267 results about "Water saturation" patented technology

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The invention discloses a shale oil sample oil-water saturation determination method based on a dry distillation technology. The problem that the oil-water saturation of the shale oil reservoir rock sample is difficult to accurately measure by using a single sample is solved. Comprising the following steps: S1, preparing a full-diameter flaky shale sample to be detected; s2, performing a sample pore water removal experiment on the tested shale sample; s3, carrying out a low-temperature dry distillation water recovery rate measurement experiment; s4, carrying out low-temperature dry distillation, and measuring the mass of the moisture trap and the shale sample; s5, measuring the total volume of the shale sample; s6, removing oil from the shale sample; s7, dehumidifying the shale sample subjected to oil removal; s8, measuring the volume of the skeleton; s9, correcting and measuring the total volume of the fracture sample; and S10, calculating the oil-water saturation of the shale sample. According to the method, on the basis of a low-temperature dry distillation technology, the pore water of the shale sample and the oil-water saturation of the shale oil sample with the effective porosity can be determined on the same sample, and the determination and analysis method is convenient, rapid and accurate.

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

The application discloses a kind of considering the dynamic change of water saturation tight gas reservoir productivity calculation method.This application method is by selecting multiple core samples, combined with the geological data of research area, using the way of steady state method and seepage method, experimental measurement each core sample under different water saturation conditions Start-up pressure gradient and gas-water relative permeability, dynamic start-up pressure gradient empirical formula is established, according to the gas-water relative permeability of each core sample under different water saturation conditions, the gas-water ratio of each core sample is calculated, and based on the physical model of tight gas reservoir fracturing horizontal well and considering the mathematical model of one-way shale gas reservoir fracturing horizontal well, the productivity model of tight gas reservoir fracturing horizontal well considering gas-water two-phase is established, and the IPR curve considering the dynamic change of start-up pressure under different water saturation conditions is obtained.The application realizes the accurate calculation of the productivity of tight gas reservoir, and lays a foundation for the development of tight gas reservoir.

The invention relates to the technical field of geotechnical engineering monitoring, and discloses a water-rich sand pebble bed pile foundation settlement monitoring system and method.The system comprises at least one intelligent sensing pile internally and integrally provided with a mechanical-temperature sensing module used for obtaining strain and temperature distribution of a pile body, a water-rich sand pebble bed pile foundation settlement monitoring module, a water-rich sand pebble bed pile foundation settlement monitoring module, a water-rich sand pebble bed pile foundation settlement monitoring module and a water-rich sand pebble bed pile foundation settlement monitoring module, the electrical sensing module comprises an electrode array and is used for applying current and measuring potential; the acoustic sensing module is used for passively collecting acoustic emission signals of soil around the pile; and the data processing module is configured to execute joint inversion imaging, that is, the strain and / or acoustic emission signals are used as prior constraints to invert the electrical data so as to generate a three-dimensional resistivity image representing the state of the soil body around the pile. According to the method, through the multi-physical field joint inversion and physical property parameter decoupling technology, accurate positioning of the damage of the soil body around the pile and quantitative diagnosis of the porosity and the water saturation are achieved.

The present invention discloses a method for predicting the recovery rate of deep coalbed methane, comprising: determining correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation, as well as average coal reservoir pressure, cumulative water production and conventional average deviation coefficient of gas under multiple production dates, calculating the actual average deviation coefficient of gas, establishing a prediction model for reservoir gas production, calculating an iterative value of a control volume according to the correction values ​​of physical parameters, capillary pressure, reservoir porosity and water saturation and original gas reserves of the reservoir, returning the iterative value to an initial given value that replaces the control volume for cyclic calculation, determining a first relationship model between cumulative water production and average coal reservoir pressure, determining a vertical axis prediction value of the prediction model under a given exhaust gas pressure according to the first relationship model, substituting the vertical axis prediction value into the prediction model established last time in the cyclic calculation to obtain the recoverable reserves of coalbed methane and calculate the recovery rate, thereby achieving the purpose of improving the reliability of the prediction.

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

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

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