47 results about "Relative permeability" patented technology

The invention discloses a salt-cavern gas storage sealing performance evaluation method based on gas-water two-phase seepage, and belongs to the technical field of salt-cavern gas storages, the method comprises the following steps: embedding a formula in a fluid-solid-gas coupling theoretical model under a saturated water surrounding rock gas injection and production condition into finite element software, inputting mechanical parameters and pore permeability parameters of rock, and calculating the sealing performance of the salt-cavern gas storage according to the mechanical parameters and the pore permeability parameters; the correction coefficient of the slippage effect on the gas permeability, the gas relative permeability and the pore water relative permeability are obtained; based on the initial stress of surrounding rock, corresponding stratum stress values and hydrostatic pressure values are applied to the top, the bottom and the side faces of a rock stratum respectively, an injection-production air pressure boundary is applied to the surface of a salt cavern cavity, numerical simulation is carried out through a fluid-solid-gas coupling theoretical model and parameters, and the gas seepage velocity is obtained through solving. And evaluating the cumulative gas leakage rate in combination with the cumulative gas leakage rate model. According to the method, the gas seepage behavior under the real working condition is simulated, the slippage effect of the small molecule gas and the gas-water displacement process of the water-saturated rock stratum are considered, and the gas leakage amount evaluation is more accurate.

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 volcanic gas reservoir productivity prediction method and system based on a digital core model, and belongs to the technical field of exploration. Comprising the following steps: acquiring a corresponding digital core three-dimensional image; a pore phase is determined after the three-dimensional image is segmented; carrying out microscopic two-phase gas-water flow simulation on the pore phase digital core to obtain a relative permeability curve, determining the permeability in different directions based on an LBM method, and obtaining effective permeability; establishing a productivity evaluation model of the volcanic gas reservoir under different well types and well completion modes by considering stress sensitivity and a high-speed non-darcy effect; and substituting the effective permeability into a productivity evaluation model of the volcanic gas reservoir for productivity evaluation. According to the method, the productivity of the gas well is verified on the basis of the permeability obtained by the productivity evaluation model and the microscopic digital core method, well test interpretation data and digital core calculation data are compared, the obtained theoretical yield error is smaller than 3%, and a good prediction effect is achieved.

The invention discloses a multiphase flow relative permeability prediction method and device, electronic equipment, a storage medium and a program product. The method comprises the steps that fluid information of a fracture-vug system and fluid information of a bedrock system in the fracture-vug type oil reservoir are obtained; according to the fluid information of the fracture-vug system and the fluid information of the bedrock system, determining a fracture-vug priority flow boundary parameter, a first influence coefficient and a second influence coefficient; determining equivalent relative permeability information of the two-phase flow according to the fracture-cavity priority flow limit parameter, the first influence coefficient and the second influence coefficient; and according to the equivalent relative permeability information of the two-phase flow, determining the relative permeability information of the multiphase flow based on a pre-acquired numerical simulation model. According to the technical scheme, the problem that existing multiphase flow relative permeability prediction precision is low is solved, the relative seepage curve of the multiphase flow can be predicted more accurately by considering the fracture-vug priority characteristics in the relative permeability prediction process, and therefore the reliability of fracture-vug type oil reservoir multiphase flow numerical simulation is achieved.

The application discloses a reservoir gas-water relative permeability determination method, and relates to the field of reservoir permeability determination. The method comprises the following steps: obtaining a core sample of a target reservoir and determining the geometric size of the core sample; injecting simulated formation water into the core sample until the core sample is saturated, and performing nuclear magnetic scanning to obtain a reference nuclear magnetic signal and an initial porosity distribution; performing a multistage gas injection pressure experiment in an intermittent displacement mode to obtain quasi-steady-state displacement data; constructing a two-phase percolation numerical model with phase permeability curve parameters and capillary pressure curve parameters as to-be-inverted parameters; constructing a target function based on the quasi-steady-state data and performing inversion solving to obtain optimal parameters; and determining the phase permeability curve and the capillary pressure curve based on the optimal parameters. The application obtains the fluid distribution inside the core through nuclear magnetic resonance, obtains quasi-steady-state data in combination with intermittent displacement, and inversely solves the phase permeability and the capillary pressure, so that the problem that the fluid distribution inside the core cannot be accurately reflected and the multi-solution problem cannot be solved is solved, and the influence of the capillary end effect is eliminated.

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.

Relative permeability modifier (RPM) macromolecules when combined with nanoparticles are effective in modifying the permeability of subterranean reservoirs at temperatures in excess of 250° F.

The application discloses a kind of high-pressure conditions under multiple medium digital core gas-water two-phase percolation simulation method, and the gray scale image of fracture-pore type piston rock sample is obtained by CT scanning, the fracture-pore network model of the rock sample is constructed, then the experimental results of gas-water relative permeability under normal temperature and pressure are used to correct the model, carry out permeability stress sensitivity experiment under high temperature and high pressure, obtain the relationship curve of permeability with confining pressure, the fracture opening in the corrected fracture-pore network model is used to simulate the fracture closure under high temperature and high pressure, and the experimental results of permeability under high temperature and high pressure are used to correct, obtain the relationship of fracture opening with confining pressure, further predict the gas-water two-phase relative permeability curve under different pressures, provide theoretical support for efficient development of high-pressure gas reservoir.

The invention discloses a component natural gas pore network stress coupling simulation method and system and a medium. Relates to the technical field of natural gas reservoir model simulation. Through a multi-component diffusion flow coupling model considering effective aperture change, real-time change of pore radius and permeability along with reservoir stress and seepage phenomena of pore change along with stress and flow coupling of multi-component gas in a pore scale are displayed, and meanwhile, aiming at the multi-component diffusion flow coupling model considering effective aperture change, the permeability of the multi-component gas is improved. A special coupling simulation method is designed, a multi-component gas pore scale seepage model is established, discretization processing and model solving are carried out on the multi-component gas pore scale seepage model in combination with throat characteristic parameters, and dynamic coupling simulation of component natural gas pore network stress is achieved. The change of the relative permeability of the fluid under different stress conditions is shown, and the adaptability of a multi-component diffusion flow coupling model is enhanced.

This invention discloses a method for determining the gas well penetration rate and pressure drop plot through proppant volume conservation numerical simulation, comprising: establishing a gas well numerical model of structural layers and dividing the development sub-layers; acquiring gas saturation and average adsorbed gas content data for each development sub-layer, and establishing three-dimensional models of free gas saturation and adsorbed gas saturation respectively; performing inversion to obtain artificial fracturing parameters; establishing an embedded discrete fracture model; dividing the embedded discrete fracture model into zones; acquiring stress-sensitive data and relative permeability data, and establishing stress-sensitive and relative permeability models; acquiring diffusion coefficient, reservoir temperature and pressure basic parameters, establishing embedded discrete fracture numerical models of fractures at different heights, and using the embedded discrete fracture numerical models to determine the fracture height range; establishing embedded discrete fracture numerical models under different penetration rate conditions, and generating a plot of the relationship between gas well penetration rate and pressure drop through numerical simulation calculation.

The present application relates to a method for fitting carbon dioxide miscible pressure of capillary tube experiment considering feature points. The method comprises the following steps: drawing a carbon dioxide miscible pressure chart according to the displacement experiment result; determining a BIC binary interaction coefficient according to a high-pressure miscible point, determining a relative permeability curve according to a low-pressure immiscible point, and determining a critical interfacial tension according to a miscible inflection point based on the carbon dioxide miscible pressure chart, so as to determine a fitting sequence of the low-pressure immiscible point, the miscible inflection point and the high-pressure miscible point; calculating an initial parameter of the high-pressure miscible point based on the BIC binary interaction coefficient; and fitting the oil displacement efficiency of the high-pressure miscible point by adjusting the interaction coefficient of carbon dioxide and C7+, fitting the oil displacement efficiency of the low-pressure immiscible point by adjusting the oil displacement efficiency of the relative permeability curve, and fitting the oil displacement efficiency of the miscible inflection point by adjusting the value of the critical interfacial tension, so as to fit the oil displacement efficiency value of the carbon dioxide of the capillary tube experiment.

The application discloses a kind of multilayer heterogeneous reservoir percolation simulation analysis methods based on digital core, including obtaining the three-dimensional digital core model of high-permeability reservoir sample, medium-permeability reservoir sample and low-permeability reservoir sample;Get the pore network model after commingling;Based on the pore network model after commingling, simulate oil-water displacement and suction process by percolation theory, calculate the corresponding capillary pressure curve and relative permeability curve, and compare and analyze percolation characteristics.The beneficial effects of the technical scheme proposed in the application include: based on the pore network model after commingling, simulate oil-water displacement and suction process by percolation theory, calculate the corresponding capillary pressure curve and relative permeability curve, and compare and analyze percolation characteristics.Thereby, the multilayer heterogeneous reservoir percolation process can be simulated, and the interlayer interference influence mechanism and residual oil distribution characteristics during multilayer commingling in the reservoir with large differences in low-permeability and heterogeneity can be truly reflected.

The invention belongs to the technical field of grouting simulation, and particularly discloses a deformation porous medium splitting grouting simulation method and system.The method comprises the steps that a three-dimensional geometric model of a porous medium in an area to be simulated is built, a computational domain is determined, and the computational domain is divided into a plurality of non-overlapped unit grids; establishing a multiphase system control equation, and carrying out numerical updating on relative permeability, density, viscosity and surface tension; on the basis of the updated parameters, fluid velocity field calculation is conducted through a fluid control equation of the pure fluid area; calculating transmission time based on the obtained fluid velocity, and updating a slurry viscosity field through a slurry viscosity space-time tracking model; and the solid speed and mass are updated based on the solid mass and momentum conservation equation, and the grouting simulation process is completed. According to the method, the permeability change of the porous medium and the dynamic coupling effect of the stress state are comprehensively considered, and a scientific basis is provided for grouting design and optimization under complex working conditions in engineering.

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.

A relative permeability curve calculation method based on a phase field model relates to the technical field of oil and gas development, and comprises the following steps: selecting a core sample to establish a pore-scale model, performing a single-phase flow simulation, calculating the absolute permeability of the pore-scale model, performing a gas-water two-phase flow simulation, respectively calculating the gas and water phase fluid distribution volume fractions and the total fluid volume flow rate of the pore-scale model in each time interval, then respectively calculating the total gas and water two-phase fluid flow rates of the pore-scale model in each time interval, respectively calculating the volume flow rates of the gas and water phase fluids in each time interval, further calculating the corresponding relative gas phase permeability and relative water phase permeability in each time interval, and drawing a relative permeability curve in combination with water saturation; the relative permeability curve in the present invention can better characterize the fluid physical properties of the complex porous medium pore model, and thus accurately obtain the seepage characteristics of the fluid in the porous medium model.

The present application relates to the technical field of oil and gas exploration and development, and discloses a method for determining gas-gas relative permeability curve in CO2 injection and CH4 displacement process.The present application establishes an experimental test and mathematical processing method for gas-gas two-phase seepage mechanism by regarding supercritical CO2 and CH4 as two independent fluids, aiming at the blank of lacking effective gas-gas relative permeability determination means in the prior art.The method comprises the following steps: core and fluid preparation, CH4 saturation, and CO2 injection and displacement test.The key of the method is as follows: the gas chromatograph is used to monitor the output gas components in real time, so that the components can be finely metered;the high temperature and high pressure volume correction mathematical model is introduced to convert the ground measurement value into the fluid volume under the formation condition;and the double gas permeability calculation and saturation normalization processing model is constructed to realize quantitative and accurate determination of the gas-gas relative permeability curve.The present application solves the problems that the components are difficult to distinguish and the relative permeability parameters are difficult to obtain in the gas displacement process, and provides high-precision basic data for dynamic evaluation of the reservoir gas displacement.

The application discloses a high-temperature and high-pressure water-gas dynamic phase permeability test method, which comprises the following steps: extracting, cleaning and drying a retrieved core, and then measuring physical parameters of the core; then, the core is saturated in formation water, and then is placed in a core holder; water phase permeability and permeability under the state of bound water are calculated by using Darcy formula; the test device is heated to the original temperature of the formation, and the pressure in the core holder is increased to the original pressure of the formation; formation water in an intermediate container enters the core holder; the water and gas output of the core is tested by gradually reducing the pressure; until the core does not output gas and stably outputs water, relevant data are recorded, and a dynamic water-gas phase permeability curve is determined. The application considers the dynamic change rule of water-gas fluid in rocks when the formation pressure changes in the high-temperature and high-pressure development process, and the determined result is more in line with the actual mining process, so that a more reasonable and reliable dynamic water-gas phase permeability curve test method is provided for the development of high-temperature and high-pressure gas reservoirs.

The application discloses a critical path-based oil-water two-phase seepage model construction method and system and a medium, relates to the oil and gas field development technical field, and combines traditional black oil model simulation technology and critical radius technology based on critical path seepage theory, proposes an oil-water two-phase seepage characteristic oil reservoir simulation method considering microscale critical paths on the basis of ensuring the scale of the oil reservoir model, restores micro characteristics such as internal pore throat structures of real reservoir rocks to the maximum extent by using the critical radius, and studies factors such as the influence of the dominant channel (critical path) of oil-water two-phase fluid seepage in the pore throat and displacement efficiency on the phenomenon from the micro perspective, so that higher-precision oil reservoir simulation analysis results are obtained; the scheme directly calculates the flow and pressure of each component of oil and water based on the critical radius and the critical path length, does not need to input a static oil-water relative permeability curve in the simulation process, and can more directly reflect the stress state and change process of each part of the oil reservoir.

The present application belongs to the technical field of permeability measurement, and relates to a system and method for measuring relative permeability under the condition of coexistence of CO2 and water in three phases. The method comprises: obtaining relative permeability data of gaseous CO2 by using a gaseous CO2-water relative permeability experiment; obtaining relative permeability data of liquid CO2 by using a liquid CO2-water relative permeability experiment; normalizing the three-phase saturations of the water phase, gaseous CO2 and liquid CO2 according to the relative permeability data of gaseous CO2 and the relative permeability data of liquid CO2, combining the STONE model, and simultaneously calculating the relative permeability of the water phase to obtain the three-phase relative permeability of the CO2 liquid phase-CO2 gaseous phase-water phase. The present application can accurately calculate the three-phase relative permeability of the CO2 liquid phase-CO2 gaseous phase-water phase.

Disclosed herein is a method for obtaining depth-variant relative permeability and capillary pressure curves utilizes downhole in-situ logging data and formation testing measurements. The method involves obtaining multi-frequency dielectric data and NMR T2 data under residual water and oil saturation conditions, and obtaining formation testing data from which relative permeability and capillary pressure values are determined. Rock properties related to rock texture and fluid distribution are determined from the obtained multi-frequency dielectric and NMR T2 data. Additional NMR T2 and multi-frequency dielectric data are obtained at various saturation conditions and depths, and data sets are formed based on their possession of similar rock properties. A mathematical function is determined, relating water relative permeability, oil relative permeability, and capillary pressure with water saturation, using the rock properties and formed data sets. Finally, continuous depth-variant relative permeability and capillary pressure curves are generated based on the determined mathematical function.

This application discloses a method for determining the relative permeability of gas and water in reservoirs, relating to the field of reservoir permeability determination. The method includes obtaining core samples from the target reservoir and determining their geometric dimensions; injecting simulated formation water into the core samples until saturation and performing nuclear magnetic resonance (NMR) scanning to obtain a baseline NMR signal and initial porosity distribution; conducting multi-stage gas injection pressure experiments using intermittent displacement to obtain quasi-steady-state displacement data; constructing a two-phase flow numerical model using relative permeability curve parameters and capillary pressure curve parameters as inversion parameters; constructing an objective function based on the quasi-steady-state data and performing inversion to obtain optimal parameters; and determining the relative permeability curve and capillary pressure curve based on the optimal parameters. This application obtains the fluid distribution inside the core through NMR, combines it with intermittent displacement to obtain quasi-steady-state data, and jointly inverts and solves for relative permeability and capillary pressure, solving the problems of inaccurately reflecting the fluid distribution inside the core and the multiple solutions in inversion, and eliminating the influence of capillary end-effects.

The invention belongs to the technical field of geological exploration, and discloses a method for measuring a two-phase relative permeability curve, which comprises the following steps of: 1, measuring CT values of oil, gas and water for simulation; step 2, respectively carrying out vacuumizing, oil saturation, gas saturation and water saturation on the rock core, and carrying out CT (Computed Tomography) scanning; step 3, injecting simulated oil into the rock core at a set pressure until no water is generated at an outlet, and performing CT scanning as an initial state; step 4, injecting simulation gas into the rock core at set pressure, and performing CT scanning once every set time interval; and 5, sequentially arranging a plurality of pressure measuring points in the length direction of the rock core, calculating the local relative permeability according to the partial pressure data obtained by each pressure measuring point and the calculated on-way saturation, and finally weighting to obtain a relative permeability curve of the whole rock core. According to the method, the gas-driven front edge interface is captured through online CT scanning, and the influence caused by the end effect can be effectively avoided.

The application discloses a kind of two-phase flow phase permeability curve boundary processing method and system based on lattice Boltzmann method, comprising: the average density of import boundary fluid is calculated and import and export pressure difference is calculated, and then volume force is calculated;Using lattice Boltzmann method to solve the velocity and density of fluid;According to fluid velocity, correct volume force, ensure that import flow rate is consistent with set value;According to the velocity distribution of fluid that is updated by corrected volume force and fluid density, then optimize and perfect the simulation of steady phase permeability curve.The application has the advantages that: by converting velocity-pressure boundary condition into periodic boundary condition of volume force format, the change of boundary pressure and injection flow rate can be accurately simulated when simulating steady phase permeability curve, ensure that import flow rate remains constant, so as to improve the calculation accuracy of phase permeability curve.

The application provides a reservoir water production rate calculation method and device, electronic equipment and storage medium, and relates to the technical field of geological exploration. The method comprises the following steps: first, obtaining the rock-soil sample of the target reservoir, obtaining the rock-electricity experiment data and rock cation exchange measurement data, constructing the digital core data body, extracting the pore network model of the digital core data body, and obtaining the corresponding simulation data according to the pore network model; according to the rock-electricity experiment data and the rock cation exchange measurement data, the resistivity increase coefficient is corrected, and then the influence of the argillaceous additional conductivity is eliminated; then, according to the pore structure parameters introduced in the simulation data, the I-Kr model considering the pore structure is established, the conversion of the resistivity index and the relative permeability is completed, and the problem that the residual wet phase saturation and the residual non-wetting phase saturation are difficult to obtain is solved. Finally, according to the corrected resistivity increase coefficient and the pore structure parameters, the water production rate of the target reservoir is calculated, and the calculation result is more accurate.

The present application relates to a method for determining artificial fracture oil-water relative permeability based on two-dimensional nuclear magnetic resonance, which comprises: oil-water nuclear magnetic signal calibration under reservoir temperature and pressure conditions; two-dimensional nuclear magnetic substrate signal test of shale matrix; artificial fracture filling with fracturing fluid, calculation of single-sided wall surface area of the fracture, estimation of fracture volume; making the conditions of the core and artificial fracture be the initial state of the reservoir after fracturing; nuclear magnetic resonance test of the initial state of the reservoir after fracturing; initial fracture width CT scan test; calculation of absolute permeability of the fracture; fracture fluid saturation test during flowback production process, calculation of water saturation and oil saturation in the fracture at t i ; fracture width test during flowback production process, calculation of fracture width at t 10 ; calculation of artificial fracture oil-water relative permeability; and drawing of a shale oil reservoir artificial fracture relative permeability curve. The present application can non-destructively, in-situ and in real time reveal the dynamic percolation behavior of artificial fractures in multiphase flow process.

The application discloses a salt cavern gas storage sealing evaluation method based on gas-water two-phase seepage, and belongs to the technical field of salt cavern gas storage, and the method comprises the following steps: embedding a formula in a fluid-solid-gas coupling theory model under water-saturated surrounding rock injection and production conditions into finite element software, inputting mechanical parameters and porosity and permeability parameters of rock, and a correction coefficient of gas permeability, gas relative permeability and pore water relative permeability of a slippage effect; based on the initial stress of the surrounding rock, corresponding stratum stress values and hydrostatic pressure values are respectively applied to the top, bottom and side of the rock stratum, an injection and production pressure boundary is applied to the surface of the salt cavern cavity, numerical simulation is carried out by using the fluid-solid-gas coupling theory model and parameters, gas seepage velocity is obtained by solving, and gas cumulative leakage is evaluated in combination with a gas cumulative leakage model. The method simulates the gas seepage behavior under real working conditions, considers the slippage effect of small molecule gas and the gas-water displacement process of water-saturated rock stratum, and is more accurate in gas leakage evaluation.

The invention belongs to the technical field of permeability measurement, and relates to a system and a method for measuring relative permeability under a CO2 and water three-phase coexistence condition. The method comprises the following steps: carrying out a gas-phase CO2-water relative permeability experiment to obtain relative permeability data of gas-phase CO2; obtaining relative permeability data of liquid-phase CO2 by utilizing a liquid-phase CO2-water relative permeability experiment; according to the relative permeability data of the gas-phase CO2 and the relative permeability data of the liquid-phase CO2, the three-phase saturation of the water phase, the gas-phase CO2 and the liquid-phase CO2 is normalized in combination with an STONE model, meanwhile, the relative permeability of the water phase is calculated, and the CO2 liquidophase-CO2 gas phase-water phase three-phase relative permeability is obtained. According to the method, the relative permeability of the CO2 liquid phase, the CO2 gas phase and the water phase can be accurately calculated.

The application discloses a method for constructing a relative permeability curve of a power-law non-Newtonian fluid, which comprises the following steps: first, a non-steady-state relative permeability curve displacement experiment device is built; then, rock sample pretreatment, non-Newtonian fluid rheological parameter testing and displacement experiment data acquisition are completed; the outlet water breakthrough time, the cumulative liquid production and the displacement pressure difference of the non-Newtonian fluid when the constant-speed displacement of the non-Newtonian fluid is recorded; after the experimental data is preprocessed, a relative permeability curve model is preset, the water cut is implicitly solved and the derivative is calculated, and the injection pore multiple of the non-Newtonian fluid and the displacement pressure difference are derived; based on the experimental data, the water saturation-water cut and the displacement pressure difference-water saturation relationship are simultaneously fitted through an iterative optimization algorithm, and finally, the coefficients in the relative permeability curve formula are determined, and the relative permeability curve is constructed. The method improves the smoothness and physical rationality of the relative permeability curve of the non-Newtonian fluid, improves the calculation accuracy, and provides a reliable means for analyzing the seepage characteristics of complex fluids.

The invention provides a rock core saturation correction method and device, and the method comprises the steps: firstly, converting the saturation of a rock core on the ground into the saturation of a corresponding stratum according to the overburden pressure pore permeability experimental data of the rock core and the fluid high-pressure physical property experimental data; then, the reservoirs are classified according to the absolute permeability of the rock core, and a diversion rate expression under the reservoir of the current category is determined according to oil-water relative permeability experimental data; according to the diversion rate expression, the saturation of the corresponding stratum is subjected to multi-process inversion to recover the loss amount, so that a saturation correction model is generated; wherein the saturation correction model is used for representing the saturation after loss recovery; and finally, solving the saturation correction model by taking the sum of the oil saturation and the water saturation after loss recovery as 1 as an objective function so as to correct the saturation of the rock core. According to the method, the rock core analysis saturation value can be reasonably corrected, so that the rock core analysis saturation value can directly reflect the fluid distribution condition under the formation condition, and the oiliness of the reservoir is correctly evaluated.