative permeability curve chart. The method can measure the water saturation of the proppant filling crack in real time under the shale oil reservoir temperature and pressure condition.

The present application belongs to the technical field of saturated water detection, and relates to a coal-based hydrocarbon fuel oil saturated water content measurement correction method and device, the measurement correction method comprising: 1) determining the water activity of each temperature node corresponding saturated fuel oil sample at normal temperature; and detecting the water content corresponding to each temperature node saturated fuel oil sample by using Karl Fisher Coulomb method; 2) correcting the saturation degree calculation formula of the saturated fuel oil sample by using the measurement results of step 1), and determining the correction coefficients A, B and C values; 3) cooling the saturated fuel oil sample, real-time monitoring the temperature and the corresponding water activity in the cooling process, and substituting into the corrected formula, and calculating the saturated water content in the saturated fuel oil at low temperature. The coal-based hydrocarbon fuel oil saturated water content measurement correction method provided by the present application corrects the saturation degree calculation formula, thereby improving the measurement accuracy of trace saturated water at low temperature.

This invention relates to a method for characterizing the distribution of primordial water in rocks and its application. The method includes: preparing particles from fresh rock cores as fresh samples and particles from dried rock cores as dried samples; calculating the scattering length density of the rock to be tested based on the dried sample, and preparing a deuterated toluene contrast-matching fluid with the same scattering length density as the rock to be tested; immersing the fresh sample and the dried sample in the deuterated toluene contrast-matching fluid respectively to obtain immersion samples; performing small-angle neutron scattering (SANS) experiments on the dried sample and the immersion samples respectively; obtaining pore structure information before and after immersion based on the experimental results; and determining the distribution of primordial water in the rock to be tested based on the pore structure information. This invention, based on SANS experiments, provides a novel experimental technique for characterizing the distribution and water saturation of primordial water in sedimentary rocks, with advantages such as being non-destructive, efficient, time-saving, and highly accurate.

The invention relates to the technical field of oil and gas reservoir damage evaluation, in particular to a method and device for calculating irreducible water saturation of a tight sandstone reservoir, electronic equipment, a storable medium and a computer program product. The method comprises the following steps: acquiring a pore distribution curve of a compact sandstone sample; based on the pore distribution curve of the compact sandstone sample, determining the capillary bound water content of different pressure differences of the compact sandstone reservoir; carrying out total rock and clay mineral analysis on the compact sandstone sample to obtain the content of the clay bound water in the compact sandstone reservoir; and obtaining the irreducible water saturation of the tight sandstone reservoir based on the capillary irreducible water content and the clay irreducible water content. According to the method, the relationship between the absolute content, the pore distribution, the stress distribution and the interfacial tension of the clay mineral and the irreducible water saturation is established, so that qualitative and quantitative analysis on the irreducible water saturation is quickly and accurately performed.

The invention relates to the technical field of oil development, and discloses a method, a device and equipment for determining soaking time and an oil reservoir imbibition utilization rate. The method comprises the following steps: step S10, selecting a rock sample; step S20, cutting the rock sample into a long plunger and a plurality of short plungers; s30, performing saturated crude oil simulation on the long plunger and the plurality of short plungers to obtain related parameters of the long plunger in an initial oil layer state and water saturation Sw0 of the short plungers in the initial oil layer state; step S40, simulating a soaking process and an imbibition process; s50, the relevant parameters of the long plunger at different imbibition time are obtained at different time of the imbibition process; step S60, measuring the water saturation Sw2 of the short plunger for multiple times; and S70, the soaking time and the oil reservoir imbibition utilization rate are obtained. According to the method, the soaking time of the shale oil reservoir and the imbibition utilization rate of the oil reservoir can be obtained, so that the recovery efficiency of shale oil is improved.

The invention discloses a power transmission and transformation project rock-soil body mechanical property in-situ test landslide stability evaluation device, which comprises a multi-frequency sound wave excitation module, a sound wave characteristic acquisition module, a multi-electrode array measurement module, a mechanical parameter coupling analysis module, a landslide stability dynamic evaluation module and a parameter adaptive optimization module, a dynamic elastic modulus and a dynamic Poisson's ratio are obtained through sound wave propagation characteristic testing, resistivity three-dimensional distribution is obtained through georesistivity tomography, the dynamic elastic modulus and the dynamic Poisson's ratio are innovatively coupled to determine water saturation and shear strength parameters, landslide stability is dynamically evaluated based on the shear strength parameters, and an early warning signal is output. According to the method, the lossless rapid testing of the mechanical property of the rock-soil body and the dynamic evaluation and early warning of the landslide stability are realized.

The application discloses a kind of rock gas relative permeability measurement method based on lattice Boltzmann method, comprising the following steps: (1) determining the porosity corresponding to each water saturation grade of rock, using four-parameter growth method to generate the rock porous medium model consistent with the porosity of each water saturation grade rock;(2) using lattice Boltzmann method to carry out gas seepage simulation, the bias pressure of gas boundary is applied to the rock porous medium model, the gas permeability and relative permeability of rock porous medium model under different porosity are calculated;(3) draw the curve of rock gas relative permeability and different water saturation, determine the relative permeability of rock under different water saturation.The application carries out gas seepage simulation by rock porous medium model and lattice Boltzmann method, obtains the permeability of rock porous medium model under different water saturation, and then calculates the relative permeability, constructs the functional relationship between rock sample water saturation and relative permeability, to determine the rock gas relative permeability simply and effectively.

The invention provides a method for detecting the porosity of a cement-based material by adopting an ultrasonic sound velocity method, and belongs to the technical field of detection of the porosity of the cement-based material.The method comprises the steps that a multi-phase sound velocity prediction model is established by preparing a gradient moisture content standard test piece, and a pore water saturation correction function is established by adopting a longitudinal and transverse wave velocity ratio; the moisture content interference is eliminated by using a saturation-sound velocity coupling inversion algorithm, the accurate detection of the three-dimensional porosity distribution of the to-be-detected material is realized by combining multi-angle ultrasonic tomography and a multiphase sound velocity distribution optimization game model, the result reliability is ensured through multi-path cross validation, the rationality of the porosity result obtained by inversion is judged, and the accuracy of the three-dimensional porosity distribution of the to-be-detected material is improved. When the porosity value exceeds the normal range threshold value corresponding to the material type, a multi-path sound velocity data cross validation program is started, the porosity is recalculated after abnormal measurement values are removed, and the technical problem that the porosity detection precision of the ultrasonic method is interfered by the water-containing state is solved.

This invention relates to the field of carbonate rock lithology identification technology, and particularly to a method, system, and apparatus for automatically identifying carbonate rock lithology based on well logging curves; comprising the following steps: S1, acquiring well logging curve data, core data, and thin section data from multiple wells in the area to be identified; S2, standardizing and environmentally correcting the well logging curve data; S3, using an optimization model to solve for the lithological profile of the area to be identified, thereby determining the clay content, porosity, and water saturation; S4, constructing rock structure curves and formation fracture porosity curves; S5, constructing a machine learning model, setting a learning sample set, and inputting the learning sample set into the machine learning model for training, so that the trained machine learning model can automatically identify carbonate rock lithology; this invention improves the accuracy of carbonate rock lithology identification.

This invention provides a fluid identification method, device, processor, and machine-readable storage medium, relating to the field of oil and gas reservoir evaluation. The method includes: determining the porosity correction coefficient for escaping fluids in multiple full-diameter core sections; determining the apparent total porosity, two-dimensional nuclear magnetic resonance T1-T2 spectra, and porosity of each fluid component in the full-diameter core; determining the porosity of the fluid distribution range, the porosity of the bound fluid distribution range, the porosity of the movable fluid in vacuum-saturated water, and the total porosity; determining the escaping fluid porosity correction coefficient based on the total porosity, apparent total porosity, and bound water porosity of the full-diameter core, and establishing a porosity correction coefficient model based on the correction coefficients of multiple core sections, and determining the total porosity based on the model; and determining the oil and gas saturation and water cut of the entire well section core using the apparent total porosity, total porosity, water saturation, and porosity of each fluid component. Through this invention, the porosity of gas reservoir cores can be accurately measured, fluid properties can be accurately identified, and quantitative evaluation can be performed.

The invention discloses a closed coring saturation correction system, which relates to the technical field of oil and gas reservoir evaluation and comprises a movable water degassing correction model based on a nuclear magnetic simulation experiment and a bound water volatilization correction model based on a volatilization experiment. The method comprises the following steps: determining movable water loss through a nuclear magnetic simulation experiment, and establishing a movable water degassing correction model with permeability, movable water saturation and time; determining irreducible water loss through a volatilization experiment, and establishing an irreducible water volatilization correction model with permeability, irreducible water saturation and time; through combination of the movable water degassing correction model and the irreducible water volatilization correction model, more accurate correction of the closed coring water saturation is realized.

The embodiment of the present application provides a variable flow degree adjustment method and system based on seepage theory calculation, and belongs to the technical field of oil reservoir development. The method comprises the following steps: calculating the seepage velocity of each well based on water injection-oil production working condition information; identifying the well group to be adjusted in terms of variable flow degree based on the spatial and / or temporal difference characteristics of the seepage velocity of each well; calculating the front water saturation in each well group to be adjusted in terms of variable flow degree based on the water injection-oil production working condition information, and obtaining the water drive front position in each well group to be adjusted in terms of variable flow degree based on the front water saturation calculation; and determining and executing the adjustment scheme of each well group to be adjusted in terms of variable flow degree based on the water drive front position. The present application can effectively improve the water drive development effect, increase the water injection swept volume, overcome the low development efficiency problem caused by unreasonable well spacing or the formation of dominant channels in the prior art, and thus realize more efficient oil reservoir development and resource utilization.

The invention provides a water breakthrough time prediction method and device for an oil well in a deepwater oil reservoir, and relates to the technical field of oil reservoir engineering. Establishing a target function of the dynamic relative permeability of the rock core in the deep water reservoir and the displacement speed and water saturation of the rock core; determining the derivative of the target function at the water saturation of the water drive front; and predicting the water breakthrough time of the oil well in the deepwater reservoir according to the derivative, the static pressure of the deepwater reservoir, the formation pressure of the deepwater reservoir, the porosity of the reservoir in the deepwater reservoir, the pore volume in the seepage region between the injection wells and the production wells, the target water injection rate of the oil well and a target formula. Therefore, on one hand, the influence of the dynamic relative permeability on the water breakthrough time is considered, the accuracy of water breakthrough time prediction is improved, on the other hand, the waterless oil production period of the oil well is prolonged, the accumulated oil production and the recovery efficiency of the oil well are improved, and a basis is provided for subsequent development and adjustment.

The invention belongs to the technical field of petroleum and natural gas exploration and development, and provides a method and a device for analyzing the rock resistivity of glauconite sandstone. Generating a first relation curve and a second relation curve according to the different glauconite content conditions, the rock water saturation of the glauconite sandstone, the rock resistivity of the glauconite sandstone and the rock resistance increase rate of the glauconite sandstone corresponding to the different glauconite content conditions; and analyzing the change trend and the change degree of the rock resistivity and the rock resistance increase rate of the glauconite sandstone to obtain an analysis result. According to the analysis method provided by the embodiment of the invention, quantitative analysis can be carried out on the low-resistivity cause of the glauconite sandstone stratum, and the influence and degree of the change of the content of glauconite, the change of the rock resistivity of the glauconite sandstone and the change of the rock resistance increasing rate can be quantitatively judged.

The invention discloses a saturation quantitative calculation method based on water flooded layer classification, which comprises the following steps: firstly, determining the type of a water flooded layer by using the resistivity of original formation water and the resistivity of injected water, and then determining the calculation range of the saturation according to the physical definition of the water saturation of the water flooded layer; according to the water flooded layer resistivity model, calculating the corresponding saturation when the formation resistivity is the minimum value, and after a solving interval is further subdivided, solving the saturation by adopting a dichotomy loop iteration method; and finally, comprehensively determining the water saturation of the water flooded layer according to the water flooding type, wherein most of parameters involved in the process can be directly obtained. The result obtained through the method is high in precision, high in universality, wide in practicability and low in dependence on data and models.

The invention relates to the technical field of oil and gas field development simulation, in particular to a device and method for evaluating the multi-round injection and production effect of a sandstone oil and gas reservoir. According to the device and method for evaluating the multi-round injection and production effect of the sandstone oil and gas reservoir, a rock core of a target stratum is put into a rock core holder, and the rock core holder is divided into a water injection end and an output end corresponding to a water injection well and a reinjection well according to the actual production condition; the water injection end and the output end are sequentially subjected to core pore volume measurement, irreducible water saturation calculation, core oil displacement and multi-round reinjection oil displacement work according to the actual exploitation process, and experimental data matched with actual sandstone oil and gas reservoir exploitation process data are obtained; the multi-round injection and production effect of the sandstone oil and gas reservoir is clear, and technical support is provided for sandstone oil and gas reservoir building feasibility exploration.

The utility model discloses a water-saturated volume weight detection device for bubble light soil, which relates to the technical field of highway engineering and structurally comprises a water tank with a built-in self-priming pump and used for feeding liquid in the water tank into a still water closed container through a pipeline; the still water closed container is provided with a closed containing cavity and is used for storing liquid or gas, and the bubble light soil standard test piece with the water saturation volume weight to be detected is placed in the closed containing cavity and is immersed in the liquid stored in the closed containing cavity; the air compression assembly is used for compressing air to a set pressure value and conveying compressed air to the closed containing cavity of the still water closed container through a pipeline. According to the utility model, the mechanical property of the bubble light soil in a set pressure and water saturation state can be detected, and detection data can be better provided for a bubble light soil area with a high water level and a high durability requirement as a technical support.

The application discloses a kind of shallow shale gas preservation condition microcosmic evaluation method, the method obtains blocky rock sample from study target layer, and carries out equal division, and is prepared into the sample of different water saturation;Through the results of several groups of different temperature and saturation conditions under the methane high-pressure adsorption experiment, and interpolation, the methane theoretical maximum adsorption amount under the condition of any formation temperature, water saturation and pressure can be obtained.Then compare with the gas content of present target layer, finally evaluate the preservation condition of the target reservoir on site.The application has a positive effect on shale gas production planning and reservoir evaluation.

The invention belongs to the technical field of oil-gas exploration, and particularly relates to an oil saturation calculation method based on a four-water electric conduction model. Comprising the following steps: S1, constructing a four-water saturation equation; s2, calculating four porosities; s3, resistivity parameters are determined; s4, determining a lithologic coefficient and a cementation index by an optimization method; and S5, calculating the oil saturation. According to the method, on the basis of a traditional three-water conductive model, the fine silt pore water which is a new conductive component is introduced, the conductive characteristic of the argillaceous development sandstone reservoir is better met, refined characterization of a complex conductive mechanism is achieved, the reliability of an oil saturation calculation result is improved, the well logging interpretation conclusion is more reliable, and the method has good application prospects. By combining laboratory core analysis and logging data, determination and rapid calculation of parameters in different regions can be realized, and the method has good practicability.

The application discloses a method and device for establishing a physical property and fluid rock physical quantity version and a storage medium. The method comprises the following steps: acquiring well logging data of a reservoir; determining a fluid sensitive parameter based on elastic parameters under different water saturation in a preset porosity range; determining a physical property sensitive parameter based on elastic parameters under different porosity in a preset water saturation range; constructing a rock physical model which can consider the non-uniformity of pore structure and the non-uniform distribution of immiscible fluids inside the pores based on an equivalent embedded body stress average model and a standard linear body model; establishing a physical property prediction rock physical quantity version based on the rock physical model in combination with the physical property sensitive parameter, the porosity and the water saturation; and establishing a fluid prediction rock physical quantity version based on the rock physical model in combination with the fluid sensitive parameter, the porosity and the water saturation. The application can provide theoretical support for fine prediction of physical properties and fluids of an ultra-deep carbonate reservoir.

The application of prediction method for diffusion behavior of underground hydrogen in pore scale of water-containing clay mineral belongs to the technical field of underground hydrogen energy storage and unconventional gas migration prediction, and the key point is to fill water molecules and salt ions into the pores according to the target water saturation and salinity; the initial model of the water-containing clay mineral pores is pre-equilibrated by the molecular dynamics method; hydrogen molecules are filled under the given temperature and pressure conditions by the grand canonical Monte Carlo method, and the hydrogen pressure is corrected by the SRK-EOS state equation; the hydrogen diffusion simulation is carried out by the molecular dynamics method with temperature and fugacity as input parameters, the mean square displacement of hydrogen in the pores is calculated, and the self-diffusion coefficient is obtained; the application can quantitatively characterize the diffusion rate change rule of hydrogen in the clay pores under different water film thickness, salinity and temperature and pressure conditions, and reveal the diffusion inflection point, diffusion inhibition stage and migration restriction mechanism caused by the water film or water bridge structure.

This invention discloses a method for determining the upper limit of water saturation in tight gas reservoirs using two-phase permeability analysis, comprising: 1. Selecting several rock samples for gas-water two-phase permeability analysis, and establishing a gas-water phase permeability curve based on the relative permeability of the water phase, the relative permeability of the gas phase, and the water saturation value of each rock sample; 2. Based on the gas-water phase permeability curve, first reading the water saturation value of each rock sample when the relative permeability of the water phase is a set value A, then reading the relative permeability of the gas phase corresponding to the same water saturation value of each rock sample, and determining the upper limit of water saturation for each rock sample accordingly; 3. Calculating the average value of the upper limit of water saturation for each rock sample, and the obtained average value is the upper limit of water saturation for the tight gas reservoir. This invention can accurately determine the upper limit of water saturation in tight gas reservoirs using relatively simple means, simplifying the determination process and improving accuracy compared to existing technologies, providing an accurate basis for the rational exploitation of tight gas reservoirs.