15 results about "Bound water" patented technology

The application discloses a shale oil reservoir core micro-percolation model and a preparation method and application thereof, and belongs to the technical field of oilfield development experiment researches.The core micro-percolation model comprises a rock sample and adhesive glass sheets used on two surfaces of the rock sample, and according to the oil-water flow direction in the rock sample, the side surface of the rock sample is set as an inflow end, an outflow end, a first end and a second end respectively, one or two needle heads are arranged close to the inflow end, one needle head is arranged close to the outflow end, and the core micro-percolation model is packaged through glue.The single-needle head and double-needle head micro-percolation models are prepared for different types of shale oil reservoir cores, and oil-water two-phase percolation experiments are carried out on typical rock samples; through the experiments, more accurate understanding of the percolation channels of oil and water in the shale reservoir core is obtained, the distribution states of residual oil and bound water in the core are accurately characterized in a visualized mode, and important references can be provided for the research on percolation curves, the understanding of percolation rules and the compilation of development schemes.

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

The application discloses a kind of sandy conglomerate fluid property identification method based on bound water saturation model, belong to complex lithology reservoir comprehensive evaluation technical field, solve the technical problem that although the existing technique comprehensive identification method can identify fluid property to some extent, but because reservoir structure is complex, strong heterogeneity, oil-water identification is difficult, lack of systematicness when evaluating.The method disclosed in the application obtains single well average J type function by laboratory mercury injection experiment, obtains bound water saturation S wi From function, corrected porosity physical value φ is established with bound water saturation S wi Fitting, obtain the bound water saturation model based on corrected porosity physical value, then recalculate water saturation, bound water saturation, then and well logging data establish fluid identification chart, with reliable theoretical basis, easy to operate and the like.

To simultaneously collect and systematically evaluate information regarding free water and bound water within living organisms. [Solution] A magnetic resonance imaging apparatus according to one embodiment comprises a setting unit and a scanner. The setting unit sets a pulse sequence. The pulse sequence includes a plurality of sub-pulse sequences. The plurality of sub-pulse sequences collect MR (Magnetic Resonance) data corresponding to each of the plurality of echo signals generated after the application of MT (Magnetization Transfer) pulses and RF (radio frequency) pulses to the subject, using a UTE (Ultrashort Echo Time) sequence. The scanner collects MR data based on the pulse sequence set by the setting unit. The MR data corresponding to the first echo signal after the application of the RF pulse from among the plurality of echo signals of at least one sub-pulse sequence is used for the analysis of both bound water and free water in the subject.

The application is suitable for the technical field of oil and gas field stimulation and reconstruction, and provides a gas reservoir water lock releasing method based on adsorption-desorption dynamic balance regulation and control. The method first injects a low-concentration water lock releasing agent solution into a reservoir to form a non-saturated adsorption layer; then, a high-concentration water lock releasing agent is injected in a slug mode, and the surfactant component is redistributed and rearranged on the interface driven by the concentration gradient; by controlling the residence time, the interface molecules are partially desorbed and re-adsorbed to establish adsorption-desorption dynamic balance; combined with injection parameter window regulation and control, the periodic reconstruction of the interface structure and the release of water lock are realized. Through the synergistic mechanism of "staged injection-concentration gradient-residence regulation", the surfactant component presents a dynamic conversion behavior, effectively weakens the stability of the water film and promotes the release of bound water. The application does not depend on the structure of a specific chemical agent, has wide application range and strong interface regulation and control capability, and is suitable for the release of water lock in low-porosity and low-permeability and tight gas reservoirs.

This invention relates to a soil complex dielectric hybrid model that integrates interfacial polarization and temperature competition mechanisms, comprising the following steps: (1) measuring clay content, temperature, and humidity in the soil, while simultaneously determining the microwave frequency of the desired remote sensing product, and calculating the maximum bound water content and free water conductivity; (2) obtaining the real part of the free water dielectric considering the MW interfacial polarization mechanism; (3) obtaining the imaginary part of the free water dielectric considering the bound water effect, the MW interfacial polarization mechanism, and the temperature competition mechanism; (4) obtaining the complex dielectric constant of bound water; (5) based on the complex dielectric constants of free water, bound water, soil parent material, and air, as well as the maximum bound water content, soil porosity, volume fraction of soil parent material, soil humidity, and the wet soil complex dielectric hybrid model, calculating the real and imaginary parts of the complex dielectric constant of wet soil. This invention provides a soil complex dielectric hybrid model with higher accuracy and a wider frequency band applicability, offering a new parameterization scheme for passive microwave remote sensing and in-situ soil moisture inversion.

The present invention relates to a method for producing a composite material from a cementitious body, aggregate, and reinforcing material. The cementitious body is produced by preparing a starting product containing at least 20% by mass of one or more components from ultramafic rock, weathered ultramafic rock, olivine, and / or industrial waste; homogenizing the starting product; and hydrothermally treating the homogenized starting product in a heat treatment apparatus at a temperature exceeding 100°C for at least 12 hours. Furthermore, the bound water of the converted starting product is dehydrated by heat treatment and / or reactive grinding. Subsequently, the converted and dehydrated starting product is used as a binder, and hardening water is added for hardening. The water / binder ratio is 1:2 or less. Before, after, and / or simultaneously with the addition of hardening water, aggregate and reinforcing material are added to the converted and dehydrated starting product to improve its load-bearing capacity. The reinforcing material is resistant to pH values ​​below 11 and / or provides protection against pH values ​​below 11. Additionally or alternatively, additives to increase the pH value of the pore solution in the cementitious material can be added to the starting product of the cementitious material.

This invention provides a method, apparatus, and system for determining the thickness of a water film in sandstone. The method involves obtaining a T2 NMR spectrum curve from a sandstone sample, and then determining the corresponding capillary radius distribution curve based on the T2 NMR spectrum curve and a pre-defined pore structure. The number of capillaries in the sandstone sample is determined based on the pore volume and capillary radius distribution curve. The bound water saturation is established by centrifuging the sandstone sample, and the bound water volume is determined. The water film thickness is then determined based on the bound water volume, the number of capillaries, and the capillary radius distribution curve. This invention enables a quantitative description of the sandstone water film thickness. The determined water film thickness can be effectively applied to the analysis of movable water in gas reservoirs and the evaluation of reservoir gas production capacity, providing technical support for subsequent analysis of movable water in gas reservoirs and the evaluation of reservoir gas production capacity.

This invention discloses a method for analyzing the gas-water distribution characteristics corresponding to water intrusion dynamics based on micro-CT, comprising: S1, preparing interlayered full-diameter cores; S2, placing the interlayered full-diameter cores on a gas reservoir water intrusion experimental device, establishing a bound water state, and performing CT scanning on the interlayered full-diameter cores after depressurization to obtain the first scan data; S3, re-establishing the bound water state, establishing formation pressure, and achieving water intrusion attenuation by reducing back pressure through pump withdrawal, attenuating to the abandonment pressure at an attenuation rate; after attenuation, performing CT scanning on the interlayered full-diameter cores to obtain the second scan data; S4, comprehensively analyzing the gas-water distribution characteristics. This invention selects real cores to prepare interlayered cores and combines them with CT images of the reservoir before and after water intrusion to obtain the gas-water distribution in the pores of the rock sample. It can also analyze the influence of different core permeability, different water body sizes, and different attenuation rates on water intrusion characteristics, thereby obtaining the gas-water distribution characteristics.

This invention relates to the field of oil and gas exploration and development technology, and is a method for oil-water identification based on radar model-based well logging nuclear magnetic resonance (NMR). It involves establishing radar charts corresponding to different fluid properties using five parameters: water affinity coefficient, oil affinity coefficient, and normalized original bound fluid signal, bound oil signal, and bound water signal. The radar chart of the original core sample whose fluid properties are to be identified is compared with the radar charts corresponding to the different fluid properties to determine the fluid properties of the original core sample. This invention combines the five parameters—water affinity coefficient, oil affinity coefficient, and normalized original bound fluid signal, bound oil signal, and bound water signal—to establish radar charts. By identifying the fluid properties of the formation through these radar charts, this method can effectively reflect the fluid property characteristics of the formation and provides important data support for subsequent well logging, oil testing, layer selection suggestions, and interpretation evaluation.

A fluid identification method, relating to the field of oil and gas reservoir evaluation, and comprising: determining an escaping fluid porosity correction coefficient of a multi-section full-diameter core: determining apparent total porosity, a two-dimensional nuclear magnetic T1-T2 spectrum, and component fluid porosity of the full-diameter core; determining fluid distribution intervals, bound fluid porosity, vacuum pumping and water saturation-based movable fluid porosity, and total porosity; and determining the escaping fluid porosity correction coefficient on the basis of the total porosity, the apparent total porosity, and bound water porosity of the full-diameter core; establishing a porosity correction model on the basis of the correction coefficient of the multi-section core; determining the total porosity on the basis of the model; and using the apparent total porosity, the total porosity, water saturation, and the component fluid porosity to determine oil and gas saturation of a full-well-section core. The method allows for accurate measurement of the porosity of a gas reservoir core, accurate identification of fluid properties, and quantitative evaluation. The present invention also relates to a fluid identification apparatus, a processor, and a machine-readable storage medium.

This invention relates to the field of chromatographic analysis technology, and discloses an alkaline treatment activation method for an acrylonitrile-divinylbenzene stationary phase. The method includes: immersing the acrylonitrile-divinylbenzene stationary phase in an aqueous diethanolamine solution; filtering to remove the diethanolamine solution; rinsing the stationary phase with deionized water until neutral; and then heat-treating the rinsed stationary phase at 105°C and 270°C under nitrogen purging and vacuum conditions; cooling and then sieving before column packing. This invention effectively neutralizes acidic sites on the stationary phase surface through alkaline diethanolamine immersion, combined with segmented heat treatment to remove bound water and residual diethanolamine, significantly improving the tailing phenomenon of ammonia chromatographic peaks, reducing the asymmetry factor from 1.8 to 1.3; simultaneously, it greatly improves analytical reproducibility, reducing the sample standard deviation from 0.404 to 0.096. This method is simple to operate, low in cost, and suitable for gas chromatographic determination of ammonia content in syngas.

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.

The application relates to an oil layer water production rate calculation method, system and storage medium, and relates to the technical field of reservoir evaluation in oil geological exploration. The oil layer water production rate calculation method comprises the following steps: obtaining geological data of core samples in a target area. A function relationship between a resistivity increase coefficient and water saturation in the geological data is fitted to obtain a fitting relationship value of the resistivity increase coefficient and the water saturation. A pore structure factor of the core samples is determined according to a reservoir quality factor, a nuclear magnetic resonance T2 geometric mean value and a clay content in the geological data. The bound water saturation of the core samples is determined according to the pore structure factor. The movable water saturation of the core samples is determined according to the bound water saturation and the water saturation. The movable water saturation and the fitting relationship value are calculated through a water production rate calculation model to obtain the water production rate of the core samples. By introducing various rock physical parameters, the movable water saturation which is difficult to confirm is replaced, so that the calculation is more accurate.