69 results about "Relative permeability" patented technology

The invention provides an infilled well location determination method and device based on old well water ridge waves and a model. The infilled well location determination method comprises the steps that reservoir physical property parameters and fluid parameters of a production horizon of a target horizontal well and production dynamic data of the target horizontal well are obtained; obtaining a relative permeability curve and oil displacement efficiency through a rock core relative permeability experiment; the height of a water ridge during sidetrack drilling is calculated; the water ridge height, the reservoir physical property parameters, the fluid parameters and the production dynamic data are substituted into a horizontal well oil-water interface description formula, and the formula is nondimensionalized through normalization deformation; the corresponding relation between the dimensionless cumulative oil production and the dimensionless water ridge width and the dimensionless water ridge height is calculated through the oil displacement efficiency according to the water-oil displacement theory; establishing a data map comparison table of the dimensionless cumulative oil production, the dimensionless water ridge width and the dimensionless water ridge height, and judging the limit well spacing of the infilled well according to the data map comparison table; and according to the limit well spacing, carrying out encryption or branch reconstruction on the target horizontal well.

The invention discloses a two-phase flow relative permeability curve boundary processing method and system based on a lattice Boltzmann method, and the method comprises the steps: calculating the average density of an inlet boundary fluid, calculating the pressure difference between an inlet and an outlet, and then calculating the volume force; solving the velocity and density of the fluid by using a lattice Boltzmann method; correcting the volume force according to the fluid velocity to ensure that the inlet flow velocity is consistent with a set value; and updating the velocity distribution of the fluid according to the corrected volume force and fluid density so as to optimize and perfect the simulation of the steady-state relative permeability curve. The method has the advantages that by converting the speed-pressure boundary condition into the periodic boundary condition in the volume force format, the change of the boundary pressure and the injection flow velocity can be accurately simulated when the relative permeability curve is obtained through the steady-state method, and the inlet flow velocity is kept constant, so that the calculation precision of the relative permeability curve is improved.

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.

A method and device for determining oil-water relative permeability information of a medium-high permeability reservoir, relating to the technical field of oil and gas reservoir development. The method comprises: acquiring nuclear magnetic resonance T2 spectrum information of a medium-high permeability reservoir in multiple states (101); determining pore distribution and oil phase distribution on the basis of the nuclear magnetic resonance T2 spectrum information in multiple states (102); using the pore distribution and the oil phase distribution of the medium-high permeability reservoir, combined with the wettability type of a core of the medium-high permeability reservoir, to divide movable oil-water space in the nuclear magnetic resonance T2 spectrum information in multiple states (103); on the basis of the nuclear magnetic resonance T2 spectrum information of the medium-high permeability reservoir in multiple states, determining a correspondence between the normalized saturation of the movable oil-water space and a T2 value (104); and on the basis of the correspondence between the normalized saturation of the movable oil-water space and the T2 value, determining an oil-phase relative permeability curve and a water-phase relative permeability curve of the medium-high permeability reservoir (105).

The invention discloses an oil-water two-phase seepage model construction method and system based on a critical path and a medium. Relates to the technical field of oil-gas field development. According to the scheme, a traditional black oil model simulation technology and a critical radius technology based on a critical path seepage theory are combined, and on the basis of ensuring the scale of an oil reservoir model, the oil-water two-phase seepage characteristic oil reservoir simulation method considering the micro-scale critical path is provided; microscopic characteristics such as a pore throat structure in a real reservoir rock are restored to the greatest extent by using the critical radius, and phenomena such as a dominant channel (critical path) of seepage of oil-water two-phase fluid in a pore throat and factors influencing displacement efficiency are researched from a microscopic perspective, so that a higher-precision oil reservoir simulation analysis result is obtained; according to the scheme, the flow and pressure of each component of oil and water are calculated directly based on the critical radius and the critical path length, a static oil-water relative permeability curve does not need to be input in the simulation process, and the stress state and the change process of each part of the oil reservoir can be reflected more directly.

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.

The invention discloses a tight reservoir CO2-WAG oil displacement and burying capacity calculation method, device and equipment, and the method comprises the steps: constructing a first seepage control equation representing three-phase seepage control of a matrix system and a second seepage control equation representing three-phase seepage control of an artificial fracture system according to the law of mass conservation and momentum conservation; establishing a three-phase seepage auxiliary equation; and solving the first seepage control equation, the second seepage control equation and the three-phase seepage auxiliary equation based on the basic parameters of the tight reservoir of the target area, and calculating to obtain the productivity data of carbon dioxide-water vapor alternate driving carbon utilization and burying of the tight reservoir. According to the method, the influence of factors such as diffusion mass transfer, three-phase capillary pressure, three-phase relative permeability hysteresis and fluid channeling between fractures and matrixes on the CO2-WAG flooding seepage law of the tight reservoir is fully considered, and accurate and effective prediction and evaluation of the productivity and carbon dioxide burying potential of the tight reservoir in the target area can be achieved.

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.

The invention discloses a relative permeability curve averaging method based on multi-sample virtual overall measurement. The relative permeability curve averaging method comprises the following steps: acquiring a relative permeability curve, a capillary force curve, absolute permeability and porosity of a sample as well as reservoir volume and rock stratum thickness data represented by each sample; drawing a capillary pressure-wet phase saturation curve graph and a relative permeability-wet phase saturation curve graph; assuming that the average wet phase saturation of all the samples under the condition of each specified capillary pressure value is calculated under the condition of overall measurement of the multiple samples, and determining the relative permeability value of each phase corresponding to the wet phase saturation; and respectively calculating the average value of the relative permeability of the wet phase and the average value of the relative permeability of the non-wet phase in the parallel and series arrangement directions of the rock strata to obtain an averaged relative permeability curve of all samples with anisotropic characteristics. The technical problem that the coarsening error of the relative permeability curve is too large is solved.

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 present invention provides a method for determining the relative permeability of oil and water and a dynamic characterization model in the process of infiltration regulation and oil recovery. The method for determining the relative permeability of oil and water includes: constructing a capillary bundle geometric model; respectively determining the initial contact angle, final contact angle and oil-water interfacial tension of each capillary in the capillary bundle geometric model during the flow simulation process; constructing a contact angle constitutive model that reflects the change in rock wettability during the process of infiltration regulation and oil recovery, so as to constrain the size of each capillary contact angle in the capillary bundle geometric model during the flow simulation process; based on the initial contact angle, final contact angle, oil-water interfacial tension and contact angle constitutive model of each capillary in the capillary bundle geometric model during the flow simulation process, using the capillary bundle geometric model, step-by-step controlling the displacement pressure difference to perform multiple rounds of flow simulation, and obtaining the oil-water relative permeability curves at different stages in the process of infiltration regulation and oil recovery; wherein the flow simulation is a displacement flow simulation or a suction flow simulation.

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 invention relates to a method for calculating the effective burying amount of green methanol generated by H2 / CO2 collaborative storage, which comprises the following steps of: establishing an underground methanol flow control equation based on the mass conservation law of a porous medium and the Darcy flow law; carrying out numerical discretization of a finite difference format on the underground methanol flow control equation; establishing an underground green methanol micro-compressible flow model, and solving distribution of liquid phase saturation S1 and liquid phase fluid pressure P1; based on an underground green methanol micro-compressible flow model, the influence of the capillary force effect and the relative permeability on methanol flow is analyzed, along with the increase of the capillary force effect and the relative permeability, the fluid pressure and saturation diffusion are also increased, and the capillary force effect and the relative permeability are favorable factors for methanol storage; and quantitatively characterizing the influence of capillary force action and relative permeability factors on methanol burying, and calculating the effective burying amount of methanol. According to the invention, underground flow of methanol is simulated, and the effective burying amount of methanol can be calculated.

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.