31 results about "Relative permeability" patented technology

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.

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 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.

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 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 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.

The invention discloses a rapid identification method for sandstone gas reservoir fluid output types. On the basis of a relative permeability experiment result, irreducible water saturation, irreducible gas saturation and critical water saturation of the rock cores with different permeability are extracted, and a gas-water production identification chart is established, so that the sandstone gas reservoir fluid production type is rapidly and effectively judged through the reservoir physical property and the water saturation.

The application discloses a method for determining relative permeability of loose sandstone gas and water, and comprises the following steps: drying and weighing a rock sample to obtain a dry weight, saturating the rock sample with formation water, applying a set confining pressure to obtain a wet weight, and calculating an effective pore volume of the rock sample; performing a non-steady-state gas displacement water relative permeability determination experiment on the rock sample according to a set displacement pressure difference, obtaining total sand water volume and gas volume change data over time; determining the volume of sand in the produced sand water, determining a water production volume correction coefficient according to the total sand water volume and the volume of sand in the produced sand water, and obtaining net water production volume change data over time; and determining the gas saturation of the rock sample and the gas and water relative permeability change data over time according to the effective pore volume and the net water production volume and gas volume change data over time. The method can obtain more accurate effective pore volume, accurately measure the sand volume, correct the net water production, and improve the accuracy of the determination of the relative permeability of loose sandstone gas and water.

The embodiment of the invention provides a condensate gas reservoir staging yield correction method and a computer readable storage medium, and belongs to the field of gas reservoir development. The correction method comprises the following steps: determining a multiphase seepage resistance ratio of the condensate gas reservoir according to the relative permeability of each phase in multiple phases and a flow equation of each phase; according to the multiphase seepage resistance ratio of the condensate gas reservoir and the water saturation and oil saturation of the current state, staging characteristic parameters of the condensate gas reservoir are constructed; on the basis of the staging characteristic parameters of the condensate gas reservoir and the multiple grades, correction coefficients of the staging yield of the corresponding condensate gas reservoir are obtained; and based on the correction coefficient of the condensate gas reservoir staging yield corresponding to the plurality of grades and the condensate gas reservoir seepage resistance characteristic slope, determining the condensate gas reservoir staging yield corresponding to each of the plurality of grades. According to the embodiment of the invention, the condensate gas reservoir yield can be subjected to staged analysis and the staged yield can be corrected, so that the accuracy of predicting the gas production rate is improved.

A method for determining a relative permeability of a porous medium uses a segmented structural image generated from a 3D image to produce a pore-scale output from a pore-scale flow simulation. A Darcy-scale flow model is generated by simulating fluid flow on boundary conditions of the pore-scale flow simulation and an initial relative permeability model. The Darcy-scale output is compared to the pore-scale output to determine a degree of match. The initial relative permeability model is updated and the Darcy-scale simulation and inverse modeling steps are repeated until the degree of match falls within a pre-determined tolerance.

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 belongs to the technical field of grouting simulation, and particularly discloses a method and system for simulating split grouting of a deformed porous medium, which comprises the following steps: constructing a three-dimensional geometric model of a porous medium in a region to be simulated, determining a calculation domain, and dividing the calculation domain into a plurality of non-overlapping unit grids; establishing a multiphase system control equation, and performing numerical updating on relative permeability, density, viscosity and surface tension; based on the updated parameters, performing fluid velocity field calculation by using a fluid control equation of a pure fluid region; calculating the transmission time based on the obtained fluid velocity, and then updating the slurry viscosity field by using a slurry viscosity space-time tracking model; updating the solid velocity and mass based on the solid mass and momentum conservation equation, and completing the grouting simulation process. The application comprehensively considers the dynamic coupling effect of the permeability change and stress state of the porous medium, and provides a scientific basis for grouting design and optimization under complex working conditions in engineering.

The embodiment of the invention provides a fractured rock mass pulse two-phase flow stress sensitivity testing method and platform, and the method comprises the steps: S1, making a fractured rock mass sample, and putting the sample into a testing platform; s2, according to the pressure upper limit, the pressure lower limit and the pulse frequency of the pulse two-phase flow, pulse pump pressure in a sine wave form is obtained through calculation; s3, measuring the relative permeability of the pulse two-phase flow in the sample when the pulse two-phase flow is injected into the sample in a sine wave form pulse pump pressure under the set confining pressure; s4, adjusting the ratio of the gas-phase fluid to the liquid-phase fluid in the pulse two-phase flow for multiple times, and repeating S3 to obtain the relative permeability of a group of pulse two-phase flow; and S5, changing the set confining pressure for multiple times, repeating the steps S3 to S4 to obtain the relative permeability of the multiple groups of pulse two-phase flows, and analyzing the stress sensitivity of the pulse two-phase flows in the fractured rock mass. According to the embodiment of the invention, the stress sensitivity of the pulse two-phase flow in the fractured rock mass is analyzed, and powerful technical support is provided for efficient exploitation of oil and gas resources.

This invention relates to the field of carbon dioxide geological storage and utilization technology, specifically to a method for determining the relative permeability of shale gas and water considering CO2 connectivity. It includes: obtaining basic parameters of the shale; establishing the relationship between CO₂ connectivity (CI) and bound water saturation (S). wi The quantitative relationship; based on the theory of variable diameter capillary tubes, the shape coefficient F of the pore throat unit is introduced. i This invention couples CO₂ connectivity (CI) into the analytical expression of gas-water relative permeability, constructing a shale gas-water relative permeability calculation model that considers CO₂ connectivity. By incorporating this dynamic key parameter into the model construction and establishing an exponential quantitative relationship between CO₂ connectivity and bound water saturation, the influence of the proportion of effective flow paths of CO₂ in the pore-throat network on seepage is accurately quantified. This results in a correlation coefficient between the model's calculated values ​​and experimentally measured values ​​exceeding 0.95, significantly outperforming the traditional Brooks-Corey model and improving the accuracy of relative permeability prediction for low-permeability shale.

This invention discloses a method for jointly inverting the fluid diffusion coefficient and relative permeability in a dual-porous medium. The method includes: determining the governing equations for fluid transport in the reservoir; obtaining basic rock physical parameters; conducting a gas-driven water physics simulation experiment to monitor gas pressure and water saturation in fractures at different times and locations; constructing a training dataset based on initial experimental conditions, boundary conditions, and monitoring data; establishing a physical information neural network model, using location and time as inputs, and outputting gas pressure in the matrix, gas pressure in fractures, and water saturation, calculating a loss function by automatically differentiating the output results and combining them with the governing equations; and training the physical information neural network model using the training dataset with the goal of minimizing the loss function, jointly inverting the gas diffusion coefficient and gas-liquid relative permeability. This invention achieves the joint inversion of the gas diffusion coefficient and gas-liquid relative permeability in a dual-porous medium.

This invention discloses a method for constructing a relative permeability model of tight cores that considers the effect of seepage. This method takes into account the reduction in oil saturation caused by seepage during the post-fracturing well stagnation process, which leads to the inadequacy of traditional relative permeability curves. A capillary force model of tight cores based on fractal theory is proposed. Based on this, analytical solutions for capillary force models and relative permeability models that do not consider seepage and those that do consider seepage are constructed respectively. This is of great significance for explaining the mechanism of enhanced oil recovery during the post-fracturing well stagnation process and can be widely applied in the field of enhanced oil recovery through fracturing in unconventional reservoirs.